20160623AVU to Staff 3-5,8-13,15,23-32,34,35.pdf

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: N/A
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 001 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide copies of any and all data requests submitted to you by any party to this proceeding and your corresponding responses to those data requests. This is an ongoing request.

RESPONSE:
Avista has not responded to any data requests at this time, but Avista will provide copies of data requests,
along with corresponding data responses, from all parties to this proceeding as they are received.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/20/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 002 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please state what base rate increase (or decrease) from 2015 levels would have occurred if an attrition
adjustment were excluded from the filing and provide workpapers to derive this value on the same basis as they were provided in the original filing.
RESPONSE:
Were the Attrition adjustments excluded, the pro forma studies that were provided as a cross check to the
attrition analyses would independently support the requested electric and natural gas increases. See Smith Exhibit Nos. _(JSS-2) and _(JSS-3), and Smith workpapers previously provided.

Page 1 of 3
-20%
0%
20%
40%
60%
80%
100%
120%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Av
g
.

%

C
h
a
n
g
e

f
r
o
m

2
0
0
5

B
a
s
e
l
i
n
e
Utility Costs are Rising Faster than Sales
Net Plant Investment Non-Fuel O&M/A&G Retail kWh Sales Retail Therm Sales
Actual
Forecast
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 003 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Does the Company have any cost reduction initiatives during the rate period in the current rate case? If
no, please describe what actions the Company plans to take to constrain costs. If yes, please describe each cost reduction initiative planned by the Company, including the expected amount of cost reduction,
the timing of the initiative, and the financial accounts impacted.
RESPONSE:
In a direct response to the continuing increase in non-fuel O&M/A&G year over year, senior management of the Company took steps to reduce this trend in increasing expenditures. Examples of cost management efficiencies and steps taken to reduce the growth in expenses is discussed below and include resource-
related decisions, the Voluntary Severance Incentive Plan (VSIP) to reduce employee complement and
changes to pension and post-retirement medical programs. These changes illustrate Avista’s efforts to
control our costs, improve efficiency, and focus on long-term sustainable savings to continuously improve our service to customers and manage costs into the future.
The impact of these cost management efficiencies and steps taken to reduce the growth in expenses affect
the rate year and can be seen in the following chart, provided in Mr. Morris’ direct testimony at Exhibit
No. (SLM-1T) page 11, Illustration No. 7:

Page 2 of 3
This chart clearly shows the reduction in expenses in 2013, as represented by the green Non-Fuel
O&M/A&G line and continuing at a lower level through 2018. Furthermore, as explained in Andrews’
testimony at Exhibit No. __(EMA-1T) page 28, lines 6-9, although Avista’s O&M/A&G costs have grown at an annual rate of approximately 5.7% per year for the past six years (2007-2013), we have used
a lower annual growth rate of 3% per year for our Attrition Study to reflect the recent cost-cutting
measures implemented by the Company, and the expectation that Avista will manage the growth in these
expenses to a lower level in future years.
As noted at Exhibit No. __(SLM-1T), starting at page 12, line 1, the reduction in operating expenses in
2013 (green line) related primarily to Avista’s Voluntary Severance Incentive Plan (VSIP) executed in the
fourth quarter of 2012, reducing employee complement at the Company. In addition, in 2013, senior
management made changes to Avista’s pension and post-retirement medical plans, effective January 1,
2014, which has reduced future O&M/A&G costs.
Avista’s response to ICNU_DR_019C showed the annual savings of the 55 eliminated positions totaled
over $5 million. In addition, 2015 and 2016 savings related to the Company’s changes in its pension and
post retirement medical plans on a system basis are estimated to be approximately $2.6 million and $3
million, respectively, with increasing annual savings expected going forward. As noted above, these savings are reflected in the Company’s filing for 2016 through a reduced attrition escalation factor of all
O&M and A&G expenses of 3%. These savings are also reflected in the Company’s Pro Forma Cross
Check Studies, as the reduced level of labor is already reflected in the Company’s twelve-months ended
September results of operations for Washington, and the 2016 level of pension and post retirement
medical expenses have been reflected in the Pro Forma Employee Benefit adjustments (see Exhibit Nos._(JSS-2) and _(JSS-3).)

Other examples of cost management which have a future impact, relate to the biomass energy bill
(SB5575) signed by Washington Governor Christine Gregoire on March 7, 2012 and the decisions made
related to the Company’s Palouse Wind Project. The biomass energy bill (SB5575) qualified legacy biomass energy (built before 1999) as an eligible renewable resource for purposes of meeting the
renewable portfolio standard (RPS) requirements of the Washington State Energy Independence Act (I-
937). As a result of the bill’s passage, the energy generated at Avista’s Kettle Falls biomass plant
qualifies to meet our RPS requirements, beginning in 2016. The passage of the bill, which involved a
multi-year legislative effort led by Avista, will save our customers millions of dollars over the long-term, because Avista can now use this existing renewable power to meet our State mandates, which reduces the
need to buy renewable energy credits or invest in the development of new resources.

In December 2012, with the addition of the Palouse Wind Project to Avista’s electric generation portfolio,
Avista began receiving power from this relatively low-cost purchased power agreement (PPA). As background leading to acquiring the output to this Project, Avista had purchased the Reardan wind site in
2008 for the purpose of installing renewable wind generation to comply with the requirements of I-937.
In 2009, the Reardan project was compared against 29 competing proposals for renewable energy offered
by third-parties to Avista through a Request for Proposals (RFP). Analysis of all of the proposals showed
that the Reardan Project was the Company’s least-cost option for securing a new renewable resource for its customers. However, even though it was the least-cost option, the levelized cost to customers from
Reardan would still be over 10 cents per kWh. After further consideration, the Company chose, in 2010,
to delay development of Reardan due, in large part, to the fact that the Company did not have an
immediate need for energy resources or renewable resources, immediate development of the Project
would increase retail rates for customers, and the fact that Reardan represented a low-cost option to hold for later development. Avista continued to watch the market for wind resources, and in late 2010/early
2011, indications were that prices for wind turbines and other equipment had declined. Avista issued

Page 3 of 3
another RFP in February 2011, and executed the PPA with First Wind for the Palouse Wind Project in
June 2011. Although the pricing for this PPA is confidential, Avista had requested renewable resource
proposals with a levelized cost equal to or less than 6.2 cents/kWh, and the pricing was well below the prior estimates of Reardan. By choosing to delay the Reardan Project, Avista was able to later take
advantage of much lower cost wind generation, which resulted in substantial benefits for the Company’s
customers. Because the Palouse Wind Project is a PPA, Avista receives no earnings associated with
acquiring the output from that Project. Therefore, Avista not only provided substantial cost savings to
customers, but also passed up the opportunity to invest in the Reardan Wind Project and earn a return for shareholders on what would have been a substantial investment.
These are two recent significant examples highlighting the extent of the efforts that Avista has made to
mitigate the long-term costs to its customers.

Additional measures worthy of note, are the continuing measures related to hiring restriction and the efforts of “Customer Touch Point Teams,” discussed below.

Hiring Restrictions: The Company continues to operate under a hiring restriction which requires
approval by the Chairman/President/CEO, President of the Utility, the CFO, and the Sr. VP for Human
Resources for all replacement or new hire positions.
Customer Touch Point Teams: In the fall of 2011, a team from across the Company identified every
contact point or “touch point” a customer has with Avista. The objective of the initiative is to improve our
customers’ overall experience when doing business with us, as well as improve responsiveness in a
respectful and least cost manner. This team identified a “touch point map” of 172 different customer interactions or touch points. To date, the touch point teams have made improvements to 57 distinct touch points. In 2014 Avista touch point team projects focused on Electric and Gas Emergency Operation
Planning (involving customer touch points), Paperless Billing, Damage Assessment During Storms, and
Storm Estimated Restoration Time. In 2013, other examples included touch point team projects that
focused on customer awareness of natural gas safety, the distributed generation application process, and accuracy of electric outage estimated restoration times.
Although not all examples noted above are specifically quantified and provided here, as explained above,
the Company has reflected the reduction to its O&M and A&G costs in its requested revenue requirement
through its use of a lower “Adopted Operating Expenses” factor used within its electric and natural gas Attrition Studies. (See page 9 of Exhibit Nos. _(EMA-2) and _(EMA-3).)

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 004 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
For each of the past five rate years, on a Washington jurisdictional basis for both electric and natural gas
operations, please indicate whether Avista earned above its authorized return on equity. RESPONSE:
For the last 5-years (2009-2013) Avista’s consolidated Washington electric and natural gas operations return
on equity (ROE) on a normalized basis was under its authorized ROE, as shown in the table below:
2009 2010 2011 2012 2013
Normalized 7.83%8.09%7.39%8.13%9.47%
Authorized 10.20%10.20%10.20%10.20%9.80%
Washington Combined Electric and Gas Return On Equity (ROE)
For consolidated Washington electric and natural gas operations ROE on an actual basis, for the period 2009 through 2014, please see Avista’s response to ICNU_DR_029.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/23/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 005 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Does the Company have a methodology or process in place to prioritize capital expenditures, such that projects providing greater benefits to ratepayers are completed prior to those providing less ratepayer
benefits (or some other prioritization metric)? If yes, please provide all policies, procedures, manuals and
other documentation relied on by the Company to prioritize its capital expenditures.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 005C. Please note that
Avista’s response to ICNU – 005C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205.
Yes, the Company is utilizing business case documents to facilitate standardized discussion and
prioritization of capital projects. (Business cases of projects discussed in the Company’s direct filed case
were provided as Exhibit No. _(KKS-5). The “Assessment Score” (brief discussion below) in the top
right corner of the business case document represents one data point that the Company uses for prioritization.

Each business case has five criteria that contribute to an assessment score. The “Assessments” section in
the top right corner of the business case document contains four criteria, and the “Category” field in the
top left corner also contributes to the “Assessment Score”. The financial assessment represents the customer, rather than shareholder, internal rate of return. Greater benefits to customers, which may take
the form of reductions in costs or reductions in the growth of costs, result in a higher score. The strategic
assessment represents the company strategy to which the project or program aligns. The business risk
assessment refers to reductions in risk exposure, such as legal or environmental risk, as a result of the
capital project. The project or program risk assessment reflects the level of certainty of cost, schedule, and resource estimates, where high certainty is preferable. Finally, the category serves to adjust the raw
score. Most notably, a project that is mandatory via Washington Administrative Code (WAC), Federal
Energy Regulatory Commission (FERC) guidelines, etc. will have a higher score as compared to a non-
mandatory project. The “Assessment Score” is then used for the funding prioritization discussion, along
with considerations of availability/utilization of crews, compliance requirements, work efficiency, safety, and partially funding programs versus an “all or nothing” approach.

Please refer to ICNU_DR_005C Confidential Attachment A for a list of all business case submission
requests and approved funding levels. In each of the years considered (2015-2019), several proposals
were either rejected, delayed and/or cut back as a result of this analysis. This reduction in proposed capital expenditures (as can be seen in Attachment A) by year and by project is $48.9 million (2015),
$85.0 million (2016), $55.1 million (2017), $41.4 million (2018) and $58.8 million (2019).

For Internal Use Only

2014
Rendall Farley, Tia Benjamin
Asset Management
Avista Corp.

Electric Transmission System 2014 Annual Update
ICNU_DR_006 Attachment A Page 1 of 48

2 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Front cover:
Inspector Javier Tamez testing the Walla Walla – Wanapum 230kV line
(December, 2013)

ICNU_DR_006 Attachment A Page 2 of 48

3 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Table of Contents
Purpose ................................................................................................................................................................... 5
Executive Summary ................................................................................................................................................. 5
Assets ...................................................................................................................................................................... 7
Key Performance Indicators (KPIs) ........................................................................................................................ 10
Capital Replacement and Maintenance Investment ............................................................................................. 13
Risk Prioritization .................................................................................................................................................. 20
Unplanned Spending ............................................................................................................................................. 22
Outages ................................................................................................................................................................. 24
Programs ............................................................................................................................................................... 28
1. Major Rebuilds ............................................................................................................................................. 28
2. Minor Rebuilds ............................................................................................................................................. 28
3. Air Switch Replacements .............................................................................................................................. 29
4. Structural Ground Inspections (Wood Pole Management) ......................................................................... 32
5. Structural Aerial Patrols ............................................................................................................................... 33
6. Vegetation Aerial Patrols and Follow-up Work ............................................................................................ 33
7. Fire Retardant Coatings ................................................................................................................................ 34
8. 230kV Foundation Grouting ......................................................................................................................... 34
9. Polymer Insulators........................................................................................................................................ 34
10. Conductor & Compression Sleeves ............................................................................................................ 35
Benchmarking ....................................................................................................................................................... 35
Data Integrity ........................................................................................................................................................ 37
Material Usage ...................................................................................................................................................... 39
Root Cause Analysis (RCA)..................................................................................................................................... 39
Business Cases ....................................................................................................................................................... 40
System Planning Projects ...................................................................................................................................... 41
Area Work Plans .................................................................................................................................................... 42
Projects .............................................................................................................................................................. 43
Major Rebuilds and Other Projects ................................................................................................................... 43
Minor Rebuilds .................................................................................................................................................. 46
Ground Inspections ........................................................................................................................................... 47
References ............................................................................................................................................................. 48
ICNU_DR_006 Attachment A Page 3 of 48

4 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Figure 1: Example Transmission Asset Components and Expected Service Life .................................................... 8
Figure 2: Transmission and Distribution System Replacement Values, Average Service Life, and Levelized
Replacement Spending ......................................................................................................................................... 13
Figure 3: Replacement Cost vs. Remaining Service Life ....................................................................................... 14
Figure 4: 2013 Transmission Spending Categories ............................................................................................... 18
Figure 5: 2013 Planned Capital, O&M, and Emergency Spending ....................................................................... 18
Figure 6: Outage Charts, 2009 - 2013................................................................................................................... 27
Figure 7: Air Switch Replacement Value vs. Remaining Service Life .................................................................... 30
Figure 8: Maintenance Benchmarking: Aerial Patrols (left) and Pole Inspections (right) .................................... 36
Figure 9: Idaho Power Long-term Replacement Costs ......................................................................................... 37
Figure 10: System Planning Projects (Big Bend, CDA & Lewiston/Clarkston) ...................................................... 41
Figure 11: System Planning Projects (Palouse, Spokane and System) ................................................................. 42

Table 1: Primary Assets of the Electric Transmission System – Circuits ................................................................ 7
Table 2: Component Assets and Quantities ........................................................................................................... 8
Table 3: Transmission Structures and Poles ........................................................................................................... 9
Table 4: 115kV vs 230kV Pole Materials .............................................................................................................. 10
Table 5: Transmission KPIs and Unity Box Metrics............................................................................................... 11
Table 6: Additional Performance Measures, 2009 - 2013 .................................................................................... 12
Table 7: Levelized Replacement Spending Options ............................................................................................. 15
Table 8: 2013 Transmission Spending .................................................................................................................. 16
Table 9: 2013 Planned Capital Projects (Non-Reimburseable) ............................................................................ 17
Table 10: 30-year Planned Capital and O&M Recommendations........................................................................ 19
Table 11: Health and Failure Probability Index Criteria ....................................................................................... 20
Table 12: Criticality Index Criteria ........................................................................................................................ 21
Table 13: Unplanned/Emergency Spending, 2006 - 2013 .................................................................................... 23
Table 14: 115kV, 230kV, and 500kV Unplanned Spending per Mile .................................................................... 24
Table 15: Transmission Outage Causes, 2009 - 2013 ........................................................................................... 25
Table 16: Major Rebuild Projects, 2014 - 2017 .................................................................................................... 28
Table 17: Airswitch Priority List for Repairs and Replacements .......................................................................... 31
Table 18: Transmission Asset Data Integrity ........................................................................................................ 38
Table 19: Relative Material Purchases, 10/2010 – 10/2012 ................................................................................ 39
Table 20: Simulation-Supported Business Cases, 2012 - 2015 ............................................................................. 40

ICNU_DR_006 Attachment A Page 4 of 48

5 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Purpose
Annual updates are meant to serve a general audience from the perspective of long-term, balanced
optimization of lifecycle costs, performance, and risk management. The intent is to help the reader become
rapidly familiar with the system’s physical assets, performance, risks, and replacement and maintenance
programs. Consistent annual updates also provide the continuity required for useful historical information and
continuous improvement of asset management practices.
In addition to this narrative report, two other elements of the annual update include a “Quick Facts” sheet
highlighting key points, and a spreadsheet providing supporting data. Additional “Quick Facts” sheets
describing various asset management programs and projects are also available. This annual update reflects
the best available information as of December 31, 2013. For more details, please visit the Asset Management
Sharepoint site at AM Annual Updates.
Executive Summary
In order to maintain reliability levels and provide the best value to customers, the bulk of Avista’s aging
transmission infrastructure requires replacement over the next 20 to 30 years. This totals over $600M in
capital replacement investment, based on current material, labor and other project costs. Ramping up over
the next two years, we are effectively doubling planned design and construction output from the former $12M
to a sustained level of over $25M in annual projects. This represents a significant undertaking, requiring
careful management and support. In order to be most effective, it also requires fact-based prioritization and
targeting of available funds to the riskiest elements of the system. In this respect, although a long term capital
replacement budget of over $20M per year is clearly needed, planned condition assessment of older lines in
the next few years may well justify larger investments in the near term.
While outages and related unplanned/emergency spending on the 230kV system have remained at a relatively
low level (less than $200k per year), they increased substantially for the 115kV system to over $1.5M in 2013.
This continues a trend of rising 115kV emergency spending since 2011. However, if not for two separate storm
events in Othello and northeast Washington, 115kV emergency spending would have seen a slight decrease
from the $1.1M spent in 2012. While no statistically significant trends are evident, last year also saw an
increase in outages caused by birds and other animals, primary conductor, and vehicles hitting poles. Pole
fires and tree related issues continued to decrease, possibly due to the effectiveness of fire protective coatings
and the transmission vegetation management programs.
ICNU_DR_006 Attachment A Page 5 of 48

6 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Notable achievements in 2013 include continued compliance with clearance mitigation (LiDAR) work
mandated by NERC . Nine LiDAR projects were completed last year, maintaining schedule for all lines
complete in 2015. Major rebuilds of the Moscow City to North Lewiston 115kV line at $6.4M, and the Burke-
Thompson A&B 115kV lines at $2.2M were also accomplished. Wood pole inspections surpassed goals last
year, allowing for earlier condition assessment and future rebuild work on the Walla Walla – Wanapum and
Hot Springs – Noxon #2 230kV lines. Although for a few more years many 115kV lines will not have had a
ground inspection for 20 years, at the current pace we will reach the targeted 15-year inspection cycle for all
transmission circuits by 2019. With a few exceptions, timely follow-up work remains on-track. Confirmation of
230kV data including the location of larch wood poles is now complete and progress is underway on the 115kV
system. This is critical to making more accurate risk assessments and effectively targeting capital funding,
given the shorter service life of larch compared to cedar wood species. The large backlog of job updates to
drawings and electronic records was also completed, as well as a detailed air switch asset inventory,
preparations for Maximo implementation, the development of new standards and methods integrating the use
of new PLS-CADD design software, and a root cause analysis and implementation of preventive actions
following the Othello storm.
Beyond execution of approved construction, below is a list of recommended initiatives to further improve the
long-term performance and management of transmission assets.
Top 10 Recommendations
1. Confirm the location, quantity and age of larch, cedar and steel poles on all 115kV circuits.
2. Complete the Risk Index for all transmission circuits, use it to prioritize and schedule ground
inspections, business case development, follow-up repairs and rebuilds.
3. Continue refinement, reporting and use of transmission system KPIs.
4. Complete simulation studies and business cases for rebuilds of Cabinet – Noxon, Benewah – Pine
Creek, and Hot Springs – Noxon #2 230kV circuits in 2014.
5. Complete a system-wide simulation study to support optimal Transmission asset inspection
intervals and long-term asset replacement policies/budgets.
6. Investigate industry best practices and develop agreement on a systematic air switch risk ranking
method, replacement schedule, and inspection and maintenance program.
ICNU_DR_006 Attachment A Page 6 of 48

7 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

7. Reduce the lead time for as-built construction updates to AFM, Plan and Profile (P&P) drawings,
and the engineering vault files to one month (currently 6 to 12 months).
8. Investigate industry best practices, develop and implement an inspection and planned
maintenance program for steel transmission structures.
9. Determine the risks and appropriate mitigation work resulting from structural loads of distribution
underbuild, across the entire transmission system.
10. Publish a major revision of transmission construction standards, accurately reflecting best
practices in design and construction work. Engage the line crews and regional staff, commit to
continuous improvement and prompt updates of these standards for the long term.
Assets
The tables and charts below provide a high-level summary of physical assets in the transmission system.
Replacement values represent the cost to replace existing assets with equivalent new equipment in 2014
dollars, not including right-of-way purchases, capacity or ratings upgrades, mandated projects, and other work
associated with growth-related installations.

Table 1: Primary Assets of the Electric Transmission System – Circuits
60kV Circuit $250,000 $20,000 0.4 $72,049
115 Single Circuit $400,000 $20,000 1452.2 $609,915,600
115 Underground Circuit $3,600,000 $180,000 2.8 $10,584,000
115 Double Circuit $525,000 $20,000 23.9 $13,014,600
230 Single Circuit $700,000 $20,000 604.0 $434,851,200
115-230 Double Circuit $850,000 $20,000 55.3 $48,145,800
230 Double Circuit $900,000 $20,000 25.8 $23,736,000
2164.3 $1,140,319,249
Average Asset Lifecycle (Years)70
Annual Levelized Replacement Spending over Lifecycle $16,290,275
ICNU_DR_006 Attachment A Page 7 of 48

8 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Table 2: Component Assets and Quantities

Figure 1: Example Transmission Asset Components and Expected Service Life
Structures 4990 16483 21473 70
Poles 9021 27401 36422 78
Air switches (not incl substations)2 188 190 40
Conductor (miles)2055 4602 6657 100
Compression sleeves 1370 3068 4438 50
Insulators (Ceramic/Poly/Glass)22978 60202 83180 70
ICNU_DR_006 Attachment A Page 8 of 48

9 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Table 3: Transmission Structures and Poles

ICNU_DR_006 Attachment A Page 9 of 48

Table 4: 115kV vs 230kV Pole Materials
Key Performance Indicators (KPIs)
The table below shows overall KPI results for 2013, which are monitored and recorded on a monthly
basis throughout the year. The first four are leading indicators over which we have direct operational
control. The final two KPIs are lagging indicators of system performance, which should have a causal link
to the leading indicators. In other words, if we consistently execute well as demonstrated by the leading
indicators, over time we should see satisfactory outcomes as manifested by the lagging indicators, and
vice versa. When this does not occur, deeper investigation and root-cause analysis is justified, as
something other than the expected causal relationship is potentially at play.
18%
77%
5%
115kV pole material
28%
50%
22%
230kV pole material
pole material larch cedar steel total
service life 55 75 150 78
# 115 poles 4989 20820 1341 27150
# 230 poles 2613 4665 1994 9272
total # poles 7602 25485 3335 36422
ICNU_DR_006 Attachment A Page 10 of 48

11 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Table 5: Transmission KPIs and Unity Box Metrics
2,400 3,476 0.69
100 100 1.00
% of 115kV system inspected 70 70 1.00
10 10 1.00
1 1 1.00
oldest item in backlog (# months since inspection)18 17 0.94
500 296 1.86
# 230kV wood poles older than 50 years replaced with steel 175 15 23.33
# air switches > 40 yrs old replaced 4 5 0.80
113,142 238,861 2.88
# of Customers with Unplanned Transmission Outages > 3 Hrs 10,182 17,135 3.17
$204,022 $118,329 0.58
115kV Emergency Spending $1,116,997 $1,512,614 1.35
Total Emergency Spending $1,321,019 $1,630,943 1.23
20%0.7
20%1.0
15%1.0
15%6.1
15%1.7
15%1.2
100%1.8
ICNU_DR_006 Attachment A Page 11 of 48

12 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

By these measures, performance was much better than planned for structural ground inspections, as
the Walla-Walla – Wanapum 230kV line was inspected ahead of schedule to facilitate mandated
clearance violation mitigation and other repair work in 2014. Aerial patrol inspections and system-wide
followup repairs from ground and aerial patrol inspections remained on-track overall. Emergency
spending was slightly worse than “planned” (the average since 2009), and reliability performance even
more so – as detailed in the unplanned spending and outages sections of this report. Aging
infrastructure replacement was much less than that required to maintain system reliability over the long
term, as recently established with levelized replacement budgets recommended at $21M per year over
a 30-year timeframe ($12M for aging 115kV, $9M for 230kV). As we ramp up replacement construction
in the years ahead, we expect to meet or exceed these goals. We will continue to replace equipment
primarily on the basis of recent inspection and condition assessments. However the age and respective
service life of the system at a high-level provides a strong leading indicator of long-term system
reliability.
Additional performance measures are tabulated below since 2009:

Table 6: Additional Performance Measures, 2009 - 2013
Note that important performance measures currently cannot be evaluated due to inadequate data
availability. This includes safety incidents from transmission work, the total number of annual failures
and respective failure modes for various asset components such as poles, air switches, crossarms,
insulators, splice connections, and so forth. An ongoing, long-term effort is necessary to make this
information available and assimilate into our set of KPIs and circuit risk rankings.
Performance Measure Goal 2009 2010 2011 2012 2013 Remarks
ICNU_DR_006 Attachment A Page 12 of 48

13 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Capital Replacement and Maintenance Investment
Levelized replacement spending represents the annual spending required to replace the asset category
in a perfectly level form over the asset’s service life in 2014 dollars, not including inflation. Prior to
adjusting for uneven service life profiles, this provides a simple, rough-cut measure to compare against
actual replacement spending each year, i.e. the minimum needed to keep up with aging infrastructure
replacement. This currently stands at $16.3 M per year for the transmission system.
Relative to other major areas of the transmission and distribution (T&D) system, transmission assets
have a longer service life, and the total replacement value of $1.1B is on par with substation’s $0.9B and
about half of distribution’s $2.0B. All together, levelized replacement spending is roughly $84 M per
year in perpetuity for Avista’s T&D system (2014 dollars). However, as shorter lived wood materials are
replaced with steel in the decades ahead, we expect overall service life to increase from 70 years to over
100 years for the transmission system. Assuming all other factors being equal, this in turn would reduce
the minimum levelized spending to under $12M/year, roughly 50 years from now.

Figure 2: Transmission and Distribution System Replacement Values, Average Service Life,
and Levelized Replacement Spending
ICNU_DR_006 Attachment A Page 13 of 48

14 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

The next step is to look more closely at the replacement cost of actual installed assets compared to
remaining service life. This provides the basis for levelized replacement budgets given an uneven
profile, as summarized in the following chart:

Figure 3: Replacement Cost vs. Remaining Service Life
Note that $185M of assets in the field, mostly 115kV, are currently beyond expected service life based
on their age and statistical predictions of mean time to failure. This represents a significant risk to the
continued reliability of the transmission system, particularly for those 115kV circuits with more than 10
years past normal service life.
To address this issue, several alternatives present themselves in terms of long-term replacement
policies, as shown in the table below. The 30-year replacement period is recommended at $21M per
year, split between $12M for 115kV and $9M for 230kV. This policy, when coupled with an ongoing,
annual risk assessment and targeting of funds, over the long term will effectively reduce risks. This does
not take into account further opportunities to reduce lifecycle costs, which in many cases present very
real and substantial benefits. For example, lower costs of capital and capturing economies of scale by
rebuilding larger sections of line could justify higher infrastructure replacement in the near term, in
order to achieve optimal lifecycle costs and system performance for the long term. In fact, when we
look at the older lines scheduled to be inspected in the next few years (see the Area Work Plans section
at the end of this report), it is probable that we will discover such a large number of unacceptable
conditions that major if not full rebuilds will provide the optimal business cases, dramatically increasing
0
50
100
150
200
250
-1001020304050607080
Re
p
l
a
c
e
m
e
n
t

C
o
s
t

(
$
)
Mi
l
l
i
o
n
s
Remaining Service Life (years)
Transmission System Replacement Cost -vs-Remaining Service Life
ICNU_DR_006 Attachment A Page 14 of 48

15 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

the recommended budgets as presented here. Accordingly, recommendations will be revised as
inspections and subsequent analyses are completed in the years ahead.
In any case, the table below presents a simple levelization as a starting point, that addresses the aging
infrastructure problem in a way that reduces the volatility and operational business risk of ramping up
and down construction work from year to year, while responsibly maintaining system performance.
Again, it should be emphasized that in order to be most effective, this level of replacement spending
must be targeted at those assets that pose the greatest overall risk, as discussed in the Risk Prioritization
section of this report.

Table 7: Levelized Replacement Spending Options
A variety of data uncertainties result in +/- 10% confidence in the stated figures. In terms of
replacement costs, the most significant uncertainty from year to year involves the volatility of contract
labor, which has risen 12% since last year. Extensive work was recently completed to confirm 230kV
pole data, most importantly the identification of pole material. However, this work remains to be
completed in 2014 for the 115kV system. When completed, we expect relatively small changes to high-
level funding recommendations. However, it will significantly improve confidence in risk rankings and
targeting of available replacement funds on a line-by-line basis.
The recommended $21M/year in levelized replacement spending over the next 30 years compares to
$9.9M actual spending in 2013. Significant effort is underway to ramp up replacement construction
within the next two years. Other project categories include growth/mandated, reimburseable,
Cumulative Replacement Costs ($)
Tx Capital Assets
Service Life (yrs)
Levelized
Replacement
Period (yrs)115kV 230kV Total
Annual
Levelized
Replacement
Spending ($)
ICNU_DR_006 Attachment A Page 15 of 48

16 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

operations and maintenance (O&M), and unplanned/emergency. These figures are tabulated below for
2013. Spending associated with liability claims and the underground network are not included, due to
data uncertainty. Please note that many construction projects involve a combination of replacement
and growth/upgrade/mandated work, and are reflected accordingly as approximate values. Historically,
upwards of 90% of transmission construction is through contractors. However, the rising costs of
contract labor and greater availability of Avista crews has reduced this percentage recently.

Table 8: 2013 Transmission Spending
$9,906,225 Replacement Capital Projects
$3,965,832 Growth/Mandated Capital Projects
$1,630,943 Unplanned/Emergency Work
$1,100,000 O&M - Vegetation Management
$500,000 O&M - Other
$1,136,787 Reimburseable Capital Completed
Total Tx Planned and Unplanned Spending
$15,008,844 Total Planned Capital (including reimburseable)
$1,600,000 Total Planned O&M
Total Planned Capital & O&M
$418,080 Colstrip capital Tx&Sub Avista portion
$378,000 Colstrip O&M Tx&Sub Avista portion
$796,080 Total Colstrip Tx&Sub Capital & O&M, Avista portion
ICNU_DR_006 Attachment A Page 16 of 48

17 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Table 9: 2013 Planned Capital Projects (Non-Reimburseable)

2013 Project Spend Program/Project Description Project Type
ICNU_DR_006 Attachment A Page 17 of 48

Figure 4: 2013 Transmission Spending
Categories

Figure 5: 2013 Planned Capital, O&M, and
Emergency Spending
This shows that approximately 90% of spending is planned, vs. 10% unplanned. The percent of planned
work should increase as planned replacements ramp up and unplanned/emergency spending is held
constant or reduced. Mandated clearance mitigation work (a.k.a. LiDAR projects) accounted for $1.5M
of the $4M in the growth/mandated category for 2013. Although the spending in this category is highly
variable from year to year, a constant value of $3M is assumed for the future. Note that it is possible
that a system plan for looped 230kV system around Spokane may become solidified, in which case
spending in this category would increase substantially. A small increase of 2% per year is assumed for
reimbursable projects such as road moves. O&M dollars may be reduced over the long-term, due to
lower inspection costs of wood vs. steel poles, however this was not accounted for as it is somewhat
uncertain and represents a relatively insignificant sum. Other figures represent recommendations for
planned replacement and maintenance programs as specified in the Programs section of this report. As
stated earlier, optimal planned spending may vary considerably after making adjustments for actual
condition assessments as inspections are completed, capturing economies of scale opportunities when
rebuilding larger sections of line, and taking into account cost of capital considerations from year to
year. Notwithstanding these variables, the numbers below represents the minimum recommended for
consistent, planned transmission work in the years ahead.
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
81%
9%10%
2013 Planned Capital, O&M and
Unplanned Transmission Spending
ICNU_DR_006 Attachment A Page 18 of 48

19 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Table 10: 30-year Planned Capital and O&M Recommendations
In short, in order to minimize lifecycle costs and maintain system performance, the bulk of the
transmission system needs to be rebuilt over the next three decades, if not sooner. This is no small
endeavor, entailing significant financial and operational risk. Although construction and even design
work may be contracted out, internal workloads will in all cases rise substantially in the years ahead for
the Transmission Engineering group and supporting departments. A successful transition and sustained
production of high quality design work and construction in the field – that will last well into the 22nd
century – requires careful management and strong support across the company.
$0
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
2013 2014 2015-2018 2019-2043
30-year Transmission Planned Capital
and Maintenance Recommendations (2014 dollars)
Ma
j
o
r

C
a
p
i
t
a
l

Re
p
l
a
c
e
m
e
n
t

P
r
o
j
e
c
t
s
Gr
o
w
t
h
/
M
a
n
d
a
t
e
d

Ca
p
i
t
a
l

P
r
o
j
e
c
t
s
Re
i
m
b
u
r
s
e
a
b
l
e

C
a
p
i
t
a
l

Pr
o
j
e
c
t
s
Air

S
w
i
t
c
h

Re
p
l
a
c
e
m
e
n
t
s
Min
o
r

R
e
b
u
i
l
d
s

&

Re
p
a
i
r
s
St
r
u
c
t
u
r
a
l

G
r
o
u
n
d

In
s
p
e
c
t
i
o
n
St
r
u
c
t
u
r
a
l

A
e
r
i
a
l

P
a
t
r
o
l
s
Ve
g
e
t
a
t
i
o
n

Ma
n
a
g
e
m
e
n
t
Fir
e

R
e
t
a
r
d
a
n
t

P
r
o
g
r
a
m
23
0
k
V

F
o
u
n
d
a
t
i
o
n

Gr
o
u
t
i
n
g

O&M %0% 0% 0% 0% 0% 100% 100% 100% 100% 100%
Capital %100% 100% 100% 100% 100% 0% 0% 0% 0% 0%Total Capital Total O&M Total Planned
2013 $8,785,633 $3,965,832 $1,136,787 $150,556 $970,036 $294,000 $94,595 $1,100,000 $200,000 $100,000 $15,008,844 $1,788,595 $16,797,439
2014 $14,110,816 $2,210,000 $1,159,523 $264,000 $1,300,000 $192,000 $100,000 $1,200,000 $242,000 $100,000 $19,044,339 $1,834,000 $20,878,339
2015 $19,436,000 $3,000,000 $1,182,713 $264,000 $1,300,000 $192,000 $100,000 $1,200,000 $242,000 $100,000 $25,182,713 $1,834,000 $27,016,713
2016 $19,436,000 $3,000,000 $1,206,367 $264,000 $1,300,000 $192,000 $100,000 $1,200,000 $242,000 $100,000 $25,206,367 $1,834,000 $27,040,367
2017 $19,436,000 $3,000,000 $1,230,495 $264,000 $1,300,000 $192,000 $100,000 $1,200,000 $242,000 $100,000 $25,230,495 $1,834,000 $27,064,495
2018 $19,436,000 $3,000,000 $1,255,105 $264,000 $1,300,000 $192,000 $100,000 $1,200,000 $242,000 $0 $25,255,105 $1,734,000 $26,989,105
2019-2043 $19,450,000 $3,000,000 $1,280,207 $250,000 $1,300,000 $175,000 $100,000 $1,000,000 $50,000 $0 $25,280,207 $1,325,000 $26,605,207
ICNU_DR_006 Attachment A Page 19 of 48

20 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Risk Prioritization
According to Wikipedia, risk is defined as “ . . . 1. The probability of something happening multiplied by
the resulting cost or benefit if it does. (This concept is more properly known as the 'Expectation Value'
and is used to compare levels of risk)”
- from http://en.wikipedia.org/wiki/Risk
In mathematical form, this is expressed as:
Risk/Benefit = ∑𝑛𝑖=1 (Event Probability) 𝑖 * (Event Consequence) 𝑖
Beginning this year, the transmission system’s major circuits will be ranked by this formulation. The
rankings will be used as a starting point for further deliberation among internal stakeholders, with the
goal of allocating resources where they will have the most significant impact. The rankings may also be
used to justify inspection and follow-up work earlier than normally scheduled (currently a 15-year
inspection cycle on each line). At minimum, the rankings will be used to prioritize the commissioning of
detailed studies, simulations and development of business cases for major line rebuild projects.
The first component of risk for our transmission lines is the probability of a failure event, which we will
refer to as the asset’s “Health and Failure Probability Index”. This is a normalized score from 0 (low
failure probability) to 100 (high failure probability). The factors and respective weighting for the Health
and Failure Probability Index are as follows, derived from a combination of the line’s condition, track
record, and severity of operating environment. Each factor is scored from 1 (low) to 5 (high), based on a
set of objective measures collaboratively developed by representatives in Asset Management,
Transmission Design, System Planning, and System Operations groups.
% weight criteria
25 Unplanned outages/spending
20 Remaining service life
20
20 # of miles
15 conditions, weather intensity, vegetation, relative
Table 11: Health and Failure Probability Index Criteria
ICNU_DR_006 Attachment A Page 20 of 48

21 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

The second component of risk (event consequence), we will refer to as the asset’s “Criticality Index”. It
is basically a measure of the severity of consequences should an unplanned failure event occur. This is
also a normalized score from 0 (low severity = low event consequence) to 100 (high severity = high event
consequence). The factors and respective weighting for the Criticality Index are as follows, derived from
the relative importance of the line in terms of power flow, its effect on the system should it become
unavailable, the relative time and cost to effect repairs, and potential secondary damage based safety
and environmental issues and its proximity to other company and private property. These factors are
also scored from 1 (low) to 5 (high), based on a set of objective measures.
% weight criteria
40 power delivery
20 potential damages
15 access
15 system stability, voltage control and thermal
10 voltage & configuration
Table 12: Criticality Index Criteria
Given the Health and Failure Probability Index and Criticality Index, we now have the ability to prioritize
lines based on comparable risk levels, which we refer to as the line’s “Reliability Risk Index” , where
Reliability Risk Index = (Health and Failure Probability Index) * (Criticality Index)
This is also normalized from a score of 0 (low risk) to 100 (high risk). In order to be worthwhile, it is
essential that the risk index is ultimately useful to making practical business decisions. It must produce
credible results to a wide variety of experts and decision makers, and it must be reliably reproduced
each year without a great burden of effort. In this light, we expect some iteration as we obtain results
from the formulation developed thus far and gain additional feedback from stakeholders and technical
experts. Over time, improvement in our ability to collect and use data may also allow us to evaluate
shorter segments of lines, rather than the entire circuit. This would facilitate a more detailed view of
system risks and targeted mitigation efforts. The development and use of aids that help visualize results
(e.g. color-coded system maps), may also be worthwhile.
ICNU_DR_006 Attachment A Page 21 of 48

22 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Finally, once the Reliability Risk Index is fully vetted and found useful, we may consider including a
simple, quantitative measure of other concerns from various groups such as system planning,
operations, and communications. This is essentially a way to quantify subjective knowledge of different
kinds of risks/benefits other than reliability. A “Stakeholder Index” could easily be produced, for
example, by allocating a number of points to each representative, distributing these points to
respective lines in the system based on their level of concerns and/or potential opportunities. This
could then provide the basis for a final “Capital Project Index”, where
Capital Project Index = Reliability Risk Index + Stakeholder Index
In reality, this is simply the summation of two different sets of risks/benefits that apply to the same set
of assets, consistent with expected value methodology. A reasonable weighting factor for each set is
advisable, e.g. 75% reliability weighting, 25% stakeholder weighting.
Ultimately, objective rankings must be truly useful, helping the organization arrive at the right business
decisions with less effort. Asset management staff will continue to facilitate and support this
collaborative undertaking, striving for improvement and strong results.
Unplanned Spending
Unplanned spending represents capital replacement of those transmission assets that have
unexpectedly failed and require prompt attention, typically by Avista crews (e.g. storm response
events). Despite the variability that is correlated with fluctuations in weather intensity, unplanned
spending is an especially important lagging indicator of system performance, trends, and the
effectiveness of asset management programs. In addition to cost premiums incurred from overtime
labor, unplanned work typically presents greater safety risks to the public and on-site Avista employees,
as well as other risks including property damage, environmental, general liability, planned work delays,
and additional rework costs following the event. We have set annual goals at the average of unplanned
spending from 2009 through 2012 as shown in the chart and table below, reflecting a desire to maintain
system reliability. This results in targets of $1.1M for 115kV and $210k for 230kV, for a total of $1.3M
per year. Note that we have consistently spent a much greater amount of total unplanned dollars on
the 115kV system, at four times the proportional value of capital assets when compared to the 230kV
system. Normalizing for respective system replacement values, each year we are spending an average
of $0.0017 unplanned capital for every 115kV asset dollar in the field, compared to $0.0004 for 230kV.
ICNU_DR_006 Attachment A Page 22 of 48

23 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

This is consistent with the fact that 230kV assets are felt to pose a higher potential consequence should
they fail, and therefore we maintain them accordingly – deliberately effecting a lower frequency of
unplanned events on the 230kV system, relative to 115kV. While this may be the case, it remains that
the optimal target of unplanned spending has not been quantitatively determined for either system.
This is a desired output from a future system model and analysis, involving the quantification and
simulation of all significant risks and costs associated with unplanned events and
maintenance/replacement work. Note that zero emergency spending is actually sub-optimal unless
there is zero tolerance for any risk – otherwise, it represents over-investment in the design
configuration and actual condition of physical assets.

Table 13: Unplanned/Emergency Spending, 2006 - 2013
$0
$200,000
$400,000
$600,000
$800,000
$1,000,000
$1,200,000
$1,400,000
$1,600,000
$1,800,000
2006 2007 2008 2009 2010 2011 2012 2013
115kV unplanned Tx capital 230kV unplanned Tx capital
2005 2006 2007 2008 2009 2010 2011 2012 2013 Avg 2009-2012
115kV - WA $127,835 $312,958 $609,438 $265,221 $874,996 $649,760 $585,250 $499,341 $1,123,122
115kV - ID $170,725 $406,111 $161,470 $221,343 $349,459 $626,503 $274,517 $608,163 $389,492
115kV - all $298,560 $719,070 $770,908 $486,564 $1,224,455 $1,276,263 $859,767 $1,107,505 $1,512,614 $1,116,997
230kV - WA $79,136 $215,228 $97,946 $215,416 $57,721 $73,482 $156,491 $58,976 $89,984
230kV - ID $10,018 $74,783 $32,856 $120,056 $89,364 $79,950 $12,979 $228,681 -$134,091230kV - MT w/ Colstrip $6,015 $0 $286,338 $257,879 $249,429 $368,855 $574,428 $298,059 $436,991
230kV - MT w/o Colstrip $6,015 $0 $1,590 $59,590 $27,525 $13,275 $0 $72 $18,910
230kV - OR $0 $12,273 $0 $0 $2,475 $0 $360 $14,738 $9,435230kV - all w/o Colstrip $95,170 $302,285 $132,392 $395,062 $177,085 $166,706 $169,830 $302,467 $118,329 $204,022
115kV and 230kV (all)$393,729 $1,021,354 $903,300 $881,625 $1,401,539 $1,442,969 $1,029,597 $1,409,972 $1,630,943 $1,321,019
ICNU_DR_006 Attachment A Page 23 of 48

24 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Total unplanned spending increased in 2013 to just over $1.6M, above the average of $1.3M per year
since 2009. This was largely due to over $500k in costs attributed to the Othello 115kV storm response
in September. Unplanned spending for 115kV in Idaho actually decreased by over $200k in 2013
compared to 2012, as well as nearly $200k in reduced 230kV unplanned spending overall. 230kV
unplanned spending was dominated by $72k on the Walla Walla – Wanapum line, and $24k on the Lolo
– Oxbow line.
Unfortunately, the use of 115kV blanket accounts does not allow for ready analysis of unplanned
spending on individual 115kV circuits. This is necessary to get a better understanding of risk and asset
prioritization on a line-by-line basis. It is hoped that Maximo will help remedy this situation.
The figures above do not include spending on the 11% Avista ownership of the roughly 500 miles of
500kV Colstrip transmission and substation assets. Total planned and unplanned Colstrip
transmission/substation spending under the project #42401050 account was $418k in capital and
another $378k in O&M expenses in 2013. This work is performed by Northwestern Power. Further
investigation would be required to determine what portion of this spending is planned vs. unplanned,
and to segregate transmission and substation spending. 11% of 500 miles is 55 miles (plus our
proportion of substation assets), for which we spent nearly $800k to replace and maintain last year.
This works out to nearly $15k spent per mile of 500kV assets, compared to just over $7k per mile of
115kV and 230kV assets.

Table 14: 115kV, 230kV, and 500kV Unplanned Spending per Mile
Outages
The following information is taken from the number of sustained outages (longer than five minutes) for
Transmission–type events per the annual Reliability Report created by Operations Management.
$15,472,057 Total Tx Planned Construction & O&M, Non-reimburseable
2,164 # miles Tx 115kV & 230kV
$7,149 Total spending per mile, 115kV & 230kV
$796,080 Total Colstrip Tx&Sub Capital & O&M spend
55 # equivalent miles 11% ownership of 500miles 500kV Tx
$14,474 Total Spending Tx&Sub per mile, 500kV
ICNU_DR_006 Attachment A Page 24 of 48

25 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Outages are a strong lagging indicator of system reliability, highly correlated with unplanned/emergency
spending.
Table 15: Transmission Outage Causes, 2009 - 2013
Notable changes include the large increase in planned outages and weather events, particularly from
wind and lightning. Although the number of wind events went down from 34 to 23, the customer-hours
outage went up considerably – from 2,748 to 100,450. The increase in weather related outages was
mostly due to large storm events near Colville and Kettle Falls in August, and Othello in September.
Lightning and wind make up 12 of the 13 largest outage events for the year, a primary conductor event
in Springdale, WA in August the lone non-weather event to make this list. Pole fire outages continued
Subreason 2009 2010 2011 2012 2013
Bird 10 15
Other 1
Squirrel 2
Company - Other 4 1 4 6
Conductor - Pri 1 20
Connector - Pri 4 1
Crossarm-rotten 7 10 1
Insulator 2 1
Cutout/Fuse 1
Highside Breaker 1
Relay Misoperation 1
Tranformer 4 2
Equipment - Other 1
See Remarks 1
Planned - Forced Outage 3 4 1 1 8
Planned - Maint/Upgrade 17 11 10 32
Pole Fire 6 18 20 14 9
Car Hit Pole 15 3 5 13
Public - Tree 3 1
Tree Fell 1 1 11
Undetermined 45 4 43 22 18
Weather - Lightning 13 9 19 32
Weather - Snow/Ice 83 17 12 8 7
Weather - Tree 5 5 3
Weather - Wind 6 40 11 34 23
Grand Total 170 142 134 126 195
# Outage Occurances
ICNU_DR_006 Attachment A Page 25 of 48

26 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

their decline, and tree incidents also dramatically decreased – positive indicators for the effectiveness of
the fire protective coating and vegetation management programs, respectively. However, two separate
fire events occurred last year on the Walla Walla – Wanapum 230kV line despite the recent application
of fire protective coating.
The large increase in bird incidents and car hit poles is not conclusive as they are on par with some
previous years, but warrants close attention for sustained trends in future years. Closer scrutiny of
those events resulting in a large number of customers experiencing an outage greater than three hours
is advisable in the future, as recent surveys indicate this is the most important reliability factor driving
customer satisfaction.

Cu
s
t
o
m
e
r
-Ho
u
r
s
Year
Customer-Hrs Extended Outage from
Unplanned Transmission Causes
# C
u
s
t
o
m
e
r
s
Year
# Customers Experiencing > 3hrs
Outage from Unplanned Transmission
Causes
# O
c
c
u
r
a
n
c
e
s
# Occurances Extended
Transmission Outage by Cause
Cu
s
t
o
m
e
r
-Ho
u
r
s

O
u
t
a
g
e
Customer-Hours Extended
Transmission Outage by Cause
ICNU_DR_006 Attachment A Page 26 of 48

Figure 6: Outage Charts, 2009 - 2013
As far as weather-attributed causes, in fact the root cause could be a component which has fallen below
its required specification parameters, waiting as a “hidden” failure until such time as a storm of
sufficient force makes it evident through an extended outage. It might be possible to “normalize” the
data to a reasonable measure of weather intensity, so that we might have some indication as to
whether outages are being caused by weather conditions above and beyond design specifications, or by
component degradation. This could help ascertain root causes, and if storm intensity trends are evident
to justify changes to component specifications. Exactly how this might be accomplished is uncertain,
however, and requires further evaluation.
The Reliability Report is derived from the Transmission Outage Report (TOR) and OMT data, providing
excellent information on overall transmission related outages, but not directly on individual
transmission lines. The TOR in turn is produced by System Operations, based on a custom logging tool
with daily updates. This report includes any transmission event, not just actual customer outage events
per the Reliability Report. Utilizing the TOR, System Operations compiles the Transmission Adequacy
Database System (TADS), and associated NERC reports. The TADS provides information on individual
230kV lines, but not 115kV lines as it is not a NERC requirement.
In order to improve the reliability risk indices, it would be desirable to obtain event information on a
line-by-line basis. With current information and systems, this would require approximately 250 work-
hours annually. A cost/benefit analysis and business case could be considered to obtain this information
with additional resources and/or improved data collection.
Cu
s
t
o
m
e
r
-Ho
u
r
s

O
u
t
a
g
e

p
e
r

O
c
c
u
r
a
n
c
e
Customer-Hours Extended
Transmission Outage per Occurance
ICNU_DR_006 Attachment A Page 27 of 48

28 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Programs
1. Major Rebuilds
Out of the $9.9M in planned capital replacement projects in 2013, $8.8M was spent on major rebuilds,
$970k on minor rebuilds and $151k on switch replacements. The recommended level is a minimum of
$19.4M, $1.3M and $264k, respectively, for a total of $21M replacement spending per year over 30
years. As stated previously, replacement projects do not include additional capital projects that are
mandated, growth related, reimburseable, or otherwise do not address aging infrastructure.
Furthermore, the recommended spending is the minimum levelized spending over the entire 30 year
period, which in the shorter term may need to be increased to minimize lifecycle costs – given
inspection results, risk analysis, cost of capital, and economies of scale opportunities.
The most significant major rebuild projects planned through 2017 are listed below, with rough estimates
of budget dollars allocated for each year.

Table 16: Major Rebuild Projects, 2014 - 2017
2. Minor Rebuilds
The information collected by aerial patrols is used in conjunction with inspection reports to prioritize
and budget minor rebuild capital projects, where a major rebuild is not justified. Our goal is to complete
repairs and replacements for high-risk issues from 0 to 6 months after identification by aerial or ground
inspection, and for all other moderate risk issues by the end of the year following the inspection year.
Planned inspections and follow-up work in the form of minor rebuilds is effective in maintaining service
levels while minimizing capital and O&M costs. However, from a quantitative perspective it has not yet
been established at what point it becomes suboptimal to “patch together” a line per the minor rebuild
approach, when instead large sections if not the entire line should be rebuilt. Where warranted and on
a line-by-line basis, detailed simulation modeling helps ascertain the optimal rebuild approach and
support a business case to compete with others in the company’s capital projects selection and
budgeting process. A system-wide simulation model is needed to help validate and provide adjustment
recommendations to our inspection intervals, minor rebuild budgets, and fact-based policies on minor
vs. sectional vs. full rebuild thresholds.
See the Area Work Plans section at the end of this report for a list of minor rebuild projects in 2014.
ER Description BI Proj BI Description 2014 2015 2016 2017 2014-2017
Benewah-Moscow 230kV PT305 Reconductor/Rebuild $25,000 $7,815,802 $8,060,576 $8,302,393 $24,203,771
CDA-Pine Creek 115kV Rebuild CT300 Rebuild Transmission $25,000 $0 $4,500,000 $5,750,000 $10,275,000
Devils Gap-Lind 115kV Rebuild ST302 Rebuild Transmission $2,346,742 $3,947,144 $4,050,558 $0 $10,344,444
Ben-Oth SS 115 - ReCond/ReBld FT130 Ben-Oth SS 115 - ReCond/ReBld $2,500,000 $3,600,000 $3,500,000 $0 $9,600,000
Sys - Rebuild Trans - Condition AMT81 BRX-CAB & BRX-SCR Rebuild $2,500,000 $2,500,000 $2,500,000 $2,000,000 $9,500,000
Pine Creek-Burke-Thompson Falls CT101 Rebuild Transmission $3,700,000 $3,500,000 $0 $0 $7,200,000
LP Line Ratings Mitigation Project CT305
ICNU_DR_006 Attachment A Page 28 of 48

29 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

3. Air Switch Replacements
Transmission Air Switches (TAS) are used to sectionalize transmission lines during outages or when
performing maintenance. The frequency of operation varies greatly depending on location. Some TAS
may not be operated for years.
TAS may not operate properly when opened and flashover, possibly tripping the line out. This can be the
result of a component failure (whips and vac-rupters) or the TAS may be out of adjustment. Although
most TAS mis-operations could be avoided with regular inspection and maintenance, we currently have
no planned inspection or maintenance program. Inspections could range from systematic visual
inspection to infrared scanning and inspections for corona discharge. Maintenance could consist of
exercising switches, lubrication, blade adjustment, replacement of live parts such as contacts and whips,
and repair of ground mats/platforms.
Ground grids and platforms are installed at the base of each switch to provide equal potential between
an operator’s hands and feet in the event of a flashover of the air switch. The typical ground grid is
buried copper wire attached to ground rods covered with fine gravel. Over time the ground grids may
be damaged by machinery, cattle and erosion, or even theft. We are currently benchmarking other
utility’s practices and configurations regarding air switch grounding, in order to evaluate and implement
changes that may minimize these issues. Preliminary indications are that most utilities perform much
more inspection and maintenance of their air switch assets than Avista.
With radial switching of the 115kV transmission system, many TAS are operated remotely. In these
instances, company personnel are not present to observe the opening of the switch and some problems
therefore remain hidden. A small problem could progress to the point where a major failure occurs. A
small amount of material is maintained in the warehouse and Beacon yard for emergency repairs, but
many of the switches are old and parts are often difficult to locate.
Typically three to four TAS are replaced each year. A detailed inventory of 115kV TAS outside
substations was completed in 2013, including determination of age where formerly 20% of the assets
were unknown. TAS inventory includes 180 switches of various types and configurations, as shown
below according to remaining service life. Based on this profile, levelized replacement should increase
to five replacements per year (increase to $264M annual budget), prioritized according to a rational
condition assessment and quantitative risk assessment, rather than ad-hoc requests from field
personnel and anecdotal observation.
ICNU_DR_006 Attachment A Page 29 of 48

30 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Figure 7: Air Switch Replacement Value vs. Remaining Service Life
In 2008, 80 TAS were fitted with grounding platforms for worker safety. During this process a new worm
gear handle was installed and disconnecting whips were adjusted. Operating pivot joints of the switch
mechanisms are not affected by this work. Thus, the 2008 work was safety related, not switch
mechanism related. Remaining switches in the system requiring new platforms need to be confirmed
and upgraded.
Investigation of industry best-practices regarding inspection and planned maintenance of air switches,
with follow-up recommendations is currently in progress. At minimum, a reasonable condition
assessment program is envisioned, such as visual inspection at least every two years, possibly annual
inspection for those more critical switches, and annual performance evaluation based on System
Operations input. Below is a prioritized list of switches due for repairs or replacement in the next few
years, with those switches exhibiting operational problems listed first.
Re
p
l
a
c
e
m
e
n
t

V
a
l
u
e
Age (Years)
Transmission 115 kV Air Switches
40 Years Expected Service Life
$750,000 of
Capital
Assets
Beyond
Expected
Service Life
ICNU_DR_006 Attachment A Page 30 of 48

31 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Table 17: Airswitch Priority List for Repairs and Replacements
Finally, transmission outage cause tracking needs to be improved in order to ascertain failure trends for
the air switch population. In reading through notes on the TOR, Asset Management was able to
determine that there were 122 outages from 1975 through 2007. An average of 3.7 outages per year
were caused by switches.
SW #Problems Age (yrs)LINE/SUBSTATION
A-70 Problem Switch 84 Chelan-Stratford
A-336 Old KPF, Needs Replaced 49 Grangeville-Nez Perce #1: Cottonwood Tap
A-355 Old KPF on a broken pole 48 Jaype-Orofino
A-346 Wood in Switching Mech. Is bowed 47 Grangeville-Nez Perce #2
A-376 Old KPF, Needs Replaced 43 Grangeville-Nez Perce #2
A-298
Needs whips; Center 0 and North 0 gone, South
Bent 38 115kv Boulder-Rathdrum
A-158
Doesn't work properly, drop load on both sides then
use switch, mat ground straps need repair 31 Beacon-Francis & Cedar
A-345 Pole Needs Structure # Tag 30 Grangeville-Nez Perce #2
A-442 Broken Whip 26 Dworshak-Orofino
A-377 Scott paper tap; Engerized to Switch 21 Grangeville-Nez Perce #2 : Scott Paper Tap
A-176 Mat ground straps need repair 18 Bell-Northeast
A-679 Difficult to Close 15 Othello-Warden #2
A-680 Motor Operator is too slow - it arcs 15 Othello-Warden #2
A-358 Old KPF, Needs Replaced 10 Jaype-Orofino
A-407 Broken Crossarms ??4 Grangeville-Nez Perce #1
A-421 Ground Cables and Strands cut, NEEDS REPAIR 4 Ramsey-Rathdrum #1
A-184 61 Shawnee-Sunset
A-19 59 Pine Street-Rathdrum: Oldtown Tap
A-26 59 Burke-Pine Creek # 3
A-220 57 Lolo-Nez Perce
A-221 57 Lolo-Nez Perce
A-173 47 Moscow 230-Orofino
A-58 46 Chelan-Stratford
A-295 46 Benewah-Pine Creek : St Maries Tap
A-49 44 Devils Gap-Stratford
A-126 40 8th & Fancher-Latah 115 kV
A-127 40 8th & Fancher-Latah 115 kV
ICNU_DR_006 Attachment A Page 31 of 48

32 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

4. Structural Ground Inspections (Wood Pole Management)
Avista wood transmission structures are predominately butt-treated Western Red Cedar poles. Most of
the service territory is in a semi-arid climate. The most common failure mode for wood poles is internal
and external decay at or near the ground line. Transmission Wood Pole Management (WPM) measures
this decay and determines which poles must be reinforced or replaced. Details describing inspection
techniques are in the company’s “Specification for Inspection and Treatment of Wood Poles, S-622”.
This specification was revised in 2013 to include protocols for prompt reporting and remediation of
severely degraded poles.
The testing program is valuable in identification of poles needing replacement or reinforcement.
Compared to the pre-1987 method of solely visual inspections for pole integrity, the testing program
replaces about 15% as many poles.
The wood transmission poles are on a 15-year inspection cycle. We are currently targeting inspection of
2400 wood transmission poles annually out of 36,422 wood poles installed. At this pace, by 2019 we will
reach the 15-year cycle for all transmission lines. See the Area Work Plans section of this report for a list
of future planned inspections.
In recent years, prioritization and scheduling of ground inspections has been based on the time since the
last ground inspection. Results of these inspections provide the basis for case-by-case analysis and the
scope of subsequent minor and major rebuild projects on each line. While it is important that we
maintain a maximum 15-year ground inspection cycle, it is recommended that future inspection
scheduling includes the risk index, which may justify earlier inspection. As a general rule, critical assets
that exhibit age-related failures should be inspected to verify condition and justify service extension or
removal near the end of their expected service lives. We currently have many 115kV lines with assets
10 or more years past expected service life, that have not been inspected for nearly 20 years. This poses
a significant unknown risk.
If actual condition assessment warrants service extension, shorter inspection intervals are prudent when
the time to failure characteristics worsen with age – as is the case with much of our transmission wood
infrastructure. Approximately 17% of the system is beyond its expected life, with a large portion of
those assets over 15 years since the last ground inspection. The scattered age profile on many lines that
results over many decades from periodic minor rebuilds and one-off replacements, makes this situation
difficult to remedy – one must choose between the pros and cons of a somewhat spotty and expensive
replacement policy, larger line section replacements and full rebuilds, or detailed analysis and business
case development tailored to each individual line. Regardless, for those lines that have significant
sections or quantities of older assets that demonstrate higher relative risks, out-of-cycle inspection and
a shorter inspection interval may be warranted (e.g. 10 years instead of 15).

ICNU_DR_006 Attachment A Page 32 of 48

33 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

5. Structural Aerial Patrols
The Avista transmission system covers a large geographical area that has all types of terrain. Some parts
of the system are so remote and difficult to access that they only get inspected when company
personnel are in the area due to a failure or a major reconstruction project. Transmission Aerial Patrols
(TAP) have been utilized to provide a quick above-ground inspection to identify significant problems that
require immediate attention, such as lightning damage, cracked or sagging crossarms, fire damage, bird
nests and danger trees.
In addition, aerial patrols can identify improper uses of the transmission Right-of-Way (R/W), such as
dwellings, grain bins, and other types of clearance problems that must be addressed. Typically, the
patrol will be performed in the spring. Identified repairs, depending on severity, are scheduled to be
performed within 6 months.
TAP inspects 100% of 230kV lines and 70% of 115kV lines annually. The remaining 30% of 115kV lines
are located in urban areas that are frequently viewed by line personnel for potential problems. The
Transmission Design group schedules patrols for each service territory. The TAP areas are: Spokane
(includes Othello, Davenport and Colville), CD’A (includes Kellogg and St. Maries), Pullman, and
Lewiston/Clarkston (includes Grangeville and Orofino).
Aerial patrols are performed by qualified personnel from Transmission Design, often accompanied by
local office personnel. Inspection forms have been developed that contain a weighting system to
identify the severity of defects. This information can then be utilized to make recommendations for
necessary repairs.
6. Vegetation Aerial Patrols and Follow-up Work
The Transmission Vegetation Management (TVM) program maintains the transmission system clear of
trees and other vegetation, in order to provide safe clearance from trees and reduce outages caused by
trees, weather, snow/ice, and wind.
The entire 230kV system is annually inspected with a combination of aerial and ground patrols by the
System Forester, who solely manages the overall program. Select 115kV lines are also patrolled
according to criticality. In addition, vegetation issues noted during structural aerial patrols on the 115kV
system, as well as fielding of transmission line projects by Transmission Engineering are relayed to the
System Forester. Based on this information, follow-up work plans are adjusted and executed with
contract crews over the course of the year.
An increase from the current budget of $1.1 M to $1.2 M is recommended to allow for optimal
completion of major re-clearing work and a transition to mostly herbicide applications over the next ten
years. At this point overall costs should come back to the $1 M/yr level.
See the Transmission Vegetation Management Program reference for more details on the program.
ICNU_DR_006 Attachment A Page 33 of 48

34 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

7. Fire Retardant Coatings
After several fires and a 2008 study to initiate systematic remediation, fire retardant coating has been
applied to the base of wood transmission poles. At this point the entire 230kV system has been deemed
adequately protected and the 115kV system is approximately 22% complete. Targeted areas include
those subject to grassland fires and in close proximity to railroads. Protective coating is not applied to
heavily forested areas as it is deemed inadequate in these areas to merit the cost of application.
It is estimated that approximately 5182 poles remain to be coated in the 115kV system. Following the
current plan to coat 792 poles in 2014, it recommended to coat 1000 poles per year for the following
five years to complete the work by 2020. At a total labor and materials cost of $242/pole, this equates
to $242,000/year. Beyond this, regular maintenance and upkeep will only be required, at an unknown
amount depending on the longevity of the coatings. Until better information is obtained, estimate
$50k/year for ongoing coating maintenance. Performance metrics should be established to monitor
performance of this program, possibly in terms of % of the system protected, maintenance spending and
actual fire damage costs. As noted in the Outages section, pole fire incidents have come down
dramatically of late, however at least two pole fire events occurred on lines with recent application of
fire retardant coating.
See Whicker (2013) for more details and history of this program, which is now administered by the
Transmission Design group.
8. 230kV Foundation Grouting
The Noxon-Pine Creek and Cabinet – Rathdrum 230kV circuits have unique steel structures where the
interface between the steel sleeve in the foundation and above-ground structure requires re-grouting
after approximately 30 years, to avoid destructive corrosion. This work has been completed on the
Noxon-Pine Creek 230kV line. Approximately $100k out of $500k worth of additional work remaining
on Cabinet – Rathdrum 230kV was completed in 2013, with another $100k/year planned for 2014
through project completion in 2017.
9. Polymer Insulators
Transmission Line Polymer Insulators (TPI) provide insulation at the connection points for transmission
lines to the supporting structure. Other types of insulators include toughened glass and older porcelain
types. Although no significant problems have been noted on 115kV lines, there were numerous faults
on 230kV lines from 1998 to 2008 attributable to poly insulators causing line outages, and five
mechanical failures that caused the line to fall.
In 2008 a plan was initiated to replace TPIs and install corona rings on dead-end TPI insulators on various
230kV lines (without corona rings, TPIs are expected to fail in the 10 – 15 year timeframe, with corona
rings the expected service life is extended to an unknown age).
ICNU_DR_006 Attachment A Page 34 of 48

35 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Work was completed primarily in 2009 on N. Lewiston - Shawnee 230kV and Dry Creek – N. Lewiston
230kV, and in 2011 all suspension and dead-end TPIs on the Hatwai - N. Lewiston 230kV were replaced
with toughened glass insulators.
This work appears to have been effective. From 2009 to 2012, only 2 sustained outage occurances
involving insulators are recorded. However, the degree to which TPIs exist on the remainder of the
system, and the prediction of current and future risk is unknown.
For this reason, it is recommended that at least on 230kV lines, future ground inspections include
information gathering on the insulator type, so that an analysis of risk and optimal mitigation actions
may be made in a short time period should that become necessary.
Current transmission engineering standards use toughened glass insulators for 230kV, and either
toughened glass or poly insulators for 115kV. Due to the lighter weight of polymer insulators, they are
generally preferred by Avista crews. However, given the problems experienced on 230kV lines and
anecdotal evidence of high scrap rates for TPIs on 115kV projects, their use on 115kV lines poses some
unknown risks and a systematic monitoring program may be advisable.
10. Conductor & Compression Sleeves
Credible condition and failure characteristics of conductor and compression sleeves, and the location
and age of thousands of compression sleeves in the system are currently unknown. Provided proper
installation, protection, and service conditions, most conductor will last over 100 years, if not
indefinitely. The compression sleeves, however, are expected to last between 40 and 50 years, posing a
more immediate reliability risk.
Between 2008 and 2010, an effective risk mitigation program was carried out for compression sleeves
on 230kV AAC lines, following several years of one to two failures per year. Since then, no known
compression sleeve failures have occurred. However, at some point we should expect failures to
resurface. Until that time, an effort to determine sleeve locations and confirmation of reliable reporting
of conductor and sleeve failures system-wide is advisable. Proactive reinforcement of sleeves may also
be justified, pending more detailed study.
See Whicker (2009) for more details on the 230kV sleeve mitigation project.
Benchmarking
As stated previously, investigation of air switch maintenance practices of various utilities is in progress,
with preliminary results indicating that most utilities perform a much greater degree of maintenance
than Avista.
In terms of broader maintenance benchmarking, a study through a CEATI report (excerpts below) show
that Avista is among the majority of peers conducting aerial patrols once per year, but that of all 15
ICNU_DR_006 Attachment A Page 35 of 48

36 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

utilities responding, we have the longest ground inspection interval at 15 years, as compared to the
most common interval of 10 years.
This does not necessarily mean that our inspection interval needs to be shortened. However, it does at
least indicate where we stand relative to other utilities participating in the survey, and at minimum
would tend to discourage extending our inspection interval any further.

Figure 8: Maintenance Benchmarking: Aerial Patrols (left) and Pole Inspections (right)
Idaho Power, which did not participate in the CEATI survey, is a very good benchmark utility for Avista in
terms of size, operating environment and electric transmission component/system similarities. In
discussions with their staff, thorough transmission structure ground inspections are conducted every 10
years, with quick visual inspections (drive-bys) every 2 years. It is also clear that in general, Idaho Power
spends considerably more time and effort on O&M maintenance activities relative to Avista, at least in
areas of transmission and substation systems.
Idaho Power is also projecting a significant rise in capital replacement of aging infrastructure in the next
several decades, as shown below. Over just the next 10 years, this indicates a total capital spend for
Idaho Power of $211 M for replacement of wood poles alone, or $21 M per year levelized. This is similar
in magnitude to the recommended replacement of aging wood infrastructure at Avista over the next
several decades.
Avista
Avista
ICNU_DR_006 Attachment A Page 36 of 48

37 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Figure 9: Idaho Power Long-term Replacement Costs
Data Integrity
The following table lists the various sources of information used for Asset Management purposes. Data
gathering from non-electronic sources, mining and cleaning of available information makes up a
disproportionately large amount of current work for Asset Management staff, on the order of 80% of
total work. Long term, in order to provide the most value to Avista this needs to be reversed with 80%
applied to analyzing data and 20% to gathering and cleaning data.
ICNU_DR_006 Attachment A Page 37 of 48

38 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Table 18: Transmission Asset Data Integrity
Transmission system records in particular are outdated and/or insufficient in many cases to perform
effective asset management analyses, e.g. outdated Plan & Profile drawings, unreliable AFM data,
missing larch pole information, conflicting line names between data sources due to line name changes,
lack of component failure data, etc. It is hoped that with Maximo implementation, much of this
problem will be resolved over time.
Status Data Source Notes/Comments
ICNU_DR_006 Attachment A Page 38 of 48

39 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

We are 100% complete processing updates to a backlog of 459 transmission jobs dated from 1992 to the
present in our GIS/AFM database and on plan and profile (P&P) drawings. However, prompt updates
from construction as-builts continue to be problematic, as most of the transmission jobs completed in
2013 have yet to be updated in system records.
Material Usage
According to Supply Chain staff, a definitive list of parts, quantities and funds spent on transmission
work is currently unavailable. The following list of materials was tabulated from a query of the Oracle
database for those projects listed as Transmission from October 2010 to October 2012. This should not
be taken as complete costing information, but may be reasonably considered accurate for the relative
use of material categories.

Table 19: Relative Material Purchases, 10/2010 – 10/2012
Root Cause Analysis (RCA)
Following the Othello storm in September 2013, a team was formed to study the causes of the event
and develop effective solutions to prevent recurrence, as appropriate. Representatives from
Transmission Design, Asset Management, Distribution Engineering, Construction Services, and Spokane
Electric participated. In addition to technical forensics, a rigorous methodology was followed known as
the “Apollo Root Cause Analysis methodTM ”, requiring evidence and team consensus to develop
effective solutions. Not only the root causes, but also the significance of the event and the more severe
consequences that were narrowly avoided were unexpectedly discovered through the team’s
Category Total Amount %
steel poles $1,770,582 44%
other $466,378 12%
fire retardant coating $445,514 11%
crossarms $349,709 9%
air switches $293,131 7%
conductor $259,622 6%
insulators $228,702 6%
crossbraces $96,212 2%
vibration dampers $78,916 2%
wood poles $52,927 1%
total $4,050,929 100%
ICNU_DR_006 Attachment A Page 39 of 48

40 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

deliberations. A summary report was generated and a number of significant action items initiated to
prevent or mitigate similar events in the future.
Unexpected events such as the Othello storm, while undesirable, in many cases offer rare opportunities
to learn and improve. No single formula or approach is generically applicable to all problems. However,
the Apollo RCA method or close variant is applicable to many, and it is hoped that it may be used to
greater effect in the future. Lessons learned from this effort will inform the next RCA effort if/when it
arises.
Business Cases
This section highlights specific business cases developed on the basis of optimized asset management,
supported by detailed simulation studies. The list below provides a summary of current and anticipated
work in this area, based on planned ground inspections.
Business Case Anticipated
Line Submission Construction Status
Devil’s Gap – Lind 115kV 2012 2014 - 2016 Approved
Benewah – Moscow 230kV 2013 2015 – 2016 Approved
Cabinet – Noxon 230kV 2014 2016 – 2018 In progress
Benewah – Pine Creek 230kV 2014 2016 – 2018 In progress
Hot Springs – Noxon #2 230kV 2014 2016 – 2019 In progress
Walla-Walla – Wanapum 230kV 2015 2017 – 2020 Pends analysis
Moscow230 – Orofino 115kV 2015 2017 – 2020 Pends inspection
Devil’s Gap - Stratford 115kV 2015 2017 – 2020 Pends inspection

Table 20: Simulation-Supported Business Cases, 2012 - 2015
In addition to the above list, a system-wide simulation study is desired to help support policy decisions
for levelized, long-term inspection and replacement schedules. This is a stretch-goal for 2014.
Acceptable simulation studies require a recent inspection (within five years of the study), in order to
provide valid results and recommendations. For this reason it is critical that the reliability risk index is
completed and used to schedule future inspections, prioritize rebuild studies and follow-up work.
ICNU_DR_006 Attachment A Page 40 of 48

41 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

It should be noted that not all rebuild projects warrant the time and expense of conducting a simulation
study. This is the case, for example, where the right business decision is obvious or may be sufficiently
justified by easier and/or faster means.
System Planning Projects
The following table lists substation and transmission projects at various stages from study through
construction, as provided by system planning on Sharepoint. This list is a snapshot of current plans and
is subject to frequent change. In particular, projects to create a looped 230kV system around Spokane is
in development and not included here. See the Area Work Plans section of this report for more detail
on transmission specific projects and inspection plans.

Figure 10: System Planning Projects (Big Bend, CDA & Lewiston/Clarkston)

ICNU_DR_006 Attachment A Page 41 of 48

42 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Figure 11: System Planning Projects (Palouse, Spokane and System)
Area Work Plans
The following transmission projects are scheduled for work based on a variety of factors including
changing system and operational requirements, remaining service life, asset condition and performance.
This list is provided for planning and reference purposes only. It represents current plans and is subject
to frequent change. See the Transmission Engineering Manager for the latest revision. Those items
with no marks for any year represent tentative projects under consideration.
See the end of the list for the current minor rebuild and ground inspection schedule, which typically
drives follow-up repairs and minor rebuilds the following year (when a major rebuild is not justified
based on condition assessment).
ICNU_DR_006 Attachment A Page 42 of 48

43 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Projects

Major Rebuilds and Other Projects

EFA = Reimburseable or Growth
HPRM = High Priority Line Ratings Mitigation Program Business Case
IAA = Other
LPRM = Low Priority Line Ratings Mitigation Program Business Case
MPRM = Medium Priority Line Ratings Mitigation Program Business Case
NG = New Growth
NT = New Transmission Program Business Case
PS = Project Specific Business Case
SDSR = Substation - Distribution Station Rebuild Program Business Case
SNDS = Substation - New Distribution Stations Program Business Case
SVTR = Spokane Valley Transmission Reinforcement Program Business Case
TAM = Transmission Asset Management Program Business Case
TRR = Transmission Rebuild/Reconductor Program Business Case
Business
Case Area ER Description 2014 2015 2016 2017 2018
MPRM Big Bend Walla Walla-Wanapum 230kV Mitigation X
NT Big Bend Coulee - Westside 230 - Construct (Acquire ROW)
PS Big Bend Harrington 115-4kV - Integration X
PS Big Bend Odessa Substation - Re-integration X
SDSR Big Bend Stratford 115kV Sub - Rebuild - Integration X
SDSR Big Bend Ford 115-13kV Sub - Integration X X
SDSR Big Bend Little Falls 115kV Sub - Integration X X X
SNDS Big Bend Bruce Siding 115 Sub - New - Tap to Sub
SNDS Big Bend 49 Deg North 115-21 Feeder - Integration
TRR Big Bend Devils Gap-Lind 115kV Rebuild Transmission X X X
TRR Big Bend Ben-Oth SS 115 - ReCond/ReBld X X X
ICNU_DR_006 Attachment A Page 43 of 48

44 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Business
Case Area ER Description 2014 2015 2016 2017 2018
BLKT CDA 15th Street Road Widening (CDA) - Reimburseable X
EFA CDA Prairie Avenue Road Widening - Reimbursable X
EFA CDA KEC Beck Rd Sub - Trans Integration- Reimbursable X
HPRM CDA Benewah-Pine Creek 230kV Trans Mitigation X
ICNU_DR_006 Attachment A Page 44 of 48

45 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Business
Case Area ER Description 2014 2015 2016 2017 2018
BLKT Spokane MLK New Road Relocation - Reimbursable X
EFA Spokane Hawthorne 115 Sub - Construct - Integration
MPRM Spokane Beacon-F&C 115kV Mitigation X
MPRM Spokane Northwest-Westside 115kV Mitigation X
MPRM Spokane Beacon-Bell #5 230kV Mitigation X
MPRM Spokane Beacon-Boulder #2 115kV Mitigation X
MPRM Spokane Ninth & Central-Otis 115kV Mitigation X
MPRM Spokane Beacon-Bell #4 230kV Mitigation X
NT Spokane Westside/Garden Springs 230/115 - New
PS Spokane Westside 230kV Sub - Rebuild - Integration
PS Spokane Beacon 230kV Sub - 115kV Rebuild - Integration
PS Spokane Garden Springs 230-115-13 Sub - Integration X X X
PS Spokane 9CE Sub - New 230kV Transformation - Integration
SDSR Spokane Sunset 115kV Sub - Rebuild - Integration X X
SDSR Spokane 9CE 115 Sub - Rebuild/Expand X X
SDSR Spokane Northwest 115-13kV Sub - Integration X X
SDSR Spokane Chester 115-13kV Sub - Integration X X
SDSR Spokane Beacon 230 - 2 X 2 - Integration
SDSR Spokane Metro 115-13kV Sub - Integration X X X
SNDS Spokane Hillyard 115-13 Sub - Construct - Integration X X
SNDS Spokane Greenacres 115 Sub - Construct - Integration X
SNDS Spokane Downtown West 115 Sub- New - Tap to Sub X
SNDS Spokane Downtown East 115 Sub- New - Tap to Sub
SVTR Spokane BEA-BLD #2 115 - Upgrd 140MVA X X
SVTR Spokane Irvin SS 115 - Construct - Integration X X
SVTR Spokane Opportunity Sub 115-13kV - Integration X
TRR Spokane Garden Springs - Silver Lake 115kV - Recon/Rbld X X
TRR Spokane BEA-BEL-F&C-WAI 115kV - reconfig @ Bell and Waikiki X X
TRR Spokane 9CE-Sunset 115kV Transmission - Recon/Rbld X X
TRR Spokane
ICNU_DR_006 Attachment A Page 45 of 48

46 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Minor Rebuilds

SDSR All Sys - Wood Sub Rebuilds - STR Design X X X X X
TAM All Transmission Minor Rebuilds - WA X X X X X
TAM All Transmission Minor Rebuilds - ID X X X X X
TAM All Sys - Trans Air Switch Upgrade X X X X X
TAM All Trans Air Switch Platform Grd Mat
Big Bend Addy - Devil's Gap 115kV
Big Bend Othello - Warden #2 115kV
Big Bend Walla Walla - Wanapum 230kV
CDA Noxon - Hot Springs #2 230kV
Lewis-Clark Grangeville - Nez Perce #1 115kV
Lewis-Clark Jaype - Orofino 115kV
Lewis-Clark Moscow 230 - Orofino 115kV
Palouse Benewah-Pine Creek 230kV
Spokane Beacon - Bell #4 230kV
Spokane Ninth & Central - Otis 115kV
Spokane Post St. - Third & Hatch 115kV
Spokane Ross Park - Third & Hatch 115kV
Spokane/Palouse Shawnee - Sunset Phase 2 115kV
ICNU_DR_006 Attachment A Page 46 of 48

47 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

Ground Inspections

2014-2018 Structural Ground Inspections
Area Transmission Line # wood poles
Big Bend Walla Walla - Wanapum 230kV 175
Big Bend Moscow230-Orofino*115kV 1101
Big Bend Devil's Gap - Stratford**115kV 1173
2274 Year 2014 total
* includes Deary Tap
** partial inspection, from DG to Odessa only
Palouse Latah-Moscow 115kV 706
Big Bend Addy - Gifford 115kV 275
Lewis-Clark Grangeville-Nez Perce #2 115kV 507
Lewis-Clark Lolo - Oxbow 230kV 716
Spokane
ICNU_DR_006 Attachment A Page 47 of 48

48 2014 Transmission System Annual Update
Sharepoint - Asset Management Annual Updates

References
Avista Utilities (2012). Transmission Vegetation Management Program.
http://sharepoint/departments/enso/tran/
Avista Utilities (2014). Specification for Inspection and Treatment of Wood Poles, S-622.
Dan Whicker (2013). Fire Guard Coating for Wood Transmission Poles. April 16, 2013
Dan Whicker (2009). 230kV Transmission Compression Sleeve Couplings. (2009)
Ken Sweigart (2014). Transmission Capital Budget 5-Year Plan. February 17, 2014.
Rendall Farley and Valerie Petty (2013). 2012 Transmission System Review. April 15, 2013.
Reuben Arts (2014). Reliability Data 2013.
Rodney Pickett, Rendall Farley, and Tracy West (2012). Idaho Power – Avista Corp. Asset Management
Meeting. May 2, 2012.

ICNU_DR_006 Attachment A Page 48 of 48

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/23/2015
CASE NO: UE-150204 &UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Karen Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 006 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please explain in detail the need for any significant capital expenditure (above $20 million) when Avista is experience no load growth.

RESPONSE:
The Company has the following projects over $20 million on a system basis:

• Transmission – Reconductors and rebuilds are listed in Company witness Schuh’s, Exhibit No.
__(KKS-4), totaling $21.161 million (System) in 2016. ICNU_DR__006 Attachment A, Electric Transmission 2014 Annual Update, in the Capital Replacement and Maintenance Investment section (pages 13 –19) describes the need for this spending in order to maintain the reliability of
the system.

• The Customer Information System (Project Compass) is also listed in Exhibit No__(KKS-4), page 4 and totals $95.108 million (System) in 2015. Company witness Mr. Kensok discusses the
Customer Information System in his testimony at Exhibit No. ___(JMK-1T).

• Nine Mile Rehab Project is also listed in Exhibit No.___(KKS-4), page 6 and totals $51.323 million (System) in 2015. Company witness Mr. Kinney discusses the Nine Mile Rehab Project in
his direct testimony at Exhibit No. ___(SJK-1T).

• Washington Advanced Metering Infrastructure (AMI) is listed in Exhibit No.__(KKS-4) and totals $32.243 million (System) in 2016. Company witness Mr. Kopczynski discusses the Washington
AMI Project in his direct testimony at Exhibit No. ___(DFK-1T).

In general, all of these projects are largely predicated on the advancing age and declining functionality of
the plant being replaced. And in order to achieve optimum life-cycle cost/value for ratepayers, these categories of plant need to be replaced in a timely manner.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/23/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Karen Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 007 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

For Table 2 through Table 7 in the Direct Testimony of Ms. Schuh, please provide these tables with the capital projects sorted by priority and for each project, please indicate the expected ratepayer benefit of
the projects in terms of present value revenue requirement (“PVRR”) or another comparable metric.

RESPONSE:
Please see ICNU_DR_007 Attachment A, for Tables 2 through 8 sorted by functional group then by
assessment score that is included on the business case. The assessment score consists of several factors
including; a financial assessment, strategic assessment, business risk assessment and a project/program risk
assessment. The assessment score is used to help prioritize business cases or projects as part of the overall assessment. Please see the Company’s response to ICNU_DR_005 for further detail on the capital budgeting
process and how the Company prioritizes capital projects.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/13/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: James Gall
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 008 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an Excel workbook(s) containing actual net system loads on an hourly basis for the calendar years from 2010 to 2014.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 008C. Please note that Avista’s
response to ICNU – 008C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205.

Please see ICNU_DR_008C Confidential Attachment A for the hourly Avista native loads. Due to the
voluminous nature of the document, it is provided in electronic format only.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/13/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: James Gall
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 009 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an Excel workbook(s) containing normalized, commission basis net system loads on an hourly basis for the calendar years from 2010 to 2014.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 009C. Please note that
Avista’s response to ICNU – 009C is Confidential per Protective Order in UTC Dockets UE-150204 and
UG-150205.

Please see ICNU_DR_009C Confidential Attachment A for the hourly loads used in the commission basis report between 2010 and 2014. Due to the voluminous nature of the document, it is provided in electronic
format only.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/13/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: James Gall
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 010 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide an Excel workbook(s) containing forecasted net system loads on an hourly basis for each
calendar year from 2015 to 2025 based on the most recent load forecast completed by the Company.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 010C. Please note that
Avista’s response to ICNU – 010C is Confidential per Protective Order in UTC Dockets UE-150204 and
UG-150205.
Avista does not forecast loads hourly on a long term basis. Each year, the Company prepares a long-term
monthly load forecast. These loads are used every other year as an input into the IRP process. During the
IRP process the most recent year’s hourly load shape is applied to the monthly load forecast.
ICNU_DR_010C Confidential Attachment A includes the most recent monthly energy forecast (July 2014). See Avista’s response to ICNU_DR_008C for historical load shapes.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 011 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Referring to ICNU Data Requests 008 to 010, please detail the hourly loads requested by customer class, including both Idaho and Washington jurisdictions.

RESPONSE:
For the requested time period of 2010 through 2025, the Company has the following information:

For hourly customer class data, please see ICNU_DR_011 Attachment A (provided electronically only)
which contains the hourly data by customer class for the twelve month period July 1, 2013 through June
30, 2014.
For calendar years 2010 and 2011, as well as the July 2012 through June 2013 time periods, the Company
has estimated the customer class contribution to the 12 coincident peak hours as a part of general rate case
cost of service studies. ICNU_DR_011 Attachment B provides the customer class results for each
coincident peak hour available during the time frame requested.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/20/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Dr. Grant Forsyth
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 012 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an Excel workbook(s) containing forecasted kWh sales on a monthly basis for each customer class in both Washington and Idaho in calendar years 2015 to 2025 based on the most
recent load forecast completed by the Company.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 012C. Please note that
Avista’s response to ICNU – 012C is Confidential per Protective Order in UTC Dockets UE-
150204 and UG-150205.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/20/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Dr. Grant Forsyth
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 013 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an Excel workbook(s) containing forecasted kW and kVa demand on monthly basis for each customer class. The forecasted kW and kVa demand should be the sum of the individual
customers’ demand rather than the non-coincident demand of the entire class.

RESPONSE:
The Company does not attempt to forecast kW and kVa. For purposes of pricing both kW and kVa in
the revenue forecast, the Company uses an average of actual kW and kVa from prior periods.

Please see the Company’s response to ICNU_DR_012, to see the historical kW and kVa utilized in the Company’s forecast.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 014 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide the attrition analysis and all associated workpapers as proposed by the Company in the
2014 general rate proceeding, consolidated dockets UE-140188 and UG-140189. RESPONSE: See ICNU_DR_014 Attachment A - for attrition analysis included in the Company’s 2014 general rate
proceeding in Docket Nos. UE-140188 and UG-140189.
Folders included to consolidate the data provided include:
“2015 Attrition – As Filed-06.30.2013 basis” – includes Andrews’ Attrition Studies in excel filed with the
Company’s direct filed case, using Commission Basis Results (CBR) as of June 30, 2013.

“2015 Attrition - Final Revised 12.31.2013 basis” – provide final revised Attrition Studies in excel provided during the process of the case, updating the Company’s Attrition Study analysis using the CBR data as of
December 31, 2013.

AVISTA CORPORATION
STATE OF WASHINGTON DOCKET NO. UE-011595
POWER COST DEFERRAL REPORT
MONTH OF JANUARY 2015

ERM Report Month of January 2015
Page 1 of 40
INCU_DR_015 Attachment A Page 1 of 40
Ferc Acct Jurisdiction Accounting Period Beginning Balance Monthly Activity Ending Balance
186280 WA 201312 0.00 1,256,447.00 1,256,447.00
WA 201401 1,256,447.00 -1,247,407.00 9,040.00
WA 201402 9,040.00 -9,040.00 0.00
WA 201403 0.00 0.00 0.00
WA 201404 0.00 0.00 0.00
WA 201405 0.00 -1,748,236.00 -1,748,236.00
WA 201406 -1,748,236.00 -914,303.00 -2,662,539.00
WA 201407 -2,662,539.00 -1,955,345.00 -4,617,884.00
WA 201408 -4,617,884.00 -42,368.00 -4,660,252.00
WA 201409 -4,660,252.00 812,584.00 -3,847,668.00
WA 201410 -3,847,668.00 -91,107.00 -3,938,775.00
WA 201411 -3,938,775.00 72,210.00 -3,866,565.00
WA 201412 -3,866,565.00 -357,446.00 -4,224,011.00
WA 201501 -4,224,011.00 13,034.00 -4,210,977.00
ERM Deferral Balance (Current Year ‐ 2015)
Account 186280.ED.WA Amount Journal ID
Balance 12/31/2014 (4,224,011)$         
Deferral ‐ Current Month ‐$                       481 ‐ WA ERM
Interest ‐ Current Month (12,179)$               481 ‐ WA ERM
Transfer BPA Parallel Capacity (1)                          25,213$                 481 ‐ WA ERM/NSJ015
Transfer to 186290 (2)                          ‐$                       
Balance 1/31/2015 (4,210,977)$         
Year to date deferrals  ‐$                       
Transfer BPA Parallel Capacity 25,213$                 
Year to date interest (12,179)$               
Balance in account (4 210 977)$
Transfer BPA Parallel Capacity 25,213$                 
Year to date interest (12,179)$               
   Balance in account (4,210,977)$         
Total Absorbed Deferred
First $4,000,000 at 100% (3,298,835)$       (3,298,835)$          ‐$                                      
$4,000,000 to $10,000,000 at 25%‐$                     ‐$                       ‐$                                      
Over $10,000,000 at 10%‐$                     ‐$                       ‐$                                      
   Total (3,298,835)$       (3,298,835)$         ‐$                                      
(2) Transfer for prior year will be made in February, 2015
(1) Per Settlement Petition Order 01, Docket # UE‐130536 please see page 4, paragraph 9 of the petition.  The 
sentence reads:
“To the extent there is a difference between the actual revenues from Bonneville for 2013 and 2014 and the 
amount refunded to customers in 2014, 100% of the difference would be added to, or subtracted from, the 
Energy Recovery Mechanism (“ERM”) deferral balance without being subject to the deadband and sharing 
bands.”
Please note the ratio utilized to allocate costs between Washington and Idaho for both the ERM and REC 
deferral was inadvertently changed in error to 64.71% rather than the correct amount of 65.19%.  This correction 
to restate January will be recorded in February 2015.
ERM Report Month of January 2015
Page 2 of 40
INCU_DR_015 Attachment A Page 2 of 40
Ferc Acct Jurisdiction Accounting Period Beginning Balance Monthly Activity Ending Balance
186290 WA 201312 -9,252,504.14 -28,137.00 -9,280,641.14
WA 201401 -9,280,641.14 1,235,876.00 -8,044,765.14
WA 201402 -8,044,765.14 9,319,254.14 1,274,489.00
WA 201403 1,274,489.00 3,827.00 1,278,316.00
WA 201404 1,278,316.00 -14,785.71 1,263,530.29
WA 201405 1,263,530.29 3,692.00 1,267,222.29
WA 201406 1,267,222.29 3,692.00 1,270,914.29
WA 201407 1,270,914.29 -1,270,914.00 0.29
WA 201408 0.29 -0.29 0.00
WA 201409 0.00 0.00 0.00
WA 201410 0.00 0.00 0.00
WA 201411 0.00 0.00 0.00
WA 201412 0.00 0.00 0.00
WA 201501 0.00 0.00 0.00
ERM Deferral Balance (Prior year ‐ 2014)
Account 186290.ED.WA Amount Journal ID
Balance 12/31/2014 ‐$                       
Transfer from 186280*‐$                       
Balance 1/31/2015 ‐$                       
*Transfer will be made in Feb.   2015
ERM Report Month of January 2015
Page 3 of 40
INCU_DR_015 Attachment A Page 3 of 40
Ferc Acct Jurisdiction Accounting Period Beginning Balance Monthly Activity Ending Balance
182350 WA 201312 -10,262,209.00 382,815.00 -9,879,394.00
WA 201401 -9,879,394.00 546,382.00 -9,333,012.00
WA 201402 -9,333,012.00 -8,518,899.14 -17,851,911.14
WA 201403 -17,851,911.14 737,656.00 -17,114,255.14
WA 201404 -17,114,255.14 599,294.22 -16,514,960.92
WA 201405 -16,514,960.92 610,932.00 -15,904,028.92
WA 201406 -15,904,028.92 580,003.00 -15,324,025.92
WA 201407 -15,324,025.92 1,888,322.00 -13,435,703.92
WA 201408 -13,435,703.92 711,638.21 -12,724,065.71
WA 201409 -12,724,065.71 722,250.00 -12,001,815.71
WA 201410 -12,001,815.71 612,676.00 -11,389,139.71
WA 201411 -11,389,139.71 628,745.00 -10,760,394.71
WA 201412 -10,760,394.71 798,304.00 -9,962,090.71
WA 201501 -9,962,090.71 798,997.00 -9,163,093.71
Recoverable Deferral Balance
Account 182350.ED.WA Amount Journal ID
Balance 12/31/2014 (9,962,091)$        
Surcharge Amortization 826,446$             481 ‐ WA ERM
Interest (27,449)$              481 ‐ WA ERM
Balance 1/31/2015 (9,163,094)$        
ERM Report Month of January 2015
Page 4 of 40
INCU_DR_015 Attachment A Page 4 of 40
Ferc Acct Jurisdiction Accounting Period Beginning Balance Monthly Activity Ending Balance
283280 WA 201312 6,830,150.48 -563,893.75 6,266,256.73
WA 201401 6,266,256.73 -187,197.85 6,079,058.88
WA 201402 6,079,058.88 -276,960.25 5,802,098.63
WA 201403 5,802,098.63 -259,519.05 5,542,579.58
WA 201404 5,542,579.58 -204,577.98 5,338,001.60
WA 201405 5,338,001.60 396,764.20 5,734,765.80
WA 201406 5,734,765.80 115,712.80 5,850,478.60
WA 201407 5,850,478.60 468,277.95 6,318,756.55
WA 201408 6,318,756.55 -234,244.47 6,084,512.08
WA 201409 6,084,512.08 -537,191.90 5,547,320.18
WA 201410 5,547,320.18 -182,549.15 5,364,771.03
WA 201411 5,364,771.03 -245,334.25 5,119,436.78
WA 201412 5,119,436.78 -154,300.30 4,965,136.48
WA 201501 4,965,136.48 -284,210.48 4,680,926.00
DFIT Associated with ERM Deferrals
Account 283280.ED.WA
Account 186280.ED.WA balance (4,210,977)$         
Account 186290.ED.WA balance ‐$                       
Account 182350.ED.WA balance (9,163,094)$         
   Total (13,374,071)$       
Federal income tax rate ‐35%
Deferred FIT related to deferrals $4,680,925
Rounding 1$                           
Balance that should be in account ‐ January 31, 2015 4,680,926$           
$ , ,
Rounding 1$                           
Balance that should be in account ‐ January 31, 2015 4,680,926$           
ERM Report Month of January 2015
Page 5 of 40
INCU_DR_015 Attachment A Page 5 of 40
Ferc Acct Jurisdiction Accounting Period Beginning Balance Monthly Activity Ending Balance
186322 WA 201312 -1,309,240.81 -297,707.00 -1,606,947.81
WA 201401 -1,606,947.81 82,083.00 -1,524,864.81
WA 201402 -1,524,864.81 -79,905.00 -1,604,769.81
WA 201403 -1,604,769.81 -221,015.00 -1,825,784.81
WA 201404 -1,825,784.81 -361,430.83 -2,187,215.64
WA 201405 -2,187,215.64 84,889.00 -2,102,326.64
WA 201406 -2,102,326.64 -21,300.25 -2,123,626.89
WA 201407 -2,123,626.89 -140,262.00 -2,263,888.89
WA 201408 -2,263,888.89 -180,438.00 -2,444,326.89
WA 201409 -2,444,326.89 -271,407.00 -2,715,733.89
WA 201410 -2,715,733.89 -458,544.00 -3,174,277.89
WA 201411 -3,174,277.89 -42,690.00 -3,216,967.89
WA 201412 -3,216,967.89 -60,222.00 -3,277,189.89
WA 201501 -3,277,189.89 153,618.00 -3,123,571.89
REC Amortization Balance
Account 186322.ED.WA Amount Journal ID
Balance 12/31/2014 ‐$3,277,190
Amortization $162,668 475 ‐ WA REC AMORTIZATION
Interest ‐$9,050 475 ‐ WA REC AMORTIZATION
Balance 1/31/2015 ‐$3,123,572
Balance 1/1/2014 $0
Year to date amortization 162,668
Balance 1/1/2014 $0
Year to date amortization 162,668
Year to date interest ‐9,050
Balance 1/31/2015 ‐$3,123,572
Please note the interest was calculated using the same rate as the ERM. Per the Settlement Stipulation
the agreed upon amount is the after‐tax cost of capital interest rate of 6.34%. January 2015 will be corrected 
in February 2015.
ERM Report Month of January 2015
Page 6 of 40
INCU_DR_015 Attachment A Page 6 of 40
Ferc Acct Jurisdiction Accounting Period Beginning Balance Monthly Activity Ending Balance
186323 WA 201501 0.00 -120,324.00 -120,324.00
REC Deferral Balance (effective 01.01.2015)
Account 186323.ED.WA Amount Journal ID
Balance 12/31/2014 $0
Deferral ‐$120,151 475 ‐ WA REC DEFERRAL
Interest ‐$173 475 ‐ WA REC DEFERRAL
Balance 12/31/2014 ‐$120,324
Balance 1/1/2014 $0
Year to date deferral ‐$120,151
Year to date interest ‐$173
Balance 12/31/2014 ‐$120,324
Please note the interest was calculated using the same rate as the ERM. Per the Settlement Stipulation
the agreed upon amount is the after‐tax cost of capital interest rate of 6.34%. January 2015 will be corrected 
in February 2015.
ERM Report Month of January 2015
Page 7 of 40
INCU_DR_015 Attachment A Page 7 of 40
Ferc Acct Jurisdiction Accounting Period Beginning Balance Monthly Activity Ending Balance
283305 WA 201312 458,234.28 104,197.45 562,431.73
WA 201401 562,431.73 -28,729.05 533,702.68
WA 201402 533,702.68 27,966.75 561,669.43
WA 201403 561,669.43 75,592.30 637,261.73
WA 201404 637,261.73 124,479.89 761,741.62
WA 201405 761,741.62 -37,792.30 723,949.32
WA 201406 723,949.32 19,320.09 743,269.41
WA 201407 743,269.41 49,091.70 792,361.11
WA 201408 792,361.11 63,153.30 855,514.41
WA 201409 855,514.41 94,992.45 950,506.86
WA 201410 950,506.86 160,490.40 1,110,997.26
WA 201411 1,110,997.26 14,941.50 1,125,938.76
WA 201412 1,125,938.76 21,077.70 1,147,016.46
WA 201501 1,147,016.46 -53,826.85 1,093,189.61
283310 WA 201501 0.00 42,173.00 42,173.00
Total 1,135,362.61
Account 283305.ED.WA / 283310.ED.WA
Account 186322.ED.WA balance ‐$3,123,572
Account 186323.ED.WA balance ‐$120,324
   Total ‐3,243,895.89
Federal income tax rate ‐35%
Deferred FIT related to deferrals $1,135,364
Rounding ‐2
Deferred FIT related to deferrals $1,135,364
Rounding ‐2
Balance that should be in account ‐ January 31, 2015 $1,135,362
ERM Report Month of January 2015
Page 8 of 40
INCU_DR_015 Attachment A Page 8 of 40
Attachment A

Avista Corporation
Monthly Power Cost Deferral Report

Month of January 2015

ERM Deferral Journal

ERM Report Month of January 2015
Page 9 of 40
INCU_DR_015 Attachment A Page 9 of 40
ERM Report Month of January 2015
Page 10 of 40
INCU_DR_015 Attachment A Page 10 of 40
ERM Report Month of January 2015
Page 11 of 40
INCU_DR_015 Attachment A Page 11 of 40
ERM Report Month of January 2015
Page 12 of 40
INCU_DR_015 Attachment A Page 12 of 40
ERM Report Month of January 2015
Page 13 of 40
INCU_DR_015 Attachment A Page 13 of 40
ERM Report Month of January 2015
Page 14 of 40
INCU_DR_015 Attachment A Page 14 of 40
ERM Report Month of January 2015
Page 15 of 40
INCU_DR_015 Attachment A Page 15 of 40
ERM Report Month of January 2015
Page 16 of 40
INCU_DR_015 Attachment A Page 16 of 40
Lin
e No
.
WA
S
H
I
N
G
T
O
N

A
C
T
U
A
L
S

J
a
n
-
1
5

F
e
b
-
1
5

M
a
r
-
1
5

A
p
r
-
1
5

M
a
y
-
1
5

J
u
n
-
1
5

J
u
l
-
1
5

A
u
g
-
1
5

S
e
p
-
1
5

O
c
t
-
1
5

N
o
v
-
1
5

D
e
c
-
1
5
1
5
5
5

P
u
r
c
h
a
s
e
d

P
o
w
e
r

$
1
8
,
5
0
8
,
2
4
9

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
2
4
4
7

S
a
l
e

f
o
r

R
e
s
a
l
e

(
$
1
1
,
6
4
3
,
0
7
2
)

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
3
L
e
s
s

S
M
U
D

R
E
C
s
$0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
4
5
0
1

T
h
e
r
m
a
l

F
u
e
l

$
3
,
0
2
4
,
7
1
4

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
5
5
4
7

C
T

F
u
e
l

$
7
,
0
3
4
,
0
5
7

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
6
4
5
6

T
r
a
n
s
m
i
s
s
i
o
n

R
e
v
e
n
u
e

(
$
1
,
3
1
3
,
9
9
3
)

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
7
5
6
5

T
r
a
n
s
m
i
s
s
i
o
n

E
x
p
e
n
s
e

$
1
,
4
6
9
,
0
9
1

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
8
5
5
7

B
r
o
k
e
r

F
e
e
s

$
3
1
,
3
9
3

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
9
L
e
s
s

C
l
e
a
r
w
a
t
e
r

d
i
r
e
c
t
l
y

a
s
s
i
g
n
e
d

t
o

I
D
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
10
Ad
j
u
s
t
e
d

A
c
t
u
a
l

N
e
t

E
x
p
e
n
s
e
$1
7
,
1
1
0
,
4
3
9
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
A
U
T
H
O
R
I
Z
E
D

N
E
T

E
X
P
E
N
S
E
-
S
Y
S
T
E
M
Ja
n
-
1
5

F
e
b
-
1
5

M
a
r
-
1
5

A
p
r
-
1
5

M
a
y
-
1
5

J
u
n
-
1
5

J
u
l
-
1
5

A
u
g
-
1
5

S
e
p
-
1
5

O
c
t
-
1
5

N
o
v
-
1
5

D
e
c
-
1
5
11

5
5
5

P
u
r
c
h
a
s
e
d

P
o
w
e
r
$1
4
,
2
4
1
,
3
0
8

$
1
2
,
8
1
6
,
2
1
6

$
1
2
,
6
8
4
,
1
0
2

$
1
0
,
1
5
7
,
9
9
2

$
8
,
8
0
1
,
8
3
9

$
8
,
9
6
6
,
5
1
1

$
9
,
0
3
2
,
3
1
2

$
1
0
,
4
4
9
,
1
3
5

$
8
,
2
2
7
,
6
1
2

$
8
,
9
5
0
,
4
9
4

$
1
2
,
7
3
1
,
4
1
8

$
1
2
,
6
1
7
,
7
7
6
12

4
4
7

S
a
l
e

f
o
r

R
e
s
a
l
e
($
5
,
3
8
5
,
8
6
4
)

(
$
7
,
0
2
6
,
4
5
4
)

(
$
8
,
1
6
7
,
2
9
5
)

(
$
8
,
6
5
5
,
0
9
9
)

(
$
9
,
1
1
1
,
9
0
2
)

(
$
8
,
3
8
9
,
0
0
9
)

(
$
5
,
1
3
0
,
6
2
1
)

(
$
3
,
2
8
4
,
3
2
0
)

(
$
4
,
6
6
1
,
3
6
4
)

(
$
4
,
8
7
5
,
5
5
8
)

(
$
6
,
0
0
0
,
1
5
4
)

(
$
4
,
7
4
2
,
8
1
2
)
13

L
e
s
s

S
M
U
D

R
E
C
s
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
14

5
0
1

T
h
e
r
m
a
l

F
u
e
l
$2
,
6
6
3
,
5
3
2

$
2
,
4
8
4
,
6
7
1

$
2
,
5
7
8
,
7
0
7

$
2
,
0
6
8
,
2
5
2

$
1
,
6
6
5
,
7
4
5

$
1
,
5
1
1
,
3
8
1

$
2
,
2
5
4
,
5
7
8

$
2
,
6
2
1
,
3
5
7

$
2
,
6
7
2
,
9
3
6

$
2
,
7
5
7
,
9
3
3

$
2
,
6
4
9
,
8
5
0

$
2
,
7
0
0
,
1
8
5
15

5
4
7

C
T

F
u
e
l
$1
0
,
1
3
3
,
3
1
1

$
9
,
4
1
9
,
6
5
0

$
9
,
3
0
5
,
4
7
6

$
5
,
8
6
7
,
7
3
5

$
3
,
1
1
2
,
7
3
5

$
2
,
5
9
5
,
9
1
8

$
5
,
6
2
3
,
1
0
0

$
7
,
7
4
3
,
9
3
5

$
8
,
2
1
9
,
1
4
5

$
8
,
8
3
4
,
7
7
9

$
9
,
0
3
5
,
1
0
4

$
9
,
8
7
3
,
7
7
6
16

4
5
6

T
r
a
n
s
m
i
s
s
i
o
n

R
e
v
e
n
u
e
($
1
,
3
0
4
,
3
2
9
)

(
$
1
,
1
0
5
,
9
2
1
)

(
$
1
,
1
2
3
,
9
7
7
)

(
$
1
,
1
5
4
,
7
8
2
)

(
$
1
,
3
7
7
,
2
3
2
)

(
$
1
,
5
5
2
,
3
5
7
)

(
$
1
,
6
5
9
,
8
3
5
)

(
$
1
,
5
0
2
,
8
9
2
)

(
$
1
,
3
0
6
,
3
6
4
)

(
$
1
,
4
6
0
,
2
9
1
)

(
$
1
,
2
4
1
,
9
3
6
)

(
$
1
,
2
2
5
,
4
2
7
)
17

5
6
5

T
r
a
n
s
m
i
s
s
i
o
n

E
x
p
e
n
s
e
$1
,
4
4
7
,
5
4
2

$
1
,
4
2
9
,
5
0
4

$
1
,
4
0
5
,
3
2
4

$
1
,
3
9
4
,
2
0
8

$
1
,
3
6
5
,
0
7
4

$
1
,
3
5
3
,
3
8
3

$
1
,
3
7
7
,
5
1
1

$
1
,
4
2
9
,
2
7
3

$
1
,
4
1
4
,
1
8
5

$
1
,
3
7
4
,
8
8
9

$
1
,
4
0
3
,
8
1
3

$
1
,
4
2
3
,
0
3
1
18

5
5
7

B
r
o
k
e
r

F
e
e
s
$8
9
,
6
6
7

$
8
9
,
6
6
7

$
8
9
,
6
6
6

$
8
9
,
6
6
7

$
8
9
,
6
6
7

$
8
9
,
6
6
6

$
8
9
,
6
6
7

$
8
9
,
6
6
7

$
8
9
,
6
6
6

$
8
9
,
6
6
7

$
8
9
,
6
6
7

$
8
9
,
6
6
6
19
Au
t
h
o
r
i
z
e
d

N
e
t

E
x
p
e
n
s
e
$2
1
,
8
8
5
,
1
6
7

$
1
8
,
1
0
7
,
3
3
3

$
1
6
,
7
7
2
,
0
0
3

$
9
,
7
6
7
,
9
7
3

$
4
,
5
4
5
,
9
2
6

$
4
,
5
7
5
,
4
9
3

$
1
1
,
5
8
6
,
7
1
2

$
1
7
,
5
4
6
,
1
5
5

$
1
4
,
6
5
5
,
8
1
6

$
1
5
,
6
7
1
,
9
1
3

$
1
8
,
6
6
7
,
7
6
2

$
2
0
,
7
3
6
,
1
9
5
20
Ac
t
u
a
l

-

A
u
t
h
o
r
i
z
e
d

N
e
t

E
x
p
e
n
s
e
($
4
,
7
7
4
,
7
2
8
)
($
1
,
3
0
4
,
3
2
9
)
To
t
a
l

t
h
r
o
u
g
h

Ja
n
u
a
r
y
$0
$1
7
,
1
1
0
,
4
3
9
$2
,
6
6
3
,
5
3
2
$1
0
,
1
3
3
,
3
1
1
$0
$2
1
,
8
8
5
,
1
6
7
$1
4
,
2
4
1
,
3
0
8
$1
,
4
4
7
,
5
4
2
$7
,
0
3
4
,
0
5
7
($
1
,
3
1
3
,
9
9
3
)
($
4
,
7
7
4
,
7
2
8
)
$8
9
,
6
6
7
($
5
,
3
8
5
,
8
6
4
)
Av
i
s
t
a

C
o
r
p
.

-

R
e
s
o
u
r
c
e

A
c
c
o
u
n
t
i
n
g
WA
S
H
I
N
G
T
O
N

P
O
W
E
R

C
O
S
T

D
E
F
E
R
R
A
L
S
$1
,
4
6
9
,
0
9
1
$3
1
,
3
9
3
$0
TO
T
A
L
$1
8
,
5
0
8
,
2
4
9
($
1
1
,
6
4
3
,
0
7
2
)
$3
,
0
2
4
,
7
1
4
20
1
5
.
0
1

W
A

&

I
D

A
c
t
u
a
l

D
e
f
e
r
r
a
l
s
.
x
l
s

-

0
2
-
1
2
-
2
0
1
5
Pa
g
e

1

o
f

3
21

R
e
s
o
u
r
c
e

Op
t
i
m
i
z
a
t
i
o
n

-
Su
b
t
o
t
a
l
($
7
2
9
,
4
9
6
)
$0
22

A
d
j
u
s
t
e
d

N
e
t

E
x
p
e
n
s
e
($
5
,
5
0
4
,
2
2
4
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
23

W
a
s
h
i
n
g
t
o
n

A
l
l
o
c
a
t
i
o
n
64
.
7
1
%

6
4
.
7
1
%

6
4
.
7
1
%

6
4
.
7
1
%

6
4
.
7
1
%

6
4
.
7
1
%

6
4
.
7
1
%

6
4
.
7
1
%

6
4
.
7
1
%

6
4
.
7
1
%

6
4
.
7
1
%

6
4
.
7
1
%
24

W
a
s
h
i
n
g
t
o
n

S
h
a
r
e
($
3
,
5
6
1
,
7
8
3
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
25
$2
6
2
,
9
4
8
26
($
3
,
2
9
8
,
8
3
5
)
27
Cu
m
u
l
a
t
i
v
e

Ba
l
a
n
c
e
($
3
,
2
9
8
,
8
3
5
)
De
f
e
r
r
a
l

Am
o
u
n
t
,

Cu
m
u
l
a
t
i
v
e

(C
u
s
t
o
m
e
r
)
$0
De
f
e
r
r
a
l

Am
o
u
n
t
,

Mo
n
t
h
l
y
$0 $0
($
3
,
2
9
8
,
8
3
5
)
($
3
,
2
9
8
,
8
3
5
)
Ne
t

P
o
w
e
r

C
o
s
t

(
+
)

S
u
r
c
h
a
r
g
e

(
-
)

R
e
b
a
t
e
($
5
,
5
0
4
,
2
2
4
)
($
3
,
5
6
1
,
7
8
3
)
Co
m
p
a
n
y

B
a
n
d

G
r
o
s
s

M
a
r
g
i
n

I
m
p
a
c
t
,

Cu
m
u
l
a
t
i
v
e
WA

R
e
t
a
i
l

R
e
v
e
n
u
e

A
d
j
u
s
t
m
e
n
t
(+
)

S
u
r
c
h
a
r
g
e

(
-
)

R
e
b
a
t
e
Ac
c
t

5
5
7
2
8
0

E
n
t
r
y
;

(
+
)

R
e
b
a
t
e
,

(
-
)

S
u
r
c
h
a
r
g
e
($
7
2
9
,
4
9
6
)
$2
6
2
,
9
4
8
$0
20
1
5
.
0
1

W
A

&

I
D

A
c
t
u
a
l

D
e
f
e
r
r
a
l
s
.
x
l
s

-

0
2
-
1
2
-
2
0
1
5
Pa
g
e

1

o
f

3
ERM Report Month of January 2015
Page 17 of 40
INCU_DR_015 Attachment A Page 17 of 40
Lin
e
No
.
TO
T
A
L

J
a
n
-
1
5

F
e
b
-
1
5

M
a
r
-
1
5

A
p
r
-
1
5

M
a
y
-
1
5

J
u
n
-
1
5

J
u
l
-
1
5

A
u
g
-
1
5

S
e
p
-
1
5

O
c
t
-
1
5

N
o
v
-
1
5

D
e
c
-
1
5
55
5

P
U
R
C
H
A
S
E
D

P
O
W
E
R
1
S
h
o
r
t
-
T
e
r
m

P
u
r
c
h
a
s
e
s
$9
,
0
8
3
,
6
7
2

$
9
,
0
8
3
,
6
7
2
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
2
C
h
e
l
a
n

C
o
u
n
t
y

P
U
D

(
R
o
c
k
y

R
e
a
c
h

S
l
i
c
e
)
$1
,
1
3
7
,
2
1
8
$1
,
1
3
7
,
2
1
8
3
D
o
u
g
l
a
s

C
o
u
n
t
y

P
U
D

(
W
e
l
l
s

S
e
t
t
l
e
m
e
n
t
)
$1
0
0
,
7
3
0
$1
0
0
,
7
3
0
4
D
o
u
g
l
a
s

C
o
u
n
t
y

P
U
D

(
W
e
l
l
s
)
$1
5
3
,
8
5
2
$1
5
3
,
8
5
2
5
G
r
a
n
t

C
o
u
n
t
y

P
U
D

(
P
r
i
e
s
t

R
a
p
i
d
s
/
W
a
n
a
p
u
m
)
$6
1
8
,
3
3
4
$6
1
8
,
3
3
4
6
Bo
n
n
e
v
ill
e

P
o
w
e
r

A
d
m
i
n
.

(
W
N
P
-
3
)
1
$2
,
7
5
9
,
8
1
6

$
2
,
7
5
9
,
8
1
6
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
7
I
n
l
a
n
d

P
o
w
e
r

&

L
i
g
h
t

-

D
e
e
r

L
a
k
e
$5
0
5
$5
0
5
8
S
m
a
l
l

P
o
w
e
r
$1
3
2
,
0
3
7
$1
3
2
,
0
3
7
9
S
t
i
m
s
o
n

L
u
m
b
e
r
$1
3
3
,
8
7
6
$1
3
3
,
8
7
6
10

C
i
t
y

o
f

S
p
o
k
a
n
e
-
U
p
r
i
v
e
r
$4
8
3
,
3
3
8
$4
8
3
,
3
3
8
11

C
i
t
y

o
f

S
p
o
k
a
n
e

-

W
a
s
t
e
-
t
o
-
E
n
e
r
g
y
$4
0
7
,
3
3
6
$4
0
7
,
3
3
6
12

P
l
a
c
e

H
o
l
d
e
r
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
13

R
a
t
h
d
r
u
m

P
o
w
e
r
,

L
L
C

(
L
a
n
c
a
s
t
e
r

P
P
A

)
$2
,
0
8
5
,
3
1
1
$2
,
0
8
5
,
3
1
1
14

P
a
l
o
u
s
e

W
i
n
d
$1
,
2
4
1
,
4
7
9
$1
,
2
4
1
,
4
7
9
15
Clearwater
(
PFI)
$0
$
0
$
0
$
0
$
0
$
0
$
0
$
0
$
0
$
0
$
0
$
0
$
0
16

W
P
M

A
n
c
i
l
l
a
r
y

S
e
r
v
i
c
e
s
$1
4
7
,
9
8
6

$
1
4
7
,
9
8
6
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
17

N
o
n
-
M
o
n
.

A
c
c
r
u
a
l
s
$2
2
,
7
5
9

$
2
2
,
7
5
9
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
18

T
o
t
a
l

5
5
5

P
u
r
c
h
a
s
e
d

P
o
w
e
r
$1
8
,
5
0
8
,
2
4
9

$
1
8
,
5
0
8
,
2
4
9
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
(1
)

E
f
f
e
c
t
i
v
e

N
o
v
e
m
b
e
r
,

2
0
0
8
,

W
N
P
-
3

p
u
r
c
h
a
s
e

e
x
p
e
n
s
e

h
a
s

b
e
e
n

a
d
j
u
s
t
e
d

t
o

r
e
f
l
e
c
t

t
h
e

m
i
d
-
p
o
i
n
t

p
r
i
c
e
,

p
e
r

S
e
t
t
l
e
m
e
n
t

A
g
r
e
e
m
e
n
t,
C
a
u
s
e

N
o
.

U
-
8
6
-
9
9
44
7

S
A
L
E
S

F
O
R

R
E
S
A
L
E
19

S
h
o
r
t
-
T
e
r
m

S
a
l
e
s
($
1
0
,
0
7
6
,
7
6
3
)

(
$
1
0
,
0
7
6
,
7
6
3
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
20

P
e
a
k
e
r

L
L
C
/
P
G
E

C
a
p

S
a
l
e
($
1
4
5
,
9
5
5
)
($
1
4
5
,
9
5
5
)
21

N
i
c
h
o
l
s

P
u
m
p
i
n
g

I
n
d
e
x

S
a
l
e
($
7
6
,
2
8
1
)
($
7
6
,
2
8
1
)
22

S
o
v
e
r
i
g
n
/
K
a
i
s
e
r

L
o
a
d

F
o
l
l
o
w
i
n
g
($
1
1
,
9
6
3
)
($
1
1
,
9
6
3
)
23

P
e
n
d

O
r
e
ill
e

D
E
S
($4
8
,
6
6
6
)
($
4
8
,
6
6
6
)
24

S
M
U
D

5
0

+

2
5
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
25

M
e
r
c
h
a
n
t

A
n
c
ill
a
r
y

S
e
r
v
i
c
e
s
($
1
,
28
3
,
4
4
4
)

(
$
1
,
2
8
3
,
4
4
4
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
26

T
o
t
a
l

4
4
7

S
a
l
e
s

f
o
r

R
e
s
a
l
e
($
1
1
,
6
4
3
,
0
7
2
)

(
$
1
1
,
6
4
3
,
0
7
2
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
50
1

F
U
E
L
-
D
O
L
L
A
R
S
27
K
t
t
l

F

l
l

W

d

5
0
1
1
1
0
$7
8
7

0
1
6
$7
8
7

0
1
6
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
Av
i
s
t
a

C
o
r
p
.

-

R
e
s
o
u
r
c
e

A
c
c
o
u
n
t
i
n
g
WA
S
H
I
N
G
T
O
N

D
E
F
E
R
R
E
D

P
O
W
E
R

C
O
S
T

C
A
L
C
U
L
A
T
I
O
N

-

A
C
T
U
A
L

S
Y
S
T
E
M

P
O
W
E
R

S
U
P
P
L
Y

E
X
P
E
N
S
E
S
27
Ke
e
a
s
oo
-
,
,
28

K
e
t
t
l
e

F
a
l
l
s

G
a
s
-
5
0
1
1
2
0
($
1
5
9
)

(
$
1
5
9
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
29

C
o
l
s
t
r
i
p

C
o
a
l
-
5
0
1
1
4
0
$2
,
1
9
1
,
9
7
3

$
2
,
1
9
1
,
9
7
3
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
30

C
o
l
s
t
r
i
p

O
i
l
-
5
0
1
1
6
0
$4
5
,
8
8
4

$
4
5
,
8
8
4
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
31

T
o
t
a
l

5
0
1

F
u
e
l

E
x
p
e
n
s
e
$3
,
0
2
4
,
7
1
4

$
3
,
0
2
4
,
7
1
4
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
50
1

F
U
E
L
-
T
O
N
S
32

K
e
t
t
l
e

F
a
l
l
s
57
,
5
7
2

57
,
5
7
2

33

C
o
l
s
t
r
i
p
98
,
8
1
2

98
,
8
1
2

50
1

F
U
E
L
-
C
O
S
T

P
E
R

T
O
N
34

K
e
t
t
l
e

Fa
l
l
s
wo
o
d
$1
3
.
6
7
35

C
o
l
s
t
r
i
p
co
a
l
$2
2
.
1
8
54
7

F
U
E
L
36

N
E

C
T

G
a
s
/
O
i
l
-
5
4
7
2
1
3
$1
,
9
3
3

$
1
,
9
3
3
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
37

B
o
u
l
d
e
r

P
a
r
k
-
5
4
7
2
1
6
$1
6
,
6
1
3

$
1
6
,
6
1
3
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
38

K
e
t
t
l
e

F
a
l
l
s

C
T
-
5
4
7
2
1
1
$1
,
1
6
1

$
1
,
1
6
1
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
39

C
o
y
o
t
e

S
p
r
i
n
g
s
2
-
5
4
7
6
1
0
$3
,
7
5
6
,
1
1
8

$
3
,
7
5
6
,
1
1
8
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
40

L
a
n
c
a
s
t
e
r
-
5
4
7
3
1
2
$3
,
2
3
4
,
2
8
0

$
3
,
2
3
4
,
2
8
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
41

R
a
t
h
d
r
u
m

C
T
-
5
4
7
3
1
0
$2
3
,
9
5
2

$
2
3
,
9
5
2
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
42

T
o
t
a
l

5
4
7

F
u
e
l

E
x
p
e
n
s
e
$7
,
0
3
4
,
0
5
7

$
7
,
0
3
4
,
0
5
7
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
43

T
O
T
A
L

N
E
T

E
X
P
E
N
S
E
$1
6
,
9
2
3
,
9
4
8
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
45
6

T
R
A
N
S
M
I
S
S
I
O
N

R
E
V
E
N
U
E
44
45
6
1
0
0

E
D

A
N
($
1
,
0
4
4
,
9
3
5
)

(
$
1
,
0
4
4
,
9
3
5
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
45
45
6
1
2
0

E
D

A
N

-

B
P
A

S
e
t
t
l
e
m
e
n
t
($
2
6
6
,
0
0
0
)
($
2
6
6
,
0
0
0
)

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
46

4
5
6
0
2
0

E
D

A
N
-
S
a
l
e

o
f

e
x
c
e
s
s

B
P
A

T
r
a
n
s

(
$3
,
0
5
8
)

(
$
3
,
0
5
8
)

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
47
Ex
c
l
u
d
e

P
r
i
o
r

Y
e
a
r

B
P
A

S
e
t
t
l
e
m
e
n
t

$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
48
45
6
7
0
5

E
D

A
N

-

D
o

n
o
t

i
n
c
l
u
d
e

L
o
w

V
o
l
t
a
g
e
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
49

T
o
t
a
l

4
5
6

T
r
a
n
s
m
i
s
s
i
o
n

R
e
v
e
n
u
e
($
1
,
3
1
3
,
9
9
3
)

(
$
1
,
3
1
3
,
9
9
3
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
20
1
5
.
0
1

W
A

&

I
D

A
c
t
u
a
l

D
e
f
e
r
r
a
l
s
.
x
l
s

-

0
2
-
1
2
-
2
0
1
5
Pa
e
3

o
f

3
ERM Report Month of January 2015
Page 18 of 40
INCU_DR_015 Attachment A Page 18 of 40
Lin
e
No
.
TO
T
A
L

J
a
n
-
1
5

F
e
b
-
1
5

M
a
r
-
1
5

A
p
r
-
1
5

M
a
y
-
1
5

J
u
n
-
1
5

J
u
l
-
1
5

A
u
g
-
1
5

S
e
p
-
1
5

O
c
t
-
1
5

N
o
v
-
1
5

D
e
c
-
1
5
Av
i
s
t
a

C
o
r
p
.

-

R
e
s
o
u
r
c
e

A
c
c
o
u
n
t
i
n
g
WA
S
H
I
N
G
T
O
N

D
E
F
E
R
R
E
D

P
O
W
E
R

C
O
S
T

C
A
L
C
U
L
A
T
I
O
N

-

A
C
T
U
A
L

S
Y
S
T
E
M

P
O
W
E
R

S
U
P
P
L
Y

E
X
P
E
N
S
E
S
56
5

T
R
A
N
S
M
I
S
S
I
O
N

E
X
P
E
N
S
E
50

5
6
5
0
0
0

E
D

A
N
$1
,
4
6
7
,
0
6
1

$
1
,
4
6
7
,
0
6
1
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
51

5
6
5
3
1
2

E
D

A
N
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
52

5
6
5
7
1
0

E
D

A
N
$2
,
0
3
0

$
2
,
0
3
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
53

T
o
t
a
l

5
6
5

T
r
a
n
s
m
i
s
s
i
o
n

E
x
p
e
n
s
e
$1
,
4
6
9
,
0
9
1

$
1
,
4
6
9
,
0
9
1
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
55
7

B
r
o
k
e
r

&

R
e
l
a
t
e
d

F
e
e
s
54

5
5
7
1
7
0

E
D

A
N
$3
1
,
0
1
8

$
3
1
,
0
1
8
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
55

5
5
7
1
7
2

E
D

A
N
$3
7
5
$3
7
5
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
56

T
o
t
a
l

5
5
7

E
D

A
N

B
r
o
k
e
r

&

R
e
l
a
t
e
d

F
e
e
s
$3
1
,
3
9
3

$
3
1
,
3
9
3
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
RE
S
O
U
R
C
E

O
P
T
I
M
I
Z
A
T
I
O
N
57

E
c
o
n

D
i
s
p
a
t
c
h
-
5
5
7
0
1
0
$2
,
5
9
1
,
8
8
9

$
2
,
5
9
1
,
8
8
9
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
58

E
c
o
n

D
i
s
p
a
t
c
h
-
5
5
7
1
5
0
$8
1
4
,
9
7
2

$
8
1
4
,
9
7
2
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
59

G
a
s

B
o
o
k
o
u
t
s
-
5
5
7
7
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
60

G
a
s

B
o
o
k
o
u
t
s
-
5
5
7
7
1
1
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
61

I
n
t
r
a
c
o

T
h
e
r
m
a
l

G
a
s
-
5
5
7
7
3
0
$2
,
8
6
2
,
5
3
0

$
2
,
8
6
2
,
5
3
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
62

F
u
e
l

D
i
s
p
a
t
c
h
F
i
n

-
4
5
6
0
1
0
($
2
,
0
1
3
,
1
7
3
)

(
$
2
,
0
1
3
,
1
7
3
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
63

F
u
e
l

D
i
s
p
a
t
c
h
-
4
5
6
0
1
5
($
1
,
0
1
0
,
4
0
7
)

(
$
1
,
0
1
0
,
4
0
7
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
64

I
n
t
r
a
c
o

T
h
e
r
m
a
l

G
a
s
-
4
5
6
7
3
0
($
3
,
9
5
2
,
6
1
6
)

(
$
3
,
9
5
2
,
6
1
6
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
65

F
u
e
l

B
o
o
k
o
u
t
s
-
4
5
6
7
1
1
$6
3
,
1
5
0

$
6
3
,
1
5
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
66

F
u
e
l

B
o
o
k
o
u
t
s
-
4
5
6
7
2
0
($
6
3
,
1
5
0
)

(
$
6
3
,
1
5
0
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
67
R
e
s
o
u
r
c
e

O
p
t
i
m
i
z
a
t
o
n

S
u
b
t
o
t
a
l
($
7
0
6
,
8
0
5
)

(
$
7
0
6
,
8
0
5
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
68

M
i
s
c
.

P
o
w
e
r

E
x
p
.

A
u
t
h
o
r
i
z
e
d
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
69

M
i
s
c
.

P
o
w
e
r

E
x
p
.

A
c
t
u
a
l
-
5
5
7
1
6
0

E
D

A
N
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
70

K
F
W
F

C
o
n
t
r
a
c
t

B
u
y
o
u
t
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
71
Mi
s
c
.

P
o
w
e
r

E
x
p
.

S
u
b
t
o
t
a
l
$0
$0
$0
72
Wi
n
d

R
E
C

E
x
p

A
u
t
h
o
r
i
z
e
d
$0
$0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
73

W
i
n
d

R
E
C

E
x
p

A
c
t
u
a
l

5
5
7
3
9
5

$
1
6

$
1
6

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
74
Win
d

R
E
C

S
u
b
t
o
t
a
l

$
1
6

$
1
6

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0

$
0
75
WA

E
I
A
9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

E
x
p
e
n
s
e
$1
5
4
,
7
1
5

$
1
5
4
,
7
1
5
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
76
WA

E
I
A

R
E
C

P
u
r
c
h
a
s
e

-

A
u
t
h
o
r
i
z
e
d
$1
8
1
,
2
5
0
$1
8
1
,
2
5
0

$
0

$
0

$
1
8
1
,
2
5
0

$
0

$
0

$
1
8
1
,
2
5
0

$
0

$
0

$
1
8
1
,
2
5
0

$
0

$
0
76
WA

E
I
A
9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

B
r
o
k
e
r

F
e
e

E
x
p
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
77
WA

E
I
A

9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

B
r
o
k
e
r

F
e
e

E
x
p
$3
,
8
2
8

$
3
,
8
2
8
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
78
EW
E
B

R
E
C

W
A

E
I
A

9
3
7

C
o
m
p
l
i
a
n
c
e
($
2
2
,
7
0
7
)

(
$
2
2
,
7
0
7
)
$0
$0

(
$
1
8
1
,
2
5
0
)
$0
$0

(
$
1
8
1
,
2
5
0
)
$0
$0

(
$
1
8
1
,
2
5
0
)
$0
$0
79

N
e
t

Re
s
o
u
r
c
e

Op
t
i
m
i
z
a
t
i
o
n
($
7
2
9
,
4
9
6
)

(
$
7
2
9
,
4
9
6
)
$0
80

A
d
j
u
s
t
e
d

Ac
t
u
a
l

Ne
t

Ex
p
e
n
s
e
$1
6
,
3
8
0
,
9
4
3

$
1
6
,
3
8
0
,
9
4
3
20
1
5
.
0
1

W
A

&

I
D

A
c
t
u
a
l

D
e
f
e
r
r
a
l
s
.
x
l
s

-

0
2
-
1
2
-
2
0
1
5
Pa
e
4

o
f

3
ERM Report Month of January 2015
Page 19 of 40
INCU_DR_015 Attachment A Page 19 of 40
Re
t
a
i
l

S
a
l
e
s

-

M
W
h
Ja
n
-
1
5

F
e
b
-
1
5

M
a
r
-
1
5

A
p
r
-
1
5

M
a
y
-
1
5

J
u
n
-
1
5

J
u
l
-
1
5

A
u
g
-
1
5

S
e
p
-
1
5

O
c
t
-
1
5

N
o
v
-
1
5

D
e
c
-
1
5

Y
T
D
To
t
a
l

B
i
l
l
e
d

S
a
l
e
s
54
8
,
3
4
2

54
8
,
3
4
2

De
d
u
c
t

P
r
i
o
r

M
o
n
t
h

U
n
b
i
l
l
e
d
(3
8
8
,
6
7
4
)

-
-
-
-
-

-
-
-
-
-
-

(3
8
8
,
6
7
4
)

Ad
d

C
u
r
r
e
n
t

M
o
n
t
h

U
n
b
i
l
l
e
d
37
2
,
4
6
8

37
2
,
4
6
8

To
t
a
l

R
e
t
a
i
l

S
a
l
e
s
53
2
,
1
3
6

-
-
-
-
-

-
-
-
-
-
-

53
2
,
1
3
6

Te
s
t

Y
e
a
r

R
e
t
a
i
l

S
a
l
e
s
54
5
,
2
0
5

49
8
,
0
3
4

48
7
,
5
5
1

42
2
,
2
4
6

42
1
,
9
8
2

42
0
,
9
0
1

46
4
,
3
9
2

48
9
,
7
6
3

42
6
,
9
6
7

45
2
,
4
2
4

49
0
,
3
1
9

57
0
,
0
2
3

54
5
,
2
0
5

Di
f
f
e
r
e
n
c
e

f
r
o
m

T
e
s
t

Y
e
a
r
(1
3
,
0
6
9
)

(1
3
,
0
6
9
)

Pr
o
d
u
c
t
i
o
n

R
a
t
e

-

$
/
M
W
h
$2
0
.
1
2

$
2
0
.
1
2

$
2
0
.
1
2

$
2
0
.
1
2

$
2
0
.
1
2

$
2
0
.
1
2

$
2
0
.
1
2

$
2
0
.
1
2

$
2
0
.
1
2

$
2
0
.
1
2

$
2
0
.
1
2

$
2
0
.
1
2
To
t
a
l

R
e
v
e
n
u
e

C
r
e
d
i
t

-

$
($
2
6
2
,
9
4
8
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0

(
$
2
6
2
,
9
4
8
)
Av
i
s
t
a

C
o
r
p
.

-

R
e
s
o
u
r
c
e

A
c
c
o
u
n
t
i
n
g
Wa
s
h
i
n
g
t
o
n

E
l
e
c
t
r
i
c

J
u
r
i
s
d
i
c
t
i
o
n
En
e
r
g
y

R
e
c
o
v
e
r
y

M
e
c
h
a
n
i
s
m

(
E
R
M
)

R
e
t
a
i
l

R
e
v
e
n
u
e

C
r
e
d
i
t

C
a
l
c
u
l
a
t
i
o
n

-

2
0
1
5
ERM Report Month of January 2015
Page 20 of 40
INCU_DR_015 Attachment A Page 20 of 40
ERM Report Month of January 2015
Page 21 of 40
INCU_DR_015 Attachment A Page 21 of 40
ERM Report Month of January 2015
Page 22 of 40
INCU_DR_015 Attachment A Page 22 of 40
ERM Report Month of January 2015
Page 23 of 40
INCU_DR_015 Attachment A Page 23 of 40
ERM Report Month of January 2015
Page 24 of 40
INCU_DR_015 Attachment A Page 24 of 40
ERM Report Month of January 2015
Page 25 of 40
INCU_DR_015 Attachment A Page 25 of 40
Attachment B

Avista Corporation
Monthly Power Cost Deferral Report

Month of January 2015

NSJ015 Reverse BPA Balance Transferred Incorrectly Journal
ERM Report Month of January 2015
Page 26 of 40
INCU_DR_015 Attachment A Page 26 of 40
ERM Report Month of January 2015
Page 27 of 40
INCU_DR_015 Attachment A Page 27 of 40
ERM Report Month of January 2015
Page 28 of 40
INCU_DR_015 Attachment A Page 28 of 40
ERM Report Month of January 2015
Page 29 of 40
INCU_DR_015 Attachment A Page 29 of 40
Attachment C

Avista Corporation
Monthly Power Cost Deferral Report

Month of January 2015

REC Revenues Deferral Journal

ERM Report Month of January 2015
Page 30 of 40
INCU_DR_015 Attachment A Page 30 of 40
ERM Report Month of January 2015
Page 31 of 40
INCU_DR_015 Attachment A Page 31 of 40
ERM Report Month of January 2015
Page 32 of 40
INCU_DR_015 Attachment A Page 32 of 40
ERM Report Month of January 2015
Page 33 of 40
INCU_DR_015 Attachment A Page 33 of 40
ERM Report Month of January 2015
Page 34 of 40
INCU_DR_015 Attachment A Page 34 of 40
ERM Report Month of January 2015
Page 35 of 40
INCU_DR_015 Attachment A Page 35 of 40
ERM Report Month of January 2015
Page 36 of 40
INCU_DR_015 Attachment A Page 36 of 40
ERM Report Month of January 2015
Page 37 of 40
INCU_DR_015 Attachment A Page 37 of 40
ERM Report Month of January 2015
Page 38 of 40
INCU_DR_015 Attachment A Page 38 of 40
ERM Report Month of January 2015
Page 39 of 40
INCU_DR_015 Attachment A Page 39 of 40
Pr
i
n
c
i
p
a
l
Li
n
e

C
o
u
p
o
n

M
a
t
u
r
i
t
y

S
e
t
t
l
e
m
e
n
t

P
r
i
n
c
i
p
a
l

I
s
s
u
a
n
c
e

S
W
A
P

D
i
s
c
o
u
n
t

L
o
s
s
/
R
e
a
c
q

N
e
t

Y
i
e
l
d

t
o

O
u
t
s
t
a
n
d
i
n
g

E
f
f
e
c
t
i
v
e

L
i
n
e
No
.

D
e
s
c
r
i
p
t
i
o
n

R
a
t
e

D
a
t
e

D
a
t
e

A
m
o
u
n
t

C
o
s
t
s

L
o
s
s
/
(
G
a
i
n
)

(
P
r
e
m
i
u
m
)

E
x
p
e
n
s
e
s

P
r
o
c
e
e
d
s

M
a
t
u
r
i
t
y

1
2
-
3
1
-
2
0
1
4

C
o
s
t

N
o
.
(a
)

(
b
)

(

c
)

(
d
)

(
e
)

(
f
)

(
g
)

(
g
)

(
h
)

(
i
)

(
j
)

(
k
)

(
l
)
1
F
M
B
S

-

S
E
R
I
E
S

A

7
.
5
3
0
%

0
5
-
0
5
-
2
0
2
3

0
5
-
0
6
-
1
9
9
3

5
,
5
0
0
,
0
0
0

4
2
,
7
1
2

-

-
9
6
3
,
0
1
1

4,
4
9
4
,
2
7
7

9.
3
5
9
%
5,5
0
0
,
0
0
0

51
4
,
7
4
4

1
2
F
M
B
S

-

S
E
R
I
E
S

A

7.
5
4
0
%
05
-
0
5
-
2
0
2
3

0
5
-
0
7
-
1
9
9
3

1
,
0
0
0
,
0
0
0

7,
7
6
6

-
-
1
7
5
,
4
1
2

81
6
,
8
2
2

9.
3
7
5
%
1,0
0
0
,
0
0
0

93
,
7
4
7

2
3
F
M
B
S

-

S
E
R
I
E
S

A

7.
3
9
0
%
05
-
1
1
-
2
0
1
8

0
5
-
1
1
-
1
9
9
3

7
,
0
0
0
,
0
0
0

54
,
3
6
4

-
-
1
,
2
2
7
,
8
8
3

5,
7
1
7
,
7
5
3

9.
2
8
7
%
7,0
0
0
,
0
0
0

65
0
,
1
1
4

3
4
F
M
B
S

-

S
E
R
I
E
S

A

7.
4
5
0
%
06
-
1
1
-
2
0
1
8

0
6
-
0
9
-
1
9
9
3

1
5
,
5
0
0
,
0
0
0

12
0
,
3
7
7

-
5
0
,
2
2
0

2,
1
4
0
,
4
4
0

13
,
1
8
8
,
9
6
3

8.
9
5
3
%
15
,
5
0
0
,
0
0
0

1,3
8
7
,
7
1
5

4
5
F
M
B
S

-

S
E
R
I
E
S

A

7.
1
8
0
%
08
-
1
1
-
2
0
2
3

0
8
-
1
2
-
1
9
9
3

7
,
0
0
0
,
0
0
0

54
,
3
6
4

-
-
-
6,
9
4
5
,
6
3
6

7.
2
4
4
%
7,0
0
0
,
0
0
0

50
7
,
0
6
4

5
6
A
D
V
A
N
C
E

A
S
S
O
C
I
A
T
1.
2
2
0
%
1
06
-
0
1
-
2
0
3
7

0
6
-
0
3
-
1
9
9
7

4
0
,
0
0
0
,
0
0
0

1
,
2
9
6
,
0
8
6

-

-
(
1
,
7
6
9
,
1
2
5
)

40
,
4
7
3
,
0
3
9

1.
1
8
3
%
40
,
0
0
0
,
0
0
0

47
3
,
0
7
2

6
7
S
e
r
i
e
s

C

S
e
t
u
p

C
N/A
06
-
1
5
-
2
0
1
3

0
6
-
1
5
-
1
9
9
8
-
6
6
6
,
1
6
9

-
-
-
-
-
7
8
F
M
B
S

-

S
E
R
I
E
S

C

6.
3
7
0
%
06
-
1
9
-
2
0
2
8

0
6
-
1
9
-
1
9
9
8

2
5
,
0
0
0
,
0
0
0

15
8
,
3
0
4

-
-
1
8
8
,
6
4
9

24
,
6
5
3
,
0
4
7

6.
4
7
5
%
25
,
0
0
0
,
0
0
0

1,6
1
8
,
8
6
3

8
9
5
.
4
5
%

S
E
R
I
E
S

5.
4
5
0
%
12
-
0
1
-
2
0
1
9

1
1
-
1
8
-
2
0
0
4

9
0
,
0
0
0
,
0
0
0

1,1
9
2
,
6
8
1

-
2
3
9
,
4
0
0

7,
2
4
4
,
9
1
8

81
,
3
2
3
,
0
0
1

6.
4
6
2
%
90
,
0
0
0
,
0
0
0

5,8
1
5
,
4
2
0

9
10

F
M
B
S

-

6
.
2
5
%

6.
2
5
0
%
12
-
0
1
-
2
0
3
5

1
1
-
1
7
-
2
0
0
5

1
5
0
,
0
0
0
,
0
0
0

1,8
1
2
,
9
3
5

(4
,
4
4
5
,
0
0
0
)

36
7
,
5
0
0

1,
7
0
0
,
3
7
6

15
0
,
5
6
4
,
1
8
8

6.
2
2
2
%

1
5
0
,
0
0
0
,
0
0
0

9,3
3
2
,
8
9
1

10
11

F
M
B
S

-

5
.
7
0
%

5.
7
0
0
%
07
-
0
1
-
2
0
3
7

1
2
-
1
5
-
2
0
0
6

1
5
0
,
0
0
0
,
0
0
0

4,7
0
2
,
3
0
4

3,7
3
8
,
0
0
0

22
2
,
0
0
0

-
1
4
1
,
3
3
7
,
6
9
6

6.
1
2
0
%

1
5
0
,
0
0
0
,
0
0
0

9,1
7
9
,
6
7
4

11
12

5
.
9
5
%

S
E
R
I
E
S

5.
9
5
0
%
06
-
0
1
-
2
0
1
8

0
4
-
0
3
-
2
0
0
8

2
5
0
,
0
0
0
,
0
0
0

2,2
4
6
,
4
1
9

16
,
3
9
5
,
0
0
0

83
5
,
0
0
0

-
2
3
0
,
5
2
3
,
5
8
1

7.
0
3
4
%

2
5
0
,
0
0
0
,
0
0
0

17
,
5
8
5
,
9
2
6

12
13

5
.
1
2
5
%

S
E
R
I
E
S
5.
1
2
5
%
04
-
0
1
-
2
0
2
2

0
9
-
2
2
-
2
0
0
9

2
5
0
,
0
0
0
,
0
0
0

2,2
8
4
,
7
8
8

(1
0
,
7
7
6
,
2
2
2
)

57
5
,
0
0
0

2,
8
7
5
,
8
1
7

25
5
,
0
4
0
,
6
1
8

4.
9
0
7
%

2
5
0
,
0
0
0
,
0
0
0

12
,
2
6
8
,
6
1
5

13
14

3
.
8
9
%

S
E
R
I
E
S

3.
8
9
0
%
12
-
2
0
-
2
0
2
0

1
2
-
2
0
-
2
0
1
0

5
2
,
0
0
0
,
0
0
0

38
5
,
1
2
9

-
-
6
,
2
7
3
,
6
6
4

45
,
3
4
1
,
2
0
7

5.
5
7
8
%
52
,
0
0
0
,
0
0
0

2,9
0
0
,
5
8
1

14
15

5
.
5
5
%

S
E
R
I
E
S

5.
5
5
0
%
12
-
2
0
-
2
0
4
0

1
2
-
2
0
-
2
0
1
0

3
5
,
0
0
0
,
0
0
0

25
8
,
8
3
4

-
-
5
,
2
6
3
,
8
2
2

29
,
4
7
7
,
3
4
5

6.
7
8
8
%
35
,
0
0
0
,
0
0
0

2,3
7
5
,
8
8
7

15
16

4
.
4
5
%

S
E
R
I
E
S

4.
4
5
0
%
12
-
1
4
-
2
0
4
1

1
2
-
1
4
-
2
0
1
1

8
5
,
0
0
0
,
0
0
0

69
2
,
8
3
3

10
,
5
5
7
,
0
0
0

-
-
73
,
7
5
0
,
1
6
7

5.
3
4
0
%
85
,
0
0
0
,
0
0
0

4,5
3
8
,
8
7
1

16
17

4
.
2
3
%

S
E
R
I
E
S

4.
2
3
0
%
11
-
2
9
-
2
0
4
7

1
1
-
3
0
-
2
0
1
2

8
0
,
0
0
0
,
0
0
0

73
0
,
8
3
3

18
,
5
4
6
,
8
7
0

-
1
0
5
,
0
2
0

60
,
6
1
7
,
2
7
7

5.
8
6
8
%
80
,
0
0
0
,
0
0
0

4,6
9
4
,
5
3
3

17
18

0
.
8
4
%

S
E
R
I
E
S

0.
8
4
0
%
08
-
1
4
-
2
0
1
6

0
8
-
1
4
-
2
0
1
3

9
0
,
0
0
0
,
0
0
0

51
5
,
3
6
9

(2
,
9
0
0
,
6
8
0
)

-
-
92
,
3
8
5
,
3
1
1

-0
.
0
4
3
%
90
,
0
0
0
,
0
0
0

(3
8
,
5
0
9
)

18
19

4
.
1
1
%

S
E
R
I
E
S

4.
1
1
0
%
12
-
0
1
-
2
0
4
4

1
2
-
1
8
-
2
0
1
4

6
0
,
0
0
0
,
0
0
0

42
0
,
1
7
7

(5
,
4
2
9
,
0
0
0
)

-
-
65
,
0
0
8
,
8
2
3

3.
6
4
9
%
60
,
0
0
0
,
0
0
0

2,1
8
9
,
6
2
1

19
20
1,
3
9
3
,
0
0
0
,
0
0
0

76
,
0
8
8
,
8
3
1

20
21
21
22

R
e
p
u
r
c
h
a
s
e
2
8.
8
5
%

0
6
-
0
5
-
2
0
2
8

0
5
-
2
4
-
2
0
0
2

1
0
,
0
0
0
,
0
0
0
(2
,
2
2
8
,
1
5
3
)

12
,
2
2
8
,
1
5
3

6
.
9
8
1
%
3
-1
8
8
,
0
8
4

2
2
23

R
e
p
u
r
c
h
a
s
e
2
8.
8
3
%

0
6
-
0
5
-
2
0
2
8

0
4
-
0
3
-
2
0
0
3

1
0
,
0
0
0
,
0
0
0
(4
5
0
,
7
6
9
)

10
,
4
5
0
,
7
6
9

8
.
3
9
5
%
3
-4
3
,
6
6
1

2
3
24

R
e
p
u
r
c
h
a
s
e
2
8.
8
3
%

1
2
-
2
9
-
2
0
2
2

0
3
-
1
1
-
2
0
0
3

5
,
0
0
0
,
0
0
0
92
,
3
6
3

4,
9
0
7
,
6
3
7

9
.
0
2
9
%
3
10
,
3
4
1

2
4
25

R
e
p
u
r
c
h
a
s
e
2
5.
7
2
%

0
3
-
0
1
-
2
0
3
4

1
2
-
3
0
-
2
0
0
9

1
7
,
0
0
0
,
0
0
0
1,
9
1
6
,
2
9
7

15
,
0
8
3
,
7
0
3

6
.
6
6
1
%
3
15
9
,
4
4
6

2
5
26

R
e
p
u
r
c
h
a
s
e
2
6.
5
5
%

1
0
-
0
1
-
2
0
3
2

1
2
-
3
1
-
2
0
0
8

6
6
,
7
0
0
,
0
0
0
3,
7
0
9
,
1
7
4

62
,
9
9
0
,
8
2
6

7
.
0
3
4
%
3
32
4
,
3
6
0

2
6
27
1,3
9
3
,
0
0
0
,
0
0
0

7
6
,
3
5
1
,
2
3
3

2
7
28
3
Sh
o
r
t

T
e
r
m
-
D
e
b
t
81
,
1
2
1
,
0
4
8
2.
3
2
7
%
81
,
1
2
1
,
0
4
8

1
,
8
8
7
,
2
9
5

2
8
29
WA
S
H
I
N
G
T
O
N
'
S

T
O
T
A
L

D
E
B
T

O
U
T
S
T
A
N
D
I
N
G

A
N
D

C
O
S
T

O
F

D
E
B
T

A
T

D
e
c
e
m
b
e
r

3
1
,

2
0
1
1,4
7
4
,
1
2
1
,
0
4
8

7
8
,
2
3
8
,
5
2
8

2
9
30
30
31
Ad
j
u
s
t
e
d

W
e
i
g
h
t
e
d

A
v
e
r
a
g
e

C
o
s
t

o
f

D
e
b
t

5
.
3
0
7
%
31
32
1
Av
e
r
a
g
e

M
o
n
t
h
l
y

A
v
e
r
a
g
e

R
a
t
e

o
v
e
r

a

t
w
e
l
v
e

m
o
n
t
h

p
e
r
i
o
d
32
33
2
Co
u
p
o
n

R
a
t
e

a
t

t
h
e

t
i
m
e

o
f

r
e
p
u
r
c
h
a
s
e
33
34
3
Ca
l
c
u
l
a
t
e
d

u
s
i
n
g

t
h
e

I
n
t
e
r
n
a
l

R
a
t
e

o
f

R
e
t
u
r
n

m
e
t
h
o
d
34
AV
I
S
T
A

C
O
R
P
O
R
A
T
I
O
N
Co
s
t

o
f

L
o
n
g
-
T
e
r
m

D
e
b
t

D
e
t
a
i
l

-

W
a
s
h
i
n
g
t
o
n
De
c
e
m
b
e
r

3
1
,

2
0
1
4
Pa
g
e
 1 of
 1
ERM Report Month of January 2015
Page 40 of 40
INCU_DR_015 Attachment A Page 40 of 40

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/23/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Bill Johnson
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 015 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the Company’s latest calculations and workpapers demonstrating the amount of deferred funds in its ERM balance.

RESPONSE:
The balance at January 31, 2015 for ERM deferrals is shown in the table below. These dollar amounts
represent benefits owed to customers.

FERC Account 186280 - 2015 Deferral (4,210,977)$
FERC Account 186290 - 2014 Deferral -$
182350 - Recoverable Deferral Balance (9,163,094)$
Total ERM Deferrals at January 31, 2015 (13,374,071)$

Please see ICNU_DR_015 Attachment A for the Monthly ERM Report that was filed with the
Commission for January 2015.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/16/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mark Baker
TYPE: Data Request DEPT: Energy Solutions
REQUEST NO.: ICNU – 016 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the amount of demand side management kWh savings by customer class, including both Idaho and Washington jurisdictions, and on a monthly basis from 2010 to 2015.

RESPONSE:
The kWh savings from the Company’s demand side management programs are tracked in the following
classes: residential, low-income, and nonresidential. The Company has data available from 2010 through
2014 for the residential, nonresidential, and low-income classes. Data for 2015 is not available at this
time. Please see ICNU_DR_016 Attachment A which provides a summary of the annual savings
associated with the measures completed in each month by customer class.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/23/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Mark Baker
TYPE: Data Request DEPT: Energy Solutions
REQUEST NO.: ICNU – 017 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the amount of demand side management kW savings coincident to the Company’s system peak load by customer class, including both Idaho and Washington jurisdictions, and on a monthly basis
from 2010 to 2015.

RESPONSE:
The system coincident demand kW savings resulting from the Company’s demand side management
programs was not calculated nor tracked during this time period.

ICNU_DR_017 Attachment A (electronic only) contains 2009 hourly load research results by jurisdiction and rate schedule which may be compared to the 2014 hourly load research results by jurisdiction and rate
schedule.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/21/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Dr. Grant Forsyth
REQUESTER: ICNU RESPONDER: Dr. Grant Forsyth
TYPE: Data Request DEPT: Forecast
REQUEST NO.: ICNU – 018 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the amount of demand side management kWh savings assumed in the Company’s most recent load forecast by customer class, including both Idaho and Washington jurisdictions, and
on an hourly basis from 2015 to 2025.

RESPONSE:
The forecast takes into account historical trends, which include, among other factors, DSM impacts.
To elaborate, the historical billed data used in the forecast has historical DSM impacts embedded,
along with other impacts related to efficiency standards. Therefore, the Company’s forecast reflects
trends related to historical DSM only; there is no forward looking DSM adjustment beyond what is being carried forward based on historical behavior.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/20/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Laura Vickers
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 019 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide copies of all board minutes and board presentations made to Avista’s board of directors from December 26, 2012 to the present regarding the Company’s cost management and efficiency initiatives or
programs, including, but not limited to, the VSIP program.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 019C. Please note that
Avista’s response to ICNU – 019C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.
The Company has prepared a Virtual Data Room, as in previous cases, which houses the requested meeting
minutes. Please contact Paul Kimball via email – [e-mail] – to get the required login
and password information.

Refer to excerpts from: Please see ICNU_DR_019C Confidential Attachment A for excerpts from the February 8, 2013 Board
minutes regarding the Company’s VSIP program.

Please see ICNU_DR_019C Confidential Attachment B for excerpts from the February 7, 2013
Compensation Committee minutes regarding the Company’s VSIP program.
Please see ICNU_DR_019C Confidential Attachment C for the board presentations titled – Doing It Right,
dated February 8, 2013.

Please see ICNU_DR_019C Confidential Attachment D for excerpts from the September 4, 2013 Compensation Committee minutes regarding cost management.
Please see ICNU_DR_019C Confidential Attachment E for excerpts from the November 7, 2013
Compensation Committee minutes regarding cost management.
Please see ICNU_DR_019C Confidential Attachment F for the retirement plan amendment.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/23/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 020 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide copies of all board minutes and board presentations made to Avista’s board of directors
from December 26, 2012, to the present regarding the Company’s increased capital expenditures, including, but not limited to, major plant investment.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 020C. Please note that
Avista’s response to ICNU – 020C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.
The Company has prepared a Virtual Data Room, as in previous cases, which houses the requested
meeting minutes. Please contact Paul Kimball via email – [e-mail] – to get the
required login and password information.

Please see ICNU_DR_020C Confidential Attachment A for the excerpts from November 13, 2014 board minutes regarding the Company’s increased capital expenditures.

Please see ICNU_DR_020C Confidential Attachment B for the excerpts from November 7, 2013 board
minutes regarding the Company’s increased capital expenditures.
Please see ICNU_DR_020C Confidential Attachment C for excerpts of presentations to Avista’s Board of
Directors regarding the Company’s increased capital expenditures.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 021 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Has the Company performed a cost-of-service study for its largest individual customers (schedule 26)? If yes, please provide any and all such studies for the test year and/or rate effective year.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 021C. Please note that
Avista’s response to ICNU – 021C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

At this time the Company does not have an electric rate Schedule 26. While Commission Staff proposed a new Schedule 26 in WUTC Docket No. UE-140188 to be made up of the largest individual customer
currently served on Schedule 25, the creation of that rate schedule was not agreed to by the parties in that
case.

ICNU_DR_021C Confidential Attachment A (electronic only except for Exhibit Summaries) is the Company’s filed cost of service study restated to show Schedule 25 segregated into two groups, specifically
the largest individual customer (Sch 25I) and all others (Sch 25O).

ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
Electronically Filed

September 2, 2014

Mr. Douglas L. Johnson, P.E. Regional Engineer, D2SI-PRO Federal Energy Regulatory Commission 805 S.W. Broadway, Suite 550 Portland, OR 97205 Subject: Spokane River Project, FERC Project No. 2545 Long Lake Hydroelectric Development Crescent Dam Maintenance and Repair Plan Dear Mr. Johnson: This letter is in response to your letter dated February 22, 2012 requesting a detailed plan and schedule for repairs to the downstream face of the Crescent Dam at the Long Lake Hydroelectric
Development. After reviewing the exploratory investigation conducted in 2010 and evaluating
the alternatives for repairing left side of the Long Lake Crescent Dam, Avista has decided to
implement the following two-phase repair plan.

Phase 1 – Grouting from the Crest

Drill injection holes from the crest and grout injection holes with microfine cement grout
to seal cracks in the dam. This work is scheduled to be completed by December 31,
2014.

Phase 2 – Concrete Repair

When favorable conditions exist to repair the concrete on the left abutment, Avista will
initiate Phase 2 of the project. During Phase 2, the concrete on the left abutment of the
crescent dam will be repaired by removing the deteriorated concrete down to sound
concrete, drilling and filling exposed cracks with grout, adding concrete dowels and
reinforcement, and placing concrete to the original profile as contained in the
construction drawings. This work is scheduled to be completed by December 31, 2015.

Attached, please find the scope of work and technical specifications for Phase 1 of this project,
along with drawings and the Water Quality Protection Plan.
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
Electronically Filed
October 15, 2014
Ms. Kimberly D. Bose, Secretary
Federal Energy Regulatory Commission 888 First Street, N.E.
Washington, DC 20426
Subject: Clark Fork Project, FERC Project No. 2058 Semi-Annual Progress Report on the Designation of Funding for the Operation and Maintenance of the Cabinet Gorge Dam Fishway
Dear Secretary Bose:
Avista herby submits the “Semi-Annual Progress Report on the Designation of Funding for the
Operation and Maintenance of the Cabinet Gorge Dam Fishway, October 15, 2014,” as required by paragraph (C) of the October 16, 2013 Order Modifying and Approving 2012 Annual Report
and 2013 Implementation Plans Per Article 402, Annual Threatened and Endangered Species
Plan Per Article 432, and Annual Fishway Plan Per Article 433. The order required Avista to file a progress report with the Commission every six months summarizing the status of funding operations and maintenance of the planned Cabinet Gorge Dam Fishway, until such time as the
matter is resolved.
The attached semi-annual progress report provides information on progress since April 16, 2014.
All documents referenced in the attached report are available for review upon your request.
While this matter is currently unresolved, significant progress has been made towards resolution as documented in the attached report.
If you have any questions regarding this report, please do not hesitate to contact me.
Sincerely,
Timothy J. Swant
Clark Fork License Manager
[phone]
ICNU_DR_022 Attachment B
Attachment: Semi-Annual Progress Report on the Designation of Funding for the Operation
and Maintenance of the Cabinet Gorge Dam Fishway
c: Clark Fork Management Committee Bruce Howard (Avista)
Keith Brooks (FERC-DHAC)
Heather Campbell (FERC-DHAC) Erich Gaedeke (FERC-PRO)
T.J. LoVullo (FERC-DHAC) Steve Hocking (FERC-DHAC)
Jodi Bush (USFWS)
Cherise Oram (Stoel Rives)
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B
ICNU_DR_022 Attachment B

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 2/23/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Heidi Evans
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 022 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a copy of the most recent Federal Energy Regulatory Commission (“FERC”) licensing application or other FERC filing, including FERC docket number, for each hydro project that is scheduled
to receive upgrades or capital investment pursuant to the Company’s current capital expenditure plan
proposed in this case.

RESPONSE:
Please see ICNU_DR_022 Attachment A, for a summary listing of FERC filings as they relate to the
Company’s current capital expenditure plan.
ICNU_DR_022 Attachment B are the Company’s public filings from Avista to FERC from June 30, 2013
relevant to the list of capital projects provided in the summary document Attachment A. Public FERC filings
made by the Company can also be found at FERC’s website at:
http://www.ferc.gov/docs-filing/ferconline.asp.
Some of the information Avista files with FERC is classified as Critical Energy Infrastructure Information
(CEII) and is referenced in these documents by a cover sheet, as these projects are highly confidential in
nature. In order to retain CEII protection, Avista must restrict access to such data. If necessary, these
documents may be reviewed on-site at the Company’s corporate headquarters upon request.

Page 1 of 3
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 023 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Given that the filed electric pro forma study results is close to the same rate increase as the “attrition
adjustment,” does the Company agree that there is no need for an attrition adjustment in this proceeding? Please answer yes or no, and provide an explanation.
RESPONSE:
No, the Company does not agree. The Attrition studies and the pro forma studies represent two different
approaches or methods to determine the need for a retail rate change for the prospective rate period. The objective of both is to determine the appropriate level of revenue, expenses and rate base for the year that
new retail rates will be in effect. The pro forma “cross-check” analyses provides further confirmation of
the results of the Attrition Studies.

The Company has provided evidence in this proceeding that Avista has been experiencing attrition, and that attrition will be an on-going issue for the foreseeable future. (See Andrews testimony at Exhibit No.
__(EMA-1T).

The Washington Utilities Transportation Commission (UTC) recognized the presence of attrition for
Avista in Order No. 09, Docket Nos. UE-120436 and UG-120437 (Consolidated), page 27, paragraph
70, which stated, “We agree with the Company and Staff that the proposed 2013 rate increase is based significantly on attrition.” Support for, and the presence of, attrition was specifically discussed by UTC
Staff witness Mr. Elgin in Avista’s rate filing, Docket Nos. UE-120436 and UG-120437, at Exhibit No. __T (KLE-1T), page 4, lines 7-13:
Staff believes an attrition analysis is the proper approach in circumstances where a utility
allege[s] it persistently fails to realize a fair return. An attrition study considers all elements
of the ratemaking formula: revenues, expenses, rate base and rate of return in order to judge whether those relationships in the rate year will be materially different than those in the test year. An attrition study also is the proper means to adjust rate year loads for any effects of
conservation programs.

In these same Dockets, Mr. Elgin further explained, starting at page 5 of Exhibit No. __T (KLE-7T), line 13: Staff conducted a detailed attrition study, and concluded Avista in all likelihood will
experience attrition in the 2013 rate year…. In fact, the record evidence is clear that attrition
is likely to prevail for the foreseeable future. Avista will continue to experience significant
increases in its rate base at a time when there is little, if any, growth in revenue. The effect of these circumstances on Avista today and for the next few years will be attrition. In particular, absent a significant reduction in the amount of its capital budget, growth in load
and decrease in operating expense, the most likely scenario for Avista in 2014 will be the

Page 2 of 3
results Avista is presenting today: a need for additional rate relief. The record evidence is
clear on this fact. (emphasis added)

Also in these same Dockets, at Exhibit JT-1T, page 26, Commission Staff provided the following
testimony regarding its own attrition analysis:
First, Staff’s attrition analysis shows Avista is experiencing significant attrition in its utility
operations. This is not a one-time phenomenon, because the historical trends demonstrate
attrition is present and ongoing. (emphasis added) This is understandable, given Avista’s capital expenditures to replace facilities necessary to provide service to Avista customers,
coupled with relatively little if any load growth that will continue in 2013 and 2014, based
on the most recent load forecasts provided to the parties.
In Avista’s more recent rate filing, in Docket Nos. UE-140188 and UG-140189, UTC Staff witness Mr.
Schooley expressed support for the use of an attrition adjustment at Exhibit No. __T (TES-1T) page 4,
line 21- page 5, line 1:
Staff believes an attrition adjustment is a proper tool to use when there is sufficient
evidence that the rate year will be materially different to the test period impacting the utility’s opportunity to earn a fair return.

The use of one or more methods to determine the revenue, expenses and rate base for prospective rate
year is consistent with the principles in the Rate Case and Audit Manual (NARUC Manual), prepared by
the NARUC Staff Subcommittee on Accounting and Finance (Summer 2003). A copy of the NARUC Manual was provided with the Company’s filing as Exhibit No. __(MEA-4). This NARUC Manual
provides an important source of guidance in processing a general rate case filed by a utility. The
following excerpts from the Introduction section (Page 4) of the NARUC Manual provide instruction as to
the purpose of the manual (see also Andrews’ testimony at pages 10-11 of Exhibit No. __(EMA-1T):
This manual has been prepared by the National Association of Regulatory Utility Commissioners (NARUC) Staff Subcommittee on Accounting and Finance as a guideline for state, territory, and
federal regulatory utility commission personnel.1 It is not our intent to provide a checklist for use
by commission auditors, accountants or analysts.2 Rather, it is our intent to set forth the most
common, basic regulatory principles, processes, and procedures used by many regulatory
commissions to examine and investigate general rate applications. We anticipate that each regulatory jurisdiction will have areas of uniqueness and specific areas of differences when it comes
to examining a utility’s revenue requirement and operating earnings. Recognizing that these
differences exist, we have tried to present the basic steps of the rate case investigation in such a way
that revisions and changes can be made by the individual jurisdictions while maintaining the overall usefulness of the more general guidelines. (emphasis added)
An example of a common difference among the jurisdictions is the test year used. Some states use
an average historic test year, others use a year-end historic test year, and others use projected, future
test periods. Yet, this difference does not generally change the nature or importance of the test year,
nor does it change the basic list of elements that are included in the rate base or the operating income statement.

1 The term “Commission” used throughout this document refers to the individual state, territory, or federal regulatory commission that is examining and investigating the general rate application.
2 The term “auditor” used throughout this document refers collectively to auditors, accountants, and analysts.

Page 3 of 3
Excerpts of some of the principles in the NARUC Manual related to the determination of the proper level
of revenue, expenses and rate base for prospective rate year are provided below (see also Andrews’
testimony at pages 11-12 of Exhibit No. __(EMA-1T):
1. Whether using a future or historic test year, the auditor should judge the appropriateness of the test
year that has been proposed. Is it representative, after adjustments, of the period in which rates
take effect? (Page 10) (emphasis added)
2. When looking at an historic test year, one of the first questions asked is whether the test year is too
stale to make it a reasonable basis upon which to establish rates for a future period. In looking at the appropriateness of the test year (and whether it might be too old), one should look at what has
happened since the end of the test year and the current time. (Page 10) (emphasis added)
3. In looking at the months beyond the end of the test year, have the growth rates for rate base,
expenses, and revenues all remained fairly close and constant, maintaining the test year
relationship among these three elements, or has one element changed dramatically, making the test year out of kilter with current operations? If so, can this situation be resolved through adjustments
to the test year? (Page 10) (emphasis added)
4. A utility’s rate filing commonly begins with test year booked numbers, which are then adjusted to
represent anticipated, normalized operations for the period, that the rates will take effect. (See
Revenue Requirement Computation example toward the end of this document.) Several types of adjustments may be included, and these adjustments may be referenced by different names in
different jurisdictions. Commonly, these adjustments will include correcting adjustments (e.g., the
removal of prior period items from the test year), normalizing adjustments (e.g., adjusting
revenues for normalized weather conditions or for a normalized level of expenses), and pro forma
adjustments (e.g., the reflection of authorized salary increases into the test year figures). In general, the pro forma adjustments can be viewed as a ratemaking attempt to transform the
relationship that exists between the elements of cost of service (revenues, expenses, taxes, and
investment) during the test year to one that would take place during the period that the rates
resulting from the rate proceeding take effect. One is trying to identify circumstances during the
test year, or beyond the end of the test year, that impact the on-going expenditures or revenues of the utility. (Page 15) (emphasis added)
5. In reviewing the prudence and reasonableness of the adjustments proposed by the utility, the
auditor should ultimately keep in mind that the ultimate purpose of the review is to determine a
revenue requirement and customer rates that are just, fair, reasonable, and sufficient. (Page 15)
(emphasis added)
6. The auditor should not only review the utility’s proposed adjustments, but should also look for the
adjustments that have not been made. Are there adjustments missing that if made would make the
test year more reflective of normal, on-going operations? (Page 15) (emphasis added)
7. Additionally, one will want to look at a multi-year comparison of annual revenue to obtain a view
of the trend for the utility. Is it growing and if so, is the growth relatively consistent? Is the growth related to new customers or additional usage of existing customers? (The answer to this
question may help explain whether the growth in revenue is consistent or inconsistent with growth
in plant.) Are revenues and expenses growing together? (Page 31) (emphasis added)

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/11/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Karen Schuh/Ryan Finesilver
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 024 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

With reference to Exhibit No. ___ (KKS-5): Please provide all workpapers and analysis used to develop the financial assessment values for each capital project detailed.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 24C. Please note that
Avista’s response to ICNU – 24C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

Per discussion with ICNU’s attorney, the Company has limited the scope of this data request to the following projects as requested by ICNU:

Each business case provided in Company witness Schuh Exhibit No. _ (KKS-5) has five criteria that contribute to an assessment score; the financial assessment, the strategic assessment, business risk
assessment, project or program risk assessment, and finally the mandatory vs. non-mandatory project
assessment. The financial assessment represents the customer, rather than shareholder, internal rate of
return. Greater benefits to customers, which may take the form of reductions in costs or reductions in the
growth of costs, result in a higher score. The financial assessment is just one component of the overall assessment score as well as just one factor used to determine if a business case will be approved by the

Page 2 of 2
Capital Planning Group. After the assessment score has been derived it is then used for the prioritization
discussion along with considerations of availability/utilization of crews, compliance requirements, work
efficiency, safety, and partially funding programs versus an “all or nothing” approach. (Please also see the Company’s responses to ICNU DR’s 067 and 068 for a better description of the capital budgeting
process.)

Please note that due to the voluminous nature of the data, only electronic copies of the attachments are
being provided. Please see the attached information as follows:
Attachment A
Attachment B
Attachment C
Attachment D
Attachment D CONFIDENTIAL
Attachment E
Attachment F
Attachment G
Attachment H
Attachment I
Attachment J
Attachment J CONFIDENTIAL
Attachment K
Attachment K CONFIDENTIAL
Attachment L
Attachment M
Attachment N
Attachment O
Attachment O CONFIDENTIAL

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/23/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark T. Thies
REQUESTER: ICNU RESPONDER: Rich Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 025 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the five-year historical senior secured, unsecured and corporate credit ratings of Avista assigned by Standard & Poor’s (“S&P”), Moody’s and Fitch. Also, please provide Avista’s current S&P
business and financial risk profiles.

RESPONSE:
The corporate credit ratings assigned by S&P, Moody’s (issuer rating), and Fitch for Avista Corp. as of
year-ends 2010 through 2014:

Date Standard and Poor’s Moody’s Fitch1

The senior secured debt ratings assigned by S&P, Moody’s, and Fitch for Avista Corp. as of year-ends 2009 through 2014:
Date Standard and Poor’s Moody’s Fitch1
The rationale for S&P’s 'BBB' rating2 on Avista Corp. is shown in the matrix below, which includes:
• Business risk profile: Strong
• Financial risk profile: Significant
• Outlook: Stable
• Busin
• ess And Financial Risk Matrix

1 As of May 20, 2011, Fitch Ratings affirmed and simultaneously withdrew its ratings for Avista Corp. This withdrawal was based on a business decision by Avista Corp. to discontinue its annual subscription with Fitch.
2 S&P Ratings Direct dated May 9, 2014.

Page 2 of 2
Business and Financial Risk Matrix
Business Risk Profile
Financial Risk Profile
Minimal Modest Intermediate Significant Aggressive Highly leveraged
Excellent aaa/aa+ aa a+/a a- bbb bbb-/bb+
Strong aa/aa- a+/a a-/bbb+ bbb bb+ bb
Satisfactory a/a- bbb+ bbb/bbb- bbb-/bb+ bb b+
Fair bbb/bbb- bbb- bb+ bb bb- b
Weak bb+ bb+ bb bb- b+ b/b-
Vulnerable bb- bb- bb-/b+ b+ b b-

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 2/23/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark T. Thies
REQUESTER: ICNU RESPONDER: Rich Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 026 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide copies of all correspondence, presentations and all other materials that Avista Corporation provided to credit and equity analysts over the last two years.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 026C. Please note that
Avista’s response to ICNU – 026C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

Please see ICNU_DR_026 Attachment A for all officer presentations to the investment community.
Please see ICNU_DR_026C Confidential Attachment A - Rating Agency 2013 Update
Please see ICNU_DR_026C Confidential Attachment B - June 2013 Forecast
Please see ICNU_DR_026C Confidential Attachment C - June 2013 Forecast Assumptions
Please see ICNU_DR_026C Confidential Attachment D - Rating Agency 2014 Update Please see ICNU_DR_026C Confidential Attachment E - July 2014 Forecast Booklet

Due to the voluminous nature of the attachments, they are being provided in electronic format only.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/23/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 027 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

On an electronic spreadsheet with all formulae intact, please provide the five-year projected and five-year historical capital structure, capital expenditures and capital funding.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 027C. Please note that
Avista’s response to ICNU – 027C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

Please see ICNU_DR_027C Confidential Attachment.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/23/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 028 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please state whether Avista Corporation has any off-balance sheet debt, such as purchased power agreements and operating leases. If in the affirmative, provide the amount of each off-balance sheet debt
item and estimate the related imputed interest and amortization expense associated with these off-balance
sheet debt equivalents.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 028C. Please note that
Avista’s response to ICNU – 028C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: WASHINGTON DATE PREPARED: 02/23/2015 CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 028 TELEPHONE: [phone]
EMAIL: [e-mail] REQUEST:

Please state whether Avista Corporation has any off-balance sheet debt, such as purchased power
agreements and operating leases. If in the affirmative, provide the amount of each off-balance sheet debt item and estimate the related imputed interest and amortization expense associated with these off-balance sheet debt equivalents.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 028C. Please note that
Avista’s response to ICNU – 028C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/20/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 029 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

On an electronic spreadsheet with formulae intact, please provide Avista’s Washington jurisdictional actual return on equity; actual capital structure; authorized return on equity; and authorized capital
structure for the years 2001 through 2014 and detailing both electric and natural gas operations on a
jurisdictional basis. If 2014 is not yet available, please provide it once it becomes available.

RESPONSE:
Please see ICNU_DR_029-Attachment A.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/03/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies/Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 030 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to Dockets UE-120436 et al., Order 09/14 at ¶ 78, and Dockets UE-110876 and UG-10877,
Order 06 at ¶¶ 42-44. Please provide a narrative response explaining the Company’s policy and/or position on managing costs and reducing expenses in relation to executive benefits and compensation.
RESPONSE:
In Dockets UE-120436 et al., Order 09/14 at ¶ 78, and Dockets UE-110876 and UG-10877, Order 06 at
¶¶ 42-44 the Commission ordered the Company to file a report including a description of current executive compensation and a description of how levels of compensation are set and a discussion as to the
appropriateness of executive compensation. In accordance with the requirements in UE-110876 and UG-
10877, on February 28, 2012 the Company filed with the UTC this report titled “Review of Executive
Compensation”.
Please see the Company’s response to ICNU_DR_032 which contains a description of the process for
determining levels of base salaries and performance-based awards programs (direct compensation) for our
executive officers. The Company believes this process is an effective method to monitor and manage the
costs associated with executive direct compensation (base salaries, short term incentive and long term
incentive)1. See also Avista’s response to ICNU_DR_033 for a narrative on the appropriateness of these costs.

In addition, similar to the process used to determine direct compensation, our total benefit value is
compared to our peers in the market. These benefits apply to all our employees, including executive
officers. Benchmarking total benefit value is the industry standard and is considered best practice due to the significant variation in plans between companies depending on company culture, philosophy and
recruitment/retention needs. Comparing total value and benchmarking to the 50th percentile in the market,
provides the Company with the flexibility to adjust individual components up or down within the package
in order to stay competitive within the market.
Approximately every two years, Avista participates in a comprehensive benefit study, BENEVAL,
conducted by Towers Watson which compares the total value of our benefit package to the total benefit
value of our peers. This study is comparable to the peer group benchmarking conducted annually for
direct compensation.
As a result of the 2013 benefit plan review, the following changes were made which will results in long term reduction in expenses:
1 Please also see the Company’s response to ICNU_DR_031 which contains a description of each element of compensation and
how much is included in rates, and ICNU_DR_033 for a narrative of the appropriateness of the amount of executive compensation included in rates (Dockets UE-120436 and UG-120437).

Page 2 of 2

• The defined benefit pension plan was revised such that as of January 1, 2014, the plan will be closed to all non-union employees hired or rehired by Avista on or after January 1, 2014. All actively employed non-union employees that were hired prior to January 1, 2014, are currently
covered under the defined benefit pension plan, will continue accruing benefits as originally
specified in the plan. A defined contribution 401(k) plan will replace the defined benefit pension
plan for all non-union employees hired or rehired on or after January 1, 2014. Under the defined contribution plan the Company will provide a non-elective contribution as a percentage of each employee’s pay based on his or her age. This defined contribution is in addition to the existing
401(k) contribution in which we match a portion of the pay deferred by each participant.

• Revisions were made to the lump sum calculation effective January 1, 2014, for non-union participants who retire under the defined pension plan. The lump sum amount is equivalent to the
present value of the annuity based upon applicable discount rates.

• The health care benefit plan was also revised for non-union employees hired or rehired on or after January 1, 2014. Upon retirement, the Company will no longer provide a contribution toward the
medical premiums for these employees. We will provide access to the retiree medical plan, but
the non-union employees hired or rehired on or after January 1, 2014 will pay the full cost of
premiums upon retirement.

• Also beginning in January 1, 2020 the method of calculating health insurance premiums for non-
union retirees under age 65 and active Company employees will be revised. The revisions will
result in separate health insurance premium calculations for each group.
The Company’s process for determining executive pay and benefits effectively manages the costs
associated with total executive compensation while meeting the Company’s goal of recruiting and
retaining the executive officers needed to efficiently manage the Company.

EXECUTIVE OFFICER
INCENTIVE PLAN FOR 2014

PLAN PROVISIONS
Approved by Board February 2014
Purpose: The Executive Officer Incentive Plan (Plan) is designed to align the interests
of senior management with both shareholder and customer interests to achieve overall
positive financial and operational performance for the Company.

Plan Year: January 1, 2014 – December 31, 2014

Eligibility:
 All executive officers hired prior to October 1st and actively employed on December 31st of the plan year, are eligible to participate
 Subsidiary officers are not eligible to participate
 Other details available in section Exceptions to Eligibility and Circumstances for
Proration

Performance Measurements: The Executive Officer Incentive Plan focuses on
shareholders by providing value through sound financial performance and on customers
by controlling costs through driving efficiencies while paying close attention to our customers’ voices regarding the products and services we provide. The Plan incorporates Earnings per Share (EPS) and Operating & Maintenance Cost per
Customer (O&M CPC) as financial performance measurements plus three non-financial
measurements: Customer Satisfaction Rating (Customer Satisfaction), Reliability Index
(Reliability), and Dispatched Gas Emergency Response Time (Response Time). These performance metrics help increase shareholder value, gain financial strength and maintain safe and reliable cost-effective service levels essential for our customers and
for the long-term success of the Company, and, with the exception of the earnings per
share goals, are identical to performance goals used in the Company’s annual cash
incentive plan for non-executive employees. The Compensation Committee believes that having similar metrics for both the executive plan and the non-executive plan encourages employees at all levels of the Company to focus on common objectives.

Utility and Non-Utility Diluted EPS - These metrics reflect the financial strength and
alignment of interests between officers and shareholders. Non-Utility EPS includes Ecova and other non-utility businesses within the corporation.

ICNU_DR_031 Attachment A Page 1 of 10

5/9/2014
O&M CPC - The O&M CPC is a measure that focuses on controlling costs and driving
efficiencies in order to keep our costs reasonable for our customers. The metric is
based on targeted O&M expense and number of customers. These components are combined to create the O&M CPC metric.
Customer Satisfaction - This measure is derived from a Voice of the Customer survey,
which is conducted each quarter by an independent agency. The rating measures
the customer’s overall satisfaction with the service they received during a recent contact with the Company’s contact center and/or service center.
Reliability - This measure tracks how quickly the Company restores outages, how
frequently customers are affected by outages and what percent of customers experience more than three sustained outages per year. The Company combined three common industry indices in order to balance our focus.

Response Time - The Response Time metric measures the percentage of time the
Company responds within targeted time goals for dispatched natural gas emergency calls. The primary objective is customer and public safety while consistently treating customers the same throughout our service territory.

Award Opportunity: The Plan has six independent metrics, each having their own goal to achieve. The Plan is sliced into pieces
– like a pie. The EPS component makes up 60
percent (Utility 50% and Non-Utility 10%) of
the total incentive award while O&M CPC is 20 percent, customer satisfaction and reliability are each at 8 percent, and response time at 4
percent.

Non-financial metrics: The non-financial pieces of the award (customer satisfaction, reliability, and response time) are all-or-
nothing goals. If the Company meets or exceeds the target goal for any one of the
metrics, employees receive 100% of the incentive award percentage allotted to the
metric. If the Company fails to meet a goal, employees do not receive any award for the metric. For example, if the Company achieves Customer Satisfaction with a 90% or better rating, employees would receive 8% of their total incentive award
opportunity. If the Company achieves 88% which is below the target, employees
would receive no award under this metric. This works the same way for each non-
financial measurement. Maximum payout for Response Time is 4% of the total incentive award opportunity and 8% for Reliability and Customer Satisfaction, respectively.

Financial metrics: The Utility and Non-Utility EPS and O&M CPC metrics work a little differently due to the various performance levels that can be met. Depending on the
ICNU_DR_031 Attachment A Page 2 of 10

5/9/2014
Company’s level of performance for a metric, employees may earn more or less than
100% of the award percentage allocated to each financial metric (50% for Utility
EPS, 10% Non-Utility EPS, and 20% O&M CPC). Using a sliding scale, increasing levels of performance are established between threshold and maximum.
For each metric the Company must achieve the minimum level of performance
(threshold) in order to receive at least 50% of the allotted award percentage. For an
employee to receive 100% of the allocation, the Company must achieve the level of performance selected for target. If the Company exceeds the target performance
level, employees may earn up to a maximum of 167.00% of the allocation for Utility
EPS and Non-Utility EPS and 150% for O&M CPC. In previous plans the maximum
payout under the Utility and Non-Utility EPS metric was 150% which limited the Plans’ overall payout opportunity to 140%. To maintain market competitiveness, the maximum payout for each Utility and Non-Utility EPS metric was adjusted to
167.00% to allow the overall Plan to pay up to 150%. Performance below threshold
will result in no award payment for the metric. For example, if the Company achieves
an O&M CPC amount of $379.65 resulting in a performance level of 63.18% which is above threshold, employees would receive 12.64% (20% multiplied by 63.18% = 12.636%) rather than 20% of their total incentive award. If the Company achieves
$374.69 which exceeds target performance, employees would receive approximately
25.20% (20% multiplied by 126.01% = 25.202%) rather than 20% of their total award opportunity. If the Company achieves an amount below threshold such as $382.23, employees would receive no award related to the O&M CPC metric. This works the
same way for each financial metric.

The maximum payout an employee may earn under the Utility EPS portion of their total incentive award is 83.50% (50% multiplied by 167.00% = 83.50%), Non-Utility EPS is 16.70% (10% multiplied by 167.00% = 16.70%), and O&M CPC is 30.00%
(20% multiplied by 150% = 30.00%).

Incentive Targets for 2014:
Utility EPS Non-Utility EPS
O&M Cost per
Customer
Customer Satisfaction Reliability Index Response Time
% of Total
Opportunity 50% 10% 20% 8% 8% 4%
Sliding Scale Meet/Not Meeting Goals
Minimum 50% $1.68 $0.09 $380.18
Target 100% $1.75 $0.12 $378.17 90% 1.00 93%
Maximum 167% $1.82 $0.15
Maximum 150% $371.48

Establish Targets: The Compensation and Organization Committee of the Board
(Committee) in conjunction with management reviews and reestablishes the targets for
ICNU_DR_031 Attachment A Page 3 of 10

5/9/2014
each measurement on an annual basis. The computations for this Plan are described
below:

Utility EPS and Non-Utility EPS: To determine the Utility and Non-Utility EPS goals for
the plan, the Committee, in conjunction with the Finance Committee of the Board
and management, considers and incorporates the EPS target range contained in the
Company’s original publicly disclosed earnings guidance and reviews this in light of
the budgeted EPS numbers. The earnings guidance for the Utility EPS excludes the earnings impact associated with changes in the Energy Recovery Mechanism
(ERM). The target in the Plan is Diluted Earnings per Share and is prior to executive
incentive payout/accrual-pro-forma and net of taxes. The actual Utility EPS results
will be affected by positive or negative changes in the ERM when computing the plan payout. Occasionally, adjustments to actual results may be deemed necessary. An example of such an adjustment was in 2008 when the positive effect of an
accounting error related to Allowance for Funds Used during Construction (AFUDC)
was excluded from EPS.
The 2014 guidance for EPS is $1.68 to $1.82 for the Utility and $0.09 to $0.15 for Non-Utility (Ecova and Other combined). The projected ERM benefit is $0.05, which
is excluded for guidance and budget purposes.
For Utility EPS, the Company used the low end of guidance to set the threshold level, the midpoint of guidance to set target and the top of guidance for the
maximum level. In this Plan, threshold is $1.68, target is $1.75 and maximum is
$1.82.
For Non-Utility EPS, the Company used the low end of guidance to set the threshold level, the midpoint of guidance to set target and the top of guidance for the
maximum level. In this Plan, threshold is $0.09, target is $0.12 and maximum is
$0.15.
Since the portion of the incentive related to EPS indirectly benefits the customer it is
charged below the line to account 417.

O&M CPC: For this measurement the Company uses the total budget for O&M expense (numerator) plus customer growth (denominator).
Numerator: The numerator of the formula is derived from the Company’s total
budget for O&M expense. Certain items are excluded from the total O&M budget
such as Account Receivable Sales, Pacesetters, and certain accounting adjustments. For each performance level, the Company estimates the potential payout for the incentive which includes payroll taxes and subtracts the result from
the total O&M budget. The estimation is based on budgeted labor costs,
employee job levels and the corresponding individual target award opportunities.
ICNU_DR_031 Attachment A Page 4 of 10

5/9/2014
Using the sliding scale concept and to establish the performance levels between
threshold and target, the Company assumes a 1:1 ratio between total O&M
budget (blue line) and O&M net of the estimated incentive payout (red line). Performance levels between target and maximum assumes a 2:1 ratio between total O&M budget and O&M net of incentive payout. Achieving maximum payout
would result in an additional pre-tax expense of $2.38M plus an additional
$2.38M in savings. Therefore $4.76M in combined savings is required to achieve
the maximum payout. The red line in the chart below illustrates the concept.

Denominator: The target uses a customer growth factor of 6,228, which is consistent
with the factor used in the budget and is slightly higher than recent historical growth. Variability in the final customer count will impact the amount of O&M savings necessary to achieve an incentive payment. For example, missing the
growth target by 1,000 customers would require an additional savings of $378K
to achieve the target level payout.
In this Plan, threshold is $380.18, target is $378.17 and maximum is $371.48. See the chart above for illustration.

Customer Satisfaction: For this measure, the Company uses the ratings from question Q3 from the Voice of the Customer survey which measures the customer’s Overall
Satisfaction with the service they received in a recent contact through the Avista
contact center and/or service center. The Overall Satisfaction question from surveys
such as this is widely used in the industry for external reporting purposes. Rather
than using the standard “satisfied” rating, which is typically used in the industry, the Company uses the average of the combined “satisfied” and “very satisfied” ratings.
By combining these two ratings the target is more difficult to achieve so more
emphasis is placed on serving the customer. In this Plan, the target is set at 90%
very satisfied/satisfied for the customer’s Overall Satisfaction rating.

Reliability: This index combines Customer Average Interruption Duration Index (CAIDI),
System Average Interruption Frequency Index (SAIFI) and Customer Experiencing
Multiple Interruptions (CEMI3). CEMI3 measures the percentage of customers that experience more than three sustained outages in the year. The Company chose this level of outages over others because industry data received from JD Power’s
ICNU_DR_031 Attachment A Page 5 of 10

5/9/2014
customer service surveys indicate that customers are more apt to be dissatisfied
after three outages. Providing safe and reliable energy to our customers is the
backbone of our business, therefore, it makes good sense to focus on service levels for our customers. By focusing on these measurements it enables the Company to direct our resources appropriately and efficiently in order to contain costs and plan
for future infrastructure upgrades that will benefit the customer.

To determine the target for the Reliability portion of the Plan, the Company sets a separate target for each metric, weighs them equally and combines them into one
metric (see the formula below). In this Plan the target is set at 1.00.

Index = CAIDI Target / CAIDI Actual + SAIFI Target / SAIFI Actual + CEMI3 Target / CEMI3 Actual
3 3 3 The formula used to set the target for each metric is described below:
 Customer Average Interruption Duration Index (CAIDI): outage duration
multiplied by the number of customers affected for all sustained outages (> 5
minutes), divided by the number of customers which had sustained outages. Per industry practice larger outages that impact a significant portion of the service territory, and typically last more than 24 hours are excluded from this metric. In
this Plan the Company uses a 5 year average with a standard deviation of 0.72
(76% probability) to set the target which is 2 hours and 7 minutes restoration
time.
 System Average Interruption Frequency Index (SAIFI): the number of customers
which had sustained outages (> 5 minutes), divided by the number of customers
served. Per industry practice larger outages that impact a significant portion of
the service territory, and typically last more than 24 hours are excluded from this metric. In this Plan the Company uses a 5 year average and a standard deviation
of 0.72 (76% probability) to set the target which is 1.34 outages per customer.
 Customers Experiencing Multiple Sustained Interruptions more than 3 (CEMI3):
the total number of customers that experience more than 3 sustained outages
per year, divided by total number of customers served. Per industry practice
large outages are not excluded from this metric. In this Plan the Company uses a
5 year average with a standard deviation of 0.72 (76% probability) to set the target at 10.5% of our customers.
Response Time: This metric represents the percent of time the Company responds
within targeted goals for natural gas emergency calls. The Company tracks the time
between the receipt of the call to the time our crew or serviceman arrives on-site, assesses the situation and reports back to dispatch. The Company sets separate
response goals for each type of emergency call: 60 minutes for priority 1 calls
(blowing gas, explosions and/or fires, etc.) and 120 minutes for priority 2 calls (inside
or outside odors, runaway furnaces, etc.). The Company wants crews and/or serviceman to respond within the targeted response time goal for each type of call. In this Plan the Company set the target at 93% of the time.
ICNU_DR_031 Attachment A Page 6 of 10

5/9/2014

Individual Target Award Opportunities: During the February Board meeting, the
Committee and the Chief Executive Officer (CEO) jointly review and approve the individual target award opportunities for the participants of the Plan. Each eligible employee has an incentive target award opportunity expressed as a percentage of their
base salary. Target opportunities range from 40% to 90% of base salary and are
assigned based on position. Actual award payments are calculated based on the
employee’s target award opportunity in effect as of December 31st and year-end regular earnings (pensionable earnings) unless otherwise noted in the Plan document (see
provisions under Exceptions to Eligibility and Circumstances for Proration section).

Individual Target Award Opportunities for 2014:
Individual Target Award Opportunity
% of Base Pay by Position Type
CEO Senior VP VP
90% 60% 40%
Incentive amounts in excess of 100% (up to 150%) of an individual’s target opportunity may be paid in the form of non-cash equivalents, at the discretion and approval of the
CEO and the Committee.

Example Award Calculation:
The Company achieved the targets indicated below: 1) Utility EPS = 167.00% on the sliding scale 2) Non-Utility EPS = 86.67% on the sliding scale
3) Cost per Customer = 138.86% on the sliding scale 4) Customer Satisfaction = 100% = met/pass 5) Reliability = 100% = met/pass
6) Response Time = 0% = fail to meet

Non-CEO Average Earnings = $287,064 Average Target Opportunity = 47% = $134,920
Goal Opportunity Weighting Pct Results Amount
Utility EPS $134,920 x 50% x 167.00% = $112,658
Non-Utility EPS $134,920 x 10% x 86.67% = $11,694
Cost per Customer $134,920 x 20% x 138.86% = $37,470
Customer Satisfaction $134,920 x 8% x 100% = $10,794
Reliability $134,920 x 8% x 100% = $10,794
Response Time $134,920 x 4% x 0% = $0
Total Payout = $183,410

Distribution of Awards: Incentive awards, if earned, will be distributed after the
February meeting of the Board of Directors of the next Plan year. In most instances actual amounts will be calculated using the participant’s regular year-end earnings (pensionable earnings), individual target award opportunity and employment status in
ICNU_DR_031 Attachment A Page 7 of 10

5/9/2014
effect as of December 31st of the Plan year. See the section Exceptions to Eligibility and
Circumstances for Proration for exceptions.
In order to communicate and calculate payout amounts consistently for the financial based metrics, the Company will round results to the nearest 100th percent based on
accounting rules. For example, if the O&M CPC result is 77.62% or 77.623%, the
Company will communicate the results using 77.62%. In order to calculate the final
payment, the Company will take the O&M portion of the award of 20% and multiply it by 77.62% which is 15.524% and round it to15.52%. Based on this example, an employee
would receive 15.52% of the O&M CPC portion of their award.

The non-financial metrics will be communicated and calculated differently. In order to communicate the results for each non-financial metric, the Company will round results to the nearest whole number or, in the case of reliability, out two decimal points based
on accounting rules. For example, customer satisfaction would be rounded to 93% from
92.8% and reliability would be 1.23 from 1.232. Unlike the financial metrics where the
final results can affect the payout up or down depending on performance level achieved, the final results for the non-financial metrics cannot vary up or down depending on performance. Payouts are either 100% for achieving the target or 0% for not achieving
it. For example, if the Company achieves 93% under the Customer Satisfaction metric,
employees would receive 8% (8% multiplied by 100% = 8%), not 93% of 8%. If the Company achieves 88%, employees would receive no award (8% multiplied by 0% = 0%) under this metric. See example award calculation section above for more details.

All incentive awards earned by a participant under this Plan are subject to the
Recoupment Policy adopted by the Company’s Board of Directors as amended from time to time (“Recoupment Policy”). If a participant becomes subject to the Recoupment Policy any award may be forfeited in whole or in part and all or part of any distribution
payable to a participant or his or her beneficiary under this Plan may be recovered by
the Company pursuant to the Recoupment Policy.

Administration of Plan: The Committee is responsible for administering the Plan and
may delegate specific administrative tasks to corporate staff, as appropriate.

The Committee has the authority to:
 Terminate, amend or modify this Plan in whole or in part for any reason at
any time without prior notice to participants
 Modify or adjust financial targets due to extraordinary occurrences and/or significant reorganizations
 Grant discretionary awards up to 15% of the individual target award
opportunity Participation in this Plan should in no way be construed as a contract or promise of
employment and/or compensation.

ICNU_DR_031 Attachment A Page 8 of 10

5/9/2014

Sun Mon Tue Wed Thu Fri Sat 28 29 30 1 2 3 4
5 6
employee 1 starts work
7 8 9 10 11
12 13 14 15 16 17
employee 2
starts work
18
19 20
employee 3
starts work
21 22 23 24
Start count for employee
1 and 2
25
26 27 28 29 30 31 1
2 3 4 5 6 7
Start count
for employee 3
8

May 2013
Exceptions to Eligibility and Circumstances for Proration:

Pay Periods: There are 26 pay periods and pay dates during the Plan year. A pay
period (pp) is made up of two pay weeks. Each pay week typically starts 12:00am
Monday and ends 11:59pm Sunday. Employees are paid on the pay date, typically
on the following Friday, after the end of the pay period. The first pay period is 12/16
– 12/29/2013 and paid on pay date 1/3/2014. Changes effective during this pay
period will count towards the 2014 plan since the earnings and pay date are part of
2014. Changes effective during the 12/15 – 12/28/2014 pay period are not included
in the 2014 Plan because the earnings and pay date are part of 2015.

Pay Period Schedule for2014:
Pay Period Pay Date Pay Period Pay Date Pay Period Pay Date
12/16 – 12/29/2013 1/3 4/21 – 5/4 5/9 8/25 – 9/7 9/12
12/30/2013 – 1/12 1/17 5/5 – 5/18 5/23 9/8 – 9/21 9/26
1/13 – 1/26 1/31 5/19 – 6/1 6/6 9/22 – 10/5 10/10
1/27 – 2/9 2/14 6/2 – 6/15 6/20 10/6 – 10/19 10/24
2/10 – 2/23 2/28 6/16 – 6/29 7/3 10/20 – 11/2 11/7
2/24 – 3/9 3/14 6/30 – 7/13 7/18 11/3 – 11/16 11/21
3/10 – 3/23 3/28 7/14 – 7/27 8/1 11/17 – 11/30 12/5
3/24 – 4/6 4/11 7/28 – 8/10 8/15 12/1 – 12/14 12/19
4/7 – 4/20 4/25 8/11 – 8/24 8/29

Proration: Proration is determined by the change of status (COS) date and the pay period (pp) in which the change falls. No matter if the COS date occurs on the first day or the last day of the pay
period, the employee receives
credit for the full pay period.
The pay date associated with the pay period is counted for
prorating purposes. For
example, employee #1 is hired
on 5/10 and employee #2 is hired on 5/17 and both remain employed throughout the Plan
year, each receives credit for
16 pay dates toward their
award. Employee #3 is hired on 5/20 which falls into the next
pay period and pay date.
Therefore he/she receives credit for 15 pay dates toward the award.

Regular Earnings: Regular earnings (pensionable earnings) will be used in calculating the final awards for employees. The earnings to be used in the calculation are as
follows: earnings designated regular, alternative/dual, One Leave (used, sick, &
ICNU_DR_031 Attachment A Page 9 of 10

5/9/2014
FMLA), short-term disability (100% and 60%), workers compensation, holiday, jury
duty, and military pay.

New Hires: Employees hired on or after October 1st will not be eligible for an award under this Plan. Awards will be calculated based on the provisions detailed above.

Leave of Absence: Eligible employees on approved unpaid leave of absence must
have at least 6 full pay periods of active service during the Plan year to receive an award. Awards will be calculated based on the provisions detailed above. Short-
term disability leave does not affect an eligible employee’s award and is excluded
from this provision.

Resignation/Termination: Any employee who resigns or is terminated for reasons other than retirement, disability or death prior to December 31st will not be eligible to
receive an award under this Plan. Those eligible employees who terminate after the
Plan year may receive an award at the time of distribution.

Death, Long-term Disability & Retirement: In the case of death, total disability (as defined under the Company’s Long-term Disability Plan) or retirement (as defined
under the Retirement Plan for Employees), an eligible employee or estate must have
at least 6 pay periods of active service within the Plan year to be eligible to receive an award. Awards will be calculated based on the provisions detailed above.
Discipline or Poor Performance: Employees who receive a fails to meet
performance rating for the Plan year or a Last Chance Agreement under the
Company’s formal discipline program and effective as of December 31st are not eligible to receive an award under this Plan.
Transfers from Subsidiaries to Corp/Utilities: Eligible employees who transfer from
a subsidiary will be treated as a new hire to the Company and all Plan criteria apply
as is. Prorated awards are at the discretion of the Committee and CEO.
Other Company Short-term Incentive Plans: Employees can only participate under
one formal incentive plan a year. If the employee becomes eligible for a different
plan during the year, the Committee and CEO has full discretion to determine which plan the employee may receive an award under. Status and/or time in position may be factors considered in determining whether the employee receives a prorated
award from both plans or an award based on the employee’s position and/or status
as of December 31st.

ICNU_DR_031 Attachment A Page 10 of 10

Page 1 of 3
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/05/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies/Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 031 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide a description of current executive compensation, including but not limited to base salary,
non-equity incentive pay, and incentive pay, and stating what elements and amounts are included in rates for the Company and what elements and amounts are not recovered through rates.

RESPONSE: Please see the Company’s response to ICNU_DR_032 for a description of how levels of executive
compensation are set, ICNU_DR_030 for a description for the Company’s policy on managing costs and
reducing expenses in relation to benefits and compensation, and ICNU_DR_033 for a narrative on the
appropriateness of these costs.
Executive Compensation is a combination of base pay, short term incentive compensation, and long term
incentive compensation. The table below summarizes each component in total and by amounts included in
the pro-forma cross check studies:

Executive Compensation
Utility System
Total*
WA - Elect WA - Gas Total WA
Base Salary 1,683,398$ 501,226$ 2,184,624$ 3,503,364$
Short Term Incentive Plan 168,454$ 49,958$ 218,412$ 349,150$
Long Term Incentive Plan 238,529$ 70,758$ 309,287$ 494,517$
Total 2,090,381$ 621,942$ 2,712,323$ 4,347,031$
*excludes amounts charged to non-utility
Per WA Pro-Forma Cross Check Study
Base Salaries Base salaries are provided to compensate executives for services rendered during the year. As noted in
the Company’s response to ICNU_DR_032, factors such as responsibilities and job complexity,
experience and breadth of knowledge and competitive pay among executives in the utilities and
diversified energy industry are considered when setting base pay. Executive base pay is allocated between utility and non-utility operations based on a survey conducted in
December 2014 that asked each officer to estimate the percentage of their time which will be spent on
non-utility operations. Each officer considers a number of factors when developing their individual
allocation percentage. Current and past job responsibilities, anticipated changes due to projects specific to the upcoming year(s), anticipated responsibility changes and/or overall upcoming strategic initiatives and

Page 2 of 3
associated roles are all taken into consideration when developing these allocations. Throughout the year,
these allocations are reviewed and updates are made in the timekeeping system for any material changes.
The total amount allocated to utility operations in this case is approximately 89%. Please see Smith workpapers 3.03-03 Executive Labor for allocation amounts for each executive.

Approximately $2.2M of total executive base pay is included in the Company’s pro-forma cross check
study. Approximately $452,000 is allocated to non-utility with costs borne by shareholders.
Short Term Incentive Plan (STIP)1
As noted in the Company’s response to ICNU_DR_032, the STIP is designed to align the interest of
executives with both customer and shareholder interests in order to achieve overall positive financial
performance for the Company. The STIP is a pay-at-risk plan whereby employees are eligible to receive
cash incentive pay if the stated targets are achieved.
The STIP has four operational components, plus two EPS components. The total amount associated with
utility operational components is 40% and is broken down as follows: 20% O&M Cost-Per-Customer, 8%
Customer Satisfaction, 8% Reliability, and 4% Response Time. The EPS components account for 60% of
the total opportunity and are broken out into 50% utility EPS and 10% non-utility EPS. Only the operational components (40%) are proposed to be included in rates. They reflect measures that are
designed to drive cost-control, and delivery of safe, reliable service with a high level of customer
satisfaction. The remaining 60% relate to EPS targets are borne by shareholders. Please see
ICNU_DR_031 Attachment A for the 2014 Executive Officer Short Term Incentive Plan document.
The amount of incentive included in the Company’s pro-forma cross check studies is approximately
$218,000 based on a 6 year average payout for O & M and operational targets.

Executive Officer Long Term Incentive Plan (LTIP)
The LTIP is made up of two components: restricted stock for 25% of the award and performance shares
accounting for 75% of the award2.

The Restricted Stock portion (25%) of the LTIP is proposed to be included in rates in this filing.
Restricted Stock is designed to provide an incentive for employees to remain employed by the Company and is therefore, appropriate to be included in rates. The long-term nature of large scale transmission and
distribution projects spanning multiple years are completed more efficiently with experienced, consistent
leadership. In addition, it is the Company’s policy to promote from within when possible, preserving the
values inherent in our culture such as customer satisfaction, reliability of service etc. Employees with a long tenure of employment with the Company are well versed in the Company’s culture and will continue to cultivate the values we have built our Company on. The amount of the Executive Officer LTIP
included in the Company’s pro-forma cross check studies is approximately $309,000 of total system
restricted stock.
The Performance Share (75%) portion of the LTIP, which is directly related to total shareholder return, has been excluded from this filing. The Company rewards performance shares to provide a direct link to
the long-term interests of customers and shareholders by assuring that shares will be paid only if the
1 Total Officer Short Term Incentive expensed for the 12 months ending September 30, 2014 is approximately $3.1 million.
Approximately 71% ($2.2 million) is allocated to non-utility operations. 2 Total CEO Long Term Incentive Plan (Performance Shares and Restricted Stock) has been excluded because both the
restricted stock and performance shares have financial performance-related triggers.

Page 3 of 3
Company attains a specific performance level of Total Shareholder Return (TSR) relative to our peers (as
reported in the S&P 400 Utilities Index). The amount of executive officer long term incentive
compensation charged to non-utility operations related to performance shares is approximately $1,941,395.

Other Benefits
In order to attract and retain executive officers and stay competitive within our peer group of companies,
additional benefits are offered to executive officers over and above those provided to employees. These benefits are as follows:

1. Supplemental Executive Officer Retirement Plan (SERP):
In addition to the Company’s retirement plan for all employees, the Company provides additional pension benefits through the SERP to executive officers of the Company who have attained the age of 55 and a minimum of 15 years of credited service with the Company. For employees who
become executive officers after February 3, 2011, the SERP benefit only restores the benefit
which would otherwise be payable from the retirement plan due to the limitations under IRS
Sections 401(a)(17) and 415. The costs associated with SERP are excluded from retail rates. 2. Deferred Compensation:
The Executive Officer Deferred Compensation plan provides the opportunity to defer up to 75%
of base salary and up to 100% of cash bonuses for payment at a future date. This plan is
competitive in the market, and provides eligible employees and executive officers with a tax-efficient savings method. The costs associated with Deferred Compensation are excluded from
retail rates.

3. Perquisites:
Because the total compensation program for executive officers is fair and market competitive, the Company does not provide any additional benefits in the form of perquisites to the CEO or any
other officer.

Finally, executive officers participate in the Company’s Pension Plan, 401(k) plan, and health/dental
insurance plans. All direct compensation and benefits are considered as part of the Company’s overall compensation plan.

ˆ200GZcqP7Jj15&D7fŠ
200GZcqP7Jj15&D7f
836681 OFC 1AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:25 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 5*
PMT 1C
SWRP64RS14
11.6.14
g17n77-1.0
Notice of May 7, 2015
Annual Meeting of Shareholders
and 2015 Proxy Statement
ICNU_DR_032 Attachment A Page 1 of 90
ˆ200GZcqP7Jj1D5u7mŠ
200GZcqP7Jj1D5u7m
836681 OFC 2AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:25 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS14
11.6.14
Important Voting Information
Brokerage firms, banks and other nominees generally have the authority to vote their customers’ shares
when their customers do not provide voting instructions. However, with respect to certain specified matters,
when such an entity does not receive instructions from its customers, shares cannot be voted on those
matters. This is called a “broker non-vote.” Matters on which organizations that are members of the New
York Stock Exchange (the “NYSE”) may not vote without instructions include the election of directors,
matters relating to executive compensation and matters relating to certain corporate governance issues. For
Avista Corporation, this means that NYSE member organizations may not vote shares on Proposals 1, 2, 4
and 5 if you have not given instructions on how to vote. Please be sure to give specific voting instructions so
that your shares can be voted.
Your Participation in Voting the Shares You Own is Important
Your vote is important. Whether or not you plan to attend the 2015 Annual Meeting of Shareholders in
person, we urge you to vote and submit your proxy by mail, telephone, or through the Internet as promptly
as possible. If you are submitting your proxy by mail, you should complete, sign, and date your proxy card,
and return it in the envelope provided. If you plan to vote by telephone or through the Internet, voting
instructions are printed on your proxy card and/or proxy notice. If you hold your shares through an account
with a brokerage firm, bank, or other nominee, please follow the instructions you receive from them to vote
your shares.
More Information is available
If you have any questions about the proxy voting process, please contact the broker, bank or other financial
institution where you hold your shares. The Securities and Exchange Commission (the “SEC”) also has a
website (www.sec.gov/spotlight/proxymatters.shtml) with more information about your rights as a
shareholder. Additionally, you may contact our Investor Relations Department at [phone].
ICNU_DR_032 Attachment A Page 2 of 90
ˆ200GZcqP7Jj11VG7.Š
200GZcqP7Jj11VG7.
836681 LTR 1AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:24 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 5*
PMT 1C
SWRP64RS04
11.6.14
g12w06-1.0
g84u55-1.0
Prompt execution of the enclosed proxy will save the expense of an additional mailing.
Your immediate attention is appreciated.
March 27, 2015
Dear Fellow Shareholder:
On behalf of the Board of Directors (the “Board”), it’s my pleasure to invite you to the Avista Corporation
(“Avista” or the “Company”) 2015 Annual Meeting of Shareholders (the “Annual Meeting”). The doors open at
7:30 a.m. and the Annual Meeting will begin promptly at 8:15 a.m.
Date: Thursday, May 7, 2015 Place: Avista Main Office Building
Time: 7:30 a.m. Doors Open Auditorium
7:45 a.m. Refreshments 1411 E. Mission Avenue
8:15 a.m. Annual Meeting Convenes Spokane, Washington
Information about the nominees for election as members of the Board and other business of the Annual Meeting
is set forth in the Notice of Annual Meeting and the Proxy Statement on the following pages.
Please take the opportunity to review the Proxy Statement and 2014 Annual Report. Your vote is important
regardless of the number of shares you own.
For your convenience, we are pleased to offer an audio webcast of the Annual Meeting if you cannot attend in
person. If you choose to listen to the webcast, go to www.avistacorp.com shortly before the meeting time and
follow the instructions for the webcast. You can also listen to a replay of the webcast, which will be archived at
www.avistacorp.com for one year.
Thank you for your continued support.
Sincerely,
Scott L. Morris
Chairman of the Board,
President & Chief Executive Officer
Avista Corporation—1411 E. Mission Ave.—Spokane, Washington 99202
Investor Relations—[phone]
If you require special accommodations at the Annual Meeting due to a disability, please call our
Investor Relations Department by April 10, 2015.
ICNU_DR_032 Attachment A Page 3 of 90
ˆ200GZcqP7Kbs&717;Š
200GZcqP7Kbs&717;
836681 NOT 1AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 17:43 EST
CLN PSPOR
RR Donnelley ProFile SWRdennp0pa 7*
PMT 1C
CA8609AC451293
11.6.14
g63n14-1.0
AVISTA CORPORATION
1411 East Mission Avenue
Spokane, Washington 99202
NOTICE OF ANNUAL MEETING
THIS PROXY STATEMENT AND THE 2014 ANNUAL REPORT ARE AVAILABLE ON THE
INTERNET AT HTTP://PROXYVOTE.COM
Date:Thursday, May 7, 2015
Time:8:15 a.m., Pacific Time
Place:Avista Main Office Building—Auditorium
1411 E. Mission Avenue, Spokane, Washington
Record Date:March 6, 2015
Meeting Agenda:1) Election of ten directors.
2) Amendment of the Company’s Restated Articles of Incorporation (the “Articles”) to
reduce certain shareholder approval requirements.
3) Ratification of the appointment of Deloitte & Touche LLP, the member firms of
Deloitte Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte”) as
the Company’s independent registered public accounting firm for 2015.
4) Amendment of the Company’s Long-Term Incentive Plan (the “LTIP” or the “Plan”)
in order to increase the number of shares reserved for issuance under the Plan.
5) Advisory (non-binding) vote on executive compensation.
6) Transaction of other business that may come before the meeting or any adjournment or
postponement thereof.
All shareholders are cordially invited to attend the meeting in person. Shareholders who cannot be present at the
meeting are urged to vote and submit their proxy by mail, telephone, or through the Internet as promptly as
possible. Please sign and date the proxy card and return it promptly or cast your vote via telephone or through the
Internet in accordance with the instructions on the proxy card and/or proxy notice.
By Order of the Board,
Karen S. Feltes
Senior Vice President & Corporate Secretary
Spokane, Washington
March 27, 2015
ICNU_DR_032 Attachment A Page 4 of 90
ˆ200GZcqP7K8z3HJ73Š
200GZcqP7K8z3HJ73
836681 NOT 2AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 04:38 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc
START PAGE
7*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
Governance Highlights
Our Company is committed to maintaining the highest standards of corporate governance. Strong corporate
governance practices help us achieve our performance goals and maintain the trust and confidence of our
investors, employees, customers, regulatory agencies and other stakeholders. Our corporate governance practices
are described in more detail starting on page 14 and in our Governance Guidelines, which can be found in the
Investors section of our website.
Director
Independence
• Nine of the Company’s ten nominees are independent.
• The Chief Executive Officer (“CEO”) is the only management director.
• During 2014, all of the Board Committees (except the Executive Committee) were
composed exclusively of independent directors.
• The average tenure of independent directors is nine years and their average age is
58.
Board Leadership • The Company has an independent Lead Director, selected by the Board.
• The Lead Director serves as liaison between management and the other non-
management directors. The Lead Director’s specific duties are set forth on page 15.
• The positions of Chairman of the Board (“Chairman”) and CEO are not separated.
Executive Sessions • The independent directors regularly meet in executive sessions without
management.
• The Lead Director presides at executive sessions.
Board Oversight of
Risk Management
• The Board reviews Avista’s systematic approach to identifying and assessing risks
faced by the Company and our business units.
• The Board and its Committees consider enterprise risk in connection with emerging
trends or developments and the evaluation of capital investments and business
opportunities.
Stock Ownership
Requirements
• Independent directors are expected to achieve a minimum investment of five times
the minimum equity portion of their retainer in Company common stock within
five years of becoming Board members and are expected to retain at least that level
of investment during their tenure.
• The stock ownership policy for the Company’s executive officers requires
executive officers to own shares based on their position and salary.
• Chief Executive Officer—5 times salary
• Senior Vice Presidents—2.5 times salary
• Vice Presidents—1 times salary
• Directors and officers are prohibited from engaging in short-sales, pledging, or
hedging the economic interest in their Company shares.
Board Practices • The Board regularly assesses its performance through Board and Committee
evaluations.
• Continuing director education is provided during regular Board and Committee
meetings.
• Directors may not stand for election after age 72.
• The Governance/Nominating Committee (“Governance Committee”) leads the full
Board in considering Board competencies and refreshment in light of Company
strategy.
Accountability • All directors stand for election annually.
• In uncontested elections, directors must be elected by a majority of votes cast.
ICNU_DR_032 Attachment A Page 5 of 90
ˆ200GZcqP7K0DCLG71Š
200GZcqP7K0DCLG71
836681 NOT 3AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:27 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc
START PAGE
6*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
Compensation Highlights
In 2014, our CEO and the Board established performance goals for the Company and aligned the short-term and
long-term incentive plans with those goals. A key element of these plans allows us to focus on maintaining an
attractive financial profile while creating long-term value for shareholders and customers.
As shown below, utility and non-utility earnings per share (“EPS”) exceeded targets and other operational targets
were met, helping produce a short-term incentive payout above target. Return on equity (“ROE”) exceeded the
target established for our CEO’s performance-based restricted stock units (“RSUs”), allowing a portion of his
RSUs to vest. Finally, our three year total shareholder return (“TSR”), determined on the basis of total
appreciation for the period 2012-2014 with all dividends reinvested, achieved 43rd percentile TSR relative to the
Standard & Poor’s (“S&P”) 400 Utilities Index, resulting in a payment of 58% of targeted performance share
awards granted for that period.
2014 Executive Compensation Highlights
• The compensation earned by our Named Executive Officers (“NEOs”) in 2014 reflects our corporate
performance for the fiscal year, as well as the impact of the challenging economy;
• The Compensation Committee approved base salary adjustments ranging from 1.8% to 6.0% for our
NEOs based on market comparisons, its assessment of individual performance and other factors as
discussed in more detail in the Compensation Discussion and Analysis (“CD&A”) starting on page 26;
• Our 2014 utility and non-utility EPS performance exceeded target resulting in an annual cash incentive
payment of 150% of target, which was 150% of base salary for our CEO and 90% of base salary for our
other NEOs;
• For our CEO, our ROE exceeded the target; therefore one-third of his RSUs granted in 2012, 2013 and
2014 and the associated dividend equivalents vested and were paid;
• Our NEOs other than our CEO received one-third of their RSUs granted in 2012, 2013 and 2014, along
with the associated dividend equivalents. The RSUs are time-based, and one-third vest each year over a
three-year period; and
• The Company’s relative TSR over the three-year performance period was above threshold performance
resulting in a 58% of target payout, and our NEOs earned a payment with respect to their 2012-2014
performance share award and the associated dividend equivalents.
ICNU_DR_032 Attachment A Page 6 of 90
ˆ200GZcqP7Kkco@i7ÆŠ
200GZcqP7Kkco@i7˘
836681 TOC 1AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 22:34 EST
CLN PSPOR
RR Donnelley ProFile SWRtonng0pa
START PAGE
10*
PMT 1C
SWRFBU-MWE-XN08
11.6.14
TABLE OF CONTENTS
ABOUT THE ANNUAL MEETING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
PROPOSAL 1—ELECTION OF DIRECTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
CORPORATE GOVERNANCE MATTERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
DIRECTOR COMPENSATION—2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
PROPOSAL 2—PROPOSED AMENDMENT OF ARTICLES OF INCORPORATION . . . . . . . . . . . . . . . 22
AUDIT COMMITTEE REPORT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
PROPOSAL 3—RATIFICATION OF PUBLIC ACCOUNTING FIRM . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
COMPENSATION DISCUSSION AND ANALYSIS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
EXECUTIVE COMPENSATION TABLES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
PROPOSAL 4—PROPOSED AMENDMENT OF LONG-TERM INCENTIVE PLAN . . . . . . . . . . . . . . . . 56
PROPOSAL 5—ADVISORY VOTE ON EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . 62
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT . . . . . . . . . . . 63
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE . . . . . . . . . . . . . . . . . . . . . . 64
ANNUAL REPORT AND FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
HOUSEHOLDING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
OTHER BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65
2016 ANNUAL MEETING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65
APPENDIX A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
APPENDIX B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1
ICNU_DR_032 Attachment A Page 7 of 90
ˆ200GZcqP7K0T5d57}Š
200GZcqP7K0T5d57}
836681 TX 1AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:35 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc
START PAGE
8*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
AVISTA CORPORATION
1411 East Mission Avenue
Spokane, Washington 99202
PROXY STATEMENT
FOR THE ANNUAL MEETING
TO BE HELD ON MAY 7, 2015
ABOUT THE ANNUAL MEETING
Why am I receiving these materials and who is soliciting my vote?
The Board is soliciting your vote in connection with the Annual Meeting or at any adjournment or postponement
thereof. The Company intends to mail this Proxy Statement and accompanying proxy card to shareholders on or
about March 27, 2015.
What is the purpose of the Annual Meeting?
The meeting will be the Company’s regular Annual Meeting. You will be voting on the following matters at the
Annual Meeting:
1) Election of ten directors.
2) Amendment of the Company’s Articles to reduce certain shareholder approval requirements.
3) Ratification of the appointment of Deloitte as the Company’s independent registered public accounting
firm for 2015.
4) Amendment of the Company’s LTIP to increase the number of shares reserved for issuance under the
Plan.
5) Advisory (non-binding) vote on executive compensation.
6) Transaction of other business that may come before the meeting or any adjournment or postponement
thereof.
How does the Board recommend I vote?
The Board recommends a vote:
1)For the election of ten directors.
2)For the amendment of the Company’s Articles to reduce certain shareholder approval requirements.
3)For ratification of the appointment of Deloitte as the Company’s independent registered public
accounting firm for 2015.
4)For the amendment of the Company’s LTIP to increase the number of shares reserved for issuance
under the Plan.
5)For the advisory (non-binding) vote on executive compensation.
Who is entitled to vote at the Annual Meeting?
The Company’s common stock is the only class of securities with general voting rights. The Board has set
March 6, 2015, as the record date for the Annual Meeting (the “Record Date”). Only shareholders who own
common stock at the close of business on the Record Date may attend and vote at the Annual Meeting.
1
ICNU_DR_032 Attachment A Page 8 of 90
ˆ200GZcqP7Jj3514hgŠ
200GZcqP7Jj3514hg
836681 TX 2AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:26 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 6*
PMT 1C
SWRP64RS31
11.6.14
What are the voting rights of holders of common stock?
Each share of common stock is entitled to one vote. There is no cumulative voting. At the close of business on
the Record Date, shares of common stock were outstanding and entitled to vote.
How many shares must be present to hold the Annual Meeting?
Under Washington law, action may be taken on matters submitted to shareholders only if a quorum is present.
The presence at the meeting in person or represented by proxy of holders of a majority of the shares of common
stock outstanding as of the Record Date will constitute a quorum. Shares represented by proxy are deemed
present for quorum purposes even if abstention is instructed or if no instructions are given. Subject to certain
statutory exceptions, once a share is represented for any purpose at a meeting, it is deemed present for quorum
purposes for the remainder of the meeting.
How do I vote shares registered in my name?
If you hold shares that were registered in your name on the Record Date, then you, as the registered holder of
those shares, may vote those shares:
• by completing, dating and signing your proxy card and returning it to the Company by mail in the
envelope provided (or bringing it with you to the Annual Meeting);
• by telephone or through the Internet, following the instructions on your proxy card; or
• by attending the Annual Meeting and voting in person.
How do I vote shares held through a broker, bank or other nominee?
If you are the beneficial owner of shares held through a broker, bank or other nominee, then you are not a record
holder of these shares and may vote them only by instructing the registered holder how to vote them.
You should follow the voting instructions given to you by the broker, bank or other nominee that holds your
shares. Generally, you will be able to give your voting instructions by mail, by telephone or through the Internet.
The Company’s common stock is listed on the NYSE. Under NYSE rules, brokerage firms, banks and other
nominees that are members of the NYSE generally have the authority to vote shares when their customers do not
give voting instructions. However, NYSE rules prohibit member organizations from voting on certain types of
matters without specific instructions from the beneficial owners—if a beneficial owner does not give instructions
on such a matter, the member organization cannot vote on that matter. This is called a “broker non-vote.” Matters
on which NYSE member organizations may not vote without instructions include the election of directors,
matters relating to executive compensation and matters relating to certain corporate governance issues. For
Avista, this means that NYSE member organizations may not vote on Proposals 1, 2, 4 and 5 unless you have
given instructions on how to vote. Please be sure to give specific voting instructions so that your shares can be
voted.
How do I vote shares held through an employee plan?
If you are the beneficial owner of shares through participation in the Company’s 401(k) plan, then you are not the
record holder of these shares and may vote them only by instructing the plan trustee or agent how to vote them.
You should follow the voting instructions given to you by the trustee or agent for the 401(k) plan. Generally, you
will be able to give your voting instructions by mail, by telephone or through the Internet.
2
ICNU_DR_032 Attachment A Page 9 of 90
ˆ200GZcqP7K0c%V0h_Š
200GZcqP7K0c%V0h_
836681 TX 3AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:36 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 8*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
How can I revoke my proxy or change my vote after returning my proxy card or giving voting
instructions?
If you were a registered holder as of the Record Date and returned a proxy card, you may revoke your proxy or
change your vote at any time before it is exercised at the Annual Meeting by giving written notice to the
Corporate Secretary of the Company. You may also change your vote by timely delivering a later-dated proxy or
a later-dated vote by telephone or through the Internet or by voting in person at the Annual Meeting.
If you were not a registered holder as of the Record Date and wish to change or revoke your voting instructions,
you should follow the instructions given to you by your broker, bank or other registered holder.
How many votes are required to elect directors and approve the other proposals?
Proposal 1—election of directors. A nominee will be elected if the number of votes cast “for” exceeds the
number of votes cast “against.” Abstentions or broker non-votes with respect to any shares will have no effect on
the election of that director since those shares will not be voted at all. If you are the registered holder of the
shares and sign but give no instructions on the proxy card with respect to this proposal, the shares represented by
that proxy card will be voted for each of the nominees. Shareholders may not cumulate votes in the election of
directors. If an incumbent director does not receive a majority of votes cast with respect to his/her re-election in
an uncontested election, he/she would continue to serve a term that would terminate on the date that is the earliest
of: (i) the date of the commencement of the term of a new director selected by the Board to fill the office held by
such director, (ii) the effective date of the resignation of such director, or (iii) December 31, 2015.
Proposal 2—the proposal for amending the Articles to reduce certain shareholder approval requirements will be
approved upon the affirmative vote of the holders of 80% of the total number of shares of common stock
outstanding. Abstentions or broker non-votes with respect to any shares will have the same impact as a negative
vote on the outcome of Proposal 2 since those shares will not be voted “for.” If you are the registered holder of
the shares and sign but give no instructions on the proxy card with respect to this proposal, the shares represented
by that proxy card will be voted for this proposal.
Proposal 3—the proposal for ratifying the appointment of the firm of Deloitte as the independent registered
public accounting firm of the Company for 2015, will be approved if the number of votes cast “for” exceeds the
number of votes cast “against.” Abstentions with respect to any shares will have no impact on the outcome of this
proposal since those shares will not be voted at all. Brokers may vote on this proposal without instructions. If you
are the registered holder of the shares and sign but give no instructions on the proxy card with respect to this
proposal, the shares represented by that proxy card will be voted for this proposal.
Proposal 4—the proposal for amending the LTIP to increase the number of shares reserved for issuance under the
Plan will be approved if the number of votes cast “for” exceeds the number of votes cast “against.” Abstentions
or broker non-votes with respect to any shares will have no impact on the outcome of this proposal since those
shares will not be voted at all. If you are the registered holder of the shares and sign but give no instructions on
the proxy card with respect to this proposal, the shares represented by that proxy card will be voted for this
proposal.
Proposal 5—the advisory (non-binding) vote on executive compensation will be approved if the number of votes
cast “for” exceeds the number of votes cast “against.” Abstentions and broker non-votes with respect to any
shares will have no impact on the outcome of Proposal 5 since those shares will not be voted at all. If you are the
registered holder of the shares and sign but give no instructions on the proxy card with respect to this proposal,
the shares represented by that proxy card will be voted for this proposal.
Who pays for the proxy solicitation and how will the Company solicit votes?
The expense of soliciting proxies will be borne by the Company. Proxies will be solicited by the Company
primarily by mail, but may also be solicited personally and by telephone at nominal expense to the Company by
3
ICNU_DR_032 Attachment A Page 10 of 90
ˆ200GZcqP7K9azRJh@Š
200GZcqP7K9azRJh@
836681 TX 4AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 04:56 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 12*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
directors, officers, and regular employees of the Company. In addition, the Company has engaged
D.F. King & Co., Inc. at a cost of $6,500 plus out-of-pocket expenses, to solicit proxies in the same manner. The
Company will also request banks, brokerage houses, custodians, nominees, and other record holders of the
Company’s common stock to forward copies of the proxy soliciting material and the Company’s 2014 Annual
Report to Shareholders to the beneficial owners of such stock, and the Company will reimburse such record
holders for their expenses in connection therewith.
Who can I contact if I have questions or need assistance in voting my shares?
If you have any questions about the proxy voting process, please contact the broker, bank or other financial
institution where you hold your shares. The SEC also has a website (www.sec.gov/spotlight/proxymatters.shtml)
with more information about your rights as a shareholder. Additionally, you may contact our Investor Relations
Department at [phone].
4
ICNU_DR_032 Attachment A Page 11 of 90
ˆ200GZcqP7JjrxdYhsŠ
200GZcqP7JjrxdYhs
836681 TX 5AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:51 EST
CLN PSPOR
RR Donnelley ProFile SWRperec0sl 7*
PMT 1C
SWRFBU-MWE-XN10
11.6.14
PROPOSAL 1—ELECTION OF DIRECTORS
Director Qualifications and Process for Selecting Board Nominees
The Board has a robust and effective director nomination and evaluation process in place. The Board has
delegated to the Governance Committee the responsibility for reviewing and recommending to the Board
nominees for director. The Governance Committee annually reviews with the Board the composition of the
Board as a whole and recommends, if necessary, steps to be taken so that the Board reflects the appropriate
balance of knowledge, experience, skills, expertise and diversity, all in the context of an assessment of the needs
of the Board and the Company at the time. Board members should possess such qualifications, skills, attributes
and experience as are necessary to provide a broad range of personal characteristics, including diversity,
leadership and management skills, business experience and industry knowledge. Directors should be able to
commit the requisite time for preparation and attendance at regularly scheduled Board and Committee meetings,
as well as be able to participate in other matters necessary to ensure good corporate governance is practiced.
In evaluating a director candidate, the Governance Committee considers factors that are in the best interests of
the Company and its shareholders, including the knowledge, experience, integrity and judgment of each
candidate; the potential contribution of each candidate to the diversity of backgrounds, experience and
competencies that the Board desires to have represented; each candidate’s ability to devote sufficient time and
effort to his or her duties as a director; independence and willingness of each candidate to consider strategic
proposals; and any other criteria established by the Board, as well as any core competencies or technical
expertise necessary to staff Board Committees.
The Board believes that it must continue to refresh itself. During the last nine years, there has been turnover of
six directors on the Board as a result of retirements and departures of Board members due to professional and
personal commitments. The average tenure of the independent directors of the Board as of December 31, 2014 is
nine years and the average age is 58. The Board consists of directors with a range of experience at policy-making
levels in business, government and other areas that are relevant to the Company’s activities. The Board does not
have a diversity policy, but does include diversity as one of the criteria it considers when evaluating any
candidate for the Board. The Board takes into account diversity of experience, skills and background, as well as
diversity in race, gender, and culture when considering individual candidates.
The Governance Committee identifies nominees by first evaluating the current members of the Board. Current
members of the Board with skills and experience that are relevant to the Company’s business and who are willing
to continue in service are considered for re-nomination. If any member of the Board does not wish to continue in
service or if the Governance Committee decides not to nominate a member for re-election, the Committee then
identifies the desired qualifications, skills, expertise, abilities and experience of a new nominee in light of the
criteria set forth above. Current members of the Board are polled for suggestions as to individuals meeting the
criteria described above. The Governance Committee may also consider candidates recommended by
management, employees, or others. The Governance Committee may also, at its discretion, engage executive
search firms to identify qualified individuals.
The Governance Committee will consider written recommendations for candidates for the Board that are made
by shareholders. Recommendations must include detailed biographical material indicating the qualifications of
the candidate for the Board, and must include a written statement from the candidate of willingness and
availability to serve. The Governance Committee will consider any candidate recommended in good faith by a
shareholder. In evaluating director nominees, the Governance Committee considers the following, among other
criteria:
• the appropriate size of the Board;
• the needs of the Company with respect to the particular talents and experience of its directors;
• the qualifications, knowledge, skills, abilities and executive leadership experience of nominees, as well
as working experience at the executive leadership level in his/her field of expertise;
5
ICNU_DR_032 Attachment A Page 12 of 90
ˆ200GZcqP7K0oY=!7GŠ
200GZcqP7K0oY=!7G
836681 TX 6AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:41 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 9*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
• familiarity with the energy/utility industry;
• recognition by other leaders as a person of integrity and outstanding professional competence with a
proven record of accomplishments;
• experience in the regulatory arena;
• knowledge of the business of, and/or facilities for, the generation, purchase, transmission and/or
distribution of electric energy and/or the purchase, storage and/or distribution of natural gas;
• attributes that would enhance the diversity and perspective of the Board; and
• knowledge of the customers, community, and employee base.
While candidates for director are usually nominated by the Board (after consideration and recommendation by
the Governance Committee, as discussed above), shareholders may directly nominate candidates for election as
directors. However, in order to do so, shareholders must follow the procedures set forth in the Company’s
Bylaws, referred to under “2016 Annual Meeting,” on page 65. The Chair of the meeting may refuse to
acknowledge any nomination not made in compliance with the Bylaws.
Nominees
Ten directors are to be elected to hold office for a one-year term, and/or until a qualified successor is elected. The
Company’s Restated Articles of Incorporation provide for up to 11 directors. The Bylaws currently provide that
the number of directors will be fixed from time to time by resolution of the Board, not to exceed 11. The Board
has fixed the number at ten.
Upon recommendation from the Governance Committee, the Board has nominated Erik J. Anderson, Kristianne
Blake, Donald C. Burke, John F. Kelly, Rebecca A. Klein, Scott L. Morris, Mark F. Racicot, Heidi B. Stanley,
and R. John Taylor to be re-elected as directors for a one-year term to expire at the Annual Meeting in 2016 or
until their successors shall have been elected. The Board appointed Janet D. Widmann as a director, effective
August 2, 2014, and has nominated Ms. Widmann to be elected as a director for a one-year term to expire at the
Annual Meeting in 2016. The nominees have consented to serve as directors, and the Board has no reason to
believe that any nominee will be unable to serve. If a nominee should become unavailable, your shares will be
voted for a Board-approved substitute. The Board has concluded that all nominees, with the exception of
Mr. Morris, are independent and should serve as directors of the Company in light of the Company’s business
and structure.
6
ICNU_DR_032 Attachment A Page 13 of 90
ˆ200GZcqP7K9J&G87?Š
200GZcqP7K9J&G87?
836681 TX 7AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 04:49 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 6*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
erik-1.0
kristianne-1.0
The following has been prepared from information furnished to the Company by the nominees.
ERIK J. ANDERSON
Director since 2000
Mr. Anderson,age 56, has been President of WestRiver Management, LLC since
2002. WestRiver is a private investment company that provides integrated capital
solutions for the global innovation economy. He is Executive Chairman of TopGolf,
Inc. an entertainment company and Clario Medical, Inc., a SAAS based radiology
process management company. Mr. Anderson is the founder of America’s Foundation
for Chess, which serves 150,000 children in the United States with its First Move
curriculum. From 1998 to 2002, Mr. Anderson was CEO of Matthew G Norton Co., a
private investment company. In addition, his experience includes tenures at the private
equity firm of Frazier & Company, LP, and Vice President at Goldman, Sachs & Co.
He holds a master’s and bachelor’s degree in Industrial Engineering from Stanford
University and a bachelor’s degree (Cum Laude) in Management Engineering from
Claremont McKenna College. Mr. Anderson served on the Board of Ecova, Inc.
(“Ecova”), a subsidiary of the Company, prior to the sale of Ecova on June 30, 2014.
Leadership Experience President and CEO experience with investment, private equity and technology firms.
Financial Experience Extensive experience with finance matters including mergers and acquisitions,
securities and debt offerings, and risk analysis.
KRISTIANNE BLAKE
Director since 2000
Ms. Blake, age 61, has been president of the accounting firm of Kristianne Gates
Blake, P.S., since 1987. She has served for 18 years on various boards of public
companies and registered investment companies including service as a board chair,
audit committee chair and governance committee member. Ms. Blake is currently
serving as board chair for the Russell Investment Company and the Russell Investment
Funds. She previously served on the boards of the Principal Funds, Inc., the Principal
Variable Contracts Funds, Inc., and Laird Norton Wealth Management. Ms. Blake
currently serves as a Regent at the University of Washington. In addition, Ms. Blake
served on the board of Ecova and was the chair of the Ecova Audit Committee, prior
to the sale of Ecova on June 30, 2014.
Leadership Experience Ms. Blake has outside board experience as a director of public companies and
registered investment companies as well as non-profit and university boards and has
served on numerous board committees including serving as chair.
Financial Experience Ms. Blake has an extensive background in public accounting. She was a Certified
Public Accountant for 32 years and she worked for 12 years for an international
accounting firm.
Community
Development
She has extensive involvement in the Spokane community, having served on many
non-profit and economic development boards.
7
ICNU_DR_032 Attachment A Page 14 of 90
ˆ200GZcqP7K0%Po%7ÀŠ
200GZcqP7K0%Po%7
836681 TX 8AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:47 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 10*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
donald-1.0
john_kelly-1.0
DONALD C. BURKE, CPA
Director since 2011
Mr. Burke, age 54, currently serves as an independent director for the Duff & Phelps Closed-
End Funds Complex. Prior to this role, Mr. Burke served as an independent trustee to
approximately 100 registered mutual funds for the Goldman Sachs mutual fund complex. In
addition, from 2006 to 2010, Mr. Burke served as a trustee for numerous global funds that
were advised by BlackRock, Inc. From 2006 to 2009, he was a managing director of
BlackRock and served as the president and CEO of the BlackRock U.S. mutual funds. In this
role, Mr. Burke was responsible for all of the accounting, tax and regulatory reporting
requirements for over 300 open and closed-end mutual funds. Mr. Burke joined BlackRock in
connection with the merger with Merrill Lynch Investment Managers (“MLIM”), taking a lead
role in the integration of the two firms’ operating infrastructures. While at MLIM, Mr. Burke
was the Head of Global Operations and Client Services and also served as the Treasurer and
Chief Financial Officer (“CFO”) of the MLIM mutual funds. He started his career with
Deloitte & Touche LLP (formerly Deloitte Haskins & Sells). Mr. Burke is a certified public
accountant and received a Bachelor of Science degree in Accounting and Economics from the
University of Delaware and a Master of Business Administration in Taxation from Pace
University. Mr. Burke served on the board of Ecova, prior to the sale of Ecova on June 30,
2014.
Financial Experience Mr. Burke brings significant financial experience to the board from his years in public
accounting and his role as the treasurer and CFO of numerous mutual funds.
Leadership Experience Mr. Burke has held a number of leadership roles throughout his career including leading a
global operations organization with employees located across four continents.
Board Experience Mr. Burke has extensive board experience, having served on the audit, compliance,
governance & nominating, and contract review committees of various boards. He also serves
on the boards of a number of charitable foundations.
JOHN F. KELLY
Director since 1997
Lead Director
Mr. Kelly, age 70, is currently the president & CEO of John F. Kelly & Associates, a
consulting company he founded in 2004, that is located in Winter Park, Florida. Mr. Kelly is
a retired chair, president and CEO of Alaska Air Group, where he also served as a Board
member from 1989 to May 2003. He was chair of Alaska Airlines from 1995 to February
2003, CEO from 1995 to 2002, and president from 1995 to 1999. He served as chair of
Horizon Air from February 1991 to November 1994, and from February 1995 until May
2003. Mr. Kelly has a BA in Business from the University of Puget Sound, has over 40 years
of business experience and has been a board member and chair of numerous boards and
committees (both profit and non-profit organizations). Mr. Kelly is a former board member
of the Dream Foundation. He also served on the board of Ecova, prior to the sale of Ecova
on June 30, 2014.
Leadership Experience Mr. Kelly has over 35 years of business experience in the airline industry, serving in numerous
management capacities, including roles as chair, CEO and president. He also brings experience
in marketing, sales, corporate governance, compensation, mergers and acquisitions, consulting,
and human resources. He currently is president and CEO of a consulting firm.
Business and
Association
He has been very involved in the Seattle, Washington business and cultural communities
including chairing the Washington Roundtable and other nonprofit boards.
Board Leadership His experience and business skills, as well as his open communication style have aided the
Board both as a Board and Committee member and in his role as the Lead Director for over
four years.
8
ICNU_DR_032 Attachment A Page 15 of 90
ˆ200GZcqP7Jj!TW&7"Š
200GZcqP7Jj!TW&7"
836681 TX 9AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:57 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
rebecca-1.0
REBECCA A. KLEIN
Director since 2010
Ms. Klein, age 49, is Principal of Klein Energy, LLC, an energy consulting company
based in Austin, Texas. Over the last 20 years she has worked in Washington, DC and
in Texas in the energy, telecommunications and national security arenas. Ms. Klein’s
professional experience also includes service with KPMG Consulting (now Deloitte)
where she headed the development of the company’s Office of Government Affairs
and Industry Relations in Washington, DC. She also served as a Senior Fellow with
Georgetown University’s McDonough School of Business. Since January 2008, she
has served as chair of the board of the Lower Colorado River Authority, a public
power utility owning generation, transmission, and water services across the central
Texas area. In addition, she is chair of Power Across Texas, a non-profit that focuses
on advancing information about clean, affordable and reliable energy in the state, and
she sits on the board of GroupNIRE, a company focused on developing energy
resources from early stage technologies to commanded deployment. Ms. Klein earned
a Juris Doctor from St. Mary’s University School of Law in San Antonio, Texas. She
also holds a Master of Arts in National Security Studies from Georgetown University
and a Bachelor of Arts in Human Biology from Stanford University. She is a member
of the State Bar of Texas.
Legal and Regulatory
Experience
Ms. Klein has a unique blend of legal and regulatory experience. She has served as a
commissioner with the Texas Public Utilities Commission and subsequently as its
chair. Her areas of legal expertise include energy and telecommunications.
Leadership Experience Ms. Klein brings extensive management, human resource, organizational
development, and national security experience to the Board.
Government Experience She has experience in the military and national public policy arenas. She also has
lobbying experience at both the state and federal level.
Board Experience She serves as a member of the board of an energy resources company, and she serves
as chair of the board of a public power utility.
9
ICNU_DR_032 Attachment A Page 16 of 90
ˆ200GZcqP7Jj!alwhÊ
200GZcqP7Jj!alwhˆ
836681 TX 10AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:57 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
scott-1.0
SCOTT L. MORRIS
Director since 2007
Mr. Morris, age 57, has been Chairman, President and CEO of the Company since
January 2008. From May 2006 to December 2007, he served as the Company’s
President and Chief Operating Officer (“COO”). Mr. Morris also serves as chair of the
Company’s subsidiaries, including having served as chair of the Ecova board until its
sale on June 30, 2014. Mr. Morris has been with the Company since 1981 and his
experience includes management positions in construction and customer service and
general manager of the Company’s Oregon and California utility business. He was
elected as a vice president in November 2000 and in February 2002 he was elected as
a senior vice president. He is a graduate of Gonzaga University and received his
master’s degree from Gonzaga University in organizational leadership. He also
attended the Stanford Business School Financial Management Program and the Kidder
Peabody School of Financial Management. Mr. Morris serves on the boards of the
Washington Roundtable, Greater Spokane Incorporated, Gonzaga University, Edison
Electric Institute, American Gas Association, and the Federal Reserve Bank of San
Francisco. He has served on a number of Spokane non-profit and economic
development Boards.
Industry and
Leadership Experience
Mr. Morris has extensive utility experience having spent his entire career in the
industry. He brings to the Board a deep knowledge and understanding of the Company
and its subsidiaries, having served in a number of management capacities throughout
the Company, including President of Utility Operations, managing the Company’s
Oregon and California gas operations, customer service, and construction areas and
CEO of the Company’s subsidiary, Ecova. He is the only officer of the Company to sit
on the Avista Board and was the only officer of the Company to sit on the Ecova board
prior to its sale in June 2014.
Business and Policy
Experience
He has experience leading a number of economic development and business
association boards. He also serves on the board of the Federal Reserve Bank of San
Francisco.
10
ICNU_DR_032 Attachment A Page 17 of 90
ˆ200GZcqP7Jj!gsZhJŠ
200GZcqP7Jj!gsZhJ
836681 TX 11AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:57 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
marc-1.0
MARC F. RACICOT
Director since 2009
Mr. Racicot, age 66, served as president and CEO of the American Insurance
Association from August, 2005 to February, 2009. Prior to that, he was a partner at the
law firm of Bracewell & Giuliani, LLP from 2001 to 2005. He is a former governor
(1993 to 2001) and attorney general (1989 to 1993) of the state of Montana. Mr.
Racicot was nominated by President Bush and unanimously elected to serve as the
chair of the Republican National Committee from 2002 to 2003 prior to assuming the
position of chair of the Bush/Cheney Re-election Committee from 2003 to 2004. He
previously served as a director for Siebel Systems, Allied Capital Corporation and
Burlington Northern Santa Fe Corporation and presently serves as a director for Plum
Creek Timber Company, Inc., Massachusetts Mutual Life Insurance Company, and
The Washington Companies. In addition, throughout his career, Mr. Racicot has
strongly committed himself to children, education and community issues. He was
appointed to the board of The Corporation for National and Community Service by
President Clinton and has also served on the boards of Carroll College, Jobs for
America’s Graduates and United Way in Helena, Montana. Mr. Racicot is also a past
chair of America’s Promise, where his predecessor was Secretary of State Colin
Powell.
Government and Policy
Experience
Mr. Racicot has served in a number of elected offices in the state of Montana
including that of Governor. He has also had a number of political appointments on
both the state and federal level where he was involved in policy development.
Legal and Regulatory
Experience
He brings extensive legal and regulatory experience from his military and
prosecutorial service, as well as from private legal practice and his elected office as
Attorney General of Montana. During his tenure as Governor of Montana, as well as
during his time in private practice, he was extensively involved in natural resource,
environmental, permitting and energy issues affecting Montana and the nation.
Governance Mr. Racicot has served on a number of public company boards and chairs a board
committee.
11
ICNU_DR_032 Attachment A Page 18 of 90
ˆ200GZcqP7K10%P&7‹Š
200GZcqP7K10%P&7
836681 TX 12AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:49 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 10*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
heidi-1.0
HEIDI B. STANLEY
Director since 2006
Ms. Stanley, age 58, is co-owner and chair of Empire Bolt & Screw, Inc., a privately-
held international distribution company headquartered in Spokane, Washington. Prior
to this, Ms. Stanley had 24 years of experience in the banking industry. She served as
CEO and chair of Sterling Savings Bank from January 2009 to October 2009. From
January 2008 to December 2008, she served as director, vice chair, president & CEO.
From October 2003 to December 2007, she served as director, vice chair and COO.
Prior to this, she held a variety of leadership positions with increasingly higher levels
of managerial responsibility. Ms. Stanley also served as director of Sterling’s
Subsidiary Company—INTERVEST Mortgage Investment Company. Prior to joining
Sterling in 1985, Ms. Stanley worked for IBM in San Francisco, California and
Tucson, Arizona. Ms. Stanley is the founding chair of Greater Spokane Incorporated,
former chair of the Association of Washington Business (“AWB”), and former chair of
the Spokane Area YMCA. Ms. Stanley currently serves on the boards of the
Washington Policy Center, AWB and the Spokane Symphony. Ms. Stanley graduated
from Washington State University with a Bachelor of Arts degree in Business
Administration.
Financial and
Banking Leadership
Experience
The foundation established from her early years at IBM Corporation, combined with
her rise to CEO over a lengthy banking career and exposure as co-owner of a
privately-held company, have given Ms. Stanley a diverse business perspective.
Specifically, her 24 years of experience in banking management included positions as
a CEO and COO of a multi-state banking operation. She has experience in operations,
risk analysis, policy development, mergers and acquisitions and in the capital markets.
Business
Associations
She has served on many industry and business boards. She currently serves on the
Washington Policy Center board and is the past chair of the Association of
Washington Business.
Community
Development
Ms. Stanley has been active in the Spokane area chairing Greater Spokane
Incorporated, a regional chamber/economic development organization. Her
community leadership extends beyond the business community and includes board
involvement with numerous charitable, educational and cultural organizations.
12
ICNU_DR_032 Attachment A Page 19 of 90
ˆ200GZcqP7K12aqu7gŠ
200GZcqP7K12aqu7g
836681 TX 13AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:50 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 7*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
john_taylor-1.0
janet-1.0
R. JOHN TAYLOR
Director since 1985
Mr. Taylor, age 65, is the Chair and CEO of the Green Leaf Alliance. The alliance was
formed to consolidate and reinsure various types of crop insurance in the western and
mid-western United States. Mr. Taylor has over 30 years experience in multi-state
insurance operations in the agriculture sector. Mr. Taylor holds similar positions with
affiliated insurance agencies and companies. In addition, he is director of Pacific
Empire Radio Corporation of Lewiston, Idaho, a twelve station Northwest radio group.
Mr. Taylor is an attorney and has been a member of the Idaho State Bar since 1976.
Leadership
Experience
Mr. Taylor has extensive experience as a CEO, President and COO of several multi-
state insurance operations.
Community
Development Experience
Mr. Taylor has been an active member of the Lewiston, Idaho community serving in a
number of capacities for community and statewide organizations. He is a former
member of the Lewiston City Council and has served as a director or board member of
several civic, political, and non-profit entities for local and state organizations. He was
a member of the Endowment Fund Investment Board of the state of Idaho from 1994
to 2012. He currently serves on the Board of Directors of the Idaho Heritage Trust, a
statewide organization dedicated to the preservation of historical properties and sites.
Political Experience He has held several local and statewide elected positions in the Idaho Republican
Party, including service as State Treasurer.
Governance and
Legal Experience
Mr. Taylor brings to the Board valuable governance experience from his service as a
director, chairman, and audit committee chair of both profit and non-profit
organizations.
JANET D. WIDMANN
Director since 2014
Ms. Widmann, age 48, has served as Executive Vice President for Blue Shield of
California since 2013 and is responsible for the overall management and performance
of Blue Shield’s 3.5 million members and $13.2 billion in annual revenue. Ms.
Widmann holds a Bachelor of Science degree in Health Administration from
California State University, Northridge and a Master of Health Administration degree
from the University of Southern California.
Leadership
Experience
Ms. Widmann has more than 25 years of budget experience in health care with both
non-profit and for-profit companies. She began her career at Health Net, eventually
serving as the COO of its dental and vision subsidiaries.
Community
Development Experience
In 2013 and 2014, Ms. Widmann was named one of the “Most Influential Women in
the Bay Area” by the San Francisco Business Journal. Ms. Widmann also serves on
the Board of the Bay Area Business Council, McKinsey & Company Bay Area
Women’s Executive Roundtable and Sponsor of Blue Shield’s Women in Leadership
Program
The Board recommends a vote “FOR” all nominees for director.
13
ICNU_DR_032 Attachment A Page 20 of 90
ˆ200GZcqP7Jj@DC3hIŠ
200GZcqP7Jj@DC3hI
836681 TX 14AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:57 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
CORPORATE GOVERNANCE MATTERS
Corporate Governance Principles
The Board is responsible for management oversight and providing strategic guidance to the Company. The Board
believes that it must continue to renew itself to ensure that its members understand the industry and the markets
in which the Company operates. The Board also believes that it must remain well-informed about the positive
and negative issues, problems, risks, and challenges facing the Company and markets so that the Board members
can exercise their fiduciary responsibilities to the Company’s shareholders. The Board has adopted Governance
Guidelines to address matters including qualification of directors, standards of independence for directors,
election of directors, responsibilities and expectations of directors, and evaluating Board and Committee
performance.
Board Leadership Structure
The Board does not have a policy as to whether the role of CEO should be separate from that of the Chairman,
nor, if the roles are separate, whether the Chairman should be selected from the independent directors or should
be an employee of the Company. The Board selects the Chairman in a manner that it determines to be in the best
interests of the Company and its shareholders. This flexibility has allowed the Board to determine whether the
role should be separated based on the individuals and the circumstances existing at that time. The Board believes
that the Company has been well served by this leadership structure. The separation of the Chairman and the CEO
could introduce a complex new relationship to the Company’s corporate governance structure. Having a single
leader for both the Company and the Board eliminates the potential for confusion or duplication of effort, and
provides clear leadership for the Company, the Board and the markets.
The positions of Chairman and CEO have not been separated, except on one occasion during 2000-2001. The
Board has examined the questions of the separation of the positions of the Chairman and the CEO and the
independence of the Chairman. The Board has concluded that it should not have a rigid policy as to these issues
but, rather, should consider them, together with other relevant factors, to determine the right leadership structure.
The Board believes that it needs to retain the ability to balance the independent Board structure with the
flexibility to appoint as Chairman someone with hands-on knowledge of and experience in the operations of the
Company. The Board periodically examines its governance practices, including the separation of the offices of
Chairman and CEO. Having a single person serve as Chairman and CEO continues to provide unified and
responsible leadership and is currently considered the right form of leadership for the Company and the Board.
The Company is led by Mr. Morris, who has served as its Chairman, President and CEO since 2008. Given the
issues facing the Company and the possible technological, regulatory and legislative changes that may occur in
the industry, the Board believes that Mr. Morris provides strategic, operational, and technical expertise and
context for the matters considered by the Board.
Duties of the Chairman
The Chairman’s duties include:
• chairing all meetings of the Board in a manner that effectively utilizes the Board’s time and which takes
full advantage of the skills, expertise and experience that each director has to offer;
• working with the Lead Director to establish schedules and agendas for Board meetings, with input from
other directors and management;
• providing input to the Chair of the Governance Committee on new Board member candidates and the
selection of the Board Committee members;
• facilitating and encouraging constructive and useful communication between the Board and
management;
14
ICNU_DR_032 Attachment A Page 21 of 90
ˆ200GZcqP7K136bthsŠ
200GZcqP7K136bths
836681 TX 15AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:51 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 7*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
• recommending an agenda to the Board for its approval for each shareholder meeting;
• providing leadership to the Board in the establishment of positions that the Board should take on issues
to come before shareholder meetings; and
• presiding at all shareholder meetings.
The Chairman is also responsible for ensuring that the Board is provided with full information on the condition
of the Company, its businesses, the risks facing the Company and the environment in which it operates.
Lead Director
The Board has also established the position of an independent Lead Director. Mr. Kelly was elected by the
independent directors to serve as Lead Director. The Lead Director’s duties include:
• maintaining an active, positive and collaborative relationship with the Chairman and the CEO and
keeping an open line of communication that provides for dissemination of information to the Board and
discussion before actions are finalized;
• serving as primary liaison between independent directors and the Chairman and CEO;
• presiding at all meetings at which the Chairman is not present, including executive sessions of the
independent directors held at each regularly scheduled Board meeting;
• calling meetings of the independent directors when necessary and appropriate; and
• working with the Chairman to set meeting schedules and agendas for the Board meetings, including
soliciting input from the other independent directors on items for the Board agendas, to ensure that
appropriate agenda items are included and that there is adequate time for discussion of these items.
The Lead Director is available for communications and consultation with major shareholders. The Company has
a mechanism for shareholders to communicate with the Lead Director and non-management directors as a group,
or on an individual basis. (See “Communications with Shareholders” on page 18.)
Director Independence
The Board has been, and continues to be, a strong proponent of director independence. It is the policy of the
Board that a majority of the directors be independent from management and that the Board not engage in
transactions that would conflict with the best interests of the Company’s business. Independence determinations
are made on an annual basis at the time the Board approves nominees for election at the next Annual Meeting
and, if a director joins the Board between Annual Meetings, at such time. To assist in this determination, the
Board adopted Categorical Standards for Independence of Directors (the “Categorical Standards”).
The Company’s corporate governance structures and practices provide for a strong, independent Board and
include several independent oversight mechanisms.
• The Board is currently comprised of Mr. Morris and nine independent directors.
• The Board has five independent Committees with separate independent Chairs.
• All members of the Board Committees are independent, with the exception of Mr. Morris who chairs the
Executive Committee.
• All Board Committees may seek legal, financial or other expert advice from sources independent from
management.
The Board believes this governance structure and these practices ensure that strong and independent directors
will continue to effectively oversee the Company’s management and key issues related to its long-range business
plans, long-range strategic issues, risks and integrity.
15
ICNU_DR_032 Attachment A Page 22 of 90
ˆ200GZcqP7K14Nom7)Š
200GZcqP7K14Nom7)
836681 TX 16AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:52 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 7*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
Each year the Board reviews and determines the independence of each director in accordance with the
Categorical Standards contained in the Governance Guidelines. As a result of this review, the Board has
affirmatively determined that the directors nominated for election at the Annual Meeting are independent of the
Company and its management with the exception of Mr. Morris, who is considered an inside director because of
his employment as President and CEO of the Company.
Related Party Transactions
The Board recognizes that related party transactions present a heightened risk of conflicts of interest and/or
improper valuation (or the perception thereof) and, therefore, has adopted a Related Party Transaction Policy,
which will be followed in connection with all related party transactions involving the Company and specified
related persons that include directors (including nominees) and executive officers, certain family members and
certain shareholders, all as outlined in the applicable rules of the SEC. During its annual review, the Board
considered whether there were any transactions or relationships between directors or any member of their
immediate family (or any entity of which a director or an immediate family member is an executive officer,
general partner, or significant equity holder) and members of the Company’s senior management or their
affiliates that are inconsistent with a determination that the director is independent.
SEC rules require that the Company disclose any related party transaction in which the amount involved exceeds
$120,000 in the last year. The Governance Committee has determined that the Company has no related party
transactions that were reportable for 2014.
In making its determination, the Board considered that the Company and its subsidiaries in the ordinary course of
business have during the last three years purchased products and services from companies at which some of our
directors were officers, board members, or investors during 2014. The Board specifically considered the
following relationships, which it determined were immaterial to the director’s independence:
• Ms. Stanley is co-owner and chair of the board of a company that had for many years prior to the date
Ms. Stanley became a director, sold hardware supplies to the Company in arm’s-length transactions. The
amount paid to that company in 2014 or in any of the prior three years did not exceed the threshold
amount in the Categorical Standards.
• Mr. Taylor is a board member of a corporation that owns and operates radio stations in Idaho,
Washington and Oregon. In 2014, the Company’s ad agency purchased radio advertisements on some of
those stations in arm’s-length transactions. The amount paid to that company in 2014 or in any of the
prior three years did not exceed the threshold amount in the Categorical Standards.
Board Meetings
The Board strongly encourages its members to attend all Board and Committee meetings and the Annual
Meeting. The Board held five meetings in 2014. The attendance at all Board and Committee meetings was
96.8%. All but one director attended the prior year’s Annual Meeting and all directors are planning to attend the
upcoming Annual Meeting.
Meetings of Independent Directors
The independent directors meet at each regularly scheduled Board meeting in an executive session without
management present. The Lead Director chairs the executive sessions. The Lead Director establishes the agenda
for each executive session, and also determines which, if any, other individuals, including members of
management and independent advisors, should be available for each such meeting.
Board Risk Oversight
The Board has an active role in overseeing the risks affecting the Company. The Board’s risk oversight process
includes receiving reports from members of corporate management on areas of material risk to the Company,
16
ICNU_DR_032 Attachment A Page 23 of 90
ˆ200GZcqP7K16cio7NŠ
200GZcqP7K16cio7N
836681 TX 17AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:53 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 7*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
including operational, financial, legal, regulatory, strategic and reputational risks. The Board’s oversight is
conducted primarily through the Committees of the Board as set out below in the description of each Committee
and as set out in their charters, but the full Board retains responsibility for general oversight of risks.
Management is responsible for the day-to-day management of risks, and the appropriate officer within the
Company reports on risk to the appropriate Board Committee or to the full Board. For example, quarterly, the
Director of Risk Management reports on the Company’s risk analysis and risk management processes to the
Audit Committee, quarterly the Environmental Committee reviews risks related to the Company’s operations,
and, annually, the CFO reports to the entire Board on the Company’s enterprise risk program and processes.
When a Committee receives a report from management, the Chair of that Committee advises the full Board at its
next meeting. This enables the Board and its Committees to coordinate risk oversight, particularly with respect to
the interrelationships among various risks.
CEO Succession Plan
Succession plans for our CEO and other officers are an important part of the Company’s long-term success, and
the Company has in place a succession-planning process that reflects the Company’s long-term business strategy.
The Compensation Committee conducts an annual review of the succession plans for our CEO and other
executives of the Company and receives quarterly updates on the plans. Our CEO and the Compensation
Committee review those succession plans annually with the full Board. The succession plans reflect the Board’s
belief that the Company should regularly identify internal candidates for the CEO and other executive positions
and that it should develop those candidates for consideration when a transition is planned or necessary.
Accordingly, management has identified internal candidates in various phases of development and has
implemented development plans to assure the candidates’ readiness. Those development plans identify the
candidates’ strengths and weaknesses and the Compensation Committee receives periodic updates and regularly
reviews the candidates’ progress. In addition to internal development pools, to assure selection of the best
candidate(s), the Company may recruit externally if such approach would better suit the Company’s strategic
needs. The Compensation Committee believes that the Company’s succession planning process provides a good
structure to assure that the Company will have qualified successors for its executive officers.
In order to have a fully comprehensive CEO succession plan in place, the Board adopted a Contingency CEO
Succession Plan to outline the procedures for the temporary appointment of an interim CEO and an interim
Chairman to avoid a vacancy in leadership that may occur because of an absence event due to death, illness,
disability, or sudden departure of our CEO.
Director Orientation and Continuing Education
The Governance Committee and management are responsible for director orientation programs. Orientation
programs are designed to familiarize new directors with the Company’s business strategies and polices. The
Governance Committee is responsible for director continuing education. Continuing education programs for
directors may include a combination of internally developed materials and presentations, programs presented by
third parties, and include financial and administrative support for attendance at academic or other independent
programs.
Director Retirement Policy
Directors may not stand for election after age 72.
Code of Business Conduct and Ethics
The Company has adopted a Code of Business Conduct and Ethics that applies to all of our employees, including
our CEO (the principal executive officer) and our CFO (the principal financial officer) and the Board.
17
ICNU_DR_032 Attachment A Page 24 of 90
ˆ200GZcqP7Jj@vRrhÊ
200GZcqP7Jj@vRrhˆ
836681 TX 18AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:57 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 9*
PMT 1C
SWRP64RS18
11.6.14
Information on Company Website
The Company’s Corporate Governance Guidelines, the Code of Business Conduct and Ethics, Categorical
Standards for Independence of Directors and the Related Party Transaction Policy are available on the
Company’s website at www.avistacorp.com. A written copy of any of these documents will be provided free of
charge to any person upon request to the General Counsel’s office at 1411 East Mission Avenue, P.O. Box 3727
(MSC-12), Spokane, Washington 99220.
Communications with Shareholders
Annually, the Company contacts a number of major shareholders to solicit information regarding issues of
concern to the shareholders with respect to corporate governance and executive compensation. Those discussions
are conducted by teleconference. The Company will continue to solicit shareholder input on issues of concern to
them.
Shareholders and other interested parties may send correspondence to our Board or to any individual director to
the Corporate Secretary’s office at 1411 East Mission Avenue, P.O. Box 3727 (MSC-10), Spokane, Washington
99220. Concerns about accounting, internal accounting controls or auditing matters should be directed to the
Chair of the Audit Committee at the same address. All communications will be forwarded to the person(s) to
whom they are addressed, unless it is determined that the communication:
• does not relate to the business or affairs of the Company or the functioning or constitution of the Board
or any of its Committees;
• relates to routine or insignificant matters that do not warrant the attention of the Board;
• is an advertisement or other commercial solicitation or communication;
• is frivolous or offensive; or
• is otherwise not appropriate for delivery to directors.
The director or directors who receive any such communication have discretion to determine whether the subject
matter of the communication should be brought to the attention of the full Board or one or more of its
Committees and whether any response to the person sending the communication is appropriate. Any such
response will be made through the Company’s Corporate Secretary or General Counsel and only in accordance
with the Company’s policies and procedures and applicable laws and regulations relating to the disclosure of
information.
Information About the Board Committees
The Board has six standing Committees—Audit Committee, Compensation and Organization Committee
(“Compensation Committee”), Governance/Nominating Committee (“Governance Committee”), Finance
Committee, Environmental and Operations Committee (“Environmental Committee”) and Executive Committee.
Each of these Committees is comprised solely of independent directors, with the exception of the Executive
Committee, which is chaired by Mr. Morris. The Committees, their membership during 2014, and their principal
responsibilities are described below.
Audit Compensation Governance Environmental Finance Executive
Blake (Chair) Taylor (Chair) Kelly (Chair) Klein (Chair) Anderson (Chair) Morris (Chair)
Burke Kelly Blake Anderson Burke Blake
Stanley Klein Racicot Racicot Stanley Kelly
Taylor Widmann(1) Widmann(2) Taylor
(1) Ms. Widmann joined the Environmental Committee effective August 2, 2014.
(2) Ms. Widmann joined the Finance Committee effective August 2, 2014.
18
ICNU_DR_032 Attachment A Page 25 of 90
ˆ200GZcqP7K1J8V#h@Š
200GZcqP7K1J8V#h@
836681 TX 19AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 23:59 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 7*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
Each Committee of the Board has adopted a charter that has been approved by the Board. The charters are
reviewed on a periodic basis and amendments are made as needed. Each Committee also performs an annual self-
assessment relative to its purpose, duties, and responsibilities. The Committee charters are located on the
Company’s website at www.avistacorp.com. A written copy of our Committee charters will be provided free of
charge to any person upon request to the General Counsel’s office at 1411 East Mission Avenue, P.O. Box 3727
(MSC-12), Spokane, Washington 99220.
Audit Committee—Assists the Board in overseeing the integrity of and the risks related to the Company’s
financial statements, the Company’s compliance program, the qualifications and independence of the
independent registered public accounting firm, the performance of the Company’s internal audit function and
independent registered public accounting firm, and the Company’s systems of internal controls regarding
accounting, financial reporting, disclosure, compliance and ethics that management and the Board have
established, including without limitation all internal controls established and maintained pursuant to the
Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the Sarbanes-Oxley Act of 2002 (the
“Sarbanes-Oxley Act”). The Audit Committee oversees the Company’s risk assessment and risk management
processes. Only independent directors sit on the Audit Committee. The Audit Committee consists of directors
Burke, Stanley, and Blake—Chair. The Board has determined that Mr. Burke is an “Audit Committee Financial
Expert,” as defined in the SEC rules. Six meetings were held in 2014.
Compensation Committee—Considers and approves, as well as oversees the risks associated with, compensation
and benefits of executive officers of the Company. The Compensation Committee is also responsible for
overseeing the organizational structure of the Company and succession planning for our CEO and executive
officers.
For a discussion of the Company’s processes and procedures for the consideration and determination of executive
officer compensation (including the role of executive officers and compensation consultants in determining or
recommending the amount or form of compensation) see the CD&A starting on page 26.
The Compensation Committee is composed of independent directors, as defined by the rules of the NYSE, and
within the Company’s Categorical Standards. In addition, the Compensation Committee complies with the
“outside director” requirements of Section 162(m) of the Internal Revenue Code of 1986, as amended (the
“Code”), and the “non-employee director” requirements of Rule 16b-3 under the Exchange Act.
Only independent directors sit on this Committee. The Committee consists of directors Kelly, Klein, and
Taylor—Chair. Five meetings were held in 2014.
Governance Committee—Advises the Board on corporate governance matters and oversees the risks relating to
such matters, including recommending guidelines for the composition and size of the Board and its committees,
evaluating Board effectiveness and organizational structure and setting director compensation (see the section on
Director Compensation on page 20). This Committee also develops Board membership criteria and reviews
potential director candidates. Recommendations for director nominees are presented to the full Board for
approval. See Proposal 1—“Director Qualifications and Process for Selecting Board Nominees” on page 5. Only
independent directors sit on this Committee. The Governance Committee consists of directors Blake, Racicot,
Taylor, and Kelly—Chair. Five meetings were held in 2014.
Environmental Committee—Assists the Board in overseeing risks associated with the Company’s business and
operational risks, other than financial risks. This includes regulatory compliance, environmental compliance,
energy resources, transmission and distribution operations, employee safety performance, corporate, cyber and
physical security, business continuity and technology strategy. Only independent directors sit on this Committee.
The Committee consists of directors Anderson, Racicot, Widmann and Klein—Chair. Four meetings were held in
2014.
19
ICNU_DR_032 Attachment A Page 26 of 90
ˆ200GZcqP7Jj#5rf7BŠ
200GZcqP7Jj#5rf7B
836681 TX 20AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
Finance Committee—Assists the Board in overseeing that corporate management has in place strategies,
budgets, forecasts, and financial plans and programs, including adequate liquidity, to enable the Company to
meet its goals and objectives and oversees the associated risks. The Finance Committee’s activities and
recommendations include reviewing management’s qualitative and quantitative financial plans and objectives for
both the short and long-term; approving strategies with appropriate action plans to help ensure that financial
objectives are met; having in place a system to monitor progress toward financial goals, including monitoring
commodity price and counterparty credit risk, as well as taking any necessary action; and overseeing and
monitoring employee benefit plan investment performance and approving changes in investment policies,
managers, and strategies. Only independent directors sit on this Committee. The Finance Committee consists of
directors Burke, Stanley, Widmann and Anderson—Chair. Five meetings were held in 2014.
Executive Committee—Has and may exercise, when the Board is not in session, all the powers of the Board that
may be lawfully delegated, subject to such limitations as may be provided in the Bylaws, by resolutions of the
Board, or by law. Generally, such action would only be taken to expedite Board authorization for certain
corporate business matters when circumstances do not allow the time, or when it is otherwise not practicable, for
the entire Board to meet. The Executive Committee consists of directors Blake, Kelly, Taylor, and Morris—
Chair. No meetings were held in 2014.
DIRECTOR COMPENSATION REPORT
Prior to September 12, 2014, directors who were not employees of the Company received an annual retainer of
$116,000, of which a minimum of $48,000 was paid in Company common stock each year. Directors had the
option of taking the remaining $68,000 in cash, stock or a combination of both cash and stock. The cash portion
of the retainer is paid quarterly. Directors were also paid $1,500 for each meeting of the Board or any Committee
meeting of the Board. Directors who served as Board Committee Chairs received an additional $7,500 annual
retainer, with the exception of the Audit Committee Chair, who received an additional $13,000 annual retainer
and the Compensation Committee Chair, who received an additional $10,000 annual retainer. The Lead Director
received an additional annual retainer of $20,000.
In addition, any non-employee director who served as a director of a subsidiary of the Company received from
the Company a $15,000 annual retainer and a meeting fee of $1,500 for each subsidiary Board meeting and
Committee meeting the director attended. The Audit Committee Chair of a subsidiary received an additional
annual chair retainer of $10,000. Directors Anderson, Blake, Burke and Kelly held Board positions with a
subsidiary of the Company until June 30, 2014, when the subsidiary was sold.
Each year, the Governance Committee reviews all components of director compensation. During 2014, the
Governance Committee engaged Meridian Compensation Partners LLC (“Meridian”) to assist in this review. The
information provided by Meridian was used to compare the Company’s current director compensation with peer
companies in the utility industry and general industry companies of similar size (the “Director Peer Group”). The
companies comprising the Director Peer Group are those companies in the S&P 400 Utilities Index.
At its September 3, 2014 meeting, the Board reviewed survey results from Meridian regarding current pay
practices for director compensation. The Board approved an increase in the annual retainer of an additional
$9,000, effective September 12, 2014. The total annual retainer is now $125,000 with $50,000 of the total
retainer to be paid in stock each year. Directors will have the option of taking the remaining $75,000 in cash,
stock or a combination of both cash and stock.
Each director is entitled to reimbursement of reasonable out-of-pocket expenses incurred in connection with
meetings of the Board or its Committees and related activities, including director education courses and
materials. These expenses include travel to and from the meetings, as well as any expenses they incur while
attending the meetings.
20
ICNU_DR_032 Attachment A Page 27 of 90
ˆ200GZcqP7Jj#FTx7"Š
200GZcqP7Jj#FTx7"
836681 TX 21AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
The Company has a minimum stock ownership expectation for all Board members. Outside directors are
expected to achieve a minimum investment of five times the minimum portion of their equity retainer payable in
Company common stock within five years of becoming a Board member, and retain at least that level of
investment during his/her tenure as a Board member. Shares previously deferred under the former Non-
Employee Director Stock Plan count for purposes of determining whether a director has achieved the ownership
expectation. Directors are prohibited from engaging in short-sales, pledging, or hedging the economic interest in
their Company shares.
The ownership expectation illustrates the Board’s philosophy of the importance of stock ownership for directors
to further strengthen the commonality of interest between the Board and shareholders. The Governance
Committee annually reviews director holdings to determine whether they meet ownership expectations. All
directors currently comply based on their years of service completed on the Board.
There were no annual stock option grants or non-stock incentive plan compensation payments to directors for
services in 2014 and none are currently contemplated under the current compensation structure. The Company
also does not provide a retirement plan or deferred compensation plan to its directors. Listed below is
compensation paid to each non-employee director who served during any part of the 2014 fiscal year.
Annual Retainer
All Other
Compensation
($)(2)
Total
Compensation($)Director Name
Fees Earned
or Paid in
Cash($)(1)
Director
Compensation
Paid in
Stock($)(1)
Erik J. Anderson . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$113,108 $ 49,017 $ 162,125
Kristianne Blake . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$126,608 $ 49,017 $ 3,200 $ 178,825
Donald C. Burke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $90,593 $ 67,032 $ 157,625
Rick R. Holley (3). . . . . . . . . . . . . . . . . . . . . . . . . . . . $23,833 $ 23,833
John F. Kelly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$136,108 $ 49,017 $ 185,125
Rebecca A. Klein . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $65,591 $ 83,034 $ 148,625
Marc F. Racicot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $93,608 $ 49,017 $ 142,625
Heidi B. Stanley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $95,108 $ 49,017 $ 144,125
R. John Taylor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$105,108 $ 49,017 $ 6,980 $ 161,105
Janet Widmann . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $42,605 $ 21,403 $ 64,008
Totals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$892,270 $465,571 $10,180 $1,368,021
(1) Prior to September 12, 2014, directors had the option of taking $68,000 of their annual retainer in Company
common stock, in cash, or in a combination of stock and cash. Amounts in these columns include cash
retainers, Chair retainers, Board and Committee meeting fees, and fees for directors sitting on a subsidiary
Board and attending subsidiary Board and Committee meetings. Anderson, Blake, Burke and Kelly were the
only directors who sat on a subsidiary Board in 2014.
(2) Amounts for Ms. Blake and Mr. Taylor include dividends paid on those shares that were deferred prior to
December 31, 2004, under the former Non-Employee Director Stock Plan. (Blake and Taylor are the only
directors who deferred receipt of stock until a later date. Ms. Blake has 2,519 deferred shares and
Mr. Taylor has 5,496 deferred shares.) The Company does not provide perquisites or other personal benefits
to its Board members.
(3) Mr. Holley resigned from the Board effective February 15, 2014.
21
ICNU_DR_032 Attachment A Page 28 of 90
ˆ200GZcqP7K1LQN%h}Š
200GZcqP7K1LQN%h}
836681 TX 22AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 00:01 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 8*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
PROPOSAL 2
PROPOSED AMENDMENT OF RESTATED ARTICLES OF INCORPORATION
TO REDUCE CERTAIN SHAREHOLDER APPROVAL REQUIREMENTS
General
The Board is proposing that the Company’s Articles, be amended to reduce the shareholder approval requirement
for specified matters from 80% of the total number of shares of common stock outstanding to a majority of such
shares outstanding.
Background
At the 2012, 2013 and 2014 Annual Meetings, the Board proposed amendments that would reduce the super
majority shareholder approval requirements for certain matters, and at the 2011 Annual Meeting, the
shareholders approved a shareholder resolution requesting that the Board take such action. At the 2012 Annual
Meeting, the shareholders approved amendments proposed by the Company that reduced the approval
requirement for certain matters from 66 2/3% to a majority of the outstanding shares of common stock. At the
same meeting, the shareholders were also asked to approve the proposed amendments that would have reduced
the approval requirement for certain other matters from 80% of the shares of common stock outstanding to a
majority of the shares outstanding. Those amendments had to be approved by holders of 80% of such shares but
were approved by the holders of only 74.62% of such shares. In light of the high approval percentage, the Board
determined to resubmit the proposal for consideration at the 2013 Annual Meeting. At that meeting, the holders
of 73.81% of such shares approved the amendment, which was short of the 80% required to approve the
amendment. The Board determined to resubmit the proposal again in 2014 and the holders of 70.79% of such
shares approved the amendment, which was again short of the 80% required to approve the amendment. Given
the continued high percentage of votes cast in favor of the proposal, the Board has determined to resubmit the
proposal to reduce the 80% approval requirement to a majority approval requirement for consideration at the
2015 Annual Meeting.
80% Approval Requirement for Certain Amendments
The Articles provide that various provisions of the Articles may not be amended or repealed, and inconsistent
provisions may not be included in the Articles or Bylaws, without the approval of the holders of 80% of the total
number of shares of common stock outstanding, including:
• the provisions regarding the number of directors, the filling of vacancies and the removal of directors by
shareholders;
• provisions regarding the calling of special meetings of shareholders;
• the “fair price” provision (described below);
• provisions regarding the adoption, alteration, amendment, change and repeal of the Bylaws of the
Corporation;
• the provisions of the Bylaws of the Corporation relating to procedures for the nomination of Directors;
and
• each provision requiring such 80% approval.
Proposal 2 would amend such provisions of the Articles to reduce such approval requirement to a majority of the
outstanding shares of common stock, consistent with Washington law. Proposal 2 would also clarify that such
provisions of the Articles do not impose any shareholder approval requirement in addition to the requirements, if
any, of Washington law with respect to any such amendment or provision that is approved by the Board. If
Proposal 2 is approved, the Board will amend provisions of the Company’s Bylaws that may be inconsistent
therewith or no longer necessary.
22
ICNU_DR_032 Attachment A Page 29 of 90
ˆ200GZcqP7Jj#c0G7cŠ
200GZcqP7Jj#c0G7c
836681 TX 23AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
Transactions with “Interested Shareholders”
The Articles require the approval of the holders of 80% of the total number of shares of common stock
outstanding for asset sales, mergers and certain other transactions with an Interested Shareholder (generally, a
holder of 10% of the outstanding shares of common stock) unless certain specified conditions are met. This
provision, which is sometimes called a “fair price” provision, was approved by the shareholders in 1987 in order
to afford protection against an unequal treatment to shareholders in the context of “two-tiered” or “front-end
loaded” tender offers.
Washington law requires the approval of the holders of at least two-thirds of the outstanding shares of common
stock for a sale of substantially all of the Company’s assets or for a merger of the Company into another entity;
provided, however, that Washington law permits a lower approval standard to be contained in the Articles, so
long as it is not less than a majority of all votes entitled to be cast. This lower standard was approved by the
shareholders at the 2012 Annual Meeting with respect to other provisions of the Articles dealing with sales of
assets and mergers. To be consistent with such other provisions, the Board proposal would amend the Articles to
require the approval by the holders of a majority of the outstanding shares of common stock for asset sales,
mergers and certain other transactions with an Interested Shareholder.
Approval of Proposal 2
Under the existing provisions of the Articles, as discussed above, and under Washington law, Proposal 2 would
be approved upon the affirmative vote of the holders of 80% of the outstanding shares of common stock.
Recommendation of the Board
In light of the apparent views of the Company’s shareholders, as evidenced by the high approval percentage for
this proposal at the 2012, 2013 and 2014 Annual Meetings, the Board has approved this Proposal 2 and believes
the Articles should be amended as described above. Accordingly, the Board recommends that the shareholders
approve Proposal 2.
The text of the relevant portions of Article FIFTH, Article SEVENTH and Article EIGHTH of the Articles, as
they would be amended if the proposal were adopted, is set forth in Appendix A to this proxy statement.
The Board recommends a vote “FOR” Proposal 2 to reduce shareholder approval requirements.
AUDIT COMMITTEE REPORT
In accordance with its written charter adopted by the Board, the Audit Committee assists the Board in fulfilling
its responsibility for oversight of the Company’s systems of internal controls, including, without limitation, those
established and maintained pursuant to the Exchange Act, as amended, and the Sarbanes-Oxley Act. The Audit
Committee also assists the Board in overseeing the integrity of the Company’s financial statements, the
Company’s compliance with legal and regulatory requirements, ethical standards and the independent auditor’s
qualifications and independence.
The Audit Committee is composed of directors who the Board has determined to be independent, as required by
the rules of the NYSE. In 2014, the Audit Committee met six times.
Prior to the inclusion of the financial statements in the Quarterly Reports on Form 10-Q for each of the first three
quarters of 2014 filed with the SEC, the Audit Committee reviewed the Company’s unaudited quarterly financial
statements and management’s discussion and analysis of financial condition and results of operation and
discussed them with management and Deloitte, the Company’s independent registered public accounting firm.
The Audit Committee reviewed with the CEO and CFO their certifications as to the accuracy of these financial
statements and the establishment and maintenance of internal controls and procedures. It also reviewed with
management all earnings press releases relating to 2014 annual and quarterly earnings prior to their issuance.
23
ICNU_DR_032 Attachment A Page 30 of 90
ˆ200GZcqP7Jj#i6w76Š
200GZcqP7Jj#i6w76
836681 TX 24AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
The Audit Committee reviewed and discussed the Company’s audited financial statements and management’s
discussion and analysis of financial condition and results of operations for the year ended December 31, 2014,
with management, which has primary responsibility for the financial statements, and with Deloitte, which is
responsible as the Company’s independent registered public accounting firm for the audit of those statements.
Based on its review and discussions, the Audit Committee recommended to the Board that the Company’s
audited financial statements be included in its Annual Report on Form 10-K for the year ended December 31,
2014, for filing with the SEC. The Board approved the recommendation.
The Audit Committee also reviewed Management’s Report on Internal Control Over Financial Reporting and the
Auditor’s Report on the effectiveness of internal control over financial reporting.
The Audit Committee reviewed and discussed with Deloitte all communications required by generally accepted
auditing standards, including those promulgated by the Public Company Accounting Oversight Board (PCAOB)
and by the SEC and, with and without management present, discussed and reviewed the results of the
independent auditor’s audit of the financial statements. The Audit Committee also discussed the results of the
internal audit examinations, received and reviewed quarterly risk management reports, and received and
reviewed annual compliance, technology and business continuity reports.
Deloitte provided the Audit Committee with the written communications required by the PCAOB Ethics and
Independence Rule 3526,Communication with Audit Committees Concerning Independence.The Audit
Committee discussed with Deloitte its internal quality-control reviews and procedures, the results of its external
reviews and inspections, and any relationships that might impact its objectivity and independence. The Audit
Committee also discussed with management, the internal auditors, and Deloitte, the quality and adequacy of the
Company’s systems of internal controls, and the internal audit functions, responsibilities, and staffing. The Audit
Committee reviewed the audit plans, audit scopes, and identification of audit risks of the independent and
internal auditors.
The Audit Committee reviewed and approved Deloitte’s services and fees. The Audit Committee, after reviewing
the performance of Deloitte, approved its reappointment in 2015 as the Company’s independent registered public
accounting firm. The Audit Committee also reviewed and approved the non-audit services performed by Deloitte
and concluded that such services were consistent with the maintenance of independence.
The Audit Committee performed the mandated tasks included in its charter. The Audit Committee also
recommended to the Board the designation of Donald C. Burke as Audit Committee Financial Expert solely for
the purposes of compliance with the rules and regulations of the SEC implementing Section 407 of the Sarbanes-
Oxley Act. The Board approved such recommendation.
Members of the Audit Committee of the Board
Kristianne Blake—Chair Donald C. Burke Heidi B. Stanley
PROPOSAL 3
RATIFICATION OF APPOINTMENT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
The Audit Committee has appointed Deloitte, as the Company’s independent registered public accounting firm
for continuing audit work in 2015. The Board has determined that it would be desirable to request that the
shareholders ratify such appointment. Deloitte has conducted consolidated annual audits of the Company for
many years, and is one of the world’s largest firms of certified public accountants. A representative of Deloitte is
expected to attend the 2015 Annual Meeting with the opportunity to make a statement if he/she desires to do so,
and is expected to be available to respond to appropriate questions.
24
ICNU_DR_032 Attachment A Page 31 of 90
ˆ200GZcqP7Jj#lcehhŠ
200GZcqP7Jj#lcehh
836681 TX 25AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 9*
PMT 1C
SWRP64RS18
11.6.14
Shareholder approval is not required for the appointment of Deloitte. However, the appointment is being
submitted to shareholders for ratification. Should the shareholders fail to ratify the appointment of Deloitte, such
failure (1) would have no effect on the validity of such appointment for 2015 (given the difficulty and expense of
changing the independent registered public accounting firm mid-way through a year) and (2) would be a factor to
be taken into account, together with other relevant factors, by the Audit Committee and by the full Board in the
selection and appointment of the independent registered public accounting firm for 2016 (but would not
necessarily be the determining factor).
The Board recommends a vote “FOR” the proposal to ratify the selection of Deloitte & Touche LLP as the
independent registered public accounting firm to audit the books, records, and accounts of the Company
for the year 2015.
Auditors Fees
Aggregate fees billed to the Company for the years ended December 31, 2014 and 2013 by Deloitte were as
follows:
2014 2013
Audit Fees (a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$1,939,850 $2,162,000
Audit-Related Fees (b). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .43,722 230,000
Tax Fees (c). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -80,000
All Other Fees (d). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .173,405 11,049
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$2,156,977 $2,483,049
(a) Audit services performed in 2014 and 2013 for which audit fees were billed consisted of:
• Audit of the Company’s annual consolidated financial statements and internal controls over financial
reporting.
• Reviews of the Company’s quarterly reports on Form 10-Q.
• Comfort letters, statutory and regulatory audits, consents, and other services related to SEC matters.
• Audits of subsidiary financial statements.
(b) Audit-related services performed in 2014 consisted of agreed-upon procedures and separate financial
statement audits of affiliated entities. And, audit-related services performed in 2013 consisted of internal
control audits, agreed-upon procedures and separate financial statement audits of affiliated entities.
(c) Tax services performed in 2013 consisted of income tax planning and advice.
(d) All other services performed in 2014 and 2013 consisted of internal control related services, licensing of
accounting literature research databases, attendance at training seminars, and other miscellaneous projects.
In considering the nature of the services provided by Deloitte, the Audit Committee determined that such
services are compatible with the provision of independent audit services. The Audit Committee discussed these
services with Deloitte and Company management to determine that they are permitted under the Sarbanes-Oxley
Act and under the rules and regulations concerning auditor independence promulgated by the SEC, the PCAOB,
and the American Institute of Certified Public Accountants.
Under the Sarbanes-Oxley Act, the Audit Committee is responsible for the appointment, compensation, and
oversight of the work of the Company’s independent registered public accounting firm. As part of this
responsibility, the Audit Committee is required to pre-approve the audit and permissible non-audit services to be
performed. The Audit Committee has adopted what it terms its Audit and Non-Audit Services Pre-Approval
Policy (the “Policy”), which sets forth the procedures and conditions pursuant to which services proposed to be
performed by the Company’s independent registered public accounting firm may be pre-approved. All services
provided by Deloitte in 2014 and 2013 were pre-approved in accordance with the Policy adopted by the Audit
Committee.
25
ICNU_DR_032 Attachment A Page 32 of 90
ˆ200GZcqP7K1PYvc78Š
200GZcqP7K1PYvc78
836681 TX 26AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 00:03 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 8*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
The SEC’s rules establish two alternatives for pre-approving services provided by the independent registered
public accounting firm. Engagements for proposed services may either be specifically pre-approved by the Audit
Committee (specific pre-approval) or entered into pursuant to detailed pre-approval policies and procedures
established by the Audit Committee, as long as in the latter circumstance the Audit Committee is informed on a
timely basis of any engagement entered into on such basis (general pre-approval). The Audit Committee
combined these two approaches in its Policy after concluding that doing so will result in an effective and efficient
procedure to pre-approve services to be performed by the Company’s independent registered public accounting
firm.
As set forth in the Policy, except for those categories of services for which the Policy requires specific pre-
approval, engagements may be entered into pursuant to general pre-approvals established by the Audit
Committee. The Audit Committee will periodically review and generally pre-approve the categories of services
that may, as contemplated by the Policy, be provided by the Company’s independent registered public accounting
firm without obtaining specific pre-approval from the Audit Committee, and will establish budgeted amounts for
such categories. The Audit Committee may add to or subtract from the list of general pre-approved services from
time-to-time, based on subsequent determinations by the Audit Committee. Any general pre-approval will be set
forth in writing and included in the Audit Committee minutes. Unless an engagement of the independent auditor
to provide a particular service is entered into pursuant to and in accordance with the Audit Committee’s general
pre-approval then in effect, the engagement will require specific pre-approval by the Audit Committee.
Proposed services exceeding pre-approved cost levels or budget amounts previously established by the Audit
Committee will also require specific pre-approval by the Audit Committee.
The Audit Committee intends to pre-approve services, whether specifically or pursuant to general pre-approvals,
only if the provision of such services is consistent with SEC and PCAOB rules on auditor independence and all
other applicable laws and regulations. In rendering specific or general pre-approvals, the Audit Committee will
consider whether the independent registered public accounting firm’s provision of specific services, or categories
of services, would be inconsistent with the independence of the auditor.
COMPENSATION DISCUSSION AND ANALYSIS
The purpose of this CD&A is to provide material information about the compensation objectives and policies for
our NEOs and to put in perspective the quantitative and narrative disclosures in the CD&A and the following
compensation tables. Our NEOs for 2014 were:
• Scott L. Morris, Chairman, President and CEO
• Mark T. Thies, Sr. Vice President, CFO and Treasurer
• Dennis P. Vermillion, Sr. Vice President, Environmental Compliance Officer (“ECO”) and President of
Avista Utilities
• Marian M. Durkin, Sr. Vice President, General Counsel and Chief Compliance Officer (“CCO”)
• Karen S. Feltes, Sr. Vice President, Human Resources and Corporate Secretary
The CD&A also describes the following:
• A summary of our business results and the alignment between executive pay and Company
performance;
• Our decision-making process on compensation design and pay levels, including our compensation
governance approach;
• Our compensation philosophy and objectives; and
• A detailed description of the elements of the Company’s executive compensation program.
26
ICNU_DR_032 Attachment A Page 33 of 90
ˆ200GZcqP7Kbv8u=heŠ
200GZcqP7Kbv8u=he
836681 TX 27AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 17:44 EST
CLN PSPOR
RR Donnelley ProFile SWRdennp0pa 8*
PMT 1C
CA8609AC451293
11.6.14
Executive Summary
In 2014, our CEO and the Board established performance goals for the Company and aligned the short-term and
long-term incentive plans with those goals. A key element of these plans allows us to focus on maintaining an
attractive financial profile while creating long-term value for shareholders and customers.
As shown below, utility and non-utility EPS exceeded targets and other operational targets were met, helping
produce a short-term incentive payout above target. ROE exceeded the target established for our CEO’s
performance-based RSUs, allowing a portion of his RSUs to vest. Finally, our three year TSR, determined on the
basis of total appreciation for the period 2012-2014 with all dividends reinvested, achieved 43rd percentile TSR
relative to the S&P 400 Utilities Index, resulting in a payment of 58% of targeted performance share awards
granted for that period.
2014 Executive Compensation Highlights
• The compensation earned by our NEOs in 2014 reflects our corporate performance for the fiscal year, as
well as the impact of the challenging economy;
• The Compensation Committee approved base salary adjustments ranging from 1.8% to 6.0% for our
NEOs based on market comparisons, its assessment of individual performance and other factors as
discussed in more detail below;
• Our 2014 utility and non-utility EPS performance exceeded target resulting in an annual cash incentive
payment of 150% of target, which was 150% of base salary for our CEO and 90% of base salary for our
other NEOs;
• For our CEO, our ROE exceeded the target; therefore one-third of his RSUs granted in 2012, 2013 and
2014 and the associated dividend equivalents vested and were paid;
• Our NEOs other than our CEO received one-third of their RSUs granted in each of 2012, 2013 and
2014, along with the associated dividend equivalents. The RSUs are time-based, and one-third vest each
year over a three-year period; and
• The Company’s relative TSR over the three-year performance period was above threshold performance
resulting in a 58% of target payout, and our NEOs earned a payment with respect to their 2012-2014
performance share award and the associated dividend equivalents.
Business Results Impact Compensation
We establish target compensation for our NEOs at the beginning of each performance period. Actual pay will be
at, above or below the target based on individual, organizational, and stock performance. Because a substantial
portion of each NEO’s compensation is in the form of equity, our NEO’s actual compensation rises or falls with
the stock price.
We employ several quantitative criteria to assess the performance of our NEOs. Our objectives include achieving
the EPS and ROE targets, exceeding TSR objectives relative to our peers, reducing our costs per customer,
improving customer satisfaction, improving our response time to natural gas emergency calls, and improving
reliability of service. The charts below illustrate the relationship between our 2014 performance and our CEO’s
2014 compensation.
27
ICNU_DR_032 Attachment A Page 34 of 90
ˆ200GZcqP7Jj#wGBh3Š
200GZcqP7Jj#wGBh3
836681 TX 28AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
g94m09-1.0
g32x80-1.0
Recent Performance Results: Select Annual Incentive Plan Metrics
Avista 2014 Target Avista Actual
$378.17 $363.64
Cost Per Customer
(FY 2014)
$50.00
$100.00
$150.00
$200.00
$250.00
$300.00
$350.00
$400.00
$450.00
$0.00
$0.12
$1.27
Non-Utilities Earnings Per
Share
(FY 2014)
$1.40
$1.20
$1.00
$0.80
$0.20
$0.40
$0.60
$0.00
$2.00
$1.80 $1.75 $1.83
Utilities Earnings Per Share
(FY 2014)
$1.60
$1.40
$1.20
$1.00
$0.80
$0.60
$0.40
$0.20
$0.00
Recent Performance Results: Long-Term Incentive Plan Metrics
5.59%
13.75%
Return on Equity
(FY 2014)
16.00%
0.00%
2.00%
6.00%
4.00%
10.00%
8.00%
14.00%
12.00%
62.0%57.0%
3-Year Cumulative TSR
(2012 - 2014)
70.0%
60.0%
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
Avista 2014 Target Avista Actual Peer Median Avista Actual
28
ICNU_DR_032 Attachment A Page 35 of 90
ˆ200GZcqP7K1hFwh7SŠ
200GZcqP7K1hFwh7S
836681 TX 29AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 00:08 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 9*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
g90c84-2.0
Chief Executive Officer: 2014 Target Compensation versus Realized Compensation
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
$3,500,000
Target Earned
Base Salary 2014 Annual Incentive RSUs*PSUs*
2014 actual pay
earned by the CEO
was 113% of
targeted value
$750,000 $747,114
$750,000
$1,120,642
$350,597
$506,143
$1,107,550
$964,554
$2,958,147
$3,338,453
* The target amount shown for our CEO’s RSUs represent the grant date fair value of the portion of awards
made in each of 2012, 2013 and 2014 that could have vested if the 2014 ROE performance condition was met.
The target amount for the CEO’s performance shares represent the aggregate grant date fair value of the 2012
awards that could have vested if the TSR performance conditions were met from 2012 through 2014. Value of
vested RSUs and PSUs includes dividends.
Compensation Governance Practices
The Company highly values strong compensation governance practices. We believe our executive compensation
practices align with our corporate values and provide a foundation for success. The governance practices that we
employ, and those that we avoid, include:
Practices We Employ Practices We Avoid
• Pay is closely linked to performance
• Undue risk is mitigated (see Risk Mitigation
Overview on page 31)
• Stock ownership guidelines have been
implemented consistent with market practices
• A recoupment (i.e., clawback) policy is in place
• Change-in-Control (“CIC”) severance requires
a double trigger
• Our Compensation Committee reviews NEO
tally sheets annually
• Our Compensation Committee is composed
entirely of independent directors
• Our Compensation Committee engages an
independent compensation consultant
• Our Compensation Committee regularly has
executive sessions without management present
• We do not provide perquisites
• We do not permit hedging or short sales of
company stock
• We do not provide dividends or dividend
equivalents on unearned performance
awards or RSUs
• We eliminated excise tax gross-ups for all
new executives after November 13, 2009
• We do not provide executive severance
except in connection with a CIC
• We do not provide additional Supplemental
Executive Retirement Plan (“SERP”)
service credits as a recruitment tool for
hiring executives
29
ICNU_DR_032 Attachment A Page 36 of 90
ˆ200GZcqP7K1jRCl7nŠ
200GZcqP7K1jRCl7n
836681 TX 30AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 00:09 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 7*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
2014 Say on Pay Advisory Vote
At the May 2014 Annual Meeting, shareholders expressed substantial support for the compensation of our NEOs,
with approximately 94.2% of the votes cast for the Say on Pay advisory resolution approving our executive
compensation. We view this outcome as a signal of strong shareholder support for our executive compensation
philosophy, policies and practices. In addition to considering the Say on Pay advisory vote, our Senior Vice
President, CFO and Treasurer; Senior Vice President, Human Resources and Corporate Secretary; and Senior
Vice President, General Counsel and CCO proactively solicit input from shareholders regarding our governance
and executive compensation programs. We believe this outreach to shareholders, together with our shareholders’
ability to contact us at any time to express specific views on executive compensation, fosters open dialogue to
assure we maintain the consistency and credibility of the program.
Following the 2014 Annual Meeting, we discussed our overall approach to executive compensation and
governance and took into consideration feedback we received from meetings with various shareholders. Based on
the feedback received and the results of the Say on Pay advisory vote, no significant changes were made during
2014 to our overall approach to executive compensation and governance.
Decision Making Process
Role of the Compensation Committee
The Compensation Committee makes all compensation decisions regarding our CEO, our other NEOs and other
executive officers, including the level of cash compensation and equity awards. Our CEO annually reviews each
executive officer’s performance ratings as determined by his or her direct manager and presents the ratings to the
Compensation Committee for it to consider with respect to salary adjustments, annual incentive opportunity, and
annual equity award amounts.
Role of the Compensation Consultant
The Compensation Committee selects and retains an independent compensation consultant to support its
oversight of our executive compensation programs. For 2014, the Compensation Committee engaged Meridian as
its independent compensation consultant. Meridian provides to the Compensation Committee consulting services
solely relating to executive compensation and governance matters. In accordance with NYSE rules, the
Compensation Committee determined that Meridian is independent and, further, that no conflict of interest exists
between Meridian and the Company.
A representative of Meridian attended Compensation Committee meetings in 2014 and advised the
Compensation Committee on all principal aspects of executive compensation, including the competitiveness of
program design and award values and specific analyses with respect to our executive officers.
The Compensation Committee determines the work to be performed by Meridian. Meridian works with our
Senior Vice President of Human Resources and her staff to gather data required in preparing the Meridian’s
analyses for Compensation Committee review, but does not otherwise provide any services or advice to
management.
While it is necessary for Meridian to interact with management to gather information and obtain
recommendations, the Compensation Committee Chair determines if and when Meridian’s advice and
recommendations can be shared with management. Ultimately, Meridian provides recommendations and advice
to the Compensation Committee in an executive session without Company management present, which is when
important pay decisions are made. This approach ensures the Compensation Committee receives objective advice
from Meridian so that the Compensation Committee may make independent decisions about executive pay.
30
ICNU_DR_032 Attachment A Page 37 of 90
ˆ200GZcqP7Jj$6Hdh3Š
200GZcqP7Jj$6Hdh3
836681 TX 31AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 6*
PMT 1C
SWRP64RS18
11.6.14
Role of Management
Whereas Meridian makes recommendations to the Compensation Committee as to the amount and form of
executive compensation for all executive officers including our CEO, our CEO has input on the
recommendations to the Compensation Committee with respect to the compensation of all of our executive
officers (other than with respect to compensation of the CEO).
At the request of the Compensation Committee, both the Senior Vice President of Human Resources and our
CEO regularly attend Compensation Committee meetings, excluding the executive sessions during which their
respective compensation and other matters are discussed.
Risk Mitigation Overview
The Compensation Committee believes that the Company’s compensation policies and practices do not create
risks that are reasonably likely to have a material adverse effect on the Company. In establishing pay practices
for the Company, the goal is to design a compensation structure that does not encourage inappropriate risk-taking
by employees or executive officers. Therefore, enterprise risk management is integral to the overall
compensation philosophy. The following features of the compensation structure reflect this approach:
• Short and long-term incentive payments are capped;
• Annual cash incentive design balances key performance metrics that are focused on financial results and
system sustainability over time;
• The total compensation program does not guarantee bonuses and has multiple financial and non-
financial performance measures;
• The Compensation Committee reviews both short-term and long-term financial scenarios to ensure the
plan design does not encourage executives to take excessive risks but also does not discourage
appropriate risks;
• Stock ownership guidelines are in place to strengthen the alignment of the financial interests of
executives with those of shareholders;
• Officers are prohibited from engaging in short-sales, pledging, or hedging the economic interest in their
Company shares; and
• The Company maintains a formal recoupment policy.
Elements of Compensation
Compensation Philosophy and Objectives
The Compensation Committee approves and implements a compensation program that focuses executives on the
achievement of specific annual, long-term, and strategic goals that align executives’ interests with those of
shareholders by rewarding performance that maintains and improves shareholder value. The Compensation
Committee believes that the overall compensation of our senior executives should be weighted toward variable
performance-based compensation, linking a significant portion of their compensation with goals related to
specific items of corporate performance that are likely to produce long-term shareholder and customer value.
31
ICNU_DR_032 Attachment A Page 38 of 90
ˆ200GZcqP7Jj$BX77iŠ
200GZcqP7Jj$BX77i
836681 TX 32AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
g75c98-2.0
g24v29-2.0
The charts below show the portion of target compensation that is variable and therefore is “at risk” for our CEO
and the average for our other NEOs. Variable compensation includes: annual incentives, RSUs and performance
shares. The charts also show the portion of target compensation for our CEO and the average for our other NEOs
that is directly linked to share value. Share value compensation includes RSUs and performance shares.
Salary
24%
Annual
Incentive
22%
Performance
Shares
40%
RSUs
14%
CEO Target Pay Mix
RSUs
11%
Salary
34%
Annual
Incentive
21%
Performance
Shares
34%
Other NEOs Target Pay Mix
Variable 76%Variable 66%
Linked to Share Value 54% Linked to Share Value 45%
Competitive Analysis and Peer Group
The Compensation Committee believes it is important to provide a compensation structure that is competitive
with compensation paid to comparable executives of companies within the energy/utility industry to ensure the
Company attracts and retains quality employees in key positions to lead the Company. To achieve this objective,
the Compensation Committee works with Meridian to conduct an annual competitive review of its total
compensation program for our CEO and other NEOs. Through the review process, the Compensation Committee
generally targets overall total compensation levels (base, short-term incentive and long-term incentives) within
the range that is 15% above and below the median of the peer group. Pay components for an NEO may be higher
or lower than the median depending on an individual’s role, responsibilities, and performance within the
Company. The Compensation Committee believes this target positioning is effective to attract and retain our
executives.
32
ICNU_DR_032 Attachment A Page 39 of 90
ˆ200GZcqP7Jj$L4T7?Š
200GZcqP7Jj$L4T7?
836681 TX 33AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
The Compensation Committee annually compares each element of NEO total compensation against a peer group
of publicly-traded companies within the energy/utility industry of similar revenue size and market capitalization.
In previous years, the Compensation Committee followed its benchmarking approach to focus on compensation
as disclosed in proxy statements. For 2014, our NEO compensation was compared with market data from a
customized group of utilities (“Proxy Peer Group”) to better represent the Company’s business, size and
competitive market for talent. All market data from the Proxy Peer Group was gathered from publicly available
sources, including proxy statements, Form 8-Ks, and Form 4s. The use of publicly disclosed data allows the
Company to maintain a consistent peer group without being restricted by private survey participation, which
varies year to year. For the Proxy Peer Group in 2014, the Committee used eighteen companies from the S&P
400 Utilities Index because the Compensation Committee believes the companies in the Proxy Peer Group better
represent the Company’s competitors for executive officers. The median revenues and market capitalization of
the Proxy Peer Group were $2.2 billion and $4.0 billion, respectively, as compared with Avista’s revenues of
$1.5 billion and market capitalization of $1.6 billion. The companies comprising the Proxy Peer Group were:
Alliant Energy Corporation Hawaiian Electric Industries, Inc. PNM Resources, Inc.
Aqua America, Inc. IDACORP, Inc. Questar
Atmos Energy Corporation MDU Resources Group, Inc. UGI Corporation
Black Hills Corporation National Fuel Gas Company Vectren Corporation
Cleco Corporation NV Energy, Inc. Westar Energy, Inc.
Great Plains Energy, Inc. OGE Energy Corporation WGL Holdings, Inc.
As in prior years, for 2014 the Compensation Committee also used the Towers Watson Energy Services
Executive Compensation database for additional compensation data on comparable diversified energy companies
with revenues between $1 billion and $3 billion. The median revenues of the companies in the survey were $1.6
billion. The advantage of also considering survey information is that it provides competitive data for all of our
executive officer positions. The Compensation Committee uses all of these sources of data to help it make
informed decisions about market compensation practices.
Performance Management
The Compensation Committee believes in aligning pay with performance. As part of that alignment, all
executives receive annual performance reviews conducted by their direct manager, and the Compensation
Committee reviews the performance ratings of each NEO. For each NEO, the Compensation Committee also
reviews the results of the Company’s 360-degree survey, which is a standardized performance survey conducted
periodically on multiple leadership performance categories that includes feedback from peers within the
Company, direct reports, and the NEO’s direct manager.
At the beginning of each calendar year, the Compensation Committee has our CEO develop specific performance
targets and goals for his role based on strategic goals set by the Board. The Compensation Committee reviews
and approves our CEO’s goals at its annual February meeting and presents the goals to the full Board for its
information and review. The Compensation Committee reviews quarterly our CEO’s performance relative to his
targets and provides quarterly status updates to the full Board. At the end of the year, the Compensation
Committee reviews our CEO’s year-end results as part of its overall CEO annual performance review process.
Base Salary
Our NEOs are provided with an annual base salary to compensate them for services rendered during the year.
The Compensation Committee reviews the base salary of all executive officers at least annually. The factors that
influence the Compensation Committee’s decisions in setting the annual base salary for our NEOs include the
market data provided by its consultant and each NEO’s job complexity, experience and breadth of knowledge in
the utility and diversified energy industry. The Compensation Committee also considers each NEO’s
responsibilities, which may include electric and natural gas utility operations, as well as subsidiary operations,
and recognizes that the Company operates in several states, thereby requiring quality relationships and
interaction with multiple regulatory agencies.
33
ICNU_DR_032 Attachment A Page 40 of 90
ˆ200GZcqP7Jj$Y8Th*Š
200GZcqP7Jj$Y8Th*
836681 TX 34AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 6*
PMT 1C
SWRP64RS18
11.6.14
2014 Base Salaries
In addition to considering the factors noted above, the Compensation Committee also reviews performance
results from the prior year to determine how our CEO performed against specific targets and operational goals
established at the beginning of the prior year. Our CEO’s annual performance goals for 2013 were generally
related to strategic planning, financial performance, safety targets, diversified energy resource management,
regulatory and legislative matters, succession planning, governance, and customer value delivery. When
reviewing the CEO’s base salary for 2014, the Compensation Committee agreed that our CEO had met the
established goals for 2013 performance.
The Compensation Committee also reviewed performance ratings of each of the other NEOs to determine
appropriate adjustments in base salary. The Compensation Committee noted that the market data provided by
Meridian showed that the base salary for several NEOs were below the median of their market levels, specifically
for Marian Durkin and Karen Feltes. After the adjustments shown below, base salaries generally are within the
range that is 15% above and below the median of the Proxy Peer Group. The table below outlines the changes to
base salary in 2014 for our NEOs.
2013 Salary
%
Increase 2014 Salary
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$735,000 2.0% $750,000
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$390,000 2.1% $398,000
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$352,000 1.8% $358,500
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$315,000 6.0% $334,000
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$285,000 5.3% $300,000
2014 Executive Officer Annual Cash Incentive
The 2014 Executive Officer Annual Cash Incentive Plan (the “Cash Incentive Plan”) was designed to align the
interests of our NEOs and senior management with both shareholder and customer interests to achieve overall
positive financial and operational performance for the Company. The Cash Incentive Plan reflects these goals by
having 60% of the total incentive opportunity tied to EPS targets and the remaining 40% tied to key components
of utility operation. Each metric is independent, which allows the Cash Incentive Plan to pay a portion of the
award upon the attainment of one goal even if the other goals are not met.
The Cash Incentive Plan’s performance metrics are based on factors that are essential for the long-term success
of the Company, and, with the exception of the EPS goals, are identical to performance metrics used in the
Company’s annual cash incentive plan for non-executive employees. The Compensation Committee believes that
having similar metrics for both the Cash Incentive Plan and the non-executive plan encourages employees at all
levels of the Company to focus on common objectives.
34
ICNU_DR_032 Attachment A Page 41 of 90
ˆ200GZcqP7K1pDj2h0Š
200GZcqP7K1pDj2h0
836681 TX 35AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 00:12 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 11*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
g04v45-2.0
The following chart shows the Cash Incentive Plan performance goals for each performance metric, the
weighting of each metric, and the 2014 actual results of each metric.
Metric Weighting Threshold Target Exceeds Actual
2014
Results
Earnings Components
Utility EPS* 50% $ 1.68 $ 1.75 $ 1.82 $ 1.87 Met 167%
Payout can vary 0%-167% based on performance level.
Non-Utility EPS* 10% $ 0.09 $ 0.12 $ 0.15 $ 1.27 Met 167%
Payout can vary 0%-167% based on performance level.
Utility Operations Components
Cost Per Customer* 20% $380.18 $378.17 $371.48 $363.64 Met 150%
The Operating and Maintenance (O&M) cost is directly related to maintaining reliable, cost-effective
service levels. Payouts can vary 0%-150% based on performance level.
Customer Satisfaction Rating 8% NA 90% NA 95% Met 100%
This rating is derived from a Voice of the Customer survey conducted each quarter by an independent
agency. The survey is used to track satisfaction levels of customers that have had recent contact with our
call center or service center. This is a hit or miss target and the payout is either 100% or 0% based on
achievement of objective.
Reliability Index 8% NA 1.00 NA 1.21 Met 100%
This measure is derived from the combination of three indices that track average restoration time for
sustained outages, average number of sustained outages per customer, and percent of customers
experiencing more than three sustained outages during the year. This is a hit or miss target and the payout is
either 100% or 0% based on achievement of objective.
Response Time 4% NA 93% NA 97% Met 100%
This measures the percentage of time the Company responds within targeted time goals for dispatched
natural gas emergency calls. This is a hit or miss target and the payout is either 100% or 0% based on
achievement of objective.
* Payout levels are interpolated on a straight-line basis for results between the threshold performance level and
the maximum level.
The Compensation Committee sets target goals for these performance metrics that are rigorous, but reasonably
achievable with strong management performance. Maximum performance levels were designed to be difficult to
achieve given historical performance and the Company’s forecasted results at the time the performance metrics
were approved. Over the last ten years, the actual performance results of the Plans have averaged 90% of target
and ranged from a low of 15% of target to a high of 150% of target as shown in the chart below.
Actual Results as % of Target
160%
120%
140%
100%
80%
60%
40%
20%
0%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Averag
e
Target Actual % of Target
82%
114%
71%
103%
90%
41%
125%
90%
150%
15%
111%
35
ICNU_DR_032 Attachment A Page 42 of 90
ˆ200GZcqP7KBsBn07iŠ
200GZcqP7KBsBn07i
836681 TX 36AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 05:30 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 9*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
2014 Executive Officer Annual Cash Incentive Target Award Opportunity
Individual annual cash incentive awards are set as a percentage of base salary. The Compensation Committee
compares annual cash incentive opportunity levels against the Proxy Peer Group. As discussed previously, the
Compensation Committee targets overall total compensation levels, which include base salaries, short-term
incentives and long-term incentives within a range of 15% above or below the market median. For 2014, the
market data provided to the Compensation Committee indicated an increase in target incentive award opportunity
from 90% to 100% of base salary for our CEO. The Committee maintained the 60% target opportunity for all
other NEOs, which aligns with the range of 15% above or below the market median. The actual total amounts
paid could increase (up to 150% of target) or decrease (as low as 0% of target) depending on the Company’s
actual performance.
2014 Results for the Executive Officer’s Annual Cash Incentive Plan
After the end of the year, the Compensation Committee assesses the performance of the Company against each
Plan objective, comparing the actual year-end results to the pre-determined threshold, target, and exceeds levels
for each objective, and an overall percentage amount for meeting the objectives is calculated and audited. The
results also are reviewed by the Finance Committee.
Based on this review, at its February 2015 meeting, the Compensation Committee determined that the Company
satisfied the maximum performance level for Utility EPS and Non-Utility EPS. The Company exceeded the
target performance level for O&M Cost Per Customer and met the targets for all three non-financial metrics:
customer satisfaction, reliability, and response time. The actual performance result of the 2014 executive
officer’s annual cash incentive plan was 150% of target. As a result, and at the same meeting, the Compensation
Committee authorized payment of cash incentives equal to 150% of base salary (150% of 100%) for our CEO,
and 90% of base salary (150% of 60%) for all our other NEOs.
Ecova-Related Cash Incentive
The Company’s NEOs provided significant support and oversight of the Ecova business. In recognition of their
support of Ecova and their contribution to its value, the Compensation Committee awarded a cash payment to the
four NEOs below in the amounts indicated. The amounts were paid following the sale of the Ecova business.
NEO Cash Payment
Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$191,506
Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$153,127
Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$121,127
Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$104,127
Long-Term Equity Compensation
The Compensation Committee believes that equity-based compensation is the most effective way to create a
long-term link between shareholder returns and the compensation provided to NEOs and other key management.
This program encourages participants to focus on long-term Company performance and provides an opportunity
for executive officers and designated key employees to maintain ownership in the Company through grants of
Company stock that can be earned based on either service or performance, and sometimes both, over a three-year
cycle. Through the use of long-term performance awards and RSUs, the Company can compensate executives for
sustained increases in the Company’s stock performance, as well as long-term growth relative to its peer group
for the relevant cycle.
The Company’s current LTIP authorizes various types of equity awards. As with all the components of executive
compensation, the Compensation Committee determines all material aspects of the long-term incentive awards—
who receives an award, the form of the award, the amount of the award, the timing of the award, as well as any
36
ICNU_DR_032 Attachment A Page 43 of 90
ˆ200GZcqP7KBsKeY7]Š
200GZcqP7KBsKeY7]
836681 TX 37AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 05:30 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 10*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
g08r90-2.0
other aspect of the award it may deem material. For 2014, our program continued to be heavily weighted toward
“performance-based” equity awards, 75% of the value being granted in the form of performance shares and 25%
being granted in the form of RSUs that vest based on continued service.
When deciding grant amounts, the Compensation Committee considers competitive market data and which
executives have the greatest ability to influence overall Company performance. In addition, and as previously
discussed, the Compensation Committee targets overall total compensation levels, which include base salaries,
short-term incentives and long-term incentive within a range of 15% above or below the median of the Proxy
Peer Group.
Performance-Based Equity Awards
Our performance-based equity awards are designed to provide a direct link to the long-term interests of
shareholders by assuring that shares will be paid only if the Company attains specified performance levels. In
previous years, vesting of performance-based equity awards were 100% contingent on the Company’s TSR
performance relative to our peers over a three-year period. In 2014, the Compensation Committee added
cumulative EPS (“CEPS”) to the mix. Under the new design, used for 2014 performance-based equity awards,
two-thirds of the awards are contingent on TSR relative to our peers and one-third is measured by our CEPS over
a three-year period.
LTI Plan Mix
Performance
Shares, 75%RSUs, 25%
CEPS, 33%
TSR, 67%
The peer group for TSR performance purposes consists of all companies comprising the S&P 400 Utilities Index
as of January 1 in the first year of the three-year performance cycle. Throughout the course of the performance
cycle, companies may be added or dropped from the index by S&P due to mergers or other activities. At the end
of the cycle, new companies that were added to the index are included in the rankings as if they had been in the
ranking from the beginning, provided there is sufficient trading history to include them in the final calculation.
When a company is dropped from the index, everything related to the company is excluded as if it were never in
the index. The amount of the payment with respect to any award is determined at the end of the three-year
performance cycle based on the Company’s percentile rate-of-return ranking compared to that of the companies
in the S&P 400 Utilities Index, and is payable at the Compensation Committee’s discretion in cash, shares of
Company common stock, or a combination of both. Dividend equivalents on performance awards are
accumulated and paid upon vesting if the awards vest and are paid based on performance. If the Company’s
relative TSR over the three-year performance period is below the threshold performance required to earn the
award, then the accumulated dividends are forfeited as well.
In 2014, the Compensation Committee added a second performance metric, CEPS, to align with current
competitive practices within the peer group based on market data provided by the Compensation Committee’s
consultant. The performance metric CEPS provides for performance awards if the Company’s CEPS grows over
the three-year performance period between 3.00% and 6.00% compounded annually. CEPS is fully diluted
earnings per share determined in accordance with generally accepted accounting principles. The amount of the
37
ICNU_DR_032 Attachment A Page 44 of 90
ˆ200GZcqP7Jj$!aL7uŠ
200GZcqP7Jj$!aL7u
836681 TX 38AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:58 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 11*
PMT 1C
SWRP64RS18
11.6.14
payment with respect to any award is determined at the end of the three-year performance cycle based on the
Company’s compounded growth, and is payable at the Compensation Committee’s discretion in cash, shares of
Company common stock, or a combination of both. Dividend equivalents on performance awards are
accumulated and paid upon vesting if the awards vest and are paid based on performance. If the Company’s
CEPS over the three-year performance period is below the threshold performance required to earn the award,
then the accumulated dividends are forfeited as well.
Range of Award Opportunity for Performance Shares
Each year, the Compensation Committee approves a grant of performance shares at target to each NEO that vest
over a three-year performance cycle based on achieving pre-determined performance goals. The number of
performance shares that may be earned at the end of the cycle can range from 0% to 200% of the target number
of performance shares granted, depending upon the level of performance.
Individual grant amounts are set at the beginning of each year. The Compensation Committee compares long-
term incentive opportunity levels against the Proxy Peer Group. As discussed previously, the Compensation
Committee targets overall total compensation levels that include base salaries, short-term incentives and long-
term incentives within a range of 15% above or below the market median. In 2014, the Compensation Committee
noted that the market data provided by Meridian showed gaps between the total compensation levels for our CEO
and all other NEO’s to the market median of the Proxy Peer Group. To reduce those gaps for 2014, adjustments
were made to the target number of performance shares granted to our NEOs. The table below shows the changes
made to the target number of performance share grants in 2014 for the performance period between 2014 and
2016 for our NEOs.
2013 Grant(#)
%
Change 2014 Grant(#)
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .42,500 6.6% 45,300
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12,000 20.0% 14,400
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12,500 (7.0%) 11,625
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12,000 (6.25%) 11,250
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12,000 (6.25%) 11,250
Two-thirds of the awards are contingent on TSR relative to our peers and one-third is measured by our CEPS
over a three-year period. The table below outlines the target number of performance share grants in 2014 split
between the two performance metrics.
Relative TSR Cumulative EPS 2014 Grant(#)
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30,200 15,100 45,300
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9,600 4,800 14,400
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . .7,750 3,875 11,625
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . .7,500 3,750 11,250
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7,500 3,750 11,250
38
ICNU_DR_032 Attachment A Page 45 of 90
ˆ200GZcqP7Jxus9Z7iŠ
200GZcqP7Jxus9Z7i
836681 TX 39AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 17:47 EST
CLN PSPOR
RR Donnelley ProFile SWRdhraj0dc 9*
PMT 1C
ACXFBU-MWE-XN01
11.6.14
g87n44-2.0
g12r67-2.0
The following graphs represent the relationship between the Company’s performance targets and the award
opportunity.
40th
Min
45th 50th
Target
60th 70th 85th 100th
Max
0%
50%
100%
150%
200%
Aw
a
r
d

O
p
p
o
r
t
u
n
i
t
y
3-year Relative TSR Percentile Rank
3%
Min
0.0375 4.5%
Target
0.0525 6%
Max
0
0.5
1
1.5
2
Aw
a
r
d

O
p
p
o
r
t
u
n
i
t
y
3-year Growth Cumulative EPS
2012-2014 Performance Shares Settlement
For performance shares granted in 2012 for the performance period ending December 31, 2014, the
Compensation Committee held a special meeting on January 9, 2015 to review, certify, and settle the issuance of
shares to executive officers. The Company’s TSR was 57% during the three-year performance cycle, which
placed the Company at the 43rd percentile among the S&P 400 Utilities Index. Based on these results, our CEO
and our other NEOs earned 58% of the performance share awards granted in 2012. Accrued cash dividend
equivalents were paid out on performance shares covered by the 2012 grant.
Realized Value Received
NEO Performance Share Awards Total
Realized
Value#Value
Dividend
Equivalents
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24,650 $874,582 $89,973 $964,555
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6,960 $246,941 $25,404 $272,345
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7,250 $257,230 $26,463 $283,693
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6,960 $246,941 $25,404 $272,345
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6,960 $246,941 $25,404 $272,345
Restricted Stock Units
The Company awards RSUs to improve retention and link compensation to the value of the Company common
stock. For all NEOs and other executive officers other than our CEO, the vesting of RSUs is time-based, and the
RSUs vest and shares are issued in three equal annual increments, provided the executive remains employed by
the Company on the last day of each year of the three-year period. Dividend equivalents on time-based RSUs
accrue and are paid in cash if and when the underlying RSUs vest. If the related RSUs are forfeited, the accrued
cash dividends are also forfeited.
For our CEO, the RSUs vest and shares are issued in three equal annual increments provided our CEO remains
employed by the Company on the last day of each year of the three-year period and the Company has attained the
performance target. In order for any annual portion of our CEO’s RSUs to vest, the Company’s ROE for the year
must exceed a hurdle rate equal to the Company’s weighted average cost of debt. Dividend equivalents accrue on
the unvested RSUs and, if the performance target is met, the dividend equivalents are paid in cash at the same
time that the underlying RSUs vest and are issued in shares. If the Company does not achieve the minimum ROE
performance target for the year, no shares or dividend equivalents are earned by our CEO.
39
ICNU_DR_032 Attachment A Page 46 of 90
ˆ200GZcqP7K1wWpnhÊ
200GZcqP7K1wWpnhˆ
836681 TX 40AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 00:16 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 7*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
Using a weighted average cost of debt, the Compensation Committee determined early in 2014 that a 5.59% ROE
hurdle rate was appropriate for 2014. For 2014, we achieved an ROE of 13.75% and the hurdle rate was met;
therefore, one-third of our CEO’s RSUs granted during each of 2012, 2013, and 2014 vested and shares were
issued along with the associated cash dividend equivalents.
Realized Value Received
NEO Restricted Stock Units Total
Realized
Value#Value
Dividend
Equivalents
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13,100 $488,237 $34,543 $522,780
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5,600 $198,464 $12,446 $210,910
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5,358 $189,888 $11,397 $201,285
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5,250 $186,060 $11,113 $197,173
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5,250 $186,060 $11,113 $197,173
Performance Based Stock Options
In February 2012, the Ecova Board approved a one-time grant of performance-based non-qualified stock options
(“NQSOs”) for our NEOs who also served as officers of Ecova. This included all NEOs with the exception of
Mr. Vermillion, who did not serve as an officer of Ecova. The Compensation Committee agreed to have the
Ecova Board take this action as they believed it was in the shareholder’s interest that our NEOs be motivated to
drive and maximize the value of Ecova’s business and be rewarded when certain performance metrics were
achieved at Ecova. The intent of the grant was to provide a target opportunity equal to approximately 50% of
each executive’s base salary. The vesting of the NQSOs was performance-based—one-third of the NQSOs were
scheduled to vest in each of 2013, 2014 and 2015 if Ecova achieved 15% growth in earnings before interest,
taxes, depreciation and amortization (“EBITDA”) for the relevant year; however, if Ecova achieved a cumulative
EBITDA growth rate of 30% after two years or 45% after three years, then all previously unvested NQSOs
would vest. If the performance condition was not met, the NQSOs would not vest.
Upon the sale of Ecova in 2014, all Ecova stock options held by Avista NEOs became fully vested and were
cashed out based upon the value of Ecova shares at the time of the sale. Additional information regarding the
Ecova options that were exercised can be found in the Summary Compensation Table and the Option Exercise
table below.
Perquisites
The Company does not provide any perquisites or personal benefits to our CEO or any other NEO.
Other Benefits
All regular employees, including our NEOs, are eligible for the Company’s defined benefit plan, the Company’s
401(k) plan, health and dental coverage, Company-paid term life insurance, disability insurance, paid time off,
and paid holidays.
The Company’s retirement plan for all employees provides a traditional retirement benefit based on employees’
compensation and years of credited service. Earnings credited for retirement purposes represent the final average
annual base salary of the employee for the highest 36 consecutive months during the last 120 months of service
with the Company.
Supplemental Executive Retirement Plan
In addition to the Company’s retirement plan for all employees, the Company provides additional pension
benefits through the SERP to the Company’s executive officers. Details of the SERP benefits and the amounts
accrued by each NEO are found in the Pension Benefits section on page 48.
40
ICNU_DR_032 Attachment A Page 47 of 90
ˆ200GZcqP7K1yfYD74Š
200GZcqP7K1yfYD74
836681 TX 41AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 00:17 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 5*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
The Compensation Committee believes the pension plans and the SERP are an important part of our NEOs
compensation. These plans are market competitive within the energy/utility industry and serve a critically
important role in the retention of senior executives. The benefits increase each year these executives remain
employed, thereby encouraging our most senior executives to remain employed and continue their work on
behalf of shareholders.
Executive Deferred Compensation
The Company also maintains an Executive Deferred Compensation Plan (the “EDC Plan”). Each NEO may
voluntarily participate in this EDC Plan on the same terms and conditions as all other eligible employees who
reach a set compensation level. This EDC Plan is competitive in the market and provides eligible employees and
executives with a tax-efficient savings method. Additional information about this EDC Plan, including 2014
contributions and year-end account balances, can be found in the Non-Qualified Deferred Compensation Plan
table on page 49.
Company Self-Funded Death Benefit Plan
To provide death benefits to beneficiaries of executive officers who die during their term of office, the Company
maintains an executive death benefit plan that will provide an executive officer’s designated beneficiary with a
lump sum payment equal to twice the executive officer’s final annual base salary, payable within 30 days of the
executive’s death. Prior to January 1, 2008, the plan continued to provide the death benefit to the beneficiaries of
executives who died after retirement. Effective January 1, 2008, the post-retirement death benefit was eliminated
for any individual who became an executive officer after that date. Individuals who were executive officers prior
to January 1, 2008 continue to be eligible for the post-retirement death benefit. For an officer who is eligible for
the post-retirement death benefit, in the event of his or her death after retirement, the designated beneficiary will
receive a lump sum equal to twice the retired executive officer’s total annual pension benefit. Death benefits are
paid from the general assets of the Company. The present value of this benefit for each NEO can be found in the
Potential Payment Upon Termination or Change in Control Tables starting on page 49.
Supplemental Executive Disability Plan
The Supplemental Executive Disability Plan provides benefits to the Company’s executive officers who become
disabled during employment. The plan provides a benefit equal to 60% of the executive officer’s annual salary at
the date of disability reduced by the aggregate amount, if any, of disability benefits provided for under the
Company’s Long-Term Disability Plan for employees, workers’ compensation benefits, and any benefit payable
under provisions of the Federal Social Security Act. Benefits will be payable until the earlier of the executive
officer’s date of retirement or age 65. The present value of this benefit for each NEO can be found in the
Potential Payment Upon Termination or Change in Control Tables on page 49.
Change in Control and Severance Benefits
In 2014, none of the executive officers had severance benefits, except for termination in connection with a CIC.
The Compensation Committee believes it is in the interest of shareholders to provide severance to our executive
officers in the event of a CIC, thereby reducing the inherent conflict of our executive officers pursuing a
transaction that may result in their personal job loss. There are no CIC agreements that provide cash severance
benefits in excess of three times base salary and bonus. The CIC agreements all have double triggers that provide
for a severance payment only upon the occurrence of both a CIC and qualified termination.
Additional information regarding the CIC agreements, including definitions of key terms and a quantification of
benefits that would have been received by our NEOs had termination occurred on December 31, 2014, due to a
CIC, is found in the Potential Payment Upon Termination or Change in Control Tables on page 49.
41
ICNU_DR_032 Attachment A Page 48 of 90
ˆ200GZcqP7Jj%V@ZhrŠ
200GZcqP7Jj%V@Zhr
836681 TX 42AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:59 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 5*
PMT 1C
SWRP64RS18
11.6.14
CIC agreements entered into on or after November 13, 2009 do not provide for excise tax gross-ups. CIC
agreements entered into before that date contain gross-ups, but the gross-up provisions have been modified to
eliminate the gross-up payment if the golden parachute excise tax imposed by Code Sections 280G and 4999
could be avoided by reducing an executive’s total CIC payments (other than the gross-up) by 10% or less.
Internal Revenue Code Section 162(m)
Code Section 162(m) limits the tax deduction that a publicly held corporation may take with respect to annual
compensation in excess of $1 million for any fiscal year paid to certain executive officers. As defined by the
Code, the $1 million limit does not apply to compensation that qualifies as “performance-based” compensation.
When consistent with the Company’s compensation philosophy and objectives, the Compensation Committee
structures its compensation plans so that all compensation expense may be deductible for tax purposes. However,
in light of the need to maintain flexibility in administering our executive compensation program, the
Compensation Committee retains discretion to recommend to the Board executive compensation that may not be
deductible.
Compensation Governance Matters
Recoupment Policy
The Compensation Committee believes that if the Company is required to prepare an accounting restatement as a
result of misconduct or a material error, incentive payouts based on the original results should be revised.
Therefore, the Board has adopted a formal recoupment policy applicable to incentive compensation awards. The
policy authorizes the Company to recover incentive payouts if those payouts are based on performance results
that are subsequently revised or restated to levels that would have produced payouts lower than the original
incentive plan payouts. If misconduct or material error results in a restatement of financial results, the
Compensation Committee may recommend that the Board either require forfeiture of incentive awards or seek to
recover appropriate portions of the executive officer’s compensation for the relevant period, in addition to other
disciplinary actions that might be appropriate based on the circumstances. The Board, in its discretion, would
determine when the need for a recoupment is triggered, to whom the recoupment would apply and the
recoupment mechanism.
Stock Ownership Guidelines
The Board has implemented a stock ownership policy for the Company’s executive officers. The policy requires
executive officers to own shares based on their position and salary, as well as to achieve set ownership levels
based on a multiple of salary. The exact multiple for each NEO depends on each executive officer’s position and
salary. The value for each executive’s ownership level is based on the closing stock price as reported on the day
on which the Compensation Committee holds a special meeting to review, certify, and settle the issuance of
shares to executive officers. The policy requires executive officers to achieve the required ownership level within
five years from the program’s inception in 2010, or from the executive officer’s employment date or applicable
promotion.
The objectives of our stock ownership policy are to:
• Strengthen alignment of the executives’ financial interests with those of shareholders;
• Enhance executive long-term perspective and focus on shareholder value growth;
• Reinforce “pay at risk” philosophy and provide an additional basis for sharing in Company success or
failure as reflected in shareholder returns; and
• Align Company practice with corporate governance best practices.
42
ICNU_DR_032 Attachment A Page 49 of 90
ˆ200GZcqP7Jj%e5Vh_Š
200GZcqP7Jj%e5Vh_
836681 TX 43AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:59 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 6*
PMT 1C
SWRP64RS18
11.6.14
The specific ownership requirements and certain other components of the policy are as follows:
Requirement Ownership Definition Retention Requirement
• CEO—5 times salary
• SVPs—2.5 times salary
• VPs—1 times salary
• Direct holding and family
holdings
• Shares held in 401(k)
• Shares held in Executive
Deferred Compensation
Account
• Unvested time-based RSUs
Officers must retain 50% of the
net shares received upon
restricted stock release or
issuance of performance shares
earned until the ownership level
is achieved.
Annually in February, the Compensation Committee reviews the ownership levels to assure adherence to the
guidelines. In 2014, the Compensation Committee conducted its annual review to assess that each officer was at
or moving toward the required ownership level for his or her position. Although several officers had not yet met
the required ownership level, after review, the Compensation Committee determined that those officers were
making appropriate progress toward the required level.
Anti-Hedging Policy
The anti-hedging policy in the Company’s insider trading policy expressly prohibits all directors, NEOs, and
other officers from engaging in a short sale, pledging, or hedging the economic interest in the Company shares
they hold.
Compensation Committee Report
The Compensation Committee of the Board has reviewed and discussed the CD&A with management and, based
on such review and discussions, the Compensation Committee recommended to the Board that the CD&A be
included in the Company’s Annual Report on Form 10-K and in this proxy statement.
Members of the Compensation & Organization Committee of the Board
John Taylor—Chair Rebecca Klein John Kelly
Compensation Committee Interlocks and Insider Participation
There are no “Compensation Committee interlocks” or “insider participation” relationships that SEC regulations
or NYSE listing standards would require to be disclosed in this proxy statement.
43
ICNU_DR_032 Attachment A Page 50 of 90
ˆ200GZcqP7KKWjB1h8Š
200GZcqP7KKWjB1h8
836681 TX 44AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 08:48 EST
CLN PSPOR
RR Donnelley ProFile SWRjayab0dc 13*
PMT 1C
RRWIN-XENP138
11.6.14
EXECUTIVE COMPENSATION TABLES
Summary Compensation Table—2014
Name and Principal Position Year Salary(1)Bonus(2)
Stock
Awards
($)(3)
Stock
Options
($)
Non-Equity
Incentive Plan
Compensation
($)(4)
Change in
Pension and
Non-Qualified
Deferred
Compensation
Earnings
($)(5)
All Other
Compensation
($)(6)
Total
Compensation
($)
S. L. Morris . . . . . . . . . . . . . . .
Chairman of the Board,
President & CEO
2014 $747,114 $191,506 $1,540,351 $1,120,642 $1,613,380 $238,340 $5,451,333
2013 $723,461 $1,305,334 $ 813,894 $ 0 $ 53,255 $2,895,944
2012 $673,847 $1,420,093 $135,250 $ 245,860 $ 969,583 $ 50,165 $3,494,798
M. T. Thies . . . . . . . . . . . . . . . .
Sr. Vice President, CFO &
Treasurer
2014 $396,462 $153,127 $ 489,648 $ 356,806 $ 211,017 $ 61,474 $1,668,534
2013 $386,538 $ 357,720 $ 289,904 $ 29,911 $ 15,300 $1,079,373
2012 $365,769 $ 545,190 $ 33,813 $ 88,970 $ 117,078 $ 13,460 $1,164,280
D. P. Vermillion . . . . . . . . . . . .
Sr. Vice President & ECO
2014 $357,251 $ 395,289 $ 321,517 $ 671,920 $ 14,850 $1,760,827
2013 $344,309 $ 371,974 $ 258,231 $ 0 $ 14,429 $ 988,943
2012 $310,385 $ 560,803 $ 75,498 $ 383,559 $ 13,907 $1,344,152
M. M. Durkin . . . . . . . . . . . . . .
Sr. Vice President,
General Counsel & CCO
2014 $330,347 $121,127 $ 382,538 $ 297,304 $ 281,334 $ 57,574 $1,481,924
2013 $314,037 $ 357,720 $ 235,528 $ 46,781 $ 11,475 $ 965,541
2012 $305,385 $ 545,190 $ 33,813 $ 74,282 $ 170,519 $ 11,250 $1,140,439
K. S. Feltes . . . . . . . . . . . . . . . .
Sr. Vice President &
Corporate Secretary
2014 $297,115 $104,127 $ 382,538 $ 267,396 $ 411,178 $ 57,574 $1,531,628
2013 $282,308 $ 357,720 $ 211,731 $ 20,422 $ 11,475 $ 883,656
2012 $267,308 $ 545,190 $ 33,813 $ 65,020 $ 253,636 $ 11,250 $1,176,217
(1) Amounts earned in the applicable year; includes regular pay, paid time-off and holiday pay. The total amounts shown in this column also include
any amounts that an NEO elected to defer in accordance with the Executive Deferred Compensation Plan. (See the “Non-Qualified Deferred
Compensation Plan” table on page 49 for more information.)
(2) Amounts shown represent the bonuses paid following the sale of Ecova.
(3) Values shown represent the aggregate grant date fair value calculated in accordance with Financial Accounting Standards Board (FASB)
Accounting Standards Codification (ASC) Topic 718 “Compensation—Stock Compensation” for RSUs and performance share awards granted in
each of the years reported. Assumptions used in the calculation of these amounts are included in Note 19 of the Company’s audited financial
statements for the year ended December 31, 2014 included in the Company’s Annual Report on Form 10-K filed with the SEC. In the case of
performance share awards, the amounts reported in the Stock Awards column represent the aggregate grant date fair value of the target number of
performance shares that may become vested if the applicable performance criteria are satisfied, and computed in accordance with ASC 718. The
aggregate grant date fair value for the target number of performance shares was calculated by using a Monte Carlo simulation, which produces a
probable value for the awards. Performance share awards vest at the end of the vesting term, however the number of shares delivered vary based
upon the attained level of performance and may range from 0 to 2.0 times the target number of performance shares awarded. For the 2014
performance share grant, if the maximum level of performance is achieved and using the closing stock price of $35.35 as reported on
December 31, 2014 to calculate the value and add the dividend equivalents using an annual amount of $1.27 per share as declared in 2014
multiplied by three years, then the value of the payouts would be:Mr. Morris $3,547,896; Mr. Thies $1,127,808; Mr. Vermillion $910,470;
Ms. Durkin $881,100; and Ms. Feltes $881,100.
(4) Amounts shown represent the annual short-term cash incentive awards paid in 2015 that were earned by our NEOs for 2014 performance in
accordance with the 2014 Executive Officer Annual Cash Incentive Plan.
(5) Any increase in the present value of the accrued pension benefit at normal retirement age (the earliest age at which retirement benefits may be
received by the NEO without any reduction in benefits) for any NEO between December 31, 2013 and December 31, 2014 is reported in this
column. All NEOs experienced an increase in the present value of their respective accrued pension benefits during 2014. The present value as of
December 31, 2014 utilizes the RP2014 mortality table with generational projection for males and females and a 4.21% discount rate for the
retirement plan and a 4.11% discount rate for the SERP. There were no above-market earnings for the Company’s Executive Deferred
Compensation Plan.
(6) Includes employer matching contributions under both the EDC Plan and the Investment and Employee Stock Ownership Plan (the “401(k)
plan”). The Company makes matching contributions on behalf of all its employees who make regular contributions of their wages, salary, cash
incentive, and overtime to the 401(k) plan during the plan year. The Company matching contribution to the 401(k) plan is equal to $0.75 for
every $1.00 of regular employee contributions up to a maximum 6% of compensation for non-union employees hired prior to January 1, 2006.
For non-union employees hired after that date, the Company matching contribution is equal to $1.00 for every $1.00 of regular employee
contributions up to a maximum of 6% of compensation. The Company matching contribution under the EDC Plan is equal to $0.75 for every
$1.00 contributed up to a maximum of 6% of the executive’s base pay less the maximum contribution allowed under the 401(k) plan assuming
the participant has contributed the maximum allowed by law. Upon the sale of Ecova in 2014, all Ecova stock options held by
44
ICNU_DR_032 Attachment A Page 51 of 90
ˆ200GZcqP7L1Tyg27dŠ
200GZcqP7L1Tyg27d
836681 TX 45AVISTA CORPORATION
NOTICE & PROXY STATE
26-Feb-2015 11:06 EST
CLN PSPOR
RR Donnelley ProFile SWRgarcm0pa 11*
PMT 1C
SWRFBU-MWE-XN17
11.6.14
Avista NEOs became fully vested and were cashed out for an amount equal to the excess of the value of Ecova shares at the time of the sale over
the option exercise price. Amounts shown in the All Other Compensation column for 2014 include the following:
Name
EDC Plan
Company Match
401(k) plan
Company Match
Paid Time Off
(Cash Outs)
Ecova Stock
Option
Cash Outs
Total All
Other
Compensation
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . .$11,700 $43,146 $183,494 $238,340
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . .$15,600 $ 45,874 $ 61,474
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . .$3,150 $11,700 $ 14,850
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . .$11,700 $ 45,874 $ 57,574
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . .$11,700 $ 45,874 $ 57,574
Grants of Plan-Based Awards—2014
Grant
Date(1)
All Other
Stock
Awards:
Number of
Shares of
Stock or
Units
(#)(5)
Grant
Date Fair
Value of
Stock
and
Option
Awards
($)(6)Name
Estimated Possible Payouts
Under Non-Equity Incentive
Plan Awards(2)
Estimated Future Payouts Under
Equity Incentive Plan
Awards(3)
Threshold($)Target($)Maximum($)Threshold(#)Target(#)Maximum(#)
S. L. Morris
Annual Cash Award . . . . . . . .02/06/14 $450,000 $750,000 $1,124,970
Performance Award . . . . . . . .02/06/14 18,120 45,300 90,600 $1,116,192
Restricted Stock Units (4) . . . 02/06/14 15,100 15,100 $ 424,159
M. T. Thies
Annual Cash Award . . . . . . . .02/06/14 $143,280 $238,800 $ 358,190
Performance Award . . . . . . . .02/06/14 5,760 14,400 28,800 $ 354,816
Restricted Stock Units . . . . . .02/06/14 4,800 $ 134,832
D. P. Vermillion
Annual Cash Award . . . . . . . .02/06/14 $129,060 $215,100 $ 322,641
Performance Award . . . . . . . .02/06/14 4,650 11,625 23,250 $ 286,440
Restricted Stock Units . . . . . .02/06/14 3,875 $ 108,849
M. M. Durkin
Annual Cash Award . . . . . . . .02/06/14 $120,240 $200,400 $ 300,592
Performance Award . . . . . . . .02/06/14 4,500 11,250 22,500 $ 277,200
Restricted Stock Units . . . . . .02/06/14 3,750 $ 105,338
K. S. Feltes
Annual Cash Award . . . . . . . .02/06/14 $108,000 $180,000 $ 269,993
Performance Award . . . . . . . .02/06/14 4,500 11,250 22,500 $ 277,200
Restricted Stock Units . . . . . .02/06/14 3,750 $ 105,338
(1) The grant date is the date the Compensation Committee and/or the Board approves the grant of performance share
awards, RSUs or non-equity incentive awards.
(2) Potential annual cash incentive awards granted to NEOs for 2014 performance in accordance with the 2014
Executive Officer Annual Cash Incentive Plan. The amounts actually paid to our NEOs for 2014 performance
appear in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. See the
CD&A for further explanation.
(3) Performance share awards are granted under the LTIP and vest over a three-year period. The number of shares
earned at the end of the three-year performance period depends on the level of performance achieved. See the
CD&A for further explanation.
(4) In 2014, Mr. Morris was awarded RSUs under the LTIP that vest over a three-year period. One-third of the shares
vest and shares are issued on an annual basis, provided that Mr. Morris is employed on the last day of the year and
the Company achieves the minimum annual ROE performance target established for that year. Dividend
equivalents accrue on the unvested RSUs and, if the performance target is met, are paid in cash at the same time
the underlying RSUs vest. Therefore, if the Company does not achieve the annual ROE performance target or if
the CEO’s employment ends prior to the last day of the vesting period, no RSUs or dividend equivalents are
earned. See the CD&A for further explanation.
45
ICNU_DR_032 Attachment A Page 52 of 90
ˆ200GZcqP7L1V1p%7.Š
200GZcqP7L1V1p%7.
836681 TX 46AVISTA CORPORATION
NOTICE & PROXY STATE
26-Feb-2015 11:06 EST
CLN PSPOR
RR Donnelley ProFile SWRgarcm0pa 10*
PMT 1C
SWRFBU-MWE-XN17
11.6.14
(5) In 2014, our NEOs, other than Mr. Morris, were awarded RSUs under the LTIP that vest over a three-year
period. One-third of the shares vest and shares are issued on an annual basis, provided that the NEO is
employed on the last day of the vesting period. Dividend equivalents accrue on the unvested RSUs and are
paid in cash at the same time the underlying RSUs vest. Therefore, if an NEO’s employment ends prior to
the last day of the vesting period, no RSUs or dividend equivalents are earned.
(6) The amounts shown for the grant date fair value of the target number of performance share awards were
calculated in accordance with ASC 718. Assumptions used in the calculation of these amounts are included in
Note 19 of the Company’s audited financial statements for the year ended December 31, 2014 included in the
Company’s Form 10-K filed with the SEC on February 25, 2015. The grant date fair value for the target
number of performance shares was calculated using a Monte Carlo simulation to produce a probable value for
the awards, which resulted in a fair value per share lower than the closing price per share on the grant date.
Employment Agreements
We currently do not have employment agreements with our NEOs, with the exception of Ms. Durkin and
Mr. Thies. Please refer to the “Pension Benefits” Table on page 48 for a discussion of the provisions that relate to
the grant of additional service credit for pension purposes, and to the “Potential Payments Upon Termination or
Change in Control” discussion on page 49, for a discussion of the change in control provisions.
Outstanding Equity Awards at Year-End—2014
Name
Date of
Grant
Stock Awards
Number of
Shares or
Units of
Stock that
Have Not
Vested (#)(1)
Market
Value of
Shares or
Units of
Stock That
Have Not
Vested
($)(2)
Equity
Incentive
Plan
Awards:
Number of
Unearned
Shares,
Units,
or Other
Rights
That
Have not
Vested(3)
Equity
Incentive
Plan
Awards:
Market
or Payout
Value of
Unearned
Shares,
Units, or
Other
Rights That
Have Not
Vested ($)(3)
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/07/2013 42,500 $1,502,375
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/07/2013 4,033 $ 142,567
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/06/2014 45,300 $1,601,355
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/06/2014 10,066 $ 355,833
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/07/2013 12,000 $ 424,200
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/07/2013 1,000 $ 35,350
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/06/2014 14,400 $ 509,040
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/06/2014 3,200 $113,120
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/07/2013 12,500 $ 441,875
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/07/2013 1,033 $ 36,517
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/06/2014 11,625 $ 410,944
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/06/2014 2,583 $ 91,309
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/07/2013 12,000 $ 424,200
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/07/2013 1,000 $ 35,350
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/06/2014 11,250 $ 397,688
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/06/2014 2,500 $ 88,375
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/07/2013 12,000 $ 424,200
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/07/2013 1,000 $ 35,350
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/06/2014 11,250 $ 397,688
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .02/06/2014 2,500 $ 88,375
(1) Number of time-based RSUs that remain unvested as of December 31, 2014. (RSUs vest and shares are
issuable over a three-year period, provided the NEO remains employed on the last day of each year of the
vesting period.)
46
ICNU_DR_032 Attachment A Page 53 of 90
ˆ200GZcqP7L1V8H0hrŠ
200GZcqP7L1V8H0hr
836681 TX 47AVISTA CORPORATION
NOTICE & PROXY STATE
26-Feb-2015 11:06 EST
CLN PSPOR
RR Donnelley ProFile SWRgarcm0pa 8*
PMT 1C
SWRFBU-MWE-XN17
11.6.14
(2) The market value of RSUs is based on the closing stock price ($35.35) as reported on December 31, 2014.
(3) Performance share awards reflect the number of performance shares at the target performance level. The
market value is based on the closing stock price ($35.35) as reported on December 31, 2014. The value for
the 2013 performance share award is shown at the target level (100%) based on results (greater than
threshold) for the first two years of the 2013-2015 performance period. The value for the 2014 performance
share awards are shown at the target level (100%) based on results (greater than threshold) for the first year
of the 2014-2016 performance period.
Option Exercises and Stock Vested—2014
Option Awards Stock Awards(1)(2)
Number of Shares
Acquired on
Exercise (#)
Value
Realized on
Exercise ($)
Number of
Shares
Acquired on
Vesting (#)
Value
Realized on
Vesting ($)Name
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .100,000(4) $183,494(4) 24,650(1) $874,582
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4,033(3) $150,310
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4,033(3) $150,310
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5,034(3) $187,617
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25,000(4) $ 45,874(4) 6,960(1) $246,941
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3,000(2) $106,320
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1,000(2) $ 35,440
M. T. Thies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1,600(2) $ 56,704
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7,250(1) $257,230
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3,033(2) $107,490
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1,033(2) $ 36,610
D. P. Vermillion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1,292(2) $ 45,788
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25,000(4) $ 45,874(4) 6,960(1) $246,941
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3,000(2) $106,320
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1,000(2) $ 35,440
M. M. Durkin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1,250(2) $ 44,300
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25,000(4) $ 45,874(4) 6,960(1) $246,941
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3,000(2) $106,320
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1,000(2) $ 35,440
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1,250(2) $ 44,300
(1) For the performance period ended December 31, 2014, our total shareholder return placed us in the 43rd
percentile of companies included in our peer group, which resulted in issuing 58% of the performance
shares granted in 2012 for the 2012-2014 performance period and the related dividend equivalents.
(2) Our NEOs were granted RSUs in 2012, 2013 and 2014, of which one-third vests each year if an NEO
remains employed on December 31. Therefore, one-third of each grant vested. Our NEOs received the last
one-third of their RSUs granted in 2012 and one-third of their RSUs granted in 2013 and 2014. Value is
based on the closing stock price ($35.44) as reported on January 2, 2015, the day on which the shares were
issuable to the recipient. Dividend equivalents were paid in cash at the same time the underlying RSUs
vested.
(3) Mr. Morris was granted RSUs in 2012, 2013 and 2014, of which one-third vests each year based on his
continued employment on December 31 and the Company achieving the minimum ROE performance target.
The 2014 performance target for the portion of the 2012, 2013 and the 2014 RSUs that could vest at the end
of 2014 was 5.59%. During 2014, we achieved an ROE of 13.75%, which exceeded the target and resulted
in vesting of one-third of each of the three grants. Value is based on the closing stock price ($37.27) as
reported on February 5, 2015, the day the Compensation Committee certified that the performance target
was met and the shares were issuable. Dividend equivalents were paid in cash at the same time the
underlying RSUs vested.
(4) Upon the sale of Ecova in 2014 all Ecova stock options held by Avista NEOs became fully vested and were
cashed out for an amount equal to the excess of the value of Ecova shares at the time of the sale over the
option exercise price.
47
ICNU_DR_032 Attachment A Page 54 of 90
ˆ200GZcqP7Jj&T6%7ÈŠ
200GZcqP7Jj&T6%7¨
836681 TX 48AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:59 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
Pension Benefits—2014
The table below reflects benefits accrued under the Retirement Plan for Employees and the SERP for our NEOs.
The Company’s Retirement Plan for Employees provides a retirement benefit based upon employees’
compensation and years of credited service. The retirement benefit under the Retirement Plan is based on a
participant’s final average annual base salary for the highest 36 consecutive months during the last 120 months of
service with the Company. Base salary for our NEOs is the amount under “Salary” in the Summary
Compensation Table.
The SERP provides additional pension benefits to executive officers of the Company, who have attained the age
of 55 and a minimum of 15 years of credited service with the Company. The SERP is intended to provide
benefits to executive officers whose pension benefits under the Company’s Retirement Plan are reduced due to
the application of limitations on qualified plans under the Code and the deferral of salary pursuant to the EDC
Plan. When combined with the Retirement Plan, the SERP will provide benefits to executive officers, other than
our CEO, who retire at age 62 or older, of 2.5% of the final average annual base salary during the highest 60
consecutive months during the last 120 months of service for each credited year of service up to 30 years. When
combined with the Retirement Plan, the SERP will provide higher benefits to our CEO, if he retires on or after
age 65, of 3% of final average base salary during the highest 60 consecutive months during the last 120 months
of service for each credited year of service up to 30 years. Benefits will be reduced for executives who retire
before age 62. Reductions are either 4% or 5% for each year of retirement before age 62 as prescribed in the
Retirement Plan.
Name Plan Name
Number of Years
Credited Service
(#)(1)
Present Value of
Accumulated
Benefit ($)
Payments During
Last
Year ($)
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . .Retirement Plan 33.17 $1,931,906 $0
SERP—pre 2005(2) 23.17 $ 168,681 $0
SERP 2005+(3) 30.00 $4,584,496 $0
M. T. Thies (4). . . . . . . . . . . . . . . . . . . .Retirement Plan 6.25 $ 179,478 $0
SERP—pre 2005(2) NA NA $0
SERP 2005+(3) 6.25 $ 351,240 $0
D. P. Vermillion . . . . . . . . . . . . . . . . . . .Retirement Plan 26.83 $1,299,318 $0
SERP—pre 2005(2) 16.83 $ 210,267 $0
SERP 2005+(3) 26.83 $ 935,604 $0
M. M. Durkin (5). . . . . . . . . . . . . . . . . .Retirement Plan 9.42 $ 423,586 $0
SERP—pre 2005(2) NA NA $0
SERP 2005+(3) 9.42 $ 511,932 $0
K. S. Feltes . . . . . . . . . . . . . . . . . . . . . . .Retirement Plan 16.67 $ 895,919 $0
SERP—pre 2005(2) 6.67 NA $0
SERP 2005+(3) 16.67 $ 658,838 $0
(1) SERP participants are limited to a maximum of 30 years of credited service under the SERP no matter how
many years of service they actually have with the Company. Mr. Morris’ credit service under the SERP 2005+
Plan has reached the maximum of 30 years. This column represents number of years of benefit service.
(2)(3) Effective January 1, 2005 the SERP was modified to comply with requirements of Code Section 409A. This
plan is noted as SERP 2005+. The plan prior to this date, SERP pre-2005, is grandfathered and is not subject to
Code Section 409A. SERP pre-2005 benefits were frozen as of December 31, 2004.
(4) After ten years, Mr. Thies will receive a “two for one” credit for vesting service for each completed year of
full-time service from year ten through year 12 (employment service). His ten-year employment anniversary
triggers commencement of the additional vesting service credit. There is no “two for one” credit prior to
completion of his tenth year of employment or after completion of his twelfth year of employment.
(5) After five years, Ms. Durkin began to receive a “two for one” credit for vesting service for each completed year
of full-time service from year six through year ten (employment service). Her five-year employment
anniversary triggered commencement of the additional vesting service credit. There is no “two for one” credit
after completion of her tenth year of employment.
48
ICNU_DR_032 Attachment A Page 55 of 90
ˆ200GZcqP7K4bX7BhoŠ
200GZcqP7K4bX7Bho
836681 TX 49AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 01:55 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 8*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
Non-Qualified Deferred Compensation Plan—2014
The following table shows the non-qualified deferred compensation activity for our NEOs accrued through
December 31, 2014:
Name
Executive
Contributions in
Last Fiscal
Year ($)(1)
Registrant
Contributions in
Last Fiscal Year
(Company Match)
($)(2)
Aggregate
Earnings
in Last
Fiscal
Year
($)(3)
Aggregate
Withdrawals/
Distributions
($)
Aggregate
Balance at
Last Fiscal
Year-End
($)
S. L. Morris . . . . . . . . . . . . . . . . . . . . . . $ 0 $ 0 $29,895 $0 $ 470,244
D. P. Vermillion . . . . . . . . . . . . . . . . . .$2,000 $3,150 $60,388 $0 $1,654,151
(1) Eligible employees may elect to defer up to 75% of their base annual salary and up to 100% of their annual
bonus. This column represents deferrals of this compensation during the last year. See the Summary
Compensation Table on page 44 for further explanation.
(2) The Company matching contribution under the EDC Plan is equal to $0.75 for every $1.00 contributed up to
a maximum of 6% of the executive’s base pay less the maximum contribution allowed under the 401(k) plan
assuming the participant has contributed up to the limit set forth in Code Section 402(g) for the plan year.
See “All Other Compensation” column of the Summary Compensation Table for further explanation.
(3) Earnings reflect the market returns of the NEO’s respective investment allocations. The earnings accrued for
deferred compensation are determined by actual earnings of Avista common stock and selected mutual
funds. None of the earnings are included as compensation on the Summary Compensation Table since none
are above market earnings. The Compensation Committee selects the mutual funds that are available for
investment under the EDC Plan, and the participants may allocate their accounts among these investments,
including Avista common stock. The investments currently available include the following:
Investment Ticker Symbol
One Year Return as
of 12/31/14
American Beacon Large Cap Value Fund . . . . . . . . . . . . . . . . . . . . . . . . . .AADEX 10.56%
American Funds EuroPacific Growth Fund . . . . . . . . . . . . . . . . . . . . . . . .RERFX -2.35%
Avista Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AVA 30.35%
Dodge & Cox International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .DODFX 0.08%
RS Partners Fund (Class A). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .RSPFX -3.85%
T. Rowe Price Blue Chip Growth Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . .TRBCX 9.28%
T. Rowe Price Mid Cap Growth Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . .RPMGX 13.16%
T. Rowe Price Personal Strategy Balanced Fund . . . . . . . . . . . . . . . . . . . .TRPBX 5.50%
Vanguard 500 Index Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VFIAX 13.64%
Vanguard Mid Cap Index Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VIMAX 13.76%
Vanguard Prime Money Market Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VMMXX 0.01%
Vanguard Short Term Treasury Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VFIRX 0.82%
Vanguard Small Cap Index Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VSMAX 7.50%
Vanguard Total Bond Market Index Fund . . . . . . . . . . . . . . . . . . . . . . . . .VBTLX 5.89%
Potential Payment Upon Termination or Change in Control
The Company has CIC agreements with all of our NEOs. The cash components are paid in a lump sum and are
based on a multiple of base salary. There are no CIC agreements that exceed three times base salary and bonus.
The CIC agreements all have double triggers that provide for a severance payment only upon the occurrence of
both a CIC and an adverse impact on an NEO’s employment.
Specifically, an NEO receives payments only if, in connection with a CIC, the executive officer’s employment is
terminated involuntarily by the Company or voluntarily by the officer for good reason. Good reason includes
49
ICNU_DR_032 Attachment A Page 56 of 90
ˆ200GZcqP7Jj&h&7hYŠ
200GZcqP7Jj&h&7hY
836681 TX 50AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:59 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
assignment of any duties inconsistent with the executive officer’s position, authority, duties or responsibilities or
any other action that results in a material diminution in such position, authority, duties or responsibilities or
material diminution in the executive’s base annual salary, or requiring the executive officer to be based at any
location over 50 miles from the location the executive officer was assigned to preceding the CIC.
The agreements also provide compensation and benefits to our NEOs during employment following a CIC of the
Company. Pursuant to the terms of the agreements, during the two or three years following a CIC of the
Company, an NEO will receive an annual base salary equal to at least 12 times the highest monthly base salary
paid to such executive officer in the 12 months preceding the CIC. In addition, each NEO will receive an annual
bonus at least equal to such executive officer’s highest bonus paid by the Company under the Company’s
Executive Officer Annual Cash Incentive Plan for the three years preceding the CIC (the “Recent Annual
Bonus”).
If employment is terminated by the Company without cause or by such executive officer for good reason during
the first three years after a CIC, the executive officer will receive a payment equal to the sum of: (i) the earned
but unpaid base salary due to such executive officer as of the date of termination; (ii) a proportionate annual
bonus due to such executive officer for the portion of the year worked prior to the termination, based on the
higher of the Recent Annual Bonus and the NEO’s annual bonus for the last year (the “Highest Annual Bonus”);
and (iii) a lump sum payment equal to two or three times (depending on the officer’s level) the sum of the NEO’s
annual base salary and the Highest Annual Bonus plus an amount equal to the 2010 bonus (paid in 2011). For all
new CIC agreements entered into on or after November 11, 2010, “Highest Annual Bonus” has been changed to
“target bonus.” The NEO will also receive all unpaid vacation pay, may continue to receive employee welfare
benefits for up to a three-year period from the date of termination, and may receive outplacement assistance.
Prior to November 2009, our CIC agreements provided that if any payments to the NEO would be subject to the
excise tax on excess parachute payments imposed by Code Section 4999, then such executive officer may be
entitled to a gross-up payment from the Company to cover the excise tax and any additional taxes on the gross-up
payment. In November 2009, the Board eliminated the excise tax gross-up benefit for all new CIC agreements
entered into on or after November 13, 2009. Agreements already in place on that date have since been modified
to provide that if payments (other than the gross-up payment) to the NEO do not exceed 110% of the maximum
amount the NEO could receive without triggering the excise tax, the payments to such executive officer will be
reduced to that maximum amount and such executive officer will not receive a gross-up payment.
The excise tax amount in the tables below is based on the Company’s best estimate of the individual’s liabilities
under Code Sections 280G and 4999, assuming the NEO was terminated in connection with a CIC on
December 31, 2014, and that the payments could not be reduced in accordance with the change described above.
If employment terminates for any reason other than for retirement, death or disability during a performance
cycle, all performance-based awards are forfeited. If employment terminates due to retirement, death or
disability, the payment amount is still determined at the end of the three-year performance cycle and is prorated
based on the number of months of active service during the cycle. If employment terminates in connection with a
CIC, RSUs are fully accelerated and performance shares have prorated acceleration.
50
ICNU_DR_032 Attachment A Page 57 of 90
ˆ200GZcqP7Jj&t387FŠ
200GZcqP7Jj&t387F
836681 TX 51AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:59 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
Payments required by these agreements, as well as payments provided by the other Company compensation
arrangements described above, are summarized in the tables below.
Potential Payment Upon Termination or Change in Control(1)
Termination
Without
Cause or
With Good
Reason after
a Change in
Control
Voluntary
Termination Retirement Death Disability
Involuntary
Termination
With or
Without Cause
Scott L. Morris
Chairman, President & CEO
Compensation Components
Severance (2). . . . . . . . . . . . . . . . . $5,505,574 $0 $ 0 $ 0 $ 0 $0
Value of Accelerated Equity (3) . . $ 3,056,311 $0 $2,768,188 $2,768,188 $2,768,188 $0
Retiree Medical (4). . . . . . . . . . . . $ 0 $0 $ 0 $ 0 $ 0 $0
Health Benefits (5). . . . . . . . . . . . . $37,538 $0 $ 0 $ 0 $ 0 $0
Death Benefit (6). . . . . . . . . . . . . . $ 0 $0 $ 0 $1,500,000 $ 0 $0
Supplemental Disability
Benefit (7). . . . . . . . . . . . . . . . . $ 0 $0 $ 0 $ 0 $2,388,547 $0
280-G Tax Gross-Up . . . . . . . . . . . $2,812,050 $0 $ 0 $ 0 $ 0 $0
Total . . . . . . . . . . . . . . . . . . .$11,411,473 $0 $2,768,188 $4,268,188 $5,156,735 $0
(1) All scenarios assume termination occurred on December 31, 2014 and a stock price of $35.35, the closing
price of Company stock on that date.
(2) Amount equals three times the sum of the executive’s annual base pay and the Highest Annual Bonus, plus
an amount equal to the Highest Annual Bonus (2013 bonus, paid in 2014) prorated for the current fiscal year
(($750,000+$813,894)×3)+$813,894.
(3) Assumes full acceleration of RSUs and prorated acceleration of performance shares (granted in 2013 and
2014) upon termination in connection with a CIC, and also assumes prorated acceleration of performance
shares and RSUs in the event of death, disability, and retirement, and assumes all shares are forfeited in the
event of voluntary or involuntary termination with cause. Under death, disability, and retirement,
achievement of performance goals were assumed to be 100%, although in actuality the participant must wait
until the end of the performance period to receive his/her prorated amount using the actual performance for
the entire measurement period.
(4) Retiree medical benefits are generally available to all employees who meet age and service eligibility
requirements.
(5) For a CIC, Mr. Morris would be credited with two years of continued health coverage based upon coverage
elected and cost of health coverage as of December 31, 2014.
(6) The “death benefit” is explained in the CD&A under Company Self-Funded Death Benefit Plan. Amount
shown is twice the annual base salary and is paid in a lump sum.
(7) The supplemental disability benefit is 60% of base annual pay and is comprised of benefits available from
the Avista Supplemental Executive Disability Plan, Long-term Disability Plan, Workers Compensation (if
applicable), and Social Security. Amount shown is the present value of the annual disability benefit payable
to age 65. Present value was determined by using an interest rate of 4.11% and the RP2014 mortality table
with generational projection for males and females.
51
ICNU_DR_032 Attachment A Page 58 of 90
ˆ200GZcqP7Jj&@XH71Š
200GZcqP7Jj&@XH71
836681 TX 52AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:59 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
Potential Payment Upon Termination or Change in Control(1)
Termination
Without
Cause or
With Good
Reason
after
a Change in
Control
Voluntary
Termination Retirement Death Disability
Involuntary
Termination
With or
Without Cause
Mark T. Thies
Senior Vice President CFO &
Treasurer
Compensation Components
Severance (2). . . . . . . . . . . . . . . . . . . .$2,353,616 $0 $ 0 $ 0 $ 0 $0
Value of Accelerated Equity (3). . . . . . $889,718 $0 $802,272 $ 802,272 $ 802,272 $0
Retiree Medical (4). . . . . . . . . . . . . . . . $ 0 $0 $ 0 $ 0 $ 0 $0
Health Benefits (5). . . . . . . . . . . . . . . . $37,538 $0 $ 0 $ 0 $ 0 $0
Death Benefit (6). . . . . . . . . . . . . . . . . $ 0 $0 $ 0 $796,000 $ 0 $0
Supplemental Disability Benefit (7) . . . $ 0 $0 $ 0 $ 0 $1,827,074 $0
280-G Tax Gross-Up . . . . . . . . . . . . . . .$1,177,120 $0 $ 0 $ 0 $ 0 $0
Total . . . . . . . . . . . . . . . . . . . . . . .$4,457,992 $0 $802,272 $1,598,272 $2,629,346 $0
(1) All scenarios assume termination occurred on December 31, 2014 and a stock price of $35.35, the closing
price of Company stock on that date.
(2) Amount equals three times the sum of the executive’s annual base pay and the Highest Annual Bonus, plus
an amount equal to the Highest Annual Bonus (2013 bonus, paid in 2014) prorated for the current fiscal year
(($398,000+$289,904)×3)+$289,904.
(3) Assumes full acceleration of RSUs and prorated acceleration of performance shares (granted in 2013 and
2014) upon termination in connection with a CIC, and also assumes prorated acceleration of performance
shares and RSUs after death, disability, and retirement, and assumes all shares are forfeited in the event of
voluntary or involuntary termination with cause. Under death, disability, and retirement, achievement of
performance goals were assumed to be 100%, although in actuality the participant must wait until the end of
the performance period to receive his/her prorated amount using the actual performance for the entire
measurement period.
(4) Retiree medical benefits are generally available to all employees who meet age and service eligibility
requirements.
(5) For a CIC, Mr. Thies would be credited with two years of continued health coverage based upon coverage
elected and cost of health coverage as of December 31, 2014.
(6) The “death benefit” is explained in the CD&A under Company Self-Funded Death Benefit Plan. Amount
shown is twice the annual base salary and is paid in a lump sum.
(7) The supplemental disability benefit is 60% of base annual pay and is comprised of benefits available from
the Avista Supplemental Executive Disability Plan, Long-term Disability Plan, Workers Compensation (if
applicable), and Social Security. Amount shown is the present value of the annual disability benefit payable
to age 65. Present value was determined by using an interest rate of 4.11% and the RP2014 mortality table
with generational projection for males and females.
52
ICNU_DR_032 Attachment A Page 59 of 90
ˆ200GZcqP7Jk02Mm7ZŠ
200GZcqP7Jk02Mm7Z
836681 TX 53AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:59 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
Potential Payment Upon Termination or Change in Control(1)
Termination
Without
Cause or
With Good
Reason
after
a Change in
Control
Voluntary
Termination Retirement Death Disability
Involuntary
Termination
With or
Without Cause
Dennis P. Vermillion
Sr. Vice President &
Environmental Compliance
Officer
Compensation Components
Severance (2). . . . . . . . . . . . . . . . . . .$1,491,693 $0 $ 0 $ 0 $ 0 $0
Value of Accelerated Equity (3). . . . . $859,336 $0 $785,423 $ 785,423 $ 785,423 $0
Retiree Medical (4). . . . . . . . . . . . . . . $ 0 $0 $ 0 $ 0 $ 0 $0
Health Benefits (5). . . . . . . . . . . . . . . $37,538 $0 $ 0 $ 0 $ 0 $0
Death Benefit (6). . . . . . . . . . . . . . . . $ 0 $0 $ 0 $717,000 $ 0 $0
Supplemental Disability
Benefit (7). . . . . . . . . . . . . . . . . . . . $ 0 $0 $ 0 $ 0 $908,229 $0
280-G Tax Gross-Up . . . . . . . . . . . . . $806,108 $0 $ 0 $ 0 $ 0 $0
Total . . . . . . . . . . . . . . . . . . . . . .$3,194,675 $0 $785,423 $1,502,423 $1,693,652 $0
(1) All scenarios assume termination occurred on December 31, 2014 and a stock price of $35.35, the closing
price of Company stock on that date.
(2) Amount equals two times the sum of the executive’s annual base pay and the Highest Annual Bonus, plus an
amount equal to the Highest Annual Bonus (2013 bonus, paid in 2014) prorated for the current fiscal year
(($358,500+$258,231)×2)+$258,231.
(3) Assumes full acceleration of RSUs and prorated acceleration of performance shares (granted in 2013 and
2014) upon termination in connection with a CIC, and also assumes prorated acceleration of performance
shares and RSUs after death, disability, and retirement, and assumes all shares are forfeited in the event of
voluntary or involuntary termination with cause. Under death, disability, and retirement, achievement of
performance goals were assumed to be 100%, although in actuality the participant must wait until the end of
the performance period to receive his/her prorated amount using the actual performance for the entire
measurement period.
(4) Retiree medical benefits are generally available to all employees who meet age and service eligibility
requirements.
(5) For a CIC, Mr. Vermillion would be credited with two years of continued health coverage based upon
coverage elected and cost of health coverage as of December 31, 2014.
(6) The “death benefit” is explained in the CD&A under Company Self-Funded Death Benefit Plan. Amount
shown is twice the annual base salary and is paid in a lump sum.
(7) The supplemental disability benefit is 60% of base annual pay and is comprised of benefits available from
the Avista Supplemental Executive Disability Plan, Long-term Disability Plan, Workers Compensation (if
applicable), and Social Security. Amount shown is the present value of the annual disability benefit payable
to age 65. Present value was determined by using an interest rate of 4.11% and the RP2014 mortality table
with generational projection for males and females.
53
ICNU_DR_032 Attachment A Page 60 of 90
ˆ200GZcqP7Jk09ddhzŠ
200GZcqP7Jk09ddhz
836681 TX 54AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:59 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 10*
PMT 1C
SWRP64RS18
11.6.14
Potential Payment Upon Termination or Change in Control(1)
Termination
Without
Cause or
With Good
Reason
after
a Change in
Control
Voluntary
Termination Retirement Death Disability
Involuntary
Termination
With or
Without Cause
Marian M. Durkin
Senior Vice President, General
Counsel & Chief Compliance
Officer
Compensation Components
Severance (2). . . . . . . . . . . . . . . . . . . .$1,944,112 $0 $ 0 $ 0 $ 0 $0
Value of Accelerated Equity (3). . . . . $827,067 $0 $755,538 $ 755,538 $ 755,538 $0
Retiree Medical (4). . . . . . . . . . . . . . . $ 0 $0 $ 0 $ 0 $ 0 $0
Health Benefits (5). . . . . . . . . . . . . . . . $27,659 $0 $ 0 $ 0 $ 0 $0
Death Benefit (6). . . . . . . . . . . . . . . . . $ 0 $0 $ 0 $668,000 $ 0 $0
Supplemental Disability Benefit (7) . . $ 0 $0 $ 0 $ 0 $ 311,075 $0
280-G Tax Gross-Up . . . . . . . . . . . . . . $954,797 $0 $ 0 $ 0 $ 0 $0
Total . . . . . . . . . . . . . . . . . . . . . . .$3,753,635 $0 $755,538 $1,423,538 $1,066,613 $0
(1) All scenarios assume termination occurred on December 31, 2014 and a stock price of $35.35, the closing
price of Company stock on that date.
(2) Amount equals three times the sum of the executive’s annual base pay and the Highest Annual Bonus, plus
an amount equal to the Highest Annual Bonus (2013 bonus, paid in 2014) prorated for the current fiscal year
(($334,000+$235,528)×3)+$235,528.
(3) Assumes full acceleration of RSUs and prorated acceleration of performance shares (granted in 2013 and
2014) upon termination in connection with a CIC, and also assumes prorated acceleration of performance
shares and RSUs after death, disability, and retirement, and assumes all shares are forfeited in the event of
voluntary or involuntary termination with cause. Under death, disability, and retirement, achievement of
performance goals were assumed to be 100%, although in actuality the participant must wait until the end of
the performance period to receive his/her prorated amount using the actual performance for the entire
measurement period.
(4) Retiree medical benefits are generally available to all employees who meet age and service eligibility
requirements.
(5) For a CIC, Ms. Durkin would be credited with two years of continued health coverage based upon coverage
elected and cost of health coverage as of December 31, 2014.
(6) The “death benefit” is explained in the CD&A under Company Self-Funded Death Benefit Plan. Amount
shown is twice the annual base salary and is paid in a lump sum.
(7) The supplemental disability benefit is 60% of base annual pay and is comprised of benefits available from
the Avista Corp. Supplemental Executive Disability Plan, Long-term Disability Plan, Workers
Compensation (if applicable), and Social Security. Amount shown is the present value of the annual
disability benefit payable to age 65. Present value was determined by using an interest rate of 4.11% and the
RP2014 mortality table with generational projection for males and females.
54
ICNU_DR_032 Attachment A Page 61 of 90
ˆ200GZcqP7Jk0GzQhyŠ
200GZcqP7Jk0GzQhy
836681 TX 55AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 08:59 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 10*
PMT 1C
SWRP64RS18
11.6.14
Potential Payment Upon Termination or Change in Control(1)
Termination
Without
Cause or
With Good
Reason
after
a Change in
Control
Voluntary
Termination Retirement Death Disability
Involuntary
Termination
With or
Without Cause
Karen S. Feltes
Senior Vice President & Corporate
Secretary
Compensation Components
Severance (2). . . . . . . . . . . . . . . . . . .$1,746,924 $0 $ 0 $ 0 $ 0 $0
Value of Accelerated Equity (3). . . . . $827,067 $0 $755,538 $ 755,538 $ 755,538 $0
Retiree Medical (4). . . . . . . . . . . . . . . $ 0 $0 $ 0 $ 0 $ 0 $0
Health Benefits (5). . . . . . . . . . . . . . . $27,659 $0 $ 0 $ 0 $ 0 $0
Death Benefit (6). . . . . . . . . . . . . . . . $ 0 $0 $ 0 $600,000 $ 0 $0
Supplemental Disability
Benefit (7). . . . . . . . . . . . . . . . . . . . $ 0 $0 $ 0 $ 0 $270,396 $0
280-G Tax Gross-Up . . . . . . . . . . . . . $882,844 $0 $ 0 $ 0 $ 0 $0
Total . . . . . . . . . . . . . . . . . . . . . .$3,484,494 $0 $755,538 $1,355,538 $1,025,934 $0
(1) All scenarios assume termination occurred on December 31, 2014 and a stock price of $35.35, the closing
price of Company stock on that date.
(2) Amount equals three times the sum of the executive’s annual base pay and the Highest Annual Bonus, plus
an amount equal to the Highest Annual Bonus (2013 bonus, paid in 2014) prorated for the current fiscal year
(($300,000+$211,731)×3)+$211,731.
(3) Assumes full acceleration of RSUs and prorated acceleration of performance shares (granted in 2013 and
2014) upon termination in connection with a CIC, and also assumes prorated acceleration of performance
shares and RSUs after death, disability, and retirement, and assumes all shares are forfeited in the event of
voluntary or involuntary termination with cause. Under death, disability, and retirement, achievement of
performance goals were assumed to be 100%, although in actuality the participant must wait until the end of
the performance period to receive his/her prorated amount using the actual performance for the entire
measurement period.
(4) Retiree medical benefits are generally available to all employees who meet age and service eligibility
requirements.
(5) For a CIC, Ms. Feltes would be credited with two years of continued health coverage based upon coverage
elected and cost of health coverage as of December 31, 2014.
(6) The “death benefit” is explained in the CD&A under Company Self-Funded Death Benefit Plan. Amount
shown is twice the annual base salary and is paid in a lump sum.
(7) The supplemental disability benefit is 60% of base annual pay and is comprised of benefits available from
the Avista Supplemental Executive Disability Plan, Long-term Disability Plan, Workers Compensation (if
applicable), and Social Security. Amount shown is the present value of the annual disability benefit payable
to age 65. Present value was determined by using an interest rate of 4.11% and the RP2014 mortality table
with generational projection for males and females.
55
ICNU_DR_032 Attachment A Page 62 of 90
ˆ200GZcqP7K28LiHhtŠ
200GZcqP7K28LiHht
836681 TX 56AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 00:28 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 8*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
PROPOSAL 4
AMENDMENT OF THE COMPANY’S LONG-TERM INCENTIVE PLAN
TO INCREASE THE NUMBER OF SHARES OFFERED FOR AWARD UNDER
THE PLAN
You are being asked to approve an increase in the number of shares reserved for issuance under the Company’s
LTIP. Except as described below, the terms of the Plan are identical to the Plan terms that shareholders approved
in 2010, when the Plan was amended and restated.
In 1998, the Board adopted the Plan, which was also approved by the Company’s shareholders at that year’s
Annual Meeting. The Company subsequently amended and restated the Plan effective May 12, 2000, January 1,
2005, and May 13, 2010. On February 6, 2015, the Board adopted, subject to shareholder approval, a Plan
amendment increasing the number of shares of Avista Corp. Common Stock, no par value (“Common Stock”)
reserved for issuance pursuant to the Plan from the current maximum of 4,500,000 shares to 6,135,000 shares. As
of March 1, 2015, an aggregate of 373,023 shares of Common Stock remained available for award pursuant to
the Plan. The Board is requesting that shareholders approve an additional 1,635,000 shares for issuance pursuant
to the Plan. If approved, the additional 1,635,000 shares plus the remaining 373,023 shares will provide
2,008,023 shares available for future awards pursuant to the Plan. This amendment will not have any effect on
the administration or operation of the Plan, other than providing additional shares for award.
The Board believes that it is important to the long-term success of the Company to continue to use Company
stock as part of the Company’s overall compensation program. Equity compensation motivates executives to
create shareholder value and encourages executives to focus on long-term value creation, because equity awards
are subject to either vesting or performance conditions and generally provide the greatest value to employees
when held for a longer term. To remain competitive without providing equity compensation, the Company would
need to replace the long-term component of its compensation with other means, including cash compensation,
which would reduce the alignment of interests between the executives and shareholders and would increase the
Company’s cash expense.
The following summary describes the material features of the Plan. This summary of the Plan is not intended to
be a complete description of the Plan and is qualified in its entirety by the actual text of the Plan. A copy of the
complete Plan, which reflects the amendment, is attached as Appendix B to this proxy statement.
Purpose
The Plan is intended to enhance the long-term shareholder value of the Company by offering opportunities to
employees, directors and officers of the Company and its subsidiaries to participate in the Company’s growth and
success, to encourage them to remain in the service of the Company and its subsidiaries and to acquire and
maintain stock ownership in the Company.
Administration
The Plan provides for administration by the Board or a Committee, consisting of two or more Board members,
appointed by the Board. The Board has delegated the authority to administer the Plan to the Compensation
Committee. Each member of the Compensation Committee administering the Plan is (a) an “outside director”
within the meaning of Code Section 162(m); (b) a “nonemployee director” within the meaning of Rule 16b-3 of
the Exchange Act, as amended; and (c) an “independent director” within the meaning of the New York Stock
Exchange listing requirements.
The terms and conditions of each award will be determined by the Compensation Committee, in its sole and
absolute discretion, and may differ from award to award. Subject to the terms and conditions of the Plan, the
Compensation Committee has the sole authority to (a) interpret the Plan; (b) to determine all matters relating to
awards pursuant to the Plan, including the selection of individuals to be granted awards, the type of awards, the
56
ICNU_DR_032 Attachment A Page 63 of 90
ˆ200GZcqP7Kc0fh!7ÈŠ
200GZcqP7Kc0fh!7¨
836681 TX 57AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 17:47 EST
CLN PSPOR
RR Donnelley ProFile SWRdennp0pa 8*
PMT 1C
CA8609AC451293
11.6.14
number of shares of Common Stock subject to an award, and all terms, conditions, restrictions and limitations, if
any, on any awards; (c) to adopt and amend rules and regulations relating to the Plan; and (d) to make all other
determinations necessary or advisable for the administration of the Plan.
The Plan provides that the Company’s senior executive officers, if authorized by the Board and consistent with
applicable law, may grant Plan awards to designated classes of employees within limits set by the Board.
Eligibility
The Plan permits grants to officers, directors and employees of the Company, as selected by the Compensation
Committee.
Shares Available
The Plan, as amended, permits the award of an aggregate of 6,135,000 shares, which consists of 4,500,000 shares
previously authorized plus 1,635,000 shares for which approval is sought by this proposal. As described above,
only 373,023 of the originally authorized 4,500,000 shares remain available for awards. Shares issued pursuant to
the Plan will be drawn from authorized and unissued shares, shares held or subsequently acquired by the
Company or shares purchased by a designated trustee on the open market. Any shares of Common Stock that
have been subject to an award that cease to be subject to the award (other than by reason of exercise or payment
of the award to the extent it is exercised for or settled in shares) will become available again for future awards
pursuant to the Plan.
Award Limits.Subject to adjustment as provided in the Plan, the Plan prohibits: (i) the issuance of more than an
aggregate of 625,000 shares of Common Stock in the form of restricted stock; (ii) the award of more than an
aggregate of 200,000 shares of Common Stock to any individual participant in any fiscal year; and (iii) the award
of more than an aggregate of 80,000 shares of Common Stock as incentive stock options (“ISOs”).
Adjustments.If a stock dividend, stock split, spin-off, combination or exchange of shares, recapitalization,
merger, consolidation, distribution to shareholders other than a normal cash dividend or other change in the
Company’s corporate or capital structure results in (a) the outstanding shares, or any securities exchanged
therefor or received in their place, being exchanged for a different number or class of securities of the Company
or of any other corporation or (b) new, different or additional securities of the Company or of any other
corporation being received by the holders of shares of Common Stock of the Company, then the Compensation
Committee shall proportionally adjust (i) the maximum number and kind of securities available for issuance
under the Plan; (ii) the maximum number and kind of securities that may be awarded to any individual
participant; and (iii) the number and kind of securities that are subject to any outstanding award and the per share
price of the securities, without any change in the aggregate price. In addition, subject to the Plan terms relating to
a Change of Control described below, the Compensation Committee has the discretion to take any further action
with respect to outstanding awards as it deems necessary, advisable, fair, and equitable to participants at any time
before a sale, merger, consolidation, reorganization, liquidation or other corporate transaction (as defined by the
Compensation Committee).
Types of Awards
The Plan permits the Compensation Committee to grant performance awards, restricted stock units, stock awards,
other stock-based awards, stock options, stock appreciation rights and dividend equivalent rights. Awards may be
granted either alone or in addition to, or in tandem with, any other type of award.
Performance Awards.The Plan permits the Compensation Committee to grant performance awards and establish
performance periods and performance goals. Performance goals may relate to earnings, earnings per share, profits,
profit growth, profit-related return ratios, cost management, dividend payout ratios, economic value added, cash
flow or total shareholder return. The Compensation Committee may measure performance in absolute terms or
relative to comparison companies. The extent to which the Company achieves its performance goals during
57
ICNU_DR_032 Attachment A Page 64 of 90
ˆ200GZcqP7Kc0uyZ7QŠ
200GZcqP7Kc0uyZ7Q
836681 TX 58AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 17:47 EST
CLN PSPOR
RR Donnelley ProFile SWRdennp0pa 7*
PMT 1C
CA8609AC451293
11.6.14
the applicable performance period will determine the dollar value or number of performance shares earned by the
participant. Performance awards may be denominated in cash, shares of Common Stock, or a combination of cash
and shares. If performance awards are denominated in cash, no more than an aggregate maximum dollar value of
$1,000,000 may be granted to any participant in any one fiscal year, to the extent required for compliance with Code
Section 162(m). Payment of earned performance awards will be in cash, shares of Common Stock, options or some
combination thereof, as determined by the Compensation Committee.
The Compensation Committee may adjust the performance goals and measurements applicable to performance
awards to include or exclude the effect of changes in tax laws, accounting principles, or other laws and the
impact of extraordinary or unusual items, events or circumstances except that, the Compensation Committee may
not make any adjustments that would result in an increase in the compensation of any participant whose
compensation is subject to Code Section 162(m) for the applicable year. Adjustments that reduce the amount
payable are permitted if and to the extent the Compensation Committee deems appropriate.
After termination of employment or service with the Company or any subsidiary of the Company, a participant
will be able to retain his or her performance shares for the time period, if any, and on the terms and conditions
determined by the Compensation Committee and stated in the award agreement. If the award agreement does not
provide the terms and conditions in the event of a participant’s termination of service: (a) a participant who
ceases to provide services as a result of retirement, early retirement, disability or death, will receive payment of
outstanding performance shares at the end of the performance period based on the Company’s performance and
prorated for the portion of the performance period during which the participant was employed; or (b) the
participant ceases to provide services during a performance period for any other reason, the participant will not
be entitled to any payment with respect to performance shares relating to that performance period, unless the
Compensation Committee determines otherwise.
Stock Awards and Other Stock-Based Awards.The Plan permits the Compensation Committee to grant stock
awards (including restricted stock) to participants on terms and conditions and subject to restrictions, if any, that
the Compensation Committee may determine. The Plan also permits the Compensation Committee to grant any
other stock-based awards (including restricted stock units) consistent with the purpose of the Plan. Restrictions
may be based on continuous service with the Company or the performance goals described above. The
Compensation Committee may waive any conditions, restrictions or forfeiture provisions with respect to
restricted stock awards. After termination of service with the Company or any subsidiary of the Company, a
participant will be able to retain his or her stock awards and other stock-based awards for the time period, if any,
and on the terms and conditions determined by the Compensation Committee.
Stock Options.Stock options entitle the holder to purchase a specified number of shares of Common Stock at a
specified price, called the exercise price, subject to the terms and conditions of the option grant. The
Compensation Committee may grant ISOs and nonqualified stock options. Incentive stock options may only be
granted to employees. All stock options must have an exercise price of not less than 100% of the fair market
value of the underlying shares of Common Stock on the grant date. An optionee may pay the exercise price in
cash, check, or, unless the Compensation Committee determines otherwise, by a combination of cash, check,
shares of Common Stock. Unless the Compensation Committee provides otherwise, the option term shall be ten
years from the grant date. Each option will vest and become exercisable at such time or times as determined by
the Compensation Committee and the Compensation Committee may waive or modify the vesting schedule at
any time. If the vesting schedule is not set forth in the option agreement, an option will become exercisable in
four equal annual installments beginning one year after the grant date. An option will vest in full if the optionee’s
services are terminated as a result of death or disability.
After termination of service with the Company or any subsidiary of the Company, a participant will be able to
exercise his or her nonqualified options for the time period, if any, and on the terms and conditions determined
by the Compensation Committee. Nonqualified options are generally exercisable for one year after termination of
services as a result of retirement, early retirement, disability or death, and for three months after all other
terminations, but in no event after the expiration of the option term. Incentive stock options must be exercised
58
ICNU_DR_032 Attachment A Page 65 of 90
ˆ200GZcqP7Jk0pm$hjŠ
200GZcqP7Jk0pm$hj
836681 TX 59AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
within three months after termination of service for reasons other than death, except that, in the case of
termination of employment due to total disability, ISOs must be exercised within one year of termination, but in
no event after the expiration of the option term. All options generally terminate automatically if the optionee’s
services are terminated for cause, as that term is defined in the Plan and all unvested options are forfeited upon
termination of the optionee’s services, unless the Compensation Committee determines otherwise.
Stock Appreciation Rights.Each stock appreciation right (“SAR”) granted pursuant to the Plan will entitle the
holder upon the exercise of the SAR to receive the excess of the fair market value of one share of Common Stock
on the exercise date over the SAR exercise price. SARs may be granted on a stand-alone basis or in tandem with
an option. The Compensation Committee may impose any conditions or restrictions on the exercise of a stand-
alone SAR as it deems appropriate except that the exercise price of stand-alone SARs may not be less than 100%
of the fair market value of the Common Stock on the grant date, and the SAR term, unless the Compensation
Committee determines otherwise, will be ten years from the grant date. A SAR granted in tandem with an option
will have an exercise price equal to the exercise price of the related option, and will have the same terms and
conditions as the related option. The related option terminates upon exercise of the tandem SARs. Payment upon
the exercise of a SAR will be in shares of Common Stock, cash, or any combination of shares and cash that the
Compensation Committee determines. Unless the Compensation Committee provides otherwise, the vesting
provisions and exercise restrictions that apply upon termination of service for options apply equally, to the extent
applicable, to SARs.
Dividend Equivalent Rights.Any awards granted pursuant to the Plan may, in the Compensation Committee’s
discretion, earn dividend equivalent rights that entitle the holder to an amount equal to the cash or stock
dividends or other distributions that would have been paid on the shares of Common Stock covered by such
award had such shares been issued and outstanding on the dividend record date. The Compensation Committee
may establish rules and procedures governing the crediting, timing, form of payment and payment contingencies
of dividend equivalent rights as it deems necessary or appropriate.
Change of Control
Unless otherwise provided in a participant’s award agreement, upon a Change of Control (as defined in the Plan),
restrictions on stock awards and other stock-based awards lapse and all options and SARS vest unless the award
is assumed or replaced with a comparable award relating to shares of the successor corporation. The treatment of
any other then-outstanding awards upon a Change of Control will be determined in accordance with the terms of
the applicable award agreement. If a participant is terminated without cause or voluntarily terminates with good
reason within three years following a Change of Control, any awards that were assumed or replaced in the change
of control will become fully vested and exercisable and free of restrictions.
Transferability
Unless the Compensation Committee determines otherwise, Plan awards may not be assigned or transferred other
than by will or by the applicable laws of descent and distribution.
Amendment and Termination
Subject to certain exceptions, the Board has the authority to amend, suspend or terminate the Plan at any time
provided that (a) any amendment to the Plan will not become effective until approved by the Company’s
shareholders if shareholder approval is required to comply with any applicable law, rule or regulation and (b) no
amendment or termination shall impair or diminish a participant’s rights with respect to any outstanding award
without the participant’s consent. The Plan does not have a fixed expiration date.
For ISO purposes, the amendment to increase the number of shares reserved for issuance under the Plan
constitutes a new plan, which means that if shareholders approve the amendment, ISOs may be granted within
ten years from the earlier of the date that the amendment is adopted by the Board or the date the amendment is
approved by shareholders.
59
ICNU_DR_032 Attachment A Page 66 of 90
ˆ200GZcqP7Jk0wD071Š
200GZcqP7Jk0wD071
836681 TX 60AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 6*
PMT 1C
SWRP64RS18
11.6.14
U.S. Federal Income Tax Consequences
The following is a general summary, as of the date of this proxy statement, of the federal income tax
consequences to participants who may receive awards pursuant to the Plan and to the Company arising out of the
granting of awards pursuant to the Plan. This summary is intended for the information of shareholders
considering how to vote at the Annual Meeting and not as tax guidance to participants in the Plan, as the
consequences may vary with the award types, the identity of the participants and the payment or settlement
method. The summary does not address the effects of other federal taxes or taxes imposed by state, local, or
foreign tax laws. Each participant is encouraged to seek the advice of a qualified tax advisor regarding the tax
consequences of participation in the Plan.
Performance Awards, Stock Awards and Other Stock-Based Awards. The federal income tax consequences with
respect to performance shares, restricted stock, restricted stock units, and other stock unit and stock-based awards
depend on the facts and circumstances of each award, including, in particular, the nature of any restrictions
imposed with respect to the awards. In general, if awards granted to a participant are subject to a “substantial risk
of forfeiture” (e.g., the awards are conditioned upon the future performance of substantial services by the
participant or the attainment of specified performance goals) and are nontransferable, a taxable event occurs
when the risk of forfeiture ceases or the awards become transferable, whichever first occurs. At such time, the
participant will recognize ordinary income to the extent of the excess of the fair market value of the awards on
such date over the participant’s cost for such awards, if any, and the Company will be entitled to a corresponding
deduction in an amount equal to the ordinary income recognized by the participant. Under certain circumstances,
a participant may elect pursuant to Code Section 83(b) to accelerate federal income tax recognition with respect
to awards that are subject to a substantial risk of forfeiture and transferability restrictions, in which event the
participant will recognize ordinary income at the time of grant in an amount equal to the excess of the fair market
value of the shares at such time over the amount, if any, paid for the shares and the Company will be entitled to a
corresponding deduction in an amount equal to the ordinary income recognized by the participant. If the awards
granted to a participant are not subject to a substantial risk of forfeiture or transferability restrictions, the
participant will recognize ordinary income with respect to the awards to the extent of the excess of the fair
market value of the awards at the time of grant over the participant’s cost, if any, and the Company will be
entitled to a corresponding deduction in an amount equal to the ordinary income recognized by the participant. If
a stock or stock unit award is granted but no stock is actually issued to the participant at the time the award is
granted, the participant will recognize ordinary income at the time the participant receives stock free of any
substantial risk of forfeiture and the amount of ordinary income will be equal to the fair market value of the stock
at such time over the participant’s cost, if any, and the Company will be entitled to a corresponding deduction in
an amount equal to the ordinary income recognized by the participant. In each case, the Company’s deduction
may be subject to compliance with Code Section 162(m). Upon disposition of any shares acquired through
performance awards or stock awards, the participant will recognize long-term or short-term capital gain or loss
depending upon the sale price and holding period of the shares.
Nonqualified Stock Options.The grant of a nonqualified option will not cause a participant to recognize ordinary
income or entitle the Company to a deduction for federal income tax purposes. Upon the participant’s exercise of
a nonqualified option, the participant will recognize ordinary income in an amount equal to the difference
between the exercise price and the fair market value on the exercise date of the shares purchased by the
participant, and the Company will be entitled to a corresponding deduction in an amount equal to the ordinary
income recognized by the participant, assuming that a deduction is allowed pursuant to Code Section 162(m). If
restrictions regarding forfeiture and transferability apply to the shares upon exercise, the time of recognition of
ordinary income and the amount thereof, and the availability of a tax deduction to the Company, generally will
be determined when the restrictions cease to apply. Upon disposition of the shares acquired by exercise of the
option, the optionee will recognize long-term or short-term capital gain or loss depending upon the sale price and
holding period of the shares.
Incentive Stock Options.In general, neither the grant nor exercise of an ISO will cause the recognition of
ordinary income by the participant, provided the participant does not dispose of the underlying shares until the
60
ICNU_DR_032 Attachment A Page 67 of 90
ˆ200GZcqP7Kc115o7uŠ
200GZcqP7Kc115o7u
836681 TX 61AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 17:47 EST
CLN PSPOR
RR Donnelley ProFile SWRdennp0pa 7*
PMT 1C
CA8609AC451293
11.6.14
later of two years from the grant date or one year after the exercise date. The amount by which the fair market
value of the shares at the time of exercise exceeds the exercise price is includable in the tax base upon which an
“alternative minimum tax” may be imposed. In general, neither the grant nor the exercise of an ISO will produce
a tax deduction for the Company.
If the optionee holds the stock received upon exercise of an ISO for at least two years from the grant date and one
year from the exercise date, the gain or loss on the sale, based upon the difference between the amount realized
and the exercise price, will constitute long-term capital gain or loss. If the optionee sells the stock received upon
exercise prior to the expiration of such periods (a “disqualifying disposition”), the optionee will recognize
ordinary income in the year of the disqualifying disposition equal to the excess of the fair market value of such
stock on the exercise date over the exercise price (or, if less, the excess of the amount realized upon disposition
over the exercise price). The excess, if any, of the sale price over the fair market value on the exercise date will
be capital gain.
The Company is not entitled to a tax deduction as a result of the grant or exercise of an ISO. If the optionee
recognizes ordinary income as a result of a disqualifying disposition, the Company is entitled to a corresponding
deduction in an amount equal to the ordinary income recognized by the participant, assuming that a deduction is
allowed pursuant to Code Section 162(m).
Stock Appreciation Rights.The grant of an SAR will not cause a participant to recognize ordinary income or
entitle the Company to a deduction for federal income tax purposes. Upon the exercise of an SAR, the participant
will recognize ordinary income in the amount of the cash or value of shares payable to the participant (before
reduction for any withholding taxes), and the Company will receive a corresponding deduction in an amount
equal to the ordinary income recognized by the participant, assuming that a deduction is allowed pursuant to
Code Section 162(m). Upon disposition of any shares acquired by exercise of a stock appreciation right, the
participant will recognize long-term or short-term capital gain or loss depending upon the sale price and holding
period of the shares.
Withholding Obligations
The Company may require a participant to pay to the Company an amount necessary for the Company to satisfy
its federal, state or local tax withholding obligations with respect to awards granted pursuant to the Plan. As
permitted by applicable law, the Company may withhold from other amounts payable to a participant an amount
necessary to satisfy these obligations, and the Compensation Committee may permit a participant to satisfy the
Company’s withholding obligation by paying cash, by electing to have the Company withhold shares of
Common Stock or by transferring shares of Common Stock to the Company in an amount equal to the tax
obligation.
Section 409A of the Code
The Compensation Committee may only grant awards that either comply with the applicable requirements of
Code Section 409A, or do not result in the deferral of compensation within the meaning of Code Section 409A. If
an award constitutes deferred compensation under Code Section 409A and fails to comply with the requirements
of Code Section 409A, at the time the award becomes vested the award may be subject to ordinary income tax,
an additional 20% tax, plus interest.
Section 162(m) of the Code
Pursuant to Code Section 162(m), the annual compensation paid to certain executive officers may not be
deductible to the extent that it exceeds $1 million unless the compensation qualifies as “performance-based”
pursuant to Code Section 162(m). The Plan has been designed to give the Compensation Committee discretion to
grant awards that qualify as “performance-based” for purposes of Code Section 162(m).
61
ICNU_DR_032 Attachment A Page 68 of 90
ˆ200GZcqP7Jk13B570Š
200GZcqP7Jk13B570
836681 TX 62AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
New Plan Benefits
Because all awards are within the discretion of the Compensation Committee, future awards, as well as the
number of employees to whom awards may be granted, are not currently determinable. As of March 1, 2015, the
market value of the shares underlying Plan awards was $ per share.
The Board recommends that you vote “FOR” the amendment increasing the number of shares reserved
for issuance pursuant to the Plan from 4,500,000 shares to 6,135,000 shares.
PROPOSAL 5
ADVISORY VOTE ON EXECUTIVE COMPENSATION
As required by the Exchange Act, the Board is submitting a separate resolution, to be voted on by shareholders in
a non-binding vote, approving, on an advisory basis, the Company’s executive compensation.
The text of the resolution in respect of this Proposal 5 is as follows:
“Resolved, that the shareholders approve, on an advisory basis, the compensation of the Company’s NEOs
as disclosed in the Company’s proxy statement, pursuant to the compensation disclosure rules of the SEC,
under the “CD&A,” “Executive Compensation Tables” and the related narrative disclosure.”
The Board recommends a vote for this resolution. As described in this proxy statement under the CD&A, the
Company’s compensation program is designed to focus Company executives on the achievement of specific
annual, long-term and strategic goals set by the Company. The goals are structured to align executives’ interests
with those of shareholders by rewarding performance that maintains and improves shareholder value. The
following features of the compensation structure reflect this approach:
• Executive compensation programs have both short and long-term components.
• Annual cash incentive components focus on both the actual results and the sustainability and quality of
those results.
• The total compensation program does not provide for guaranteed bonuses and has multiple performance
measures.
• The Company only has two executive employment agreements in place for NEOs, and they do not
contain guarantees for salary increases, non-performance-based bonuses or equity compensation.
• In 2010, the Company adopted a recoupment policy that authorizes the Board to recover incentive
payouts based on performance results that are subsequently revised or restated to levels that would have
produced payouts lower than the original incentive plan payouts.
The Board believes that the Company’s current executive compensation program properly focuses our executives
on the achievement of specific annual, long-term and strategic goals. The Board also believes that the Company’s
executive compensation program properly align the executives’ interests with those of shareholders.
Shareholders are urged to read the CD&A section of this proxy statement, which discusses in greater detail how
the Company’s compensation program implements the specific goals set by the Company.
The Board recommends a vote “FOR” the approval, on an advisory basis, of the compensation of the
Company’s NEOs.
Although the advisory vote on Proposal 5 is non-binding, the Board and the Compensation Committee will
review the results of the votes and, consistent with our record of shareholder engagement, are expected to take
the outcome of the votes into consideration, along with other relevant factors, in making a determination
concerning future executive compensation and the frequency of such advisory votes.
62
ICNU_DR_032 Attachment A Page 69 of 90
ˆ200GZcqP7K2CTR%7<Š
200GZcqP7K2CTR%7<
836681 TX 63AVISTA CORPORATION
NOTICE & PROXY STATE
25-Feb-2015 00:30 EST
CLN PSPOR
RR Donnelley ProFile SWRramth0dc 11*
PMT 1C
ACXFBU-MWE-XN02
11.6.14
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table shows the number of shares of common stock of the Company held beneficially, as of
March 1, 2015, by (i) each director and nominee, (ii) each of our NEOs in the Summary Compensation Table,
(iii) all current directors and executive officers as a group and (iv) each person who is known to the Company to
be the beneficial owner of more than 5% of our common stock. No director or executive officer owns in excess
of 1% of the stock of any indirect subsidiaries of the Company. None of the directors or NEOs has pledged
Company common stock as security. As of March 1, 2015, there were shares of common stock outstanding.
Beneficial ownership has been determined in accordance with Rule 13d-3 under the Exchange Act. Under this
rule, certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons
share the power to vote or the power to dispose of the shares). In addition, shares are deemed to be beneficially
owned by a person if the person has the right to acquire shares (for example, upon the exercise of an option or
warrant or the vesting of an equity award) within 60 days of the date as of which the information is provided. In
computing the percentage ownership of any person, the amount of shares is deemed to include the amount of
shares beneficially owned by such person by reason of such acquisition rights. As a result, the percentage of
outstanding shares of any person as shown in the table may not necessarily reflect the person’s actual voting
power at any particular date.
To our knowledge, except as indicated in footnotes to the table, the persons named in the table have sole voting
and investment power with respect to all shares of common stock shown as beneficially owned by them.
Shares Beneficially Owned Other
Total
Percent of
ClassNameDirectIndirect
Deferred
Shares(1)
RSUs Not
Yet
Vested(2)
Directors and NEOs
Erik J. Anderson . . . . . . . . . . . . . . . . . . . .22,738 22,738 *
Kristianne Blake . . . . . . . . . . . . . . . . . . . .18,301 2,519 20,820 *
Donald C. Burke . . . . . . . . . . . . . . . . . . . .9,495 9,495 *
Marian M. Durkin . . . . . . . . . . . . . . . . . . .57,789 6,800 64,589 *
Karen S. Feltes . . . . . . . . . . . . . . . . . . . . . .25,100 6,872 31,972 *
John F. Kelly . . . . . . . . . . . . . . . . . . . . . . .21,164 21,164 *
Rebecca A. Klein . . . . . . . . . . . . . . . . . . . .13,474 13,474 *
Scott L. Morris . . . . . . . . . . . . . . . . . . . . . .180,074 151(3) 180,225 *
Marc F. Racicot . . . . . . . . . . . . . . . . . . . . .11,649 11,649 *
Heidi B. Stanley . . . . . . . . . . . . . . . . . . . . .12,336 10,248(4) 22,584 *
R. John Taylor . . . . . . . . . . . . . . . . . . . . . .3,132 4,000(5) 5,496 12,628 *
Mark T. Thies . . . . . . . . . . . . . . . . . . . . . .53,094 5,751(6) 8,420 67,265 *
Dennis P. Vermillion . . . . . . . . . . . . . . . . .30,133 9,583(3) 7,916 47,632 *
Janet D. Widmann . . . . . . . . . . . . . . . . . . . 681 681 *
All directors and executive officers as a
group, including those listed above (22
individuals). . . . . . . . . . . . . . . . . . . . . .570,173 58,232 12,913 53,964 695,282 *
5% Beneficial Owners
BlackRock, Inc. (7). . . . . . . . . . . . . . . . . .9,238,117 9,238,117 14.8%
The Vanguard Group, Inc. (8). . . . . . . . . .4,266,530 4,266,530 6.85%
* As of March 1, 2015, the officers and directors as a group hold % of the shares outstanding.
(1) Shares deferred under the EDC Plan or under the former Non-Employee Director Stock Plan.
(2) Time-based RSUs that have been granted to the executive officers, but have not yet vested. RSUs vest in
three equal annual increments, provided the officer remains employed by the Company. If the employment
of an executive officer terminates, all unvested shares are forfeited.
63
ICNU_DR_032 Attachment A Page 70 of 90
ˆ200GZcqP7Jk1J8B7]Š
200GZcqP7Jk1J8B7]
836681 TX 64AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
(3) Shares held in the Company’s 401(k) plan.
(4) Shares held by Ms. Stanley’s spouse, Ronald Stanley, in a profit-sharing plan not administered by the
Company.
(5) Shares held in an employee benefit plan not administered by the Company for which Mr. Taylor shares
voting and investment power.
(6) Shares held by Mr. Thies’ spouse, Elizabeth Thies.
(7) As shown on Schedule 13G/A filed with the SEC on January 9, 2015, amending Schedule 13G filed with the
SEC on December 31, 2014 by BlackRock, Inc., a parent holding company, the beneficial owner has sole
voting power over 9,078,827 shares and sole dispositive power over 9,238,117 shares, and iShares Select
Dividend ETF has the right to receive or the power to direct the receipt of dividends from, or the proceeds
from the sale of, more than 5% of the total outstanding shares of common stock. The mailing address of the
beneficial owner is 55 East 52nd Street, New York, New York 10022.
(8) Vanguard is the holder of the Company’s 401(k) accounts. The beneficial owner has sole voting power over
87,926 shares, sole dispositive power over 4,188,104 shares and shared dispositive power over 78,426
shares. The address of the beneficial owner is 100 Vanguard Blvd., Malvern, Pennsylvania 19355.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16 of the Exchange Act requires that executive officers, directors and holders of more than 10% of the
Company’s common stock file reports of their ownership and changes in their ownership of the Company equity
securities with the SEC. Based solely on a review of Forms 3, 4 and 5 furnished to the Company with respect to
2014 and written representations from certain insiders that no other reports were required, the Company believes
that all Section 16 filing requirements applicable to these persons were completed in a timely manner.
ANNUAL REPORT AND FINANCIAL STATEMENTS
A copy of the Company’s 2014 Annual Report to Shareholders (“Annual Report”), which contains the
Company’s audited financial statements, accompanies this proxy statement. Our Annual Report and this proxy
statement are also posted on our web site at www.avistacorp.com. This Annual Report includes our 2014 Annual
Report on Form 10-K filed with the SEC (without exhibits). If you have not received or do not have access to the
Annual Report, call our Investor Relations department at [phone], and we will send a copy to you without
charge (without exhibits); or send a written request to Avista, Attn: Investor Relations Department, 1411 E.
Mission Ave., Spokane, Washington 99202.
HOUSEHOLDING
The Company understands that, if two or more beneficial owners of our common stock share the same address,
the brokerage firm or other intermediary through which these shares are held may, unless contrary instructions
are received from any such beneficial owner, deliver a single copy of the proxy statement, annual report and
related proxy soliciting materials for all beneficial owners at that address. This procedure is called
“householding.” Beneficial owners of common stock who currently receive multiple copies of the proxy
statement, annual report and other proxy soliciting materials and would prefer “householding” should contact
their broker. Beneficial owners subject to “householding” who would prefer to receive separate copies of the
proxy soliciting materials for each beneficial owner at their address should contact their broker and revoke their
consent to “householding.” Alternatively, beneficial owners may request a separate set of the proxy soliciting
materials from the Company in writing sent to Avista Corporation, Investor Relations, 1411 E. Mission Avenue,
Spokane, WA 99202 or by telephone at 509-495-4203.
The Company and its transfer agent do not engage in “householding” for registered holders of common stock.
64
ICNU_DR_032 Attachment A Page 71 of 90
ˆ200GZcqP7Jk1PwRhxŠ
200GZcqP7Jk1PwRhx
836681 TX 65AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
g63n14-1.0
OTHER BUSINESS
The Board does not intend to present any business at the meeting other than as set forth in the accompanying
Notice of Annual Meeting, and has no present knowledge that others intend to present business at the meeting. If,
however, other matters requiring the vote of the shareholders properly come before the meeting or any
adjournment(s) thereof, the individuals named in the proxy card will have discretionary authority to vote the
proxies held by them in accordance with their judgment as to such matters.
2016 ANNUAL MEETING
General
The 2016 Annual Meeting is currently scheduled for Thursday, May 12, 2016, in Spokane, Washington. Matters
to be brought before that meeting by shareholders are subject to the requirements described below.
The date and location of the 2016 Annual Meeting are subject to change. Any such change and any resulting
change in the dates referred to below, would be specified by the Company in a report filed with the SEC. In
addition, any change in the dates referred to below that results from a change in SEC rules or the Company’s
Bylaws would be similarly reported by the Company.
Notice of Nominations and Other Business to Be Presented at Annual Meeting
Notice of nominations of directors and other business to be presented by a shareholder at the 2016 Annual
Meeting must be delivered to the Company as follows:
• written notice of a shareholder’s intent to nominate a person for election as a director at the 2016
Annual Meeting must be delivered to the principal executive offices of the Company to the attention of
the Corporate Secretary on or before February 8, 2016, but not before November 9, 2015; and
• written notice of a shareholder’s intent to propose other business to be brought before the 2016 Annual
Meeting must be delivered to the principal executive offices of the Company to the attention of the
Corporate Secretary on or before February 8, 2016, but not before November 9, 2015.
In any case, the written notice of the shareholder must, in order for the matter to be eligible to be presented at the
meeting, comply with all of the requirements and contain all of the information specified in the Company’s
Bylaws, without regard to whether the proposed nomination or other business is to be included in management’s
proxy soliciting materials or those of any other person.
Notice of Proposals to be Included in Management’s Proxy Materials
Proposals that shareholders seek to have included in management’s proxy soliciting materials must be received
by the Corporate Secretary on or before November 30, 2015 and, in order to be so included, must contain the
information required by the SEC’s Rule 14a-8 and otherwise comply with SEC rules. However, in order for a
proposal to be eligible to be presented at the meeting, the shareholder must also comply with all of the
requirements specified in the Company’s Bylaws for nominating a person for election as a director and/or
bringing other business before the meeting.
By Order of the Board,
Karen S. Feltes
Senior Vice President & Corporate Secretary
Spokane, Washington
March 27, 2015
65
ICNU_DR_032 Attachment A Page 72 of 90
ˆ200GZcqP7Jk1V2@7ÀŠ
200GZcqP7Jk1V2@7
836681 TX 66AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend
START PAGE
7*
PMT 1C
SWRP64RS18
11.6.14
APPENDIX A
PROPOSED AMENDMENTS TO
RESTATED ARTICLES OF INCORPORATION
The proposed amendments and restatements of specified provisions of the Restated Articles of Incorporation are
set forth below. Text stricken through indicates deletions, and text in italics indicates additions.
Article FIFTH
The fifth paragraph of Article FIFTH, which relates to the shareholder vote required to amend the provisions of
Article FIFTH (which relates to the Board of Directors), would be amended and restated as set forth below:
Notwithstanding anything contained in these Articles of Incorporation to the contrary, the provisions of this
Article FIFTH shall not be altered, amended or repealed, and no provision inconsistent therewith shall be
included in these Articles of Incorporation or the Bylaws of the Corporation, without the affirmative vote of
the holders of at least eighty percent (80%)a majority of the voting power of all of the shares of the Voting
Stock, voting together as a single class;it being understood that this paragraph shall not impose any
shareholder approval requirement in addition to the requirements, if any, of applicable law with respect to
any such alteration, amendment, repeal or inconsistent provision that shall have been approved by the
Board of Directors.
Article SEVENTH
The existing tenth paragraph of Article SEVENTH, which relates to the shareholder vote required to amend
specified provisions of Article SEVENTH, would be amended as set forth below:
Notwithstanding anything contained in these Articles of Incorporation to the contrary, the paragraph in this
Article SEVENTH relating to the adoption, alteration, amendment, change and repeal of the Bylaws of the
Corporation, the paragraph in this Article SEVENTH relating to the calling and conduct of special meetings
of the shareholders and this paragraph, and the provisions of the Bylaws of the Corporation relating to
procedures for the nomination of Directors, shall not be altered, amended or repealed, and no provision
inconsistent therewith shall be included in these Articles of Incorporation or the Bylaws of the Corporation,
without the affirmative vote of the holders of at least eighty percent (80%)a majority of the voting power of
all the shares of the Voting Stock, voting together as a single class;it being understood that this paragraph
shall not impose any shareholder approval requirement in addition to the requirements, if any, of applicable
law with respect to any such alteration, amendment, repeal or inconsistent provision that shall have been
approved by the Board of Directors.
Article EIGHTH
Subdivision (a) of Article EIGHTH, which relates to specified “Business Combinations,” would be amended and
restated, in part, to read as set forth below:
(a) In addition to any affirmative vote required by law or these Articles of Incorporation, and except as
otherwise expressly provided in subdivision (b) of this Article EIGHTH:
[clauses (1), (2), (3), (4) and (5), each of which sets forth a type of transaction that constitutes a “Business
Combination” for purposes of Article EIGHTH, would not be changed]
shall require the affirmative vote of the holders of at least 80%a majority of the voting power of all of the
shares of the Voting Stock, voting together as a single class. Such affirmative vote shall be required
notwithstanding the fact that no vote may be required or that the vote of a lower percentage may be
specified, by law or in any agreement with any national securities exchange or otherwise. The term
“Business Combination” as used in this Article EIGHTH shall mean any transaction which is referred to in
any one or more of paragraphs (1) through (5) of this subdivision (a).
A-1
ICNU_DR_032 Attachment A Page 73 of 90
ˆ200GZcqP7Jk1Yx47/Š
200GZcqP7Jk1Yx47/
836681 TX 67AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 6*
PMT 1C
SWRP64RS18
11.6.14
The last paragraph of Article EIGHTH, which relates to the shareholder vote required to amend the provisions of
Article EIGHTH, would be amended and restated to read as set forth below:
Notwithstanding anything contained in these Articles of Incorporation to the contrary, the provisions of this
Article EIGHTH shall not be altered, amended or repealed, and no provision inconsistent therewith shall be
included in these Articles of Incorporation or the Bylaws of the Corporation, without the affirmative vote of
the holders of at least eighty percent (80%)a majority of the voting power of all of the shares of the Voting
Stock, voting together as a single class;it being understood that this paragraph shall not impose any
shareholder approval requirement in addition to the requirements, if any, of applicable law with respect to
any such alteration, amendment, repeal or inconsistent provision that shall have been approved by the
Board of Directors.
A-2
ICNU_DR_032 Attachment A Page 74 of 90
ˆ200GZcqP7Jk1dfKh%Š
200GZcqP7Jk1dfKh%
836681 TX 68AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend
START PAGE
8*
PMT 1C
SWRP64RS18
11.6.14
APPENDIX B
AVISTA CORPORATION
LONG-TERM INCENTIVE PLAN
SECTION 1. PURPOSE
The purpose of the Avista Corporation Long-Term Incentive Plan (the “Plan”) is to enhance the long-term
shareholder value of Avista Corporation, a Washington corporation (the “Company”), by offering opportunities
to employees, directors and officers of the Company and its Subsidiaries (as defined in Section 2) to participate
in the Company’s growth and success, and to encourage them to remain in the service of the Company and its
Subsidiaries and to acquire and maintain stock ownership in the Company.
The Plan was initially adopted by the Company’s shareholders on May 14, 1998 and was subsequently amended
and restated on May 12, 2000, January 1, 2005, November 9, 2006 and May 13, 2010.
SECTION 2. DEFINITIONS
For purposes of the Plan, the following terms are defined as set forth below:
2.1 Award
“Award” means an award or grant made to a Participant pursuant to the Plan, including, without limitation,
awards or grants of Options, Stock Appreciation Rights, Stock Awards, Performance Awards, Other Stock-Based
Awards or any combination of the foregoing (including any Dividend Equivalent Rights granted in connection
with such Awards).
2.2 Board
“Board” means the Board of Directors of the Company.
2.3 Cause
“Cause” means (a) the willful and continued failure of the Holder to perform substantially the Holder’s duties
with the Company or one of its Subsidiaries (other than any such failure resulting from incapacity due to physical
or mental illness) after a written demand for substantial performance is delivered to the Holder by the Board or
the Chief Executive Officer of the Company which specifically identifies the manner in which the Board or the
Chief Executive Officer believes that the Holder has not substantially performed the Holder’s duties; or (b) the
willful engaging by the Holder in illegal conduct or gross misconduct which is materially and demonstrably
injurious to the Company.
2.4 Change of Control
“Change of Control” means any of the following events:
(a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2)
of the Exchange Act) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3
promulgated under the Exchange Act) of 20% or more of either
(i) the then outstanding shares of Common Stock of the Company (the “Outstanding Company
Common Stock”) or
(ii) the combined voting power of the then outstanding voting securities of the Company entitled to
vote generally in the election of directors (the “Outstanding Company Voting Securities”);
provided, however, that for purposes of this subsection (a), the following acquisitions shall not
B-1
ICNU_DR_032 Attachment A Page 75 of 90
ˆ200GZcqP7Jk1lf%7~Š
200GZcqP7Jk1lf%7~
836681 TX 69AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 6*
PMT 1C
SWRP64RS18
11.6.14
constitute a Change of Control: (i) any acquisition directly from the Company, (ii) any acquisition
by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or
maintained by the Company or any corporation controlled by the Company or (iv) any acquisition
by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of
subsection (c) of this Section 2.4;
(b) A change in the Board so that individuals who constitute the Board (the “Incumbent Board”) as of the
date of adoption of the Plan cease for any reason to constitute at least a majority of the Board after such
date; provided, however, that any individual becoming a director subsequent to such date whose
election, or nomination for election by the Company’s shareholders, was approved by a vote of at least
a majority of the directors then comprising the Incumbent Board shall be considered as though such
individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual
whose initial assumption of office occurs as a result of an actual or threatened election contest with
respect to the election or removal of directors or other actual or threatened solicitation of proxies or
consents by or on behalf of a Person other than the Board;
(c) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or
substantially all of the assets of the Company (a “Business Combination”), in each case, unless,
following such Business Combination, (i) all or substantially all of the individuals and entities who
were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding
Company Voting Securities immediately prior to such Business Combination beneficially own, directly
or indirectly, more than 50% of, respectively, the then outstanding shares of Common Stock and the
combined voting power of the then outstanding voting securities entitled to vote generally in the
election of directors, as the case may be, of the corporation resulting from such Business Combination
(including, without limitation, a corporation which as a result of such transaction owns the Company or
all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in
substantially the same proportions as their ownership, immediately prior to such Business Combination
of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case
may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any
employee benefit plan (or related trust) of the Company or such corporation resulting from such
Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then
outstanding shares of Common Stock of the corporation resulting from such Business Combination or
the combined voting power of the then outstanding voting securities of such corporation except to the
extent that such ownership existed prior to the Business Combination and (iii) at least a majority of the
members of the Board of Directors of the corporation resulting from such Business Combination were
members of the Incumbent Board at the time of the execution of the initial agreement, or of the action
of the Board, providing for such Business Combination; or
(d) Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.
2.5 Code
“Code” means the Internal Revenue Code of 1986, as amended from time to time.
2.6 Common Stock
“Common Stock” means the common stock, no par value, of the Company.
2.7 Disability
“Disability” means “disability” as that term is defined for purposes of the Company’s Long-Term Disability Plan
or other similar successor plan applicable to salaried employees.
2.8 Dividend Equivalent Right
“Dividend Equivalent Right” means an Award granted under Section 13.
B-2
ICNU_DR_032 Attachment A Page 76 of 90
ˆ200GZcqP7Jk1rNChHŠ
200GZcqP7Jk1rNChH
836681 TX 70AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
2.9 Early Retirement
“Early Retirement” means early retirement as that term is defined by the Plan Administrator from time to time
for purposes of the Plan.
2.10 Exchange Act
“Exchange Act” means the Securities Exchange Act of 1934, as amended.
2.11 Fair Market Value
The “Fair Market Value” shall be the closing price per share for the Common Stock on the New York Stock
Exchange as such price is officially quoted in the composite tape of transactions on such exchange for a single
trading day. If there is no such reported price for the Common Stock for the date in question, then such price on
the last preceding date for which such price exists shall be determinative of Fair Market Value.
2.12 Good Reason
“Good Reason” means:
(a) The assignment to the Holder of any duties inconsistent in any respect with the Holder’s position
(including status, offices, titles and reporting requirements), authority, duties or responsibilities, or any
other action by the Company which results in a diminution in such position, authority, duties or
responsibilities, excluding for this purpose an isolated, insubstantial and inadvertent action not taken in
bad faith and which is remedied by the Company promptly after receipt of notice thereof given by the
Holder;
(b) Any failure of the Company to comply with its standard compensation arrangements with the Holder,
including the failure to continue in effect any material compensation or benefit plan (or the substantial
equivalent thereof) in which the Holder was participating at the time of a Change of Control, other than
an isolated, insubstantial and inadvertent failure not occurring in bad faith and which is remedied by
the Company promptly after receipt of notice thereof from the Holder;
(c) Any purported termination of the Holder’s employment or service for Cause by the Company that does
not comply with the terms of the Plan; or
(d) The failure of the Company to require that any Successor Corporation (whether by purchase, merger,
consolidation or otherwise) expressly assume and agree to be bound by the terms of the Plan in the
same manner and to the same extent that the Company would be required to perform if no such
succession had taken place.
2.13 Grant Date
“Grant Date” means the date the Plan Administrator adopted the granting resolution or a later date designated in
a resolution of the Plan Administrator as the date an Award is to be granted.
2.14 Holder
“Holder” means:
(a) the Participant to whom an Award is granted;
(b) for a Holder who has died, the personal representative of the Holder’s estate, the person(s) to whom the
Holder’s rights under the Award have passed by will or by the applicable laws of descent and
distribution, or the beneficiary designated in accordance with Section 14; or
(c) the person(s) to whom an Award has been transferred in accordance with Section 14.
B-3
ICNU_DR_032 Attachment A Page 77 of 90
ˆ200GZcqP7Jk1x2T75Š
200GZcqP7Jk1x2T75
836681 TX 71AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
2.15 Incentive Stock Option
“Incentive Stock Option” means an Option to purchase Common Stock granted under Section 7 with the
intention that it qualify as an “incentive stock option” as that term is defined in Section 422 of the Code.
2.16 Nonqualified Stock Option
“Nonqualified Stock Option” means an Option to purchase Common Stock granted under Section 7 other than an
Incentive Stock Option.
2.17 Option
“Option” means the right to purchase Common Stock granted under Section 7.
2.18 Other Stock-Based Award
“Other Stock-Based Award” means an Award granted under Section 12.
2.19 Participant
“Participant” means an individual who is a Holder of an Award or, as the context may require, any employee,
director or officer of the Company or a Subsidiary who has been designated by the Plan Administrator as eligible
to participate in the Plan.
2.20 Performance Award
“Performance Award” means an Award granted under Section 11, the payout of which is subject to achievement
through a performance period of performance goals prescribed by the Plan Administrator.
2.21 Plan Administrator
“Plan Administrator” means the Board or any committee or committees designated by the Board or any person or
persons to whom the Board has delegated authority to administer the Plan under Section 3.1.
2.22 Restricted Stock
“Restricted Stock” means shares of Common Stock granted under Section 10, the rights of ownership of which
are subject to restrictions prescribed by the Plan Administrator.
2.23 Retirement
“Retirement” means retirement as of the individual’s normal retirement date under the Company’s retirement
plan for salaried employees or other similar successor plan applicable to salaried employees.
2.24 Securities Act
“Securities Act” means the Securities Act of 1933, as amended.
2.25 Stock Appreciation Right
“Stock Appreciation Right” means an Award granted under Section 9.
2.26 Stock Award
“Stock Award” means an Award granted under Section 10.
B-4
ICNU_DR_032 Attachment A Page 78 of 90
ˆ200GZcqP7Jk1&t!h!Š
200GZcqP7Jk1&t!h!
836681 TX 72AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
2.27 Subsidiary
“Subsidiary,” except as provided in Section 8.3 in connection with Incentive Stock Options, means any entity
that is directly or indirectly controlled by the Company or in which the Company has a significant ownership
interest, as determined by the Plan Administrator, and any entity that may become a direct or indirect parent of
the Company.
2.28 Successor Corporation
“Successor Corporation” has the meaning set forth under Section 15.2.
2.29 Trust and Trustee
“Trust” and “Trustee” have the meanings set forth in Section 3.2.
2.30 Trustee Shares
“Trustee Shares” has the meaning set forth in Section 3.3.
SECTION 3. ADMINISTRATION
3.1 Plan Administrator
The Plan shall be administered by the Board or a committee or committees (which term includes subcommittees)
appointed by, and consisting of two or more members of the Board. If and so long as the Common Stock is
registered under Section 12(b) or 12(g) of the Exchange Act, the Board shall consider in selecting the Plan
Administrator and the membership of any committee acting as Plan Administrator, with respect to any persons
subject or likely to become subject to Section 16 of the Exchange Act, the provisions regarding (a) “outside
directors” as contemplated by Section 162(m) of the Code; (b) “nonemployee directors” as contemplated by Rule
16b-3 under the Exchange Act; and (c) “independent directors” as contemplated by Section 303A.02 of the New
York Stock Exchange Listed Company Manual. The Board may delegate the responsibility for administering the
Plan with respect to designated classes of eligible Participants to different committees consisting of two or more
members of the Board, subject to such limitations as the Board or the Plan Administrator deems appropriate.
Committee members shall serve for such term as the Board may determine, subject to removal by the Board at any
time. To the extent consistent with applicable law, the Board may authorize one or more senior executive officers of
the Company to grant Awards to designated classes of eligible employees within the limits prescribed by the Board.
3.2 Administration and Interpretation by the Plan Administrator
Except for the terms and conditions explicitly set forth in the Plan, the Plan Administrator shall have exclusive
authority, in its discretion, to determine all matters relating to Awards under the Plan, including the selection of
individuals to be granted Awards, the type of Awards, the number of shares of Common Stock subject to an
Award, all terms, conditions, restrictions and limitations, if any, of an Award and the terms of any instrument
that evidences the Award, and to authorize the Trustee (the “Trustee”) of any Trust (the “Trust”) that may be
required pursuant to the Plan to grant Awards to Participants. The Plan Administrator shall also have exclusive
authority to interpret the Plan and may from time to time adopt, and change, rules and regulations of general
application for the Plan’s administration. The Plan Administrator’s interpretation of the Plan and its rules and
regulations, and all actions taken and determinations made by the Plan Administrator pursuant to the Plan, shall
be conclusive and binding on all parties involved or affected. The Plan Administrator may delegate
administrative duties to such of the Company’s officers as it so determines.
3.3 Trust for the Long-Term Incentive Plan
Payments may be, but need not be, made to the Trustee, such payments to be used by the Trustee to purchase
shares of the Common Stock. Shares purchased by the Trustee pursuant to the terms of the Trust (“Trustee
B-5
ICNU_DR_032 Attachment A Page 79 of 90
ˆ200GZcqP7Jk273s7oŠ
200GZcqP7Jk273s7o
836681 TX 73AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
Shares”) shall be held for the benefit of Participants, and shall be distributed to Participants or their beneficiaries
by the Trustee at the direction of the Plan Administrator in accordance with the terms and conditions of the
Awards. Awards may also be made in units that are redeemable (in whole or in part) in Trustee Shares.
SECTION 4. STOCK SUBJECT TO THE PLAN
4.1 Authorized Number of Shares
Subject to adjustment from time to time as provided in Section 15.1, a maximum of 6,135,000 shares of Common
Stock (which represents the sum of: (i) 4,500,000 shares that were previously authorized; and (ii) 1,635,000
shares newly authorized by shareholders with this restatement) shall be available for issuance under the Plan.
Shares issued under the Plan shall be drawn from authorized and unissued shares or shares now held or
subsequently acquired by the Company or, if required by applicable law, shall be purchased by the Trustee on the
open market. In the event a Trust is required, the Company shall not issue any Common Stock under the Plan to
the Trust or to any Participant, nor shall the Company purchase any Trustee Shares from the Trust.
4.2 Limitations
(a) Subject to adjustment from time to time as provided in Section 15.1, not more than an aggregate of
625,000 shares shall be available for issuance pursuant to grants of Restricted Stock under the Plan.
(b) Subject to adjustment from time to time as provided in Section 15.1, not more than 200,000 shares of
Common Stock may be made subject to Awards under the Plan to any individual Participant in the
aggregate in any one fiscal year of the Company, such limitation to be applied in a manner consistent
with the requirements of, and only to the extent required for compliance with, the exclusion from the
limitation on deductibility of compensation under Section 162(m) of the Code.
(c) Subject to adjustment from time to time as provided in Section 15.1, to the extent consistent with
Section 424 of the Code, not more than an aggregate of 80,000 shares may be issued under Incentive
Stock Options.
4.3 Reuse of Shares
Any shares of Common Stock that have been made subject to an Award that cease to be subject to the Award
(other than by reason of exercise or payment of the Award to the extent it is exercised for or settled in shares)
shall again be available for issuance in connection with future grants of Awards under the Plan; provided,
however, that for purposes of Section 4.2, any such shares shall be counted in accordance with the requirements
of Section 162(m) of the Code. Shares that are subject to tandem Awards shall be counted only once.
SECTION 5. ELIGIBILITY
Awards may be granted under the Plan to those officers, directors and employees of the Company and its
Subsidiaries as the Plan Administrator from time to time selects.
SECTION 6. AWARDS
6.1 Form and Grant of Awards
The Plan Administrator shall have the authority, in its sole discretion, to determine the type or types of Awards to
be made under the Plan; provided, however, after December 31, 2004, the Plan Administrator may only award or
grant those Awards that either comply with the applicable requirements of Section 409A of the Code, or do not
result in the deferral of compensation within the meaning of Section 409A of the Code. Such Awards may
include, but are not limited to, Incentive Stock Options, Nonqualified Stock Options, Stock Appreciation Rights,
Stock Awards, Performance Awards, Other Stock-Based Awards and Dividend Equivalent Rights. Awards may
B-6
ICNU_DR_032 Attachment A Page 80 of 90
ˆ200GZcqP7Jk2FBV7QŠ
200GZcqP7Jk2FBV7Q
836681 TX 74AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
be granted singly, in combination or in tandem so that the settlement or payment of one automatically reduces or
cancels the other. Awards may also be made in combination or in tandem with, as alternatives to, or as the
payment form for, grants or rights under any other employee or compensation plan of the Company.
6.2 Acquired Company Awards
Notwithstanding anything in the Plan to the contrary, the Plan Administrator may grant Awards under the Plan in
substitution for awards issued under other plans, or assume under the Plan awards issued under other plans, if the
other plans are or were plans of other acquired entities (“Acquired Entities”) (or the parent of the Acquired
Entity) and the new Award is substituted, or the old award is assumed, by reason of a merger, consolidation,
acquisition of property or of stock, reorganization or liquidation (the “Acquisition Transaction”); provided,
however, any substitution of a new Option pursuant to a corporate transaction for an outstanding option or the
assumption of an outstanding option shall meet the requirements of Treasury Regulation §1.424-1. The preceding
sentence shall apply to “incentive stock options” as that term is defined in Section 422 of the Code and
nonqualified stock options. In the event that a written agreement pursuant to which the Acquisition Transaction is
completed is approved by the Board and said agreement sets forth the terms and conditions of the substitution for
or assumption of outstanding awards of the Acquired Entity, said terms and conditions shall be deemed to be the
action of the Plan Administrator without any further action by the Plan Administrator, except as may be required
for compliance with Rule 16b-3 under the Exchange Act, and the persons holding such Awards shall be deemed
to be Participants and Holders.
6.3 No Repricing
Other than in connection with a change in the Company’s capitalization as described in Section 15.1 of the Plan,
the exercise price of an Option or Stock Appreciation Right may not be reduced without shareholder approval.
6.4 Recoupment of Awards
Notwithstanding any other provision of the Plan, effective for any Award granted on or after February 12, 2010,
a Participant who engaged in material misconduct or a material error that contributed directly or indirectly, in
whole or in part, to the need for a restatement of the Company’s consolidated financial statements and who
becomes subject to the Company’s Recoupment Policy as adopted by the Board and as amended from time to
time (“Recoupment Policy”), may have all or any portion of his or her Award under this Plan forfeited and/or all
or a portion of any distribution payable to the Participant or his or her Beneficiary under the Plan recovered by
the Company. All awards and/or dividend equivalents described in the Plan are subject to the provisions of the
Recoupment Policy.
SECTION 7. AWARDS OF OPTIONS
7.1 Grant of Options
The Plan Administrator is authorized under the Plan, in its sole discretion, to issue Options as Incentive Stock
Options or as Nonqualified Stock Options, which shall be appropriately designated.
7.2 Option Exercise Price
The exercise price for shares purchased under an Option shall be as determined by the Plan Administrator, but
shall not be less than 100% of the Fair Market Value of the Common Stock on the Grant Date.
7.3 Term of Options
The term of each Option shall be as established by the Plan Administrator or, if not so established, shall be 10
years from the Grant Date.
B-7
ICNU_DR_032 Attachment A Page 81 of 90
ˆ200GZcqP7Jk2MK27CŠ
200GZcqP7Jk2MK27C
836681 TX 75AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
7.4 Exercise of Options
The Plan Administrator shall establish and set forth in each instrument that evidences an Option the time at
which or the installments in which the Option shall vest and become exercisable, which provisions may be
waived or modified by the Plan Administrator at any time. If not so established in the instrument evidencing the
Option, the Option will vest and become exercisable according to the following schedule, which may be waived
or modified by the Plan Administrator at any time:
Period of Holder’s Continuous Employment or
Service With the Company or Its
Subsidiaries From the Option Grant Date
Percent of Total
Option That Is Vested
and Exercisable
After 1 year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25%
After 2 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50%
After 3 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75%
After 4 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .100%
Notwithstanding the provisions of Section 7.4 above or of Section 7.6, any unvested portion of the Option shall
vest and become exercisable in full immediately upon termination of employment for reasons of Disability or
death.
To the extent that the right to purchase shares has accrued thereunder, an Option may be exercised from time to
time by written notice to the Company, in accordance with procedures established by the Plan Administrator,
setting forth the number of shares with respect to which the Option is being exercised and accompanied by
payment in full as described in Section 7.5. The Plan Administrator may determine at any time that an Option
may not be exercised as to less than 100 shares at any one time (or the lesser number of remaining shares covered
by the Option).
7.5 Payment of Exercise Price
The exercise price for shares purchased under an Option shall be paid in full to the Company by delivery of
consideration equal to the product of the Option exercise price and the number of shares purchased. Such
consideration must be paid in cash or by check, or, unless the Plan Administrator in its sole discretion determines
otherwise, either at the time the Option is granted or at any time before it is exercised, a combination of cash and/
or check (if any) and one or both of the following alternative forms:
(a) tendering (either actually or, if and so long as the Common Stock is registered under Section 12(b) or
12(g) of the Exchange Act, by attestation) Common Stock already owned by the Holder for at least six
months (or any shorter period necessary to avoid a charge to the Company’s earnings for financial
reporting purposes) having a Fair Market Value on the day prior to the exercise date equal to the
aggregate Option exercise price or
(b) if and so long as the Common Stock is registered under Section 12(b) or 12(g) of the Exchange Act,
and to the extent not prohibited by Section 402 of the Sarbanes-Oxley Act of 2002, delivery of a
properly executed exercise notice, together with irrevocable instructions, to
(i) a brokerage firm designated by the Company to deliver promptly to the Company the aggregate
amount of sale or loan proceeds to pay the Option exercise price and any withholding tax
obligations that may arise in connection with the exercise and
(ii) the Company to deliver the certificates for such purchased shares directly to such brokerage firm,
all in accordance with the regulations of the Federal Reserve Board.
In addition, the price for shares purchased under an Option may be paid, either singly or in combination with one
or more of the alternative forms of payment authorized by this Section 7.5 by such other consideration as the
Plan Administrator may permit.
B-8
ICNU_DR_032 Attachment A Page 82 of 90
ˆ200GZcqP7Jk2Qmqh:Š
200GZcqP7Jk2Qmqh:
836681 TX 76AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
7.6 Post-Termination Exercises
The Plan Administrator shall establish and set forth in each instrument that evidences an Option whether the
Option will continue to be exercisable, and the terms and conditions of such exercise, if a Holder ceases to be
employed by, or to provide services to, the Company or its Subsidiaries, which provisions may be waived or
modified by the Plan Administrator at any time. If not so established in the instrument evidencing the Option, the
Option will be exercisable according to the following terms and conditions, which may be waived or modified by
the Plan Administrator at any time.
In case of termination of the Holder’s employment or services other than by reason of death or Cause, the Option
shall be exercisable, to the extent of the number of shares purchasable by the Holder at the date of such
termination, only
(a) within one year if the termination of the Holder’s employment or services is coincident with
Retirement, Early Retirement in connection with a Company program offering early retirement or
Disability or
(b) within three months after the date the Holder ceases to be an employee, director, or officer of the
Company or a Subsidiary if termination of the Holder’s employment or services is for any reason other
than Retirement, Early Retirement in connection with a Company program offering early retirement or
Disability, but in no event later than the remaining term of the Option. Any Option exercisable at the
time of the Holder’s death may be exercised, to the extent of the number of shares purchasable by the
Holder at the date of the Holder’s death, by the personal representative of the Holder’s estate, the
person(s) to whom the Holder’s rights under the Award have passed by will or the applicable laws of
descent and distribution or the beneficiary designated pursuant to Section 14 at any time or from time
to time within one year after the date of death, but in no event later than the remaining term of the
Option. Any portion of an Option that is not exercisable on the date of termination of the Holder’s
employment or services shall terminate on such date, unless the Plan Administrator determines
otherwise. In case of termination of the Holder’s employment or services for Cause, the Option shall
automatically terminate upon first notification to the Holder of such termination, unless the Plan
Administrator determines otherwise. If a Holder’s employment or services with the Company are
suspended pending an investigation of whether the Holder shall be terminated for Cause, all the
Holder’s rights under any Option likewise shall be suspended during the period of investigation.
A transfer of employment or services between or among the Company and its Subsidiaries shall not be
considered a termination of employment or services for purposes of this Section 7.6. The effect of a Company-
approved leave of absence on the terms and conditions of an Option shall be determined by the Plan
Administrator, in its sole discretion.
SECTION 8. INCENTIVE STOCK OPTION LIMITATIONS
To the extent required by Section 422 of the Code, Incentive Stock Options shall be subject to the following
additional terms and conditions:
8.1 Dollar Limitation
To the extent the aggregate Fair Market Value (determined as of the Grant Date) of Common Stock with respect
to which Incentive Stock Options are exercisable for the first time during any calendar year (under the Plan and
all other stock option plans of the Company) exceeds $100,000, such portion in excess of $100,000 shall be
treated as a Nonqualified Stock Option. In the event the Participant holds two or more such Options that become
exercisable for the first time in the same calendar year, such limitation shall be applied on the basis of the order
in which such Options are granted.
B-9
ICNU_DR_032 Attachment A Page 83 of 90
ˆ200GZcqP7Jk2TRk7QŠ
200GZcqP7Jk2TRk7Q
836681 TX 77AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 8*
PMT 1C
SWRP64RS18
11.6.14
8.2 10% Shareholders
If a Participant owns more than 10% of the total voting power of all classes of the Company’s stock, then the
exercise price per share of an Incentive Stock Option shall not be less than 110% of the Fair Market Value of the
Common Stock on the Grant Date and the Option term shall not exceed five years. The determination of 10%
ownership shall be made in accordance with Section 422 of the Code.
8.3 Eligible Employees
Individuals who are not employees of the Company or one of its parent corporations or subsidiary corporations
may not be granted Incentive Stock Options. For purposes of this Section 8.3, “parent corporation” and
“subsidiary corporation” shall have the meanings attributed to those terms for purposes of Section 422 of the
Code.
8.4 Term
The term of an Incentive Stock Option shall not exceed 10 years.
8.5 Exercisability
To qualify for Incentive Stock Option tax treatment, an Option designated as an Incentive Stock Option must be
exercised within three months after termination of employment for reasons other than death, except that, in the
case of termination of employment due to total disability, such Option must be exercised within one year after
such termination. Employment shall not be deemed to continue beyond the first 3 months of a leave of absence
unless the Participant’s reemployment rights are provided by statute or contract. For purposes of this Section 8.5,
“total disability” shall mean a mental or physical impairment of the Participant that is expected to result in death
or that has lasted or is expected to last for a continuous period of 12 months or more and that causes the
Participant to be unable, in the opinion of the Company and two independent physicians, to perform his or her
duties for the Company and to be engaged in any substantial gainful activity. Total disability shall be deemed to
have occurred on the first day after the Company and the two independent physicians have furnished their
opinion of total disability to the Plan Administrator.
8.6 Taxation of Incentive Stock Options
In order to obtain certain tax benefits afforded to Incentive Stock Options under Section 422 of the Code, the
Participant must hold the shares issued upon the exercise of an Incentive Stock Option for two years after the
Grant Date of the Incentive Stock Option and one year from the date of exercise. A Participant may be subject to
the alternative minimum tax at the time of exercise of an Incentive Stock Option. The Plan Administrator may
require a Participant to give the Company prompt notice of any disposition of shares acquired by the exercise of
an Incentive Stock Option prior to the expiration of such holding periods.
SECTION 9. STOCK APPRECIATION RIGHTS
9.1 Grant of Stock Appreciation Rights
To the extent permitted by Section 6.1, the Plan Administrator may grant a Stock Appreciation Right separately
or in tandem with a related Option.
9.2 Tandem Stock Appreciation Rights
A Stock Appreciation Right granted in tandem with a related Option will give the Holder the right to surrender to
the Company all or a portion of the related Option and to receive an appreciation distribution (in shares of
Common Stock or cash or any combination of shares and cash, as the Plan Administrator, in its sole discretion,
B-10
ICNU_DR_032 Attachment A Page 84 of 90
ˆ200GZcqP7Jk2=5xh.Š
200GZcqP7Jk2=5xh.
836681 TX 78AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:00 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 7*
PMT 1C
SWRP64RS18
11.6.14
shall determine at any time) in an amount equal to the excess of the Fair Market Value for the date the Stock
Appreciation Right is exercised over the exercise price per share of the right, which shall be the same as the
exercise price of the related Option. A tandem Stock Appreciation Right will have the same other terms and
provisions as the related Option. Upon and to the extent a tandem Stock Appreciation Right is exercised, the
related Option will terminate.
9.3 Stand-Alone Stock Appreciation Rights
A Stock Appreciation Right granted separately and not in tandem with an Option will give the Holder the right to
receive an appreciation distribution (in shares of Common Stock or cash or any combination of shares and cash,
as the Plan Administrator, in its sole discretion, shall determine at any time) in an amount equal to the excess of
the Fair Market Value for the date the Stock Appreciation Right is exercised over the exercise price per share of
the right.
A stand-alone Stock Appreciation Right will have such terms as the Plan Administrator may determine, except
that the exercise price per share of the right must be at least equal to 100% of the Fair Market Value on the Grant
Date and the term of the right, if not otherwise established by the Plan Administrator, shall be 10 years from the
Grant Date.
9.4 Exercise of Stock Appreciation Rights
Unless otherwise provided by the Plan Administrator in the instrument that evidences the Stock Appreciation
Right, the provisions of Section 7.6 relating to the termination of a Holder’s employment or services shall apply
equally, to the extent applicable, to the Holder of a Stock Appreciation Right.
SECTION 10. STOCK AWARDS
10.1 Grant of Stock Awards
To the extent permitted by Section 6.1, the Plan Administrator is authorized to make Awards of Common Stock
to Participants on such terms and conditions and subject to such restrictions, if any (which may be based on
continuous service with the Company or the achievement of performance goals related to earnings, earnings per
share, profits, profit growth, profit-related return ratios, cost management, dividend payout ratios, economic
value added, cash flow or total shareholder return, where such goals may be stated in absolute terms or relative to
comparison companies), as the Plan Administrator shall determine, in its sole discretion, which terms, conditions
and restrictions shall be set forth in the instrument evidencing the Award. The terms, conditions and restrictions
that the Plan Administrator shall have the power to determine shall include, without limitation, the manner in
which shares subject to Stock Awards are held during the periods they are subject to restrictions and the
circumstances under which forfeiture of Restricted Stock shall occur by reason of termination of the Holder’s
services.
10.2 Issuance of Shares
Upon the satisfaction of any terms, conditions and restrictions prescribed in respect to a Stock Award, or upon
the Holder’s release from any terms, conditions and restrictions of a Stock Award, as determined by the Plan
Administrator, the Company shall release, as soon as practicable, to the Holder or, in the case of the Holder’s
death, to the personal representative of the Holder’s estate or as the appropriate court directs, the appropriate
number of shares of Common Stock.
10.3 Waiver of Restrictions
Notwithstanding any other provisions of the Plan, the Plan Administrator may, in its sole discretion, waive the
forfeiture period and any other terms, conditions or restrictions on any Restricted Stock under such circumstances
and subject to such terms and conditions as the Plan Administrator shall deem appropriate.
B-11
ICNU_DR_032 Attachment A Page 85 of 90
ˆ200GZcqP7Jk2eu57UŠ
200GZcqP7Jk2eu57U
836681 TX 79AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:01 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 6*
PMT 1C
SWRP64RS18
11.6.14
SECTION 11. PERFORMANCE AWARDS
11.1 Plan Administrator Authority
Performance Awards may be denominated in cash, shares of Common Stock or any combination thereof. To the
extent permitted by Section 6.1, the Plan Administrator is authorized to grant Performance Awards and shall
determine the nature, length and starting date of the performance period for each Performance Award and the
performance objectives to be used in valuing Performance Awards and determining the extent to which such
Performance Awards have been earned. Performance objectives and other terms may vary from Participant to
Participant and between groups of Participants. Performance objectives shall be based on earnings, earnings per
share, profits, profit growth, profit-related return ratios, cost management, dividend payout ratios, economic
value added, cash flow or total shareholder return, where such goals may be stated in absolute terms or relative to
comparison companies, as the Plan Administrator shall determine, in its sole discretion. Additional performance
measures may be used to the extent their use would comply with the exclusion from the limitation on
deductibility of compensation under Section 162(m) of the Code. Performance periods may overlap and
Participants may participate simultaneously with respect to Performance Awards that are subject to different
performance periods and different performance factors and criteria.
The Plan Administrator shall determine for each Performance Award the range of dollar values or number of
shares of Common Stock (which may, but need not, be shares of Restricted Stock pursuant to Section 10), or a
combination thereof, to be received by the Participant at the end of the performance period if and to the extent
that the relevant measures of performance for such Performance Awards are met. If Performance Awards are
denominated in cash, no more than an aggregate maximum dollar value of $1,000,000 shall be granted to any
individual Participant in any one fiscal year of the Company, such limitations to be applied in a manner
consistent with the requirements of, and to the extent required for compliance with, the exclusion from the
limitation on deductibility of compensation under Section 162(m) of the Code. The earned portion of a
Performance Award may be paid currently or on a deferred basis with such interest or earnings equivalent as may
be determined by the Plan Administrator. Payment shall be made in the form of cash, whole shares of Common
Stock (which may, but need not, be shares of Restricted Stock pursuant to Section 10), Options or any
combination thereof, either in a single payment or in annual installments, all as the Plan Administrator shall
determine.
11.2 Adjustment of Awards
The Plan Administrator may adjust the performance goals and measurements applicable to Performance Awards
to take into account changes in law and accounting and tax rules and to make such adjustments as the Plan
Administrator deems necessary or appropriate to reflect the inclusion or exclusion of the impact of extraordinary
or unusual items, events or circumstances, except that, to the extent required for compliance with the exclusion
from the limitation on deductibility of compensation under Section 162(m) of the Code, no adjustment shall be
made that would result in an increase in the compensation of any Participant whose compensation is subject to
the limitation on deductibility under Section 162(m) of the Code for the applicable year. The Plan Administrator
also may adjust the performance goals and measurements applicable to Performance Awards and thereby reduce
the amount to be received by any Participant pursuant to such Awards if and to the extent that the Plan
Administrator deems it appropriate.
11.3 Payout Upon Termination
The Plan Administrator shall establish and set forth in each instrument that evidences a Performance Award
whether the Award will be payable, and the terms and conditions of such payment, if a Holder ceases to be
employed by, or to provide services to, the Company or its Subsidiaries, which provisions may be waived or
modified by the Plan Administrator at any time. If not so established in the instrument evidencing the
Performance Award, the Award will be payable according to the following terms and conditions, which may be
waived or modified by the Plan Administrator at any time. If during a performance period a Participant’s
B-12
ICNU_DR_032 Attachment A Page 86 of 90
ˆ200GZcqP7Jk2iHthgŠ
200GZcqP7Jk2iHthg
836681 TX 80AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:01 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 6*
PMT 1C
SWRP64RS18
11.6.14
employment or services with the Company terminate by reason of the Participant’s Retirement, Early Retirement
at the Company’s request, Disability or death, such Participant shall be entitled to a payment with respect to each
outstanding Performance Award at the end of the applicable performance period (a) based, to the extent relevant
under the terms of the Award, on the Participant’s performance for the portion of such performance period
ending on the date of termination and (b) prorated for the portion of the performance period during which the
Participant was employed by the Company, all as determined by the Plan Administrator. To the extent consistent
with Section 409A of the Code, the Plan Administrator may provide for an earlier payment in settlement of such
Performance Award discounted at a reasonable interest rate and otherwise in such amount and under such terms
and conditions as the Plan Administrator deems appropriate.
Except as otherwise provided in Section 15 or in the instrument evidencing the Performance Award, if during a
performance period a Participant’s employment or services with the Company terminate other than by reason of
the Participant’s Retirement, Early Retirement at the Company’s request, Disability or death, then such
Participant shall not be entitled to any payment with respect to the Performance Awards relating to such
performance period, unless the Plan Administrator shall otherwise determine. The provisions of Section 7.6
regarding leaves of absence and termination for Cause shall apply to Performance Awards.
SECTION 12. OTHER STOCK-BASED AWARDS
To the extent permitted by Section 6.1, the Plan Administrator may grant other Awards under the Plan pursuant
to which shares of Common Stock (which may, but need not, be shares of Restricted Stock pursuant to
Section 10) are or may in the future be acquired, or Awards denominated in stock units, including ones valued
using measures other than market value. Such Other Stock-Based Awards may be granted alone or in addition to
or in tandem with any Award of any type granted under the Plan and must be consistent with the Plan’s purpose.
SECTION 13. DIVIDEND EQUIVALENT RIGHTS
To the extent permitted by Section 6.1, any Awards under the Plan may, in the Plan Administrator’s discretion,
earn Dividend Equivalent Rights. In respect of any Award that is outstanding on the dividend record date for
Common Stock, the Participant may be credited with an amount equal to the cash or stock dividends or other
distributions that would have been paid on the shares of Common Stock covered by such Award had such
covered shares been issued and outstanding on such dividend record date. The Plan Administrator shall establish
such rules and procedures governing the crediting of Dividend Equivalent Rights, including the timing, form of
payment and payment contingencies of such Dividend Equivalent Rights, as it deems are appropriate or
necessary.
SECTION 14. ASSIGNABILITY
No Option, Stock Appreciation Right, Stock Award, Performance Award, Other Stock-Based Award or Dividend
Equivalent Right granted under the Plan may be assigned or transferred by the Holder other than by will or by the
applicable laws of descent and distribution, and, during the Holder’s lifetime, such Awards may be exercised
only by the Holder or a permitted assignee or transferee of the Holder (as provided below). Notwithstanding the
foregoing, and to the extent permitted by Section 422 of the Code, the Plan Administrator, in its sole discretion,
may permit such assignment, transfer and exercisability and may permit a Holder of such Awards to designate a
beneficiary who may exercise the Award or receive compensation under the Award after the Holder’s death;
provided, however, that any Award so assigned or transferred shall be subject to all the same terms and
conditions contained in the instrument evidencing the Award.
SECTION 15. ADJUSTMENTS
15.1 Adjustment of Shares
In the event that, at any time or from time to time, a stock dividend, stock split, spin-off, combination or
exchange of shares, recapitalization, merger, consolidation, distribution to shareholders other than a normal cash
B-13
ICNU_DR_032 Attachment A Page 87 of 90
ˆ200GZcqP7Jk2nfghTŠ
200GZcqP7Jk2nfghT
836681 TX 81AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:01 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 6*
PMT 1C
SWRP64RS18
11.6.14
dividend or other change in the Company’s corporate or capital structure results in (a) the outstanding shares, or any
securities exchanged therefor or received in their place, being exchanged for a different number or class of securities
of the Company or of any other corporation or (b) new, different or additional securities of the Company or of any
other corporation being received by the holders of shares of Common Stock of the Company, then the Plan
Administrator shall make proportional adjustments in (i) the maximum number and kind of securities subject to the
Plan as set forth in Section 4.1, (ii) the maximum number and kind of securities that may be made subject to Stock
Awards and to Awards to any individual Participant as set forth in Section 4.2, and (iii) the number and kind of
securities that are subject to any outstanding Award and the per share price of such securities, without any change in
the aggregate price to be paid therefor; provided, however, any substitution of a new Option pursuant to a corporate
transaction for an outstanding Option or the assumption of an outstanding Option shall meet the requirements of
Treasury Regulation §1.424-1. The preceding sentence shall apply to “incentive stock options” as that term is
defined in Section 422 of the Code and nonqualified stock options. The determination by the Plan Administrator as
to the terms of any of the foregoing adjustments shall be conclusive and binding.
15.2 Change of Control
Except as otherwise provided in the instrument that evidences the Award, in the event of any Change of Control,
each Award that is at the time outstanding shall automatically accelerate so that each such Award shall,
immediately prior to the specified effective date for the Change of Control, become 100% vested and exercisable.
Such Award shall not so accelerate, however, if and to the extent that such Award is, in connection with the
Change of Control, either to be assumed by the successor corporation or parent thereof (the “Successor
Corporation”) or to be replaced with a comparable award for the purchase of shares of the capital stock of the
Successor Corporation. The determination of Award comparability under clause (a) above shall be made by the
Plan Administrator, and its determination shall be conclusive and binding. All such Awards shall terminate and
cease to remain outstanding immediately following the consummation of the Change of Control, except to the
extent assumed by the Successor Corporation. Any such Awards that are assumed or replaced in the Change of
Control and do not otherwise accelerate at that time shall be accelerated in the event that the Holder’s
employment or services should subsequently terminate within three years following such Change of Control,
unless such employment or services are terminated by the Successor Corporation for Cause or by the Holder
voluntarily without Good Reason.
15.3 Further Adjustment of Awards
Subject to Sections 15.2 and 17.3, and subject to the limitations set forth in Section 11, the Plan Administrator
shall have the discretion, exercisable at any time before a sale, merger, consolidation, reorganization, liquidation
or other corporate transaction, as defined by the Plan Administrator, to take such further action as it determines to
be necessary or advisable, and fair and equitable to Participants, with respect to Awards. Such authorized action
may include (but shall not be limited to) establishing, amending or waiving the type, terms, conditions or
duration of, or restrictions on, Awards so as to provide for earlier, later, extended or additional time for exercise,
payment or settlement or lifting restrictions, differing methods for calculating payments or settlements, alternate
forms and amounts of payments and settlements and other modifications, and the Plan Administrator may take
such actions with respect to all Participants, to certain categories of Participants or only to individual
Participants; provided, however, the Plan Administrator may act only in a manner that either complies with the
applicable requirements of Section 409A of the Code, or does not result in the deferral of compensation within
the meaning of Section 409A of the Code. The Plan Administrator may take such action before or after granting
Awards to which the action relates and before or after any public announcement with respect to such sale,
merger, consolidation, reorganization, liquidation or Change of Control that is the reason for such action.
15.4 Limitations
The grant of Awards will in no way affect the Company’s right to adjust, reclassify, reorganize or otherwise
change its capital or business structure or to merge, consolidate, dissolve, liquidate or sell or transfer all or any
part of its business or assets.
B-14
ICNU_DR_032 Attachment A Page 88 of 90
ˆ200GZcqP7Jk2rTphzŠ
200GZcqP7Jk2rTphz
836681 TX 82AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:01 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 4*
PMT 1C
SWRP64RS18
11.6.14
SECTION 16. WITHHOLDING
The Company may require the Holder to pay to the Company the amount of any withholding taxes that the
Company is required to withhold with respect to the grant, exercise, payment or settlement of any Award.
Subject to the Plan and applicable law and unless the Plan Administrator determines otherwise, the Holder may
satisfy withholding obligations, in whole or in part, by paying cash, by electing to have the Company withhold
shares of Common Stock (up to the employer’s minimum required tax withholding rate) or by transferring shares
of Common Stock to the Company (already owned by the Participant for the period necessary to avoid a charge
to the Company’s earnings for financial reporting purposes), in such amounts as are equivalent to the Fair Market
Value of the withholding obligation. The Company shall have the right to withhold from any Award or any
shares of Common Stock issuable pursuant to an Award or from any cash amounts otherwise due or to become
due from the Company to the Participant an amount equal to such taxes.
SECTION 17. AMENDMENT AND TERMINATION OF PLAN
17.1 Amendment of Plan
The Plan may be amended only by the Board as it shall deem advisable; provided, however, (i) the Board shall
consider the impact of Section 409A of the Code on any amendment; and (ii) to the extent required for
compliance with Section 422 of the Code or any other applicable law, rule or regulation, shareholder approval
will be required for any amendment that will (a) increase the total number of shares as to which Options may be
granted or that may be used in payment of Stock Appreciation Rights, Performance Awards, Other Stock-Based
Awards or Dividend Equivalent Rights under the Plan or that may be issued as Stock Awards, (b) modify the
class of persons eligible to receive Options, (c) result in a “material revision” of the Plan as contemplated by
Section 303A.08 of the New York Stock Exchange Listed Company Manual, or (d) otherwise require shareholder
approval under any applicable law, rule or regulation.
17.2 Termination of Plan
The Board may suspend or terminate the Plan at any time. The Plan will have no fixed expiration date; provided,
however, that no Incentive Stock Options may be granted more than 10 years after the earlier of the Plan’s adoption by
the Board and approval by the shareholders. In accordance with Treasury Regulations §§1.422-2(b)(iii) and 1.422-2(c),
the amendment and restatement of the Plan effective January 1, 2005 constitutes a new plan for purposes of the
Incentive Stock Option rules. As a result, Incentive Stock Options may be granted within ten years from the earlier of
the date the amended and restated plan is adopted by the Board or the date such plan is approved by shareholders.
17.3 Consent of Holder
The amendment or termination of the Plan shall not, without the consent of the Holder of any Award under the
Plan, impair or diminish any rights or obligations under any Award theretofore granted under the Plan. Any
change or adjustment to an outstanding Incentive Stock Option shall not, without the consent of the Holder, be
made in a manner so as to constitute a “modification” that would cause such Incentive Stock Option to fail to
continue to qualify as an Incentive Stock Option.
SECTION 18. GENERAL
18.1 Award Agreements
Awards granted under the Plan shall be evidenced by a written agreement that shall contain such terms,
conditions, limitations and restrictions as the Plan Administrator shall deem advisable and that are not
inconsistent with the Plan.
18.2 Continued Employment or Services; Rights in Awards
None of the Plan, participation in the Plan as a Participant or any action of the Plan Administrator taken under
the Plan shall be construed as giving any Participant or employee of the Company any right to be retained in the
employ of the Company or limit the Company’s right to terminate the employment or services of the Participant.
B-15
ICNU_DR_032 Attachment A Page 89 of 90
ˆ200GZcqP7Jk2wpchKŠ
200GZcqP7Jk2wpchK
836681 TX 83AVISTA CORPORATION
NOTICE & PROXY STATE
24-Feb-2015 09:01 EST
CLN PSPOR
RR Donnelley ProFile SWRpf_rend 4*
PMT 1C
SWRP64RS18
11.6.14
18.3 Registration
The Company shall be under no obligation to any Participant to register for offering or resale or to qualify for
exemption under the Securities Act, or to register or qualify under state securities laws, any shares of Common
Stock, security or interest in a security paid or issued under, or created by, the Plan, or to continue in effect any
such registrations or qualifications if made.
The Company may issue certificates for shares with such legends and subject to such restrictions on transfer and
stop-transfer instructions as counsel for the Company deems necessary or desirable for compliance by the
Company with federal and state securities laws.
Inability of the Company to obtain, from any regulatory body having jurisdiction, the authority deemed by the
Company’s counsel to be necessary for the lawful issuance and sale of any shares hereunder or the unavailability
of an exemption from registration for the issuance and sale of any shares hereunder shall relieve the Company of
any liability in respect of the nonissuance or sale of such shares as to which such requisite authority shall not
have been obtained.
18.4 No Rights as a Shareholder
No Award shall entitle the Holder to any cash dividend (except to the extent provided in an Award of Dividend
Equivalent Rights), voting or other right of a shareholder unless and until the date of issuance under the Plan of
the shares that are the subject of such Award, free of all applicable restrictions.
18.5 Compliance With Laws and Regulations
Notwithstanding anything in the Plan to the contrary, the Board, in its sole discretion, may bifurcate the Plan so
as to restrict, limit or condition the use of any provision of the Plan to Participants who are officers or directors
subject to Section 16 of the Exchange Act without so restricting, limiting or conditioning the Plan with respect to
other Participants. Additionally, in interpreting and applying the provisions of the Plan, any Option granted as an
Incentive Stock Option pursuant to the Plan shall, to the extent permitted by law, be construed as an “incentive
stock option” within the meaning of Section 422 of the Code.
18.6 Unfunded Plan
The Plan is intended to constitute an “unfunded” plan. Nothing contained herein shall require the Company to
segregate any monies or other property, or shares of Common Stock, or to create any trusts, or to make any
special deposits for any immediate or deferred amounts payable to any Participant, and no Participant shall have
any rights that are greater than those of a general unsecured creditor of the Company.
18.7 Severability
If any provision of the Plan or any Award is determined to be invalid, illegal or unenforceable in any jurisdiction,
or as to any person, or would disqualify the Plan or any Award under any law deemed applicable by the Plan
Administrator, such provision shall be construed or deemed amended to conform to applicable laws, or, if it
cannot be so construed or deemed amended without, in the Plan Administrator’s determination, materially
altering the intent of the Plan or the Award, such provision shall be stricken as to such jurisdiction, person or
Award, and the remainder of the Plan and any such Award shall remain in full force and effect.
SECTION 19. EFFECTIVE DATE
The Plan’s effective date is the date on which it is adopted by the Board, so long as it is approved by the
Company’s shareholders at any time within 12 months of such adoption.
B-16
ICNU_DR_032 Attachment A Page 90 of 90

Page 1 of 4
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/05/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies/Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 032 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide a description of how levels of executive compensation are set, including whether the
Company considered factors discussed by the Commission in Dockets UE-110876 and UG-110877, Order 06 at ¶ 42.

RESPONSE:
Avista’s compensation program design and philosophy for establishing executive compensation levels, including consideration of those factors discussed by the Commission in Dockets UE-110876 and UG-
110877 Order 06 at ¶ 42 is described below:

Avista is committed to providing a total compensation program that will attract and retain qualified
people required to meet the needs and expectations of all utility stakeholders, including but not limited to,
customers, shareholders and regulators. The overarching compensation philosophy is that success is
measured by the ability to hire, develop and retain the most qualified people to work in a very complex
industry. In an effort to recruit and retain such people, Avista provides base salaries, performance-based
award programs and benefits that are competitive in the marketplace as benchmarked against other
similar-sized companies in regional and national markets.

The Compensation Committee of the Board of Directors is responsible for reviewing and approving, as
well as overseeing the risks associated with, compensation and benefits of executive officers of the
Company. The overall design principle is to create an effective total compensation plan structured to
focus executive officers on the achievement of specific annual, long-term, and strategic goals and align
executives’ interests with those of customers and shareholders by rewarding performance that meets
and/or exceeds Company operational goals and maintains and improves shareholder value. Considerable
time is spent weighing various design options to ensure that top management compensation is primarily
performance-based, fair and reasonable while not encouraging key decision makers to take excessive
risks.

The Compensation Committee is composed of independent directors as defined by the rules of the New
York Stock Exchange, and in addition, complies with the “outside director” requirement of Section
162(m) of the Internal Revenue Code of 1986, as amended (the Code), and the “non-employee director”
requirement of Rule 16b-3 under the Exchange act. Board members are elected based on factors that are
in the best interest of the stakeholders of the Company including the knowledge, experience, integrity,
and judgment of each candidate; the potential contributions of each candidate to the diversity of

Page 2 of 4
backgrounds, experience and competencies that the Board desires to have represented; each candidates’
ability to devote sufficient time and effort to his or her duties as a director; independence and willingness
to consider all strategic proposals and other criteria established by the Board, as well as any core
competencies or technical expertise necessary to staff Board Committees. The Company’s compensation
policies and practices do not include factors which create risks that are reasonably likely to have a
material adverse effect on the Company.

The Compensation Committee believes that the compensation of our senior executives should be a
combination of base pay and pay at risk / variable performance-based incentive plans, with a significant
portion of their compensation related to achievement of specific goals for corporate performance that are
likely to produce long-term customer and shareholder value.

The executive officer short term incentive plan (STIP) is designed to align the interests of senior
management with both customer and shareholder interests in order to achieve overall positive financial
and operational performance for the Company. The performance metrics for the STIP are based on factors
that are essential to the long-term success of the Company, and with the exception of the EPS goals, are
identical to performance metrics used in the Company’s annual cash incentive plan for non-executive
employees. These metrics are designed to be reasonably achievable with strong management
performance. Maximum performance levels are designed to be difficult to achieve given historical
performance and forecasted results at the time the metrics are approved. The Compensation Committee
believes that having similar metrics for both the executive short term incentive plan (STIP) and the non-
executive employee annual incentive plan encourages employees at all levels of the Company to focus on
common objectives.

The Executive Officer Long Term Incentive Plan (LTIP) is designed to align the interests of executives
with customer and shareholder interests in order to achieve positive financial performance for the
Company over the long term. The LTIP is a pay-at risk plan whereby executive officers and other key
employees are eligible to receive common stock and dividend equivalents if stated targets are achieved
and employment is maintained. The program encourages participants to focus on the long term
performance of the Company and provides an opportunity to maintain ownership in the Company. The
current LTIP awards are based on 25% restricted common stock units and 75% through performance
based common stock equity awards.

The factors that influence the Compensation Committee’s decisions regarding base salary include:
responsibilities and job complexity, experience and breadth of knowledge and competitive pay among
executives in the utility and diversified energy industry. Annually, performance reviews are conducted
for each executive officer by his/her manager and the Compensation Committee reviews the performance
ratings in order to determine appropriate adjustments to base salaries. The CEO has specific stated goals
for performance with targets generally related to strategic planning, financial performance, safety targets,
energy resource management, regulatory matters, succession planning, government and customer value.
The CEO’s performance relative to established targets is reviewed both quarterly and annually with status
updates given to the full Board of Directors.

Page 3 of 4
As described above, a high degree of internal factors such as individual and Company performance goals,
succession planning, job complexity, experience, and breadth of knowledge are all considered when
developing the overall pay structure of the executive officer group. Developing an overall compensation
structure and the ability to sufficiently monitor and evaluate goals is a very difficult, complex and
dynamic process. It is not always a process based on a scientific step-by-step approach but often is
attributed to factors which cannot be directly quantified such as the value inherent in the “investment” in
an executive who has been here for a long period of time, or the value in preserving company culture by
promoting from within. The Compensation Committee of the Board of Directors is charged with making
those difficult decisions in an independent capacity.

In addition to these internal factors, the company utilizes external peer group analysis to benchmark its
executives against a group of companies with similar business profiles, similar revenue size and market
capitalization. These companies can reasonably be assumed to be companies with which we compete for
talent.

The Compensation Committee works with its consultant to conduct an annual competitive review of the
total compensation program. Through the review process, the Compensation Committee generally targets
overall compensation levels (base, short-term incentive and long-term incentives) within +/-15% of the
median of the peer group. Pay components may vary higher or lower than the median depending on an
individual’s role, responsibilities, and performance within the Company. The Compensation Committee
believes this target positioning is effective to attract and retain our executives.

Annually each element of total compensation, which includes base salary, annual cash incentives, and
long-term incentives, is compared against a peer group of companies which represent Company
competitors for executive talent. The following factors are considered in peer group selection:

• Relative Peer Company Scope – Revenue and Market Capitalization
• Industry Focus and Operational Focus
• Attainability and Quality of pay data
• Statistical Valid Sample
• Compensation Committee Selection Approval

Typically local utilities have not been included in the market review data because they do not fall within
the appropriate peer company scope related to revenue and market capitalization, or are not investor
owned utilities. Investor owned utilities face different challenges than many consumer-owned utilities
(PUDs, REAs, Co-Ops, or Municipals) and, as such, executive compensation programs are structured
differently.

It is important to note while benchmarking is utilized in establishing actual pay, it is not the sole criteria.
The Compensation Committee uses a variety of sources of data to help it make informed decisions about
market compensation practices. Board members have many years of experience related to executive
compensation matters and are aware of the communication across the country related to executive
compensation. Significant flexibility is afforded Board members that carry out this responsibility. The

Page 4 of 4
Board relies on competitive data provided by outside consultants as well as public proxy data and uses
informed judgment to establish compensation that is reasonable and appropriate for all stakeholders,
based on the unique circumstances of Avista.

Please see ICNU_DR_032 Attachment A for the Company’s 2015 Preliminary Proxy Statement for
additional information on peer group selection.

Please see the Company’s response to ICNU_DR_031 for a description of current executive
compensation including but not limited to base salary, non-equity incentive pay, and incentive pay stating
which elements and amounts are included in rates and what elements are not recovered through rates.

See also Avista’s response to ICNU_DR_030 and ICNU_033.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/05/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies/Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 033 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide a narrative response explaining the Company’s policy and/or position on whether, and, if
so, why the existing levels of executive compensation are appropriate for recovery in utility rates. RESPONSE:

Avista believes that the executive officer compensation programs are structured appropriately to meet the Company’s utility business objectives and are therefore appropriate for recovery in utility rates. The
executive officer compensation programs are designed to focus the executive officer team on achieving
solid financial results, maintaining system reliability, and delivering outstanding customer service. The
compensation structure and levels serve as an appropriate tool to help motivate, retain and attract a highly
experienced, successful executive officer team to manage the Company.
Ratepayers benefit from effective and capable utility management through innovation, efficiencies and
leadership on strategic initiatives, which serve to run the company efficiently and manage costs for the
utility and its ratepayers. Avista’s total compensation philosophy creates the right focus for executive
officers because a major portion of the overall earning opportunity is at risk. For example, employees and executive officers, as a whole, have to achieve the goals of the incentive plan for the plan to payout.

This tension in plan design helps motivate and focus all employees on the stated goals of the Company. In
order to receive the pay-at-risk portion of compensation, employees have to keep focused on cost control,
customer satisfaction and reliability within the system. Avista’s existing total compensation plan is appropriately weighted to retain current employees, while remaining competitive enough to attract new
employees. A pay-at-risk component of compensation is not designed to pay out the full incentive
opportunity every year, nor is it designed to have no payout for an extended period of time. Pay-at-risk
plans are designed to help focus employees on making decisions that benefit the Company and its
customers, while at the same time functioning as an integrated component of total Compensation.
With the aid of an independent Compensation Consultant, the Compensation Committee benchmarks each
item in the compensation program against companies similar in size and business characteristics. Levels
are set based on this research, experience levels and individual contributions. These factors are evaluated
every year and adjusted as needed. The current levels of compensation are based on the results of that analysis and at a level comparable to our peer group.

Ratepayers receive several benefits from utility operational components of the incentive plan, making it
appropriate for recovery. The plan focuses the executive officers on key objectives of the Company
including reliability, customer service and operational efficiency which directly benefits customers and overall operational efficiency translates to lower rates. The operating components of the Short Term
Incentive Plan (STIP) focuses our executive officers on those areas that provide ratepayer benefit. Various

Page 2 of 2
options have been explored surrounding compensation and benefit programs to assess whether
eliminating or reducing various programs would be appropriate given today’s economic environment. If
we were to eliminate the incentive plan, Avista would have to increase base salary and/or compensation components in order to keep total employee compensation and benefits at competitive levels. Finally, the
Incentive Plan is part of a comprehensive benefits package provided to employees that makes Avista
competitive in attracting skilled, experienced talent in the marketplace.

The performance share portion of the executive officer Long Term Incentive Plan (LTIP) is not included in rates because it is based on elements focusing on shareholder value. The restricted Stock portion of the
LTIP is included in rates because it provides a vehicle to encourage retention for senior management. The
SERP and Deferred Compensation programs are also not in rates because they are benefits over and above
what is offered to all employees as part of their total compensation package. However, the employee
defined benefit pension plan is included in rates because it is a core benefit to all employees, which executives are a part of. As with all components of the overall compensation package, benefits are set at
levels consistent with a peer group of companies, such that the Company can attract, motivate and retain
qualified employees.

Overall, the Company’s executive officer compensation package is allocated appropriately between customers and shareholders. Metrics deemed to directly benefit shareholders – such as EPS targets in the
STIP and performance shares in the LTIP are charged to non-utility accounts and are not included in rates.
Those metrics which directly benefit customers – such as the operational components of the STIP are
appropriately included in rates. Additionally, all employees, including executive officers, charge a
portion of their base salaries to non-utility operations for work directly related to subsidiary operations or projects not directly related to utility operations. In summary, the Company’s overall compensation is
both appropriate in amount and allocation between utility and non-utility (shareholder) operations.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/03/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 34 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Has the Company relied on its capital budget to develop its forecast of capital expenditures in this proceeding?
RESPONSE:
Yes. The Company uses several factors including the capital budget to develop the capital transfers to
plant that are included in this proceeding. The company starts with the budgeted capital transfers to plant obtained from the Financial Planning and Analysis (FP&A) department and then verifies, updates and
reviews the projects included in the summary.

Page 1 of 3
-20%
0%
20%
40%
60%
80%
100%
120%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Av
g
.

%

C
h
a
n
g
e

f
r
o
m

2
0
0
5

B
a
s
e
l
i
n
e
Utility Costs are Rising Faster than Sales
Net Plant Investment Non-Fuel O&M/A&G Retail kWh Sales Retail Therm Sales
Actual
Forecast
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 035 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to Dockets UE-120436 et al., Order 09/14 at ¶ 75. Please explain how ratepayers will benefit
from Avista’s savings efforts, as contemplated by the Commission, if the Commission approves the trending analysis in the Company’s attrition study?

RESPONSE: In a direct response to the continuing increase in non-fuel O&M/A&G year over year, senior management
of the Company took steps to reduce the trend in increasing expenditures. Examples of cost management
efficiencies and steps taken to reduce the growth in expenses, as discussed below, include resource-related
decisions, the Voluntary Severance Incentive Plan (VSIP) to reduce employee complement, and changes to pension and post-retirement medical programs. These changes illustrate Avista’s efforts to control our
costs, improve efficiency, and focus on long-term sustainable savings to continuously improve our service
to customers and manage costs into the future.

The impact of these cost management efficiencies and steps taken to reduce the growth in expenses affect the rate year and can be seen in the following chart, provided in Mr. Morris’ direct testimony at Exhibit
No. (SLM-1T) page 11, Illustration No. 7:

Page 2 of 3
This chart clearly shows the reduction in expenses in 2013, as represented by the green Non-Fuel
O&M/A&G line and continuing at a lower level through 2018. Furthermore, as explained in Andrews’
testimony at Exhibit No. __(EMA-1T) page 28, lines 6-9, although Avista’s O&M/A&G costs have grown at an annual rate of approximately 5.7% per year for the past six years (2007-2013), we have used
a lower annual growth rate of 3% per year for our Attrition Study to reflect the recent cost-cutting
measures implemented by the Company, and the expectation that Avista will manage the growth in these
expenses to a lower level in future years.
As noted at Exhibit No. __(SLM-1T), starting at page 12, line 1, the reduction in operating expenses in
2013 (green line) related primarily to Avista’s Voluntary Severance Incentive Plan (VSIP) executed in the
fourth quarter of 2012, reducing employee complement at the Company. In addition, in 2013, senior
management made changes to Avista’s pension and post-retirement medical plans, effective January 1,
2014, which has reduced future O&M/A&G costs.
Avista’s response to ICNU_DR_019C showed the annual savings of the 55 eliminated positions totaled
over $5 million. In addition, 2015 and 2016 savings related to the Company’s changes in its pension and
post retirement medical plans on a system basis are estimated to be approximately $2.6 million and $3
million, respectively, with increasing annual savings expected going forward. As noted above, these savings are reflected in the Company’s filing for 2016 through a reduced attrition escalation factor of all
O&M and A&G expenses of 3%. These savings are also reflected in the Company’s Pro Forma Cross
Check Studies, as the reduced level of labor is already reflected in the Company’s twelve-months ended
September 2014 results of operations for Washington, and the 2016 level of pension and post retirement
medical expenses have been reflected in the Pro Forma Employee Benefit adjustments (see Exhibit Nos._(JSS-2) and _(JSS-3).)

Other examples of cost management which have a future impact, relate to the biomass energy bill
(SB5575) signed by Washington Governor Christine Gregoire on March 7, 2012 and the decisions made
related to the Company’s Palouse Wind Project. The biomass energy bill (SB5575) qualified legacy biomass energy (built before 1999) as an eligible renewable resource for purposes of meeting the
renewable portfolio standard (RPS) requirements of the Washington State Energy Independence Act (I-
937). As a result of the bill’s passage, the energy generated at Avista’s Kettle Falls biomass plant
qualifies to meet our RPS requirements, beginning in 2016. The passage of the bill, which involved a
multi-year legislative effort led by Avista, will save our customers millions of dollars over the long-term, because Avista can now use this existing renewable power to meet our State mandates, which reduces the
need to buy renewable energy credits or invest in the development of new resources.

In December 2012, with the addition of the Palouse Wind Project to Avista’s electric generation portfolio,
Avista began receiving power from this relatively low-cost purchased power agreement (PPA). As background leading to acquiring the output to this Project, Avista had purchased the Reardan wind site in
2008 for the purpose of installing renewable wind generation to comply with the requirements of I-937.
In 2009, the Reardan project was compared against 29 competing proposals for renewable energy offered
by third-parties to Avista through a Request for Proposals (RFP). Analysis of all of the proposals showed
that the Reardan Project was the Company’s least-cost option for securing a new renewable resource for its customers. However, even though it was the least-cost option, the levelized cost to customers from
Reardan would still be over 10 cents per kWh. After further consideration, the Company chose, in 2010,
to delay development of Reardan due, in large part, to the fact that the Company did not have an
immediate need for energy resources or renewable resources, immediate development of the Project
would increase retail rates for customers, and the fact that Reardan represented a low-cost option to hold for later development. Avista continued to watch the market for wind resources, and in late 2010/early
2011, indications were that prices for wind turbines and other equipment had declined. Avista issued

Page 3 of 3
another RFP in February 2011, and executed the PPA with First Wind for the Palouse Wind Project in
June 2011. Although the pricing for this PPA is confidential, Avista had requested renewable resource
proposals with a levelized cost equal to or less than 6.2 cents/kWh, and the pricing was well below the prior estimates of Reardan. By choosing to delay the Reardan Project, Avista was able to later take
advantage of much lower cost wind generation, which resulted in substantial benefits for the Company’s
customers. Because the Palouse Wind Project is a PPA, Avista receives no earnings associated with
acquiring the output from that Project. Therefore, Avista not only provided substantial cost savings to
customers, but also passed up the opportunity to invest in the Reardan Wind Project and earn a return for shareholders on what would have been a substantial investment.
These are two recent significant examples highlighting the extent of the efforts that Avista has made to
mitigate the long-term costs to its customers.

Additional measures worthy of note, are the continuing measures related to hiring restriction and the efforts of “Customer Touch Point Teams,” discussed below.

Hiring Restrictions: The Company continues to operate under a hiring restriction which requires
approval by the Chairman/President/CEO, President of the Utility, the CFO, and the Sr. VP for Human
Resources for all replacement or new hire positions.
Customer Touch Point Teams: In the fall of 2011, a team from across the Company identified every
contact point or “touch point” a customer has with Avista. The objective of the initiative is to improve our
customers’ overall experience when doing business with us, as well as improve responsiveness in a
respectful and least cost manner. This team identified a “touch point map” of 172 different customer interactions or touch points. To date, the touch point teams have made improvements to 57 distinct touch points. In 2014 Avista touch point team projects focused on Electric and Gas Emergency Operation
Planning (involving customer touch points), Paperless Billing, Damage Assessment During Storms, and
Storm Estimated Restoration Time. In 2013, other examples included touch point team projects that
focused on customer awareness of natural gas safety, the distributed generation application process, and accuracy of electric outage estimated restoration times.
Although not all examples noted above are specifically quantified and provided here, as explained above,
the Company has reflected the reduction to its O&M and A&G costs in its requested revenue requirement
through its use of a lower “Adopted Operating Expenses” factor used within its electric and natural gas Attrition Studies. (See page 9 of Exhibit Nos. _(EMA-2) and _(EMA-3).)

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: E. Andrews/K. Schuh
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 036 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide a narrative response explaining the Company’s policy and/or position on customer
concerns that Avista’s continued reliance on attrition studies, cross-checked by pro forma studies, produces a mutually reinforcing or “self-fulfilling” dynamic—i.e., a tautology in which attrition studies
forecast increased capital spending which the Company “verifies” by budgeting capital spending to match
forecasts.

RESPONSE:
Through Avista’s filings in these Dockets the Company has proposed retail rates for the 2016 rate period
that are designed to be fair, just, reasonable and sufficient; for both customers and shareholders. The
Company has employed two different methodologies, an attrition analysis and pro forma analysis, using the best information available to develop proposed retail rates for 2016. Through its testimony, exhibits
and work papers, Avista has provided extensive evidence supporting the costs, investment and revenues
underlying its proposed retail rates.

The Company’s approach to developing proposed retail rates is in alignment with the fundamental principles of ratemaking outlined in the Rate Case and Audit Manual (NARUC Manual) prepared by the
NARUC Staff Subcommittee on Accounting and Finance. Ms. Andrews discusses these principles in her
direct testimony on page 10, line 4 through page 13, line 2. A copy of the NARUC Manual is attached to
Ms. Andrews testimony as Exhibit No. ____ (AMA-4).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 037 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please confirm that the Company uses a 12 coincident peak (“CP”) billing method for network transmission service, as specified in Sections 34.1 and 34.2 of Avista’s Open Access Transmission Tariff
(“OATT”). If the Company cannot confirm, please explain and provide support for the billing method
used.

RESPONSE:
Yes, the Company uses a 12 coincident peak billing method for network transmission service. A network
customers’s monthly charge is based upon the ratio of the most recent 12-month average of the customer’s
monthly loads coincident with Avista’s monthly transmission system peaks, divided by the 12-month average of Avista’s monthly transmission system peaks.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 038 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Does the Company agree that the Federal Energy Regulatory Commission (“FERC”) endorses a 12 CP billing method for network transmission service, without regard to the amount of energy flow? If no,
please provide the Company’s understanding of FERC’s sanctioned methodology, in light of FERC
Orders 888 and 889 and the Company’s own billing method in its OATT. If yes, please explain why the
Company applies the peak credit ratio, which classifies costs predominantly on an energy basis, to
transmission costs in Avista’s cost of service study (see Exhibit No.__(TLK-1T) at 11:15-17, 12:16-18). RESPONSE:

Yes, the Company agrees that FERC endorses the 12 CP billing method for network transmission service without regard to the amount of energy flow. The state jurisdictional cost of service analysis is independent of FERC ratemaking practices. Revenue from network transmission service customers reduces transmission
costs for the Company’s retail customers. This benefit is allocated to Washington and Idaho retail
jurisdictions based on the production/transmission ratio which is 50% demand and 50% energy. The peak
credit approach the Company has utilized in the Washington jurisdiction for decades addresses the dual purpose of the production and transmission system, which is to provide energy to customers throughout the year including peak times.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Scott Morris/Don Kopczynski
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 039 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST: Please refer to 6:17-19. Please provide all studies demonstrating that the cost differential of
replacing plant and equipment facilities is different today than throughout the Company’s history.

RESPONSE:
The best tool for documenting this cost differential is found in the Handy-Whitman©1 index for relevant
utility plant for the period 1912 through 2013. A file containing the index values, listed by major plant
categories by year, is provided as ICNU_DR_039, Attachment A. For an example of how the index is used, if you want to know the change in the cost of all electric transmission plant between 1960 and 2012, you take the index value for electric transmission plant for year 2012 (index value = 642) and divide that
value by the index value for transmission plant for the year 1960 (index value = 60), which yields a factor
of 10.7. The factor represents the differential in cost for electric transmission plant between the years
1960 and 2012. In this example, each dollar of investment made in 1960 would have required 10.7 times that value (or $10.70) for an equivalent amount of investment in 2012.

1 The Handy Whitman Index of Public Utility Construction Costs. Whitman, Requardt and Associates.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 040 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 10:18-12:3. Has the Company conducted any studies concerning the ratepayer impact of
the annual rate increases forecasted by Avista? If yes, please provide all such studies.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 040C. Please note that Avista’s response to ICNU – 040C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

Please see Avista’s response to ICNU_DR_020C, specifically, ICNU_DR_020C Confidential Attachment C,
pages 43-60, for material presented to the Board of Directors. This material was developed, in part, to estimate impacts of O&M expenditures, increased capital spending, capitalization changes and changes in
commodity costs on rates.

See also ICNU_DR_040C-Confidential Attachment A which includes the Company’s forecast (SEP5)
used in the Company’s direct filed case, which includes future rate adjustment margin needed in years 2016-2018, as shown on page 6.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Scott Morris/Mark Thies
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 041 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 12:6-13:9. To what extent do the cost management efficiencies discussed by Mr. Morris
apply to Avista Executive level personnel.

RESPONSE:
The cost management efficiencies discussed by Mr. Morris also apply to Executive Level Employees.
For example, one Executive Officer participated in the Voluntary Severance Incentive Plan and left the
Company. In addition, the changes to the Pension and Medical benefits apply to all employees including
the Executive Officer group.

Page 1 of 3
-20%
0%
20%
40%
60%
80%
100%
120%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Av
g
.

%

C
h
a
n
g
e

f
r
o
m

2
0
0
5

B
a
s
e
l
i
n
e
Utility Costs are Rising Faster than Sales
Net Plant Investment Non-Fuel O&M/A&G Retail kWh Sales Retail Therm Sales
Actual
Forecast
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 042 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 12:6-13:9. Please provide all studies and documentation related to actual savings achieved
by the cost management and efficiencies measures stated.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 042C. Please note that Avista’s response to ICNU – 042C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

In a direct response to the continuing increase in non-fuel O&M/A&G year over year, senior management
of the Company took steps to reduce the trend in increasing expenditures. Examples of cost management efficiencies and steps taken to reduce the growth in expenses, as discussed below, include resource-related
decisions, the Voluntary Severance Incentive Plan (VSIP) to reduce employee complement, and changes
to pension and post-retirement medical programs. These changes illustrate Avista’s efforts to control our
costs, improve efficiency, and focus on long-term sustainable savings to continuously improve our service
to customers and manage costs into the future.
The impact of these cost management efficiencies and steps taken to reduce the growth in expenses affect
the rate year and can be seen in the following chart, provided in Mr. Morris’ direct testimony at Exhibit
No. (SLM-1T) page 11, Illustration No. 7:

Page 2 of 3

This chart clearly shows the reduction in expenses in 2013, as represented by the green Non-Fuel
O&M/A&G line and continuing at a lower level through 2018. Furthermore, as explained in Andrews’
testimony at Exhibit No. __(EMA-1T) page 28, lines 6-9, although Avista’s O&M/A&G costs have
grown at an annual rate of approximately 5.7% per year for the past six years (2007-2013), we have used
a lower annual growth rate of 3% per year for our Attrition Study to reflect the recent cost-cutting measures implemented by the Company, and the expectation that Avista will manage the growth in these
expenses to a lower level in future years.

As noted at Exhibit No. __(SLM-1T), starting at page 12, line 1, the reduction in operating expenses in
2013 (green line) related primarily to Avista’s Voluntary Severance Incentive Plan (VSIP) executed in the fourth quarter of 2012, reducing employee complement at the Company. In addition, in 2013, senior
management made changes to Avista’s pension and post-retirement medical plans, effective January 1,
2014, which has reduced future O&M/A&G costs.

See Avista’s response to ICNU_DR_019C which showed the annual savings of the 55 eliminated positions totaled over $5 million. In addition, 2015 and 2016 savings related to the Company’s changes in
its pension and post retirement medical plans on a system basis are estimated to be approximately $2.6
million and $3 million, respectively, with increasing annual savings expected going forward (see
Attachment ICNU_DR_042C-Confidential Attachment A. As noted above, these savings are reflected in
the Company’s filing for 2016 through a reduced attrition escalation factor of all O&M and A&G expenses of 3%. These savings are also reflected in the Company’s Pro Forma Cross Check Studies, as
the reduced level of labor is already reflected in the Company’s twelve-months ended September 2014
results of operations for Washington, and the 2016 level of pension and post retirement medical expenses
have been reflected in the Pro Forma Employee Benefit adjustments (see Exhibit Nos._(JSS-2) and _(JSS-
3).)
Other examples of cost management which have a future impact, relate to the biomass energy bill
(SB5575) signed by Washington Governor Christine Gregoire on March 7, 2012 and the decisions made
related to the Company’s Palouse Wind Project. The biomass energy bill (SB5575) qualified legacy
biomass energy (built before 1999) as an eligible renewable resource for purposes of meeting the renewable portfolio standard (RPS) requirements of the Washington State Energy Independence Act (I-
937). As a result of the bill’s passage, the energy generated at Avista’s Kettle Falls biomass plant
qualifies to meet our RPS requirements, beginning in 2016. The passage of the bill, which involved a
multi-year legislative effort led by Avista, will save our customers millions of dollars over the long-term,
because Avista can now use this existing renewable power to meet our State mandates, which reduces the need to buy renewable energy credits or invest in the development of new resources.

In December 2012, with the addition of the Palouse Wind Project to Avista’s electric generation portfolio,
Avista began receiving power from this relatively low-cost purchased power agreement (PPA). As
background leading to acquiring the output to this Project, Avista had purchased the Reardan wind site in 2008 for the purpose of installing renewable wind generation to comply with the requirements of I-937.
In 2009, the Reardan project was compared against 29 competing proposals for renewable energy offered
by third-parties to Avista through a Request for Proposals (RFP). Analysis of all of the proposals showed
that the Reardan Project was the Company’s least-cost option for securing a new renewable resource for
its customers. However, even though it was the least-cost option, the levelized cost to customers from Reardan would still be over 10 cents per kWh. After further consideration, the Company chose, in 2010,
to delay development of Reardan due, in large part, to the fact that the Company did not have an

Page 3 of 3
immediate need for energy resources or renewable resources, immediate development of the Project
would increase retail rates for customers, and the fact that Reardan represented a low-cost option to hold
for later development. Avista continued to watch the market for wind resources, and in late 2010/early 2011, indications were that prices for wind turbines and other equipment had declined. Avista issued
another RFP in February 2011, and executed the PPA with First Wind for the Palouse Wind Project in
June 2011. Although the pricing for this PPA is confidential, Avista had requested renewable resource
proposals with a levelized cost equal to or less than 6.2 cents/kWh, and the pricing was well below the
prior estimates of Reardan. By choosing to delay the Reardan Project, Avista was able to later take advantage of much lower cost wind generation, which resulted in substantial benefits for the Company’s
customers. Because the Palouse Wind Project is a PPA, Avista receives no earnings associated with
acquiring the output from that Project. Therefore, Avista not only provided substantial cost savings to
customers, but also passed up the opportunity to invest in the Reardan Wind Project and earn a return for
shareholders on what would have been a substantial investment. These are two recent significant examples highlighting the extent of the efforts that Avista has made to
mitigate the long-term costs to its customers.

Additional measures worthy of note, are the continuing measures related to hiring restriction and the
efforts of “Customer Touch Point Teams,” discussed below.
Hiring Restrictions: The Company continues to operate under a hiring restriction which requires
approval by the Chairman/President/CEO, President of the Utility, the CFO, and the Sr. VP for Human
Resources for all replacement or new hire positions.
Customer Touch Point Teams: In the fall of 2011, a team from across the Company identified every
contact point or “touch point” a customer has with Avista. The objective of the initiative is to improve our
customers’ overall experience when doing business with us, as well as improve responsiveness in a
respectful and least cost manner. This team identified a “touch point map” of 172 different customer
interactions or touch points. To date, the touch point teams have made improvements to 57 distinct touch points. In 2014 Avista touch point team projects focused on Electric and Gas Emergency Operation Planning (involving customer touch points), Paperless Billing, Damage Assessment During Storms, and
Storm Estimated Restoration Time. In 2013, other examples included touch point team projects that
focused on customer awareness of natural gas safety, the distributed generation application process, and
accuracy of electric outage estimated restoration times.
Although not all examples noted above are specifically quantified and provided here, as explained above,
the Company has reflected the reduction to its O&M and A&G costs in its requested revenue requirement
through its use of a lower “Adopted Operating Expenses” factor used within its electric and natural gas
Attrition Studies. (See page 9 of Exhibit Nos. _(EMA-2) and _(EMA-3).)

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 043 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 14:5-6, where Ms. Andrews states that the electric attrition study is partly based on power supply cost “methodologies used and approved for ratemaking in Washington for many years.” Were any
of these methodologies approved in Avista rate cases before the WUTC? If yes, please indicate all
applicable order numbers.
RESPONSE:
Yes. The use of the power supply methodologies employed in this case, as explained by Mr. Kalich and
Mr. Johnson, have been approved by the Washington Commission in prior cases. The most recent
example where the methodologies were employed is in Docket No. UE-140188, Order 05 dated
November 25, 2014.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 044 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 15:17-18. Please explain why the revenue increase from Avista’s last general rate case
settlement is labeled “The Attrition Adjustment for 2015,” given the Commission’s lack of determination on attrition and the settling parties’ disagreement on attrition (Dockets UE-140188 and UG-140189,
Order 05 at ¶ 49).

RESPONSE:
Illustration No. 4 is meant to be illustrative in nature of how Attrition Adjustments over time provide
additional revenues to cover growth in costs that are increasing at a faster pace than revenues, as
experienced by Avista. The 2015 revenue increase was labeled “Attrition Adjustment” to reflect Avista’s assertion that attrition will be a factor in 2015-covered by the approved rate increase effective January 1,
2015. The 2016 revenues column was also labeled “Attrition Adjustment”, as again Avista asserts
attrition will be a factor during the 2016 rate year (causing a need for rate relief), as evident from the
Company’s filing.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 045 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to page 30, Illustration No. 6 & n.14. Please provide non-combined versions of this
illustration, one for electric and one for gas. RESPONSE:

As noted in Footnote 14 on page 30 of Exhibit No. _(EMA-1T), the data included in Illustration No. 6 includes combined electric and natural gas Commission Basis Net Plant After DFIT balances for the
period 2007 through 2016 on an AMA basis. Non-combined versions of this illustration are provided on
page 10 of each of Exhibit Nos. (EMA-2) and (EMA-3).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 046 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 4:17-20. Is Avista aware of any cases in which the Commission has approved similar changes in pro forma power supply development?
RESPONSE:

Yes. The Commission has approved mechanisms for PSE to recover actual major maintenance expenses at both its gas-fired plants and Colstrip.

In Docket No. UE-130617 the Commission approved the settlement agreement allowing PSE to recover
major maintenance expenses using the deferral method provided for in General Accepted Accounting
Principles (GAAP). The deferral method applies to the April-May 2013 hot gas path inspection of Mint Farm and, on a going forward basis, for all future major maintenance events on PSE’s gas-fired electric
generation facilities.

In Docket No. UE-141141 the Commission approved the settlement agreement allowing PSE to amortize
and track major maintenance at Colstrip. Major maintenance for Colstrip will be amortized over the projected time period to the next major event, which is three years, and included in rates based on
budgeted expenditures and the estimated timing of the event. The actual amortization runs through the
[PCA] mechanism as a variable item when incurred, thereby truing up for the difference between budget
and actual.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 047 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 6:1-3. Please provide any updates regarding the expected Rocky Reach/Rock Island contract, including any modifications to the Company’s pro forma power supply adjustments.
RESPONSE:

The bids for a 2016 through 2020 5% share of Rocky Reach/Rock Island are due on March 17, 2015. The
winning bidder will be notified on that day.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 048 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 9:9-10:12. Please provide all studies related to Mr. Johnson’s testimony, including any: a) comparison of customer benefits with or without an ERM trigger; and b) analysis of the cumulative
customer impact of adjustments with or without an ERM trigger.
RESPONSE:

The Company has not conducted any analysis of the ERM with or without a deferral balance trigger. The
ERM deferral balance has never reached the trigger amount. In recent rate proceedings the deferral
balance has been rebated to customers to partially mitigate general rate increases or, as in the last general
rate case, to offset the power supply update increase.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 049 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Table Nos. 2 & 3. Please provide similar tables based on actual load decrease and market power price for each month between January – October 2014, as well as January 2015, including all
supporting workpapers used to derive the data in the tables.
RESPONSE:

ICNU_DR049_Attachment A includes tables based on actual load decrease and market power price for
each month between January 2014 through January 2015. ICNU_DR_Attachments B through E include
all supporting workpapers used to derive the data in the tables, and are provided electronically.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 050 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 14:8-15:7. Is the Company proposing to include only planned maintenance costs in the ERM? If not, please provide a narrative response explaining the Company’s policy and/or position on
when it is appropriate to include unplanned or forced outage maintenance costs in the ERM.
RESPONSE:

The Company is proposing to include all operations and maintenance costs at Coyote Springs 2 and
Colstrip in the ERM. The Company’s position is that it is appropriate to include all operations and
maintenance costs whether they are planned or unplanned maintenance costs in the ERM. The Company
is also proposing that the difference between actual and estimated operations and maintenance costs be
subject to the same dead band and sharing bands as other power supply expenses.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Johnson/Andrews
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 051 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 16:10-11. Please explain why the Company uses only historic numbers in proposing an authorized level of retail sales for the ERM while applying a revenue growth factor to calculate proposed
revenue increases (e.g., the direct testimony of Ms. Andrews, page 18).

RESPONSE: The system costs included in the pro forma power supply values shown as Exhibit No.___(WGJ-2) and
related proposed ERM Authorized Base shown as Exhibit No.___(WGJ-5) are based on normalized test year
system loads, October 2013 through September 2014. Therefore, the normalized Washington retail sales
from the same period must be used to maintain consistency in the mechanism. The purpose of utilizing the “revenue growth factor” to reduce the 2016 attrition study level of revenue
requirement is to allow the proposed rates to be designed using historical test year billing determinants
(including retail sales) as opposed to forecasted billing determinants.
Revenue requirement, rate design, ERM authorized costs, and ERM authorized retail sales are all based on
the normalized historical test year numbers.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: Clint Kalich
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 052 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 9:29-31. In the prior cases referenced by Mr. Kalich, has the Company ever excluded forced outage data from modeling assumptions, due to anomalous outage circumstances?

RESPONSE:
We have not conducted research to determine whether the Company has “ever” excluded forced outage
data. In the last five general rate cases, the Company has not excluded forced outage data in the
development of its filings. The Company believes that a long-term average of forced outage data best represents the long-term average of operations.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: Clint Kalich
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 053 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 9:29-31. Please provide a narrative response explaining the Company’s policy and/or position on when it is appropriate to exclude forced outage data from dispatch modeling.
RESPONSE:

As explained in the testimony, the Company uses the 5-year average of forced outages. This averaging smoothes out year-to-year variability in outage data. Avista believes it is generally not appropriate to
exclude forced outage data from the historical record.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: Clint Kalich
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 054 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 9:31-10:1. From 2010-2014, please provide the outage rates used for each year, resulting in the 11.48% average forced outage rate for the Colstrip plant.
RESPONSE:

The values may be found in the filed workpaper of Clint Kalich entitled ‘Colstrip 34ngadProtect.xls.” In this Excel file, please refer to sheet “U1234NERCGADS,” cells AL85:AL89. The 5-year average
calculation may be found in cell AM89.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: Clint Kalich
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 055 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 10:3-5. Did the Company use the same AURORA modeling assumptions in both the current and last general rate case concerning: a) dispatch margin; b) phantom congestions; and c)
negative hydro variable O&M inputs?

RESPONSE:
No. These three “tools” are used to true-up Aurora’s market price forecast to the 60-day forward market
price average for the proforma period. Therefore, while the overall concepts between cases are the same,
the values are modified and are necessarily different in each case. The specific data are documented in
the working papers (Aurora files) of Clint Kalich. Once these Western Interconnect-wide adjustments are
made, allowing the wholesale marketplace to match forwards, Avista’s portfolio of resources are operated to maximize their value to customers. The following adjustments were made in comparison to the prior
filings.

a) Dispatch margin: Avista used the same method as for previous filings.
b) Phantom congestion: Given the forward market prices at the time of the filing, no adjustments to congestion were necessary to align Aurora prices to forward prices.
c) Negative hydro variable O&M: To model negative pricing in the case, Avista uses a new feature
of Aurora that reflects the impact of market oversupply. The new Aurora feature works the same
as our previous methodology, but it is not tracked as a variable operating cost. Instead the new
Aurora feature makes an economic adjustment to the dispatch price of affected resources to reflect negative market prices. See “Var Cost Mod1” and “Var Cost Mod2” field types in Aurora.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Brian Cox
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 056 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST: Please refer to 16:11-12. Have the Company’s continual investment needs become more
costly than during the prior 125 years of operation? If yes, please provide all studies demonstrating that
the cost differential of maintaining reliable customer service and meeting reliability standards is different today than throughout the Company’s history.
RESPONSE:

The subject testimony does not reference changes in cost of plant over the Company’s history of service,
however, it is the case that plant costs have continued to increase over this period. For an illustration and
supporting documentation, please see Avista’s response to ICNU_DR_039.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/05/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Brian Cox
REQUESTER: ICNU RESPONDER: Karen Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 057 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 18:14-16. Please provide any studies which would support the position that equipment
replacement does not reduce failure rates and after-hours labor costs.
RESPONSE: The question included in Company witness Mr. Cox’s Testimony at 18 reads as follows, with lines 14-16
in italics:

“Q. Did the Company consider any efficiency gains or offsets when evaluating the transmission projects to include in the Company’s case? A. Yes. The Company evaluated each project and determined that some of the 2014, 2015
and 2016 capital transmission projects will result in efficiency gains and potential offsets or savings, and
the Company has included those where applicable. The primary offsets result in loss savings from
reconductoring heavily-loaded transmission or distribution facilities. For these projects, an analysis was performed to determine the savings. The assumed avoided energy cost to determine the savings was $44
MWh, which is the 20 year life cycle cost calculated in Avista’s 2013 Integrated Resource Plan (see page
iii). However, not all projects will result in loss savings or other offsets. Avista has maintenance
schedules for certain equipment. These maintenance cycles range from 5-15 years depending on the
equipment. Unless the replacement of equipment occurs in the same year as the scheduled maintenance, there will not be any savings.
Although one might think that the replacement of equipment may reduce the failure rate of
equipment and reduce after-hours labor costs, newly-installed equipment can get out of alignment, or
require other adjustments. Significant system failures also occur during large weather-related events
caused by wind, lightning, and snow. Furthermore, each year as we replace old equipment with new, the remainder of our system gets another year older, which continues to generate additional failures on our
system.”

The Company is not representing that replacement of equipment does not reduce failure rate and
after-hours labor costs. There are, however, situations where additional costs can occur after the equipment has been installed; therefore, replacement of equipment does not necessarily always reduce
O&M costs. In addition, as noted above, each year as we replace old equipment with new, the remainder
of our system gets another year older, which continues to generate additional failures on our system.

ICNU_DR_058 Attachment A Page 1 of 28
ICNU_DR_058 Attachment A Page 2 of 28
ICNU_DR_058 Attachment A Page 3 of 28
ICNU_DR_058 Attachment A Page 4 of 28
ICNU_DR_058 Attachment A Page 5 of 28
ICNU_DR_058 Attachment A Page 6 of 28
ICNU_DR_058 Attachment A Page 7 of 28
ICNU_DR_058 Attachment A Page 8 of 28
ICNU_DR_058 Attachment A Page 9 of 28
ICNU_DR_058 Attachment A Page 10 of 28
ICNU_DR_058 Attachment A Page 11 of 28
ICNU_DR_058 Attachment A Page 12 of 28
ICNU_DR_058 Attachment A Page 13 of 28
ICNU_DR_058 Attachment A Page 14 of 28
ICNU_DR_058 Attachment A Page 15 of 28
ICNU_DR_058 Attachment A Page 16 of 28
ICNU_DR_058 Attachment A Page 17 of 28
ICNU_DR_058 Attachment A Page 18 of 28
ICNU_DR_058 Attachment A Page 19 of 28
ICNU_DR_058 Attachment A Page 20 of 28
ICNU_DR_058 Attachment A Page 21 of 28
ICNU_DR_058 Attachment A Page 22 of 28
ICNU_DR_058 Attachment A Page 23 of 28
ICNU_DR_058 Attachment A Page 24 of 28
ICNU_DR_058 Attachment A Page 25 of 28
ICNU_DR_058 Attachment A Page 26 of 28
ICNU_DR_058 Attachment A Page 27 of 28
ICNU_DR_058 Attachment A Page 28 of 28

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Jim Kensok
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 058 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 20:9-10. Concerning the June 2014 report attached as Exhibit No.___(JMK-2), please
explain: a) to whom this report was originally directed; b) whether this report has been modified in any way since its original drafting (explaining all changes and supplying the original version, if applicable); c)
whether such reports are typically presented in this Q&A format; and d) whether the Company drafted
similar timeline and budget forecasting reports for other capital projects (providing any such reports, if
applicable).

RESPONSE: a) This report was developed for internal and external audience in anticipation of questions that
might arise in connection with the referenced revisions to the Compass project timeline and
budget.
b) The report has not been modified since its original drafting.

c) The referenced report was developed in the Q&A format because the Company felt it was the most
effective way to address the likely flow of questions readers may have regarding this complex project. We do not know the prevalence of this reporting format across the Company over the
years, but expect that it’s not commonly used.

d) There have been cases where Avista has developed update reports for other large capital projects.
An example of one such report is provided as ICNU_DR_058, Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Jim Kensok
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 059 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST: Please refer to 21:7-9. Please provide all studies associated with: a) “the Company’s efforts
to research and understand the root causes of the failed projects of other utilities”; and b) Avista’s
“systematic application of those learnings to the design of the project.”

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 059C. Please note that
Avista’s response to ICNU – 059C is Confidential per Protective Order in UTC Dockets 150204 and UG-150205
Please find the attached report “Overview of Avista’s Project Compass,” provided as ICNU_DR_059,
Attachment A. The sections of the report pertinent to this request begin on page 22 under the heading
“Identifying Common Challenges,” and continue on pages 24 – 26, under the heading “Designing the Project Around Best Practices.” Due to the voluminous nature of these documents, they are provided in
electronic format only.
Attachment File Name
Overview of Avista’s Project Compass ICNU_DR_059 Attachment A
Report Attachment 1 ICNU_DR_059 Attachment B
Report Attachment 2 ICNU_DR_059 Attachment C Report Attachment 3 ICNU_DR_059 Attachment D Report Attachment 4 ICNU_DR_059 Attachment E
Report Attachment 5 ICNU_DR_059 Attachment F
Report Attachment 6 ICNU_DR_059 Attachment G
Report Attachment 7 ICNU_DR_059 Attachment H Report Attachment 8 ICNU_DR_059C Confidential Attachment I Report Attachment 9 ICNU_DR_059 Attachment J
Report Attachment 10 ICNU_DR_059 Attachment K
Report Attachment 11 ICNU_DR_059 Attachment L
Report Attachment 12 ICNU_DR_059C Confidential Attachment M Report Attachment 13 ICNU_DR_059C Confidential Attachment N Report Attachment 14 ICNU_DR_059C Confidential Attachment O
Report Attachment 15 ICNU_DR_059C Confidential Attachment P
Report Attachment 16 ICNU_DR_059C Confidential Attachment Q
Report Attachment 17 ICNU_DR_059C Confidential Attachment R Report Attachment 18 ICNU_DR_059C Confidential Attachment S

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Dr. Grant Forsyth
REQUESTER: ICNU RESPONDER: Dr. Grant Forsyth
TYPE: Data Request DEPT: Fin. Planning & Analysis
REQUEST NO.: ICNU – 060 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 3:2-4:7. Has the Company conducted any studies considering tautological elements in its
trend analysis methodology? If yes, please provide all such studies. If no, please provide a narrative response explaining the Company’s policy and/or position on tautological elements within the Company’s
trend analysis methodology.
RESPONSE:
No, the Company has not conducted any studies considering tautological elements in its trend analysis
methodology. The company’s position is that (1) capital-related expenditures are not expected to increase in a linear fashion, and (2) because expenditures are not expected to increase in a linear fashion, a non-linear
adjustment is needed. Please refer to Dr. Forsyth’s testimony 8:7-11:5

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Dr. G. Forsyth/E. Andrews
REQUESTER: ICNU RESPONDER: Dr. Grant Forsyth
TYPE: Data Request DEPT: Fin. Planning & Analysis
REQUEST NO.: ICNU – 061 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 3:4-19. Does the Company’s trend analysis reflect the Company’s recent and planned
expenditures? If yes, please explain why “Ms. Andrews has made an adjustment to the capital investment-related growth rates to better reflect the 2016 rate year.” If no, please explain the value of the
trend analysis, given Dr. Forsyth’s testimony that “using time periods that no longer represent recent and
planned expenditures can lead to inaccurate representations of future growth.”

RESPONSE: The Company expects a surge in growth rates beyond what would be calculated using the compound
growth formula for the 2007-2013 period. Dr. Forsyth’s testimony establishes the importance of
recognizing that a linear method is not appropriate under current circumstances. Please refer to Dr.
Forsyth’s testimony 8:7-11:5. Ms. Andrews’ testimony establishes that even with non-linear
compounding, historical growth rates are insufficient for capturing the impact of surging capital-related expenditures after 2013. Please refer to Ms. Andrews’ testimony 28:12-32:5.

Page 1 of 2
-
100,000,000
200,000,000
300,000,000
400,000,000
500,000,000
600,000,000
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Spend Transfers to Plant
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Dr. G. Forsyth/E. Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: Fin. Planning & Analysis
REQUEST NO.: ICNU – 062 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 3:13-15, 4:23-5:1, and 5:19-21. Does the year 2014 represent another “kink point” in the
previous historical trend? If no, please explain.
RESPONSE: The data sponsored by Company witness Ms. Andrews, starting on page 28 of her testimony, illustrate the
accelerated growth in transfers to plant in service for the 2014 to 2016 period.

As discussed by Mr. Thies and Ms. Schuh, the Company has increased its level of capital spending, and therefore increased its transfers to plant expected through 2016. These increases in capital spending and
transfers to plant impact the Company’s net rate base to be included during the rate year. Due to this
accelerated level of transfers to plant for 2014 to 2016, it is necessary to increase the annual growth rate
above the rate experienced from the 2007-2013 historical period. For that reason, the Company used the
2014 to 2016 growth percentages to apply to the historical base period. Otherwise, the use of the historical trend (2007-2013) would significantly understate net plant investment and depreciation expense
for 2016. This significant increase in transfers to plant in 2015 is shown in Illustration No. 1 below.

Illustration No. 1

The blue bars in the Illustration No. 1 above represent the actual capital spend from 2008-2014, and
expected spend from 2015-2017. The red bars represent actual transfers-to-plant from 2008-2014, and
expected transfers for 2015-2017.

Page 2 of 2
-
115,000
230,000
345,000
460,000
575,000
690,000
805,000
920,000
1,035,000
1,150,000
1,265,000
1,380,000
1,495,000
1,610,000
1,725,000
2007 2008 2009 2010 2011 2012 2013 9.2014*2016**
Washington Electric & Natural Gas
Net Plant After DFIT (AMA) 2007-2016
*2007 -September 2014 AMA per Attrition Study.
** 2016 per Pro Forma Cross Check Study.
Average increase 2007-September 2014 = $60M
The transfers to plant for 2015 are significantly higher than recent years, which results in a significant
increase in net plant expected in 2016 on an AMA basis, as shown in Illustration No. 2 below.
Illustration No. 2 shows the Washington electric and natural gas Net Plant After DFIT balances from 2007 to September 30, 2014, and expected for 2016, on an average-of-monthly-average (AMA) basis.
Illustrative No. 2

In Illustration No. 2 above, the black arrow reflects the historical growth in net plant (after DFIT) from 2007 to 2013, which reflects an average annual increase of $60 million during this time period.
The red arrow reflects the increase in net plant (after DFIT) from September 2014 to 2016 totaling
$219 million.
Two major projects in particular cause the significant increase in transfers to plant in 2015. The first
project, related to the Company’s Customer Information System (Project Compass) was completed in February 2015 and has been transferred to plant-in-service (approximately $95.1 million (system)).
The second project is the Nine Mile Redevelopment project, which is in progress, and barring unusual
circumstances, the Company will transfer approximately $51.3 million (system) to plant-in-service by
December 2015. There are also a number of other projects, such as the Aldyl A Pipe Replacement,
Little Falls Powerhouse Redevelopment, and Cabinet Gorge Refurbishment projects, to name a few, that are on schedule to transfer to plant-in-service during 2015. It is necessary for this higher level of
transfers to plant to be included in the attrition adjustment, in order to reflect the proper level of rate
base for 2016.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Dr. G. Forsyth/E. Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 063 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 3:4, 3:13-15, 5:1-4, and 5:19-21. Does the Company also agree that the expenditure trend
for the 2007-2013 period is not a valid reference period, because it is also no longer representative of the Company’s expenditure trend? If no, please explain. If yes, please explain the value of the Company’s
trending analysis, given that the entire period of 2001-2013 is no longer a valid reference point.
RESPONSE:
No. As compared to the 2001-2006 time period, the 2007-2013 period is more representative. However,
the best available information should be taken into consideration in the development of retail rates for the 2016 rate period, which in this case includes data for the full period of 2001-2016. The data for the entire
period is relevant, in that it illustrates the year by year changes in costs and is instructive in understanding
the appropriate level of costs and investment to include in the determination of retail rates for 2016. Also
see Avista’s response to ICNU Request No. 062. In addition, see Ms. Andrews’ testimony at 10:5 – 13:2.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Dr. Grant Forsyth
REQUESTER: ICNU RESPONDER: Dr. Grant Forsyth
TYPE: Data Request DEPT: Fin. Planning & Analysis
REQUEST NO.: ICNU – 064 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 4:4-6, and 4:19-5:15. Please reconfigure Figure 1 by directly applying the compound growth rate formula to the same historical expenditure series.

RESPONSE:
Figure 1 is only intended to be a general illustration of time-path of expenditures before and after 2007.
In other words, it is not a graph of a single, specific data series.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 065 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 5:1-3. Please explain how project sponsorship works, including: a) individuals or
positions within the Company eligible to sponsor projects; and b) whether project sponsors receive directives or commands to sponsor specific projects, sponsor projects independently, or both, including
information as to who has authority to supply sponsorship directives, if applicable.

RESPONSE:
a) Typically the sponsor is the executive officer or vice president of the functional area for which the capital funding is requested.
b) The need for a project is typically identified within each functional area of the Company. Typically
the project manager identifies the need and develops the Business Case that is then reviewed,
approved or declined by the Business Case owners. The Business Case sponsors (executive officer or
vice president) provide the oversight for each particular functional group providing the Business Case need.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 066 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 5:1-4. Please indicate or explain: a) the composition of the Financial Planning and
Analysis (“FP&A”) group, including the names, tenure and positions within the Company of all current members; and b) how often the FP&A group meets.
RESPONSE:
a) Financial Planning and Analysis (FP&A) is a department within the Finance area of the Company.
FP&A is responsible for the Capital and O&M budgets and financial forecasts for the Company, as well as project and economic analysis. FP&A is comprised of ten employees with Margie Stevens
and Jeremiah Webster involved in the facilitation of the capital planning process. Following are the
current FP&A employees:
• Margie Stevens, Director Financial Planning and Analysis, 13 years
• Jeremiah Webster, Financial Analyst, 4 years
• Rosemary Coulson, Sr. Financial Analyst, 10 years
• Dave DeFelice, Sr. Business Analyst, 29 years
• Frank Johnson, Financial Analyst, 4 years
• Grant Forsyth, Chief Economist, 3 years
• Neil Thorson, Temporary assignment Manager, Operations Analytics, 26 years
• Julie Lee, Operations Analyst, 26 years
• Stephen Carrozzo, Operations Analyst, 5 years
• Laura Vickers, Temporary assignment in Operations, 14 years b) As stated above, FP&A is a group or department within the Company which works together on a
daily basis.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 067 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 5:5-11. Please indicate or explain: a) the number and names of Directors presently
comprising the Capital Planning Group (“CPG”), including the tenure of each Director on the CPG; b) the selection process for appointing Directors to the CPG; c) any modifications to how the CPG conducts
business, including member composition, from 2006 to the present; d) the names of prior members on the
CPG, including term served; and e) the number and names of all individuals currently sitting on the Board
of Directors, including tenure.
RESPONSE: The CPG is currently a group of Directors that represent all capital intensive areas of the Company. The
CPG meets to review the submitted Business Cases and prioritize funding to meet the capital budget
targets set by senior management. After approval from senior management, the capital budget is sent to
the Board of Directors to approve the capital budget amount for the five year period. The CPG meets
monthly to review the status of the capital projects and programs, and approve or decline new business cases as well as monitor the overall capital budget.
a) The CPG is comprised of seven directors with the following individuals and tenures on the CPG :
• Mike Broemeling, Director of Customer and shared Services- 2 years
• Jim Corder, Director of IT Infrastructure - 3 years
• Bryan Cox, Director of Transmission and West Electric Operations - 1 year
• Mike Faulkenberry, Director of Natural Gas -2 years
• Bruce Howard, Director of Environmental Affairs - 3 years
• Heather Rosentrater, Director of Engineering System Operations - 2.5 years
• Andy Vickers, Director of Generation and Production Support - 2 years
b) New members are determined and appointed by the existing members of the CPG giving consideration to represented areas of the Company.
c) The CPG was commissioned January 1, 2012. The members of the original team were approved by
the Company’s officers. These members and their tenures on the CPG included:
• Kevin Christie, Vice President of Customer Solutions - ½ year;
• Tim Carlberg (Retired), Director of Generation and Production and Substation Support -1
year;
• Al Fisher (Retired), Director of Operations West - 2 years;
• Rick Vermeers (Retired), Director of Electrical Engineering - 1 year
• John Schwendener (Retired), Director of Gas Delivery - 1 year.
d) All members are internal department directors and do not sit on the Board of Directors.

Please also see Avista’s response to ICNU’s DR_069 which includes minutes of the CPG meeting including participants from 2012 to present.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 068 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 5:6-8, where Ms. Schuh states: “The CPG meets to review the submitted Business Cases
and prioritize funding to meet the capital budget targets set by senior management. After approval from senior management, the capital budget is sent to the Board of Directors ….” (Emphasis added). Please
explain: a) what is meant by the term “senior management,” including the individuals comprising “senior
management”; and b) whether both uses of the term refer to the exact same individuals, or explaining any
differences between each use of the term.

RESPONSE:
a) The term senior management is referring to the Company’s senior officers that establish the capital
investment target as follows: Scott Morris (Chairman, President & CEO), Mark Thies (Sr. VP and
CFO), and Dennis Vermillion (Sr. VP and President, Avista Utilities).
b) Both uses of the term refer to the same individuals.
From:Stevens, MargieTo:Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Coulson, Rosemary; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Gustafson, Mark; Howard, Bruce; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; McClain, John; Myers, Stephanie; Olson, Tim; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Stevens, Margie; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Scott; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Sweigart, KenSubject:Capital Planning Group 1/16/14 minutes - Please forward as neededDate:Tuesday, January 21, 2014 12:42:28 PMAttachments:image001.gifCPG report jan14 meeting - post meeting sent.xlsx
The Capital Planning Group (CPG) met on Wednesday, January 15th. Attendees included: Jim Corder, Al Fisher, Heather Rosentrater, Andy Vickers, Margie Stevens, Jeremiah Webster (FP&A support), and
Karen Schuh (Rates observer). Not present (approved requests via email): Mike Broemeling, Mike Faulkenberry and Bruce Howard.

1) Through December 2013 the capital budget is under spent $1.2M (compared to original budget plus Compass carryover and additional approved budget amounts) excluding variances from the
Growth items. No carryovers will be requested for 2014.

2) The CPG discussed the value of a 2013 Capital lessons learned and celebration session for business case owners. Margie and Jeremiah will work on getting it set-up, timing should be in February.

3) Ken Sweigart attended the meeting to discuss the Walla Walla-Wanapum minor rebuild project.

4) The following requests were approved for spend in 2014: With the addition of these items the expected spend is over target by $3.2M, however it is anticipated that other offsets will be found
throughout the year.

Area Business Case/Project Amount Requester Other Information
ET CSS Replacement 2 ,650,000 Pat Dever Carried over from 2013
Fleet Fleet Budget 114,904 Chris Schlothauer Dump truck for Spokane Network
Other Jackson Prairie Storage 39,000 M. Garbarino Revision from joint ownership group
T&D Transmission - Asset Management 1,550,000 Ken Sweigart WAL-WAN line
Gen KFGS Ash Collector 1,000,000 Dan Johnson Need to advance 2015 funding in order to complete project

Margie Stevens
Director, Financial Planning & Analysis

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19Spokane, WA 99202P 509.495.8978C 509.993.0913
http://www.avistautilities.com

This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an intended recipient, please notify the sender and delete this email from your system. Thank you.
ICNU_DR_069 Attachment A Page 1 of 58
From:Stevens, MargieTo:Stevens, Margie; Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Coulson, Rosemary; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Gustafson, Mark; Howard, Bruce; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; McClain, John; Myers, Stephanie; Olson, Tim; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Scott; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Sweigart, KenSubject:RE: Capital Planning Group 1/16/14 minutes - Please forward as neededDate:Tuesday, January 21, 2014 1:20:52 PMAttachments:CPG report jan14 meeting - post meeting sent.xlsximage001.gif

Attached is a revised file attachment. The original attachment had value errors.
Margie Stevens Phone: [phone] 
From: Stevens, Margie Sent: Tuesday, January 21, 2014 12:42 PMTo: Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Coulson, Rosemary; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Gustafson, Mark; Howard, Bruce; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; McClain, John; Myers, Stephanie; Olson, Tim; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Stevens, Margie; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Scott; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Sweigart, KenSubject: Capital Planning Group 1/16/14 minutes - Please forward as needed 
The Capital Planning Group (CPG) met on Wednesday, January 15th.  Attendees included:  Jim Corder,  Al Fisher, Heather Rosentrater, Andy Vickers, Margie Stevens,  Jeremiah Webster (FP&A support), and
 Karen Schuh (Rates observer).  Not present (approved requests via email):  Mike Broemeling, Mike Faulkenberry and Bruce Howard.   

1) Through December 2013 the capital budget is under spent $1.2M (compared to original budget plus Compass carryover and additional approved budget amounts) excluding variances from the
 Growth items.  No carryovers will be requested for 2014.  

2) The CPG discussed the value of a 2013 Capital lessons learned and celebration session for business case owners.  Margie and Jeremiah will work on getting it set-up, timing should be in February.

3) Ken Sweigart attended the meeting to discuss the Walla Walla-Wanapum minor rebuild project.    

4) The following requests were approved for spend in 2014:  With the addition of these items the expected spend is over target by $3.2M, however it is anticipated that other offsets will be found
 throughout the year.

Area Business Case/Project Amount Requester Other Information
ET CSS Replacement  2 ,650,000   Pat Dever   Carried over from 2013
Fleet Fleet Budget       114,904   Chris Schlothauer   Dump truck for Spokane Network
Other Jackson Prairie Storage         39,000   M. Garbarino   Revision from joint ownership group
T&D Transmission - Asset Management    1,550,000   Ken Sweigart   WAL-WAN line
Gen KFGS Ash Collector    1,000,000   Dan Johnson   Need to advance 2015 funding in order to complete project

Margie StevensDirector, Financial Planning & Analysis
PO Box 3727 MSC-19Spokane, WA 992201411 E Mission Ave. MSC-19Spokane, WA 99202
P 509.495.8978
C 509.993.0913http://www.avistautilities.com This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an intended recipient, please notify the sender and delete this email from your system. Thank you. 
ICNU_DR_069 Attachment A Page 2 of 58
From:Webster, Jeremiah
To:Abrahamse, Bill; Benjamin, Tia; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Condosta, Kristie; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Graham, Jason; Howell, David; James, Dave; Jensen, Mary; Johnson, Dan; Kenyon, Alison; Kinney, Scott J; Krogh, Cody; Lee, Cody; Lee, Julie; Leija, Andy; Mackey, Carole; Madden, Glenn; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Newhouse, Kristina; Pike, Andrea; Plut, David; Quincy, Diane; Raymond, Robb; Reding, Matt; Reidt, Jacob; Roys, Walter; Ruppert, Vance; Schlothauer, Chris; Smith, Graham; Storey, Clay; Sweigart, Ken; Thorson, Neil; Vickers, Laura; Waples, Scott; Webb, Jeff; Wenke, Steve; Whitby, Michael
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Howard, Bruce; Machado, David; Rosentrater,
Heather; Schuh, Karen; Stevens, Margie; Vickers, Andy
Subject:Capital Planning Group Meeting Minutes 1/21/15 - please forward as needed
Date:Tuesday, January 27, 2015 3:34:45 PM
Attachments:CPG report jan15 meeting_post meeting sent.xlsx
The Capital Planning Group (CPG) held a meeting on Wednesday, January 21. Attendees
included: Jim Corder, Bryan Cox, Bruce Howard, Heather Rosentrater, Margie Stevens, Andy
Vickers, Jeremiah Webster (FP&A support), Karen Schuh (Rates observer), Dave Machado
(Rates observer), Kim Boynton (Internal Audit), and Joel Anderson (Internal Audit). Not
present: Mike Broemeling, Mike Faulkenberry.
1)December 2014 year-to-date capital spending finished over budget (excluding Project
Compass) $5.2M and $5.9M under budget excluding the growth overspend. (For
comparison purposes, December 2013 YTD was over budget $11.3M and under budget
$1.2M excluding the growth overspend).
2)The CPG reviewed all new and pending 2015 requests for funding, and approved the
following requests:
Business Case/Project Amount
Gas Ladd Canyon Gate Station 615,000
AvistaUtilities.com Redesign 1,893,000
Noxon Spare Coils 660,000
Transmission Outage Management 190,000
Post Falls South Channel Replacement 2,930,000
Segment Reconductor and FDR Tie Program 100,000
COF Long-Term Restructuring Plan 500,000
Aldyl A Replacement 150,000
Total $7,038,000
ICNU_DR_069 Attachment A Page 3 of 58
3) With the release of $2.6M, including the above approved requests the 2015 expected
spend is over target by $4.4M.
4) Mark Thies has approved the productivity request for Embotics Software that was
discussed in December’s meeting.
5) The CPG discussed and would like to sponsor a year-end capital celebration with
project/program sponsors in recognition of all the hard work and accomplishments during
2014. The date of the celebration is February 26th.
6) The CPG would like to work toward a better understanding of “What does success look
like” for the capital budget. Margie has discussed this with Mark Thies and he will join the
February meeting.
7) Business case training will be offered soon. Please contact Jeremiah Webster if you
would like to participate. Notices and meeting invites forthcoming.
8) During 2015, a business case ‘post-mortem’ process will be developed. Please contact
Jeremiah Webster if you would like to participate in the development process.

Jeremiah Webster
Financial Planning Analyst

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission MSC-19
P 509.495.2764
http://www.avistautilities.com
ICNU_DR_069 Attachment A Page 4 of 58
From:Stevens, Margie
To:Stevens, Margie; Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Coulson, Rosemary; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Gustafson, Mark; Howard, Bruce; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; McClain, John; Myers, Stephanie; Olson, Tim; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Scott; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Sweigart, Ken
Cc:Jones, Linda; Pendergraft, Lauren
Subject:Capital Planning Group 2/24/14 minutes - Please forward as needed
Date:Wednesday, February 26, 2014 9:49:54 AM
Attachments:image001.gifCPG report feb24 meeting - post meeting sent.xlsx
The Capital Planning Group (CPG) met on Monday, February 24th. Attendees included: Mike
Broemeling, Jim Corder, Mike Faulkenberry, Al Fisher, Bruce Howard, Heather Rosentrater, Andy
Vickers, Margie Stevens, Jeremiah Webster (FP&A support), Karen Schuh (Rates observer), and
Lauren Pendergraft (ALP).

1) Linda Jones attended the meeting to discuss a productivity request for LMS Analytics
(Stephanie Myers and Dave DeFelice were also in attendance to provide additional
information). The CPG requested that Linda follow-up with a revised CIRR calculation that
considers only the efficiency gains from having the analytics tool. Upon receipt of this
information, the CPG will determine whether to forward a recommendation to Mark Thies
for approval.

2) The CPG reviewed a request for additional funding for the Lancaster productivity initiative.
After some discussion, the group agreed to forward an approved recommendation to
Mark.

3) January 2014 capital spending is under budget $7.3M and $8.0M under budget excluding
the growth overspend.

4) The following request was approved for spend in 2014:
Area Business Case/Project Amount Requester
T&D Meter Minor Blanket 50,000 Josh DiLuciano

With the addition of this item the expected spend is over target by $3.3M, however it is
anticipated that other offsets will be found throughout the year. All other new requests
are still pending and are not yet approved. There is also potential to have additional
requests for funding due to the finalization of contractual agreements.

5) The celebration for 2013 Capital Business Case owners is scheduled for Tuesday, February
25th at 2:00pm. - Thanks to all who were able to attend!

Margie Stevens
Director, Financial Planning & Analysis

ICNU_DR_069 Attachment A Page 5 of 58

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19
Spokane, WA 99202
P 509.495.8978
C 509.993.0913
http://www.avistautilities.com

This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are
not an intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_069 Attachment A Page 6 of 58
From:Webster, Jeremiah
To:Abrahamse, Bill; Benjamin, Tia; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Condosta, Kristie; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Graham, Jason; Hamill, John; Howell, David; James, Dave; Jensen, Mary; Johnson, Dan; Kenyon, Alison; Kinney, Scott J; Krogh, Cody; Lee, Cody; Lee, Julie; Leija, Andy; Mackey, Carole; Madden, Glenn; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Newhouse, Kristina; Pike, Andrea; Plut, David; Quincy, Diane; Raymond, Robb; Reding, Matt; Reidt, Jacob; Roys, Walter; Ruppert, Vance; Schlothauer, Chris; Schwall, David; Smith, Graham; Storey, Clay; Sweigart, Ken; Thorson, Neil; Vandenburg, Brian; Vickers, Laura; Waples, Scott; Webb, Jeff; Wenke, Steve; Whitby, Michael
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Howard, Bruce; Machado, David; Rosentrater,
Heather; Schuh, Karen; Stevens, Margie; Vickers, Andy
Subject:Capital Planning Group Meeting Minutes 2/18/15 - please forward as needed
Date:Tuesday, February 24, 2015 1:00:25 PM
Attachments:CPG report feb15 meeting_post meeting sent.xlsx
The Capital Planning Group (CPG) held a meeting on Wednesday, February 18. Attendees
included: Mike Broemeling, Jim Corder, Bryan Cox, Mike Faulkenberry, Bruce Howard,
Heather Rosentrater, Margie Stevens, Andy Vickers, Jeremiah Webster (FP&A support),
Karen Schuh (Rates observer), Dave Machado (Rates observer), Seth Samsell (Gas
Engineering), Mike Magruder (Substation Engineering), Kim Boynton (Internal Audit), Joel
Anderson (Internal Audit) and Mark Thies (attended first half hour).
1)January 2015 year-to-date capital spending was under budget $16.0M and $16.4M
under budget excluding the growth overspend. (For comparison purposes, January 2014
YTD was under budget $7.3M and under budget $8.0M excluding the growth overspend).
2)The CPG reviewed all new and pending 2015 requests for funding, and approved the
following requests:
3)With the release of $0.5M, including the above approved requests the 2015 expected
Business Case/Project Amount
Segment Reconductor and FDR Tie 325,000
Elec Replacement/Relocation 625,000
Coyote Springs LTSA 60,000
Next Generation Radio Refresh 3,060,000
Kettle Falls Water Supply 295,000
Total $4,365,000
ICNU_DR_069 Attachment A Page 7 of 58
spend is over target by $8.2M.
4) Mark Thies discussed “What does success look like” for the capital budget.
5) Mike Magruder presented a real estate purchase opportunity near the Irvin substation.
It was determined that it was not a good fit for the capital portfolio at this time.
Reminders:
1) The CPG is sponsoring a year-end capital celebration on February 26th at 2 PM for
project/program sponsors in recognition of 2014 accomplishments.
2) Business case training will be offered soon. Please contact Jeremiah Webster if you
would like to participate. Notices and meeting invites forthcoming.
3) During 2015, a business case ‘post-mortem’ process will be developed. Please contact
Jeremiah Webster if you would like to participate in the development process. This will kick
off after the business case celebration.

Jeremiah Webster
Financial Planning Analyst

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission MSC-19
P 509.495.2764
http://www.avistautilities.com
ICNU_DR_069 Attachment A Page 8 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Condosta, Kristie; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Howell, David; James, Dave; Johnson, Dan; Kelley, Bill; Kensok, Jim; Kenyon, Alison; Kinney, Scott J; Kopczynski,
Don; Krogh, Cody; Lee, Julie; Leija, Andy; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Quincy, Diane; Reidt, Jacob; Ruppert, Vance; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Sweigart, Ken; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Whitby, Michael
Cc:Broemeling, Mike; Corder, Jim; Faulkenberry, Mike; Fisher, Al; Howard, Bruce; Rosentrater, Heather; Stevens, Margie; Vickers, Andy
Subject:Capital Planning Group 3/19/14 minutes - Please forward as needed
Date:Thursday, March 20, 2014 5:09:41 PM
Attachments:image003.jpgCPG report mar14 meeting_post meeting sent.xlsximage002.png
The Capital Planning Group (CPG) met on Wednesday, March 19th. Attendees included: Mike Broemeling,
Jim Corder, Mike Faulkenberry, Al Fisher, Bruce Howard, Heather Rosentrater, Andy Vickers, Margie
Stevens, Jeremiah Webster (FP&A support), Karen Schuh (Rates observer).
1) Randy Gnaedinger discussed and answered questions regarding a request for $173k for a gas
SCADA enhancement project required as part of the gas control room management rules.
2) Dave Schwall gave an update to the group on the progress and funding requirements of the Nine
Mile project.
3) Curt Kirkeby discussed a request for funds related to a battery storage project that is expected to
receive matching grant funds from the state of Washington.
4) February 2014 capital spending is under budget $8.1M and $9.5M under budget excluding the
growth overspend. (For comparison purposes, February 2013 YTD was under budget $5.0M and
$5.2M excluding the growth overspend).
5) The following requests were approved for spend in 2014:
With the addition of these items the expected spend is over target by $6.3M, however it is
anticipated that other offsets will be found throughout the year. All other new requests are still
pending and are not yet approved (please see attached file for details).
6) There are still $14.7M of pending capital requests as well as other potential requests that have
not yet been submitted. While these requests have not yet been approved, it is expected that
some will require funding in 2014. As such, the CPG is requesting that all areas of the company
review their capital plans and determine which projects/programs may not get completed or
ICNU_DR_069 Attachment A Page 9 of 58
can be deferred to 2015. If none are identified, the CPG may request that some
projects/programs be terminated, reduced or deferred. The CPG has requested a special
meeting in April to discuss a re-prioritization of 2014 capital projects.

Margie Stevens
Director, Financial Planning & Analysis

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19
Spokane, WA 99202
P 509.495.8978
C 509.993.0913
http://www.avistautilities.com

This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an
intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_069 Attachment A Page 10 of 58
Area Business Case/Project Amount
Gen Little Falls Plant Upgrade 800,000
ET Technology Refresh to Sustain Business Process (Citrix portion) 1,500,000
Gen Nine Mile Rehab 6,000,000
Fac HVAC Renovation Project 220,000
8,520,000
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Condosta, Kristie; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Howell, David; James, Dave; Johnson, Dan; Kensok, Jim; Kenyon, Alison; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Leija, Andy; Magruder, Mike; Marlowe, Andrea; Mecham, Mike; Myers, Stephanie; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Ruppert, Vance; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Sweigart, Ken; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Whitby, Michael
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Fisher, Al; Howard, Bruce; Rosentrater, Heather;
Stevens, Margie; Vickers, Andy
Subject:Capital Planning Group meeting 4/25/14 minutes -- Please forward as needed
Date:Wednesday, April 23, 2014 4:31:09 PM
Attachments:image001.jpgCPG report apr14 meeting_post meeting sent.xlsx
The Capital Planning Group (CPG) held a special meeting on Tuesday, April 15 and met again on
Monday, April 21. Attendees included: Mike Broemeling (April 15 only), Jim Corder, Bryan Cox
(April 21 only), Mike Faulkenberry (April 15 only), Al Fisher, Bruce Howard, Heather Rosentrater,
Andy Vickers, Margie Stevens, Jeremiah Webster (FP&A support), Karen Schuh (Rates observer),
Linda Jones (April 21 only), Stephanie Myer (April 21 only), and Dave DeFelice (April 21 only).

1) The special meeting on April 15 was held to discuss the large number of requests that have
been made for capital spend and to begin to reprioritize the 2014 budget in order to
achieve the $331M target.

2) Bryan Cox was elected to join the committee as a replacement for Al Fisher.

3) Linda Jones gave an update to the group on the productivity request for implementing a
new Learning Management system with an analytics engine. Dave discussed the various
analyses that were done as requested by the CPG during an earlier meeting. After
discussion, the CPG recommended to forward the request to Mark Thies for final approval.

4) The CPG discussed a productivity request for purchasing 20 Phase Lifting Jibs for Electric
Operations. The Jibs cost approximately $353,000 and have a CIRR of 22.49%. The CPG,
recommended to forward the request to Mark Thies for final approval.

5) March 2014 capital spending is under budget $10.2M and $13.0M under budget excluding
the growth overspend. (For comparison purposes, March 2013 YTD was under budget
$1.8M and $2.0M excluding the growth overspend).

6) The following requests were approved for spend in 2014:

ICNU_DR_069 Attachment A Page 11 of 58

With the addition of these items and the release of $6.7M, the expected spend is over
target by $8.1M. All other new requests are still pending and are not yet approved (please
see attached file for details).

7) The CPG spent the special meeting and much of the regular meeting discussing the
current overage and additional requests for funding. The CPG is requesting that all areas
of the company review their capital plans and determine which projects/programs may
not get completed or can be deferred to 2015. If additional releases of funds are not
identified, the CPG may request that some projects/programs be terminated, reduced or
deferred.

Margie Stevens
Director, Financial Planning & Analysis

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19
Spokane, WA 99202
P 509.495.8978
C 509.993.0913
http://www.avistautilities.com
This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_069 Attachment A Page 12 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Carlberg, Tim; Corder, Jim; DeFelice, Dave; Faulkenberry, Mike; Fisher, Al; Howard, Bruce; Howell, David; James, Dave; Kinney, Scott J; Lee, Julie; Magruder, Mike; Nitteberg, Kathy; Rosentrater, Heather; Schlothauer, Chris; Stevens, Margie; Thorson, Neil; Vermeers, Rick; Vickers, Laura; Waples, Scott; Weber, Vicki; Wenke, Steve
Subject:May Capital Planning Group Meeting
Date:Friday, June 01, 2012 5:18:58 PM
Attachments:image003.png
Below are the minutes from the May Capital Planning Group meeting. If you have any questions please let me know.
Thanks
The Capital Planning Group met on Wednesday, May 16th. Attendees included: Al Fisher, Bruce Howard, John
Schwendener, Jim Corder, Rick Vermeers, and Margie Stevens. Not present: Kevin Christie and Tim Carlberg.
1)John Schwendener approved RTCCS Refresh via email as he left the meeting prior to the final decision
2)The following requests were reviewed and approved:
RD Mac Asphalt Plant Extension $1,035,000 ($390k New Revenue, $645k expected spend increase)
Isolated Steel Replacement $1,000,000
RTCCS Refresh $1,228,700
AFM Training $47,500
Total Approved $3,311,200
3)Due to the transition to completing review templates for each business case, we would like to request that all
Business Case owners notify the committee of any underspend expected this year.
4)A recommendation regarding PowerPlant additional funding request for productivity was forwarded to Mark Thies
for approval on May 22, 2012.
5)URD cable is requesting additional funding of up to $2.4 million. This request is pending and will be discussed
further at the next meeting on June 20th.
6)Unfused Lateral and Chance Cutouts were approved at the last meeting as part of the Electric Distribution Minor
Blanket with no overall increase in funding. The Blanket is currently on-track to spend the budgeted amount so this
request was revisited during this meeting. Al Fisher will explore productivity funding for this request prior to the
next meeting.
7)LiDar Mitigation work (Transmission – NERC High Priority Mitigation) was approved for $600k on 3/21/12. This
request has been revised to $265k in 2012 and $1,170,000 in 2013 (a business case has been submitted).
8)Transmission Asset Management request for $1,000,000 additional funding was deferred until the next meeting.
9)Revised Spend below:
ICNU_DR_069 Attachment A Page 13 of 58
Margie Stevens
Director, Financial Planning and Analysis
Phone: [phone]
Fax: [phone]
E-mail: [e-mail]
ICNU_DR_069 Attachment A Page 14 of 58
From:Vickers, Laura
To:Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Howard, Bruce; Howell, David; James, Dave; Kelley, Bill; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Plut, David; Quincy, Diane; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Stevens, Margie; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve
Subject:Capital Planning Group 5/15/13 minutes - Please forward as needed
Date:Thursday, May 16, 2013 4:58:02 PM
Attachments:CPG report may13 meeting post meeting sent info.xlsx
The Capital Planning Group (CPG) met on Wednesday, May 15th. Attendees included: Mike
Broemeling, Jim Corder, Mike Faulkenberry, Heather Rosentrater, Andy Vickers, Jeremiah
Webster (FP&A), Laura Vickers (FP&A), Karen Schuh (Rates), Ken Sweigart (Engineering). Not
present: Bruce Howard.
1) Thru April 2013 the capital budget is under spent $0.9M excluding the variances for
electric and gas new revenue compared to YTD April 2012, we were under budget by $14M.
2) The CPG will recommend approval of the following productivity request to Mark Thies:
Remote Collar $407k Pending Mark’s
approval
3) Ken Sweigart discussed the additional jobs needed to complete in 2013 for high priority
LiDAR jobs. The request is $0.7M for 2013.

4) Additional requests this month include: (For a complete list of pending requests,
please see attachment.)
HVAC Renovation Project $883k – scope change
Segment Reconductor & FDR Tie $300k – co-locate distribution
segment w/ transmission line
Environmental Compliance $150k – accounting transfer
of 2010 permitting costs in suspense
Huntington Park $1M – total request is $1.2M
5) The following project was reviewed and approved
Rathdrum CT Replace Mark V Controller $292k Already spent; not
ICNU_DR_069 Attachment A Page 15 of 58
part of productivity
With this additional spend, offset by some release of funds, the capital budget is
currently oversubscribed $2.7M. This excludes $7.4M of pending requests.
6) The CPG spent a significant amount of time discussing the additional requests for
funding. Since the budget is currently oversubscribed and April YTD shows that we are only
$0.9M under spent, the CPG has asked that all business case owners review their
projects/programs and identify funds that can be released. If released funds are not
identified by the business owners, the CPG may be in a position to request certain cuts for
June’s meeting.

Laura Vickers
Manager, Operations Analytics
Avista Corporation
1411 E. Mission - MSC46
Spokane, WA 99220
phone - 509-495-2904
fax - 509-777-6138
ICNU_DR_069 Attachment A Page 16 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Condosta, Kristie; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Howell, David; James, Dave; Johnson, Dan; Kensok, Jim; Kenyon, Alison; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Leija, Andy; Magruder, Mike; Marlowe, Andrea; Mecham, Mike; Myers, Stephanie; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Ruppert, Vance; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Sweigart, Ken; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Whitby, Michael
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Fisher, Al; Howard, Bruce; Rosentrater, Heather;
Stevens, Margie; Vickers, Andy
Subject:CPG meeting 5/21/14 minutes
Date:Monday, June 02, 2014 3:28:51 PM
Attachments:CPG report may14 meeting_post meeting sent.xlsximage001.jpg
The Capital Planning Group (CPG) held a meeting on Wednesday, May 21. Attendees included:
Mike Broemeling, Jim Corder, Bryan Cox, Al Fisher, Bruce Howard, Heather Rosentrater, Andy
Vickers, Margie Stevens, Jeremiah Webster (FP&A support) and Karen Schuh (Rates observer).
Not present: Mike Faulkenberry

1) The CPG discussed the following productivity requests:
· GRX2 GPS Field Devices for the Real Estate Department to be used for calculating
and capturing field data for Highway Franchise agreements. The cost is
approximately $60,000 and has a CIRR of 114%. After discussion the CPG
recommended to forward the request to Mark Thies for final approval.
· Visibility: Phase 1.3 – Gas PMC Opportunity. This project configures the Ersi
Operations Dashboard to combine Zonar data, facility data and Ventyx data into
one view for use by Gas Service Dispatch. After discussion, the CPG would like
some clarification regarding the plans for the electric operations and how that is
being considered in this project. More information is needed prior to approval for
a recommendation to Mark.
· KFGS Fuel Feed System. This project would replace screw-feed auger sets, as well
as the feed chain box and chains. Redesign would improve the efficiency of the
plant. After discussion, the CPG would like more detail on the efficiency savings
prior to approval for a recommendation to Mark Thies.

2) Margie updated the CPG on a strategic funding request that has been approved by Mark
Thies related to Fleet CNG conversions. Additional spend of approximately $600,000 is
needed to complete the vehicle conversions that were contemplated in the original plan.
Overspend on the Mission fueling station resulted in the need for additional funds to
retrofit the remaining vehicles.

3) April 2014 year-to-date capital spending is under budget $13.0M and $17.2M under
budget excluding the growth overspend. (For comparison purposes, April 2013 YTD was
under budget $0.2M and $0.9M excluding the growth overspend).

4) The CPG reviewed all new requests for funding and approved:
· $400k out of the requested $1.4M to fund 2 months of AFM enhancement work
· $500k for Nine-Mile rebuild of trash racks which is offset with the deferral of the
ICNU_DR_069 Attachment A Page 17 of 58
CS2 Inlet Air System
· $440k was transferred from storms to meter minor blanket (accounting change, no
net increase in funding)
· $1,453K to upgrade the Ladd Canyon gate station (approved via email on
5/30/2014)
With the addition of these items and the release of $8.4M (see note #5 below), the
expected spend is over target by $2.7M. All other new requests are still pending and are
not yet approved (please see attached file for details).

5) The CPG discussed and wanted to emphasize that the some of the $8.4M in released
funds was an effort to reduce spending in order to fund urgent projects. Much of this
defunded work was planned and had already been designed resulting in the need to
reassign labor and defer this work until a later time. This likely will result in the need to
accelerate funding in the future to re-establish program levels.

Margie Stevens
Director, Financial Planning & Analysis

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19
Spokane, WA 99202
P 509.495.8978
C 509.993.0913
http://www.avistautilities.com

This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are
not an intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_069 Attachment A Page 18 of 58
From:Stevens, Margie
To:Carlberg, Tim; Christie, Kevin; Corder, Jim; Fisher, Al; Howard, Bruce; Schwendener, John; Stevens, Margie; Vermeers, RickSubject:June Capital Planning Group Meeting
Date:Wednesday, June 20, 2012 5:19:15 PMAttachments:image003.jpg
Please review the minutes below and notify me of any changes. Thanks
The Capital Planning Group met on Wednesday, June 20th. Attendees included: Tim Carlberg, Jim Corder, Kevin Christie (left at 2:30pm), Al
Fisher, Bruce Howard, Rick Vermeers, and Margie Stevens. Not present: John Schwendener.
1)The following requests were reviewed and approved:
60’ Bucket Truck $97,500 ($97,500 2012 cost, $277,500 total cost)
Technology Expansion (AFM portion) $804,000
Total Approved $901,500
2)Gas Compliance Application is releasing $1,501,600 since Maximo will be able to replace the functionality. Follow-up will occur
regarding the strategy for the transition period.
3)Due to the transition to review templates for each business case, an email requesting underspend projections will be forthcoming.
4)URD cable is requesting additional funding of up to $2.4 million. This request is to be refreshed and will be discussed further at the
next meeting on July 18th.
5)Transmission Asset Management request for $1,000,000 additional funding (Bronx-Cabinet Project Phase 2) is approved and being
offset with the Substation portion of Irvin.
6)Technology Expansion (beyond AFM) will be deferred and discussed further at the July meeting.
7)Expected Spend results:
Margie Stevens
Director, Financial Planning and Analysis
Phone: [phone]
Fax: [phone]
E-mail: [e-mail]
ICNU_DR_069 Attachment A Page 19 of 58
From:Webster, Jeremiah
To:Abrahamse, Bill; Benjamin, Tia; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Condosta, Kristie; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Howell, David; James, Dave; Jensen, Mary; Johnson, Dan; Kenyon, Alison; Kinney, Scott J; Krogh, Cody; Lee, Julie; Leija, Andy; Mackey, Carole; Madden, Glenn; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Ruppert, Vance; Schlothauer, Chris; Smith, Graham; Storey, Clay; Sweigart, Ken; Thorson, Neil; Vickers, Laura; Waples, Scott; Webb, Jeff; Wenke, Steve; Whitby, Michael; Kensok, Jim; Kopczynski, Don; Vermillion, Dennis; Weber, Vicki; Thackston, Jason
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Fisher, Al; Howard, Bruce; Rosentrater, Heather;
Schuh, Karen; Stevens, Margie; Vickers, Andy; Vickers, Laura
Subject:Capital Planning Group 6/18/14 minutes
Date:Tuesday, June 24, 2014 7:45:54 AM
Attachments:CPG report jun14 meeting_post meeting sent.xlsx
The Capital Planning Group (CPG) held a meeting on Wednesday, June 18. Attendees
included: Mike Broemeling, Jim Corder, Bryan Cox, Bruce Howard, Andy Vickers, Jeremiah
Webster (FP&A support) and Karen Schuh (Rates observer), Brady Hansen (ALP). Not
present: Mike Faulkenberry, Heather Rosentrater, and Margie Stevens.
1) The CPG discussed the following productivity requests:
· Visibility: Phase 1.3 – Gas PMC Opportunity. This project configures the Esri
Operations Dashboard to combine Zonar data, facility data, work order data, and Ventyx
data into one view for use by Gas Service Dispatch. The design and architecture will be such
that additional views can be configured (e.g., for electric dispatch). After discussion the CPG
recommended to forward the request to Mark Thies for final approval.
· KFGS Fuel Feed System. This project would replace conveyors, screw-feed auger
sets, and the feed chain box and chains. Redesign would improve the efficiency of the plant,
reduce load swings due to more even fuel delivery, and reduce maintenance costs. After
discussion the CPG recommended to forward the request to Mark Thies for final approval.
2) Jeremiah reported preliminary findings from the Earned Value sub-group identified
during the May business case user’s group meeting. Primarily, the sub-group was seeking
clarity about what questions the CPG wants answered regarding project/program progress
and performance. The sub-group agreed unanimously that the project management
discipline is very helpful and will continue to develop at Avista. However, the sub-group was
unsure about how the CPG may use project management metrics such as cost performance
index and schedule performance index. The CPG appreciated the feedback and had the
beginnings of a group philosophy discussion that will continue at the July meeting.
3) May 2014 year-to-date capital spending is under budget $14.8M and $20.2M under
budget excluding the growth overspend. (For comparison purposes, May 2013 YTD was over
budget $3.1M and under budget $1.3M excluding the growth overspend).
ICNU_DR_069 Attachment A Page 20 of 58
4) The CPG reviewed all new requests for funding, but did not approve any requests at this
time with the exception of a transfer from Capital Tools and Stores to Structures and
Improvements so that Facilities can complete a pole yard project. With the release of
$2.1M, the expected spend is over target by $0.6M. All other new requests are still pending
and are not yet approved (please see attached file for details).
5) The CPG is requesting that business case owners look at each business case to see
whether they will reasonably expect to complete planned work in 2014. Please make
releases as early as possible as there is a list of pending requests that can make use of the
funds. Note that the CPG is keeping a list of items deferred from 2014 so that these can be
incorporated into the capital plan in later years.

Jeremiah Webster
Financial Planning Analyst

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission MSC-19
P 509.495.2764
http://www.avistautilities.com
ICNU_DR_069 Attachment A Page 21 of 58
From:Vickers, Laura
To:Vickers, Laura; Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Howard, Bruce; Howell, David; James, Dave; Kelley, Bill; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Plut, David; Quincy, Diane; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Stevens, Margie; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve
Subject:Capital Planning Group 6/19/13 minutes - Please forward as needed
Date:Wednesday, June 19, 2013 9:10:56 PM
Attachments:CPG report jun13 meeting info to group post meeting.xlsx
The Capital Planning Group (CPG) met on Wednesday, June 19th. Attendees included: Mike
Broemeling, Jim Corder, Mike Faulkenberry, Heather Rosentrater, Andy Vickers, Laura
Vickers (FP&A), Karen Schuh (Rates), Mike Magruder (Engineering). Not present: Bruce
Howard.
1) Thru May 2013 the capital budget is under spent $1.3M excluding variances from the
Growth business case and Lucky Friday Substation rebuild (as approved by Mark Thies).
2) The CPG will recommend approval of the following productivity request to Mark Thies:
Beacon Substation Security System $66k
Pending Mark’s approval (after clarification on Productivity rules)
3) Ken Sweigart’s request of additional funds for LiDAR high priority jobs was further
discussed. An action item to Heather and Al to discuss our options to help fund this request
as well as the resources needed to complete the work.
4) Mike Magruder discussed the need to fund an additional $1.1M for the Moscow 230kV
Substation Rebuild in 2013. This was funded by an offset of other substation funds not used
this year.

5) Additional request(s) this month include: (For a complete list of pending requests,
please see attachment.)
High Voltage Protection for Substations $250k – funds
needed to complete the remaining 7 sites
6) Mark approved an additional $3.2M to help with the pending capital requests. The
following projects were reviewed and approved:
· HVAC Renovation Project $883k – scope change
ICNU_DR_069 Attachment A Page 22 of 58
· Facilities Restructuring Plan $2.7M – carryover from 2012 plus
additional costs
· Environmental Compliance $150k – accounting transfer of 2010
permitting costs in suspense
· Huntington Park $1M – total request is $1.2M
With this additional spend, offset by some release of funds, the capital budget is
currently at budget (oversubscribed $70k). However, this excludes $2.8M of
pending requests.
7) The 2014 capital budget roll-out was discussed. The July 10 deadline for business case
submission was emphasized.
Please call me if you have any questions.
Thanks,

Laura Vickers
Manager, Operations Analytics

PO Box 3727 MSC-46
Spokane, WA 99220
1411 E Mission MSC-46
P 509.495-2904
C 509-475-2416
http://www.avistautilities.com
ICNU_DR_069 Attachment A Page 23 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Condosta, Kristie; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Graham, Jason; Howell, David; James, Dave; Johnson, Dan; Kensok, Jim; Kenyon, Alison; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Leija, Andy; Magruder, Mike; Marlowe, Andrea; Mecham, Mike; Myers, Stephanie; Parsons, Amy; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Eric; Ruppert, Vance; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Sweigart, Ken; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Whitby, Michael
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Howard, Bruce; Rosentrater, Heather; Stevens,
Margie; Vickers, Andy
Subject:Capital Planning Group Meeting Minutes 7/16/14 -- Please forward as needed
Date:Friday, July 18, 2014 2:14:40 PM
Attachments:image001.jpgCPG report jul14 meeting_post meeting sent.xlsx
The Capital Planning Group (CPG) held a meeting on Wednesday, July 16. Attendees included:
Mike Broemeling, Jim Corder, Mike Faulkenberry, Heather Rosentrater, Andy Vickers, Margie
Stevens, Jeremiah Webster (FP&A support) and Karen Schuh (Rates observer). Not present:
Bryan Cox and Bruce Howard.

1) The CPG was made aware of the following items:
· The Battery Storage project of approximately $3.5 million will be funded from
strategic capital rather than the regular capital budget. This project will allow
Avista to invest in research related to integrating power generated from
intermittent renewable sources such as wind and solar into the electrical grid.
· There is a concerted effort to grow our gas business and as a result approximately
$2.1 million is planned to be spent in targeted areas under ER 1001 (New
Revenue).

2) June 2014 year-to-date capital spending is under budget $13.9M and $20.0M under
budget excluding the growth overspend. (For comparison purposes, June 2014 YTD was
over budget $0.3M and under budget $4.9M excluding the growth overspend).

3) The CPG reviewed all new and pending requests for funding, and approved the following
requests:
Business Case/Project Amount
Gas Deteriorated Steel Pipe Replacement Program 450,000
Noxon Switchyard Rebuild 1,900,000
Wa State Park & Rec Utility Use Agreement 140,000
Cafeteria transition to new vendor 150,000
Substation - New Distribution Stations 1,496,665
Worst Feeders 208,800
Central Office Facility (Mission Campus) Property Purchases 500,000

4) With the release of $6.9M, including the above approved requests the expected spend is
under target by $1.5M. All other requests are still pending and are not yet approved
(please see attached file for details).

ICNU_DR_069 Attachment A Page 24 of 58
5) Laura Vickers has been asked to research the $185k request for the Downtown Network
related to the new Walt Worthy hotel. A determination has been made that this project
qualifies as a New Revenue project.

6) The CPG has requested that the FP&A group work with project managers of productivity
and strategic initiatives to ensure that there is a clear understanding of requirements
under these funding mechanisms.

7) Capital prioritization for the 2015 planning cycle will begin during a special meeting
scheduled for August 5 at 1:00pm.

Margie Stevens
Director, Financial Planning & Analysis

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19
Spokane, WA 99202
P 509.495.8978
C 509.993.0913
http://www.avistautilities.com

This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_069 Attachment A Page 25 of 58
From:Vickers, Laura
To:Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Coulson, Rosemary; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Howard, Bruce; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Stevens, Margie; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Scott; Weber, Vicki; Webster, Jeremiah; Wenke, Steve
Subject:Capital Planning Group 7/17/13 minutes - Please forward as needed
Date:Monday, July 22, 2013 7:32:27 AM
Attachments:CPG report jul13 meeting - info to group - post meeting sent info.xlsx
The Capital Planning Group (CPG) met on Wednesday, July 17th. Attendees included: Mike
Broemeling, Jim Corder, Mike Faulkenberry, Bruce Howard, Andy Vickers, Karen Schuh,
Laura Vickers, Jeremiah Webster, Dave Schwall, Glenn Madden, Bryan Cox and Cesar
Godinez. Not present: Heather Rosentrater.
1) Thru June 2013 the capital budget is under spent $4.6M excluding variances from the
Growth business case and Lucky Friday Substation rebuild (as approved by Mark Thies).
2) The entire meeting was spent discussing new requests for 2013. A total of $11.7M in
new/revised business cases were submitted this month. After much discussion, the
following projects/programs were approved:
$000’s
WPM & TCOP $1,980 – Funds to fully utilize crews for the remainder of
the year
Gas Replacement Street & Highway $1,500 – Franchise required road move
work trending to $5M for year
Tech Refresh & Tech Expansion $ 953 – Microsoft Office - license compliance issue
--> Upgrade Office to 2013; installation will be additional (approx $1M)
LiDAR Mitigation Work $ 668 – Complete high priority LiDAR jobs
Gas Reinforcement $ 600 – Liberty Lake project is tied to taking the 6" HP
off of the Sullivan Bridge for 18 months + other projects
Regulator Station Reliability Replacement $ 250 – Projects that need to be
completed so the 6" HP main can be taken off the Sullivan Bridge for 18 months.
RTCCS Refresh $ 13 – Project complete; trailing costs
Total Approved In July $5,963k
ICNU_DR_069 Attachment A Page 26 of 58
3) With $4.6M funds released, offset with $6.0M of capital approvals, our expected spend
for 2013 is currently $1.4M oversubscribed. This excludes $7.7M of pending requests of
which $5.5M are new. The new unfunded requests this month include:
$000’s
Aldyl-A $3,750 – Actual cost per foot is higher than
budget. Requested funds is to complete 2013 planned work of replacing
16.67m and 2127 service tee transitions
Gas Non-Revenue Program $1,000 – Spend ahead of historical.
NERC Medium Priority - LiDAR Mitigation $ 599 – Start medium priority LiDAR
work. Additional requests in outer years
Transmission Asset Management $ 150 – Cover (7) additional structure
change-outs within the Spokane Operations Area as part of the Shawnee-Sunset
115kv Minot rebuild project
CS2 Inlet Air Systems $ 10 – Additional $490k in 2014: This
project would replace the present air filters with a new system that is more
effective at particulate removal than the current system.
Total requested, but not approved in July $5,509k
(Please see attachment for details for complete list of $7.7M unfunded
requests.)
4) The productivity request for GridGlo’s Revenue Analytics is currently on hold for further
review.
5) 2014-2018 business case submissions are being reviewed for assessment score
consistency. A consolidated report will be provided to CPG for review this week and the
group will meet at the end of this month to prioritize and balance the capital plan.
Note: The following business cases need to be submitted with the latest changes/requests:
WPM, TCOP, Tech Refresh, Tech Expansion and Aldyl-A.
Please call me if you have any questions.
Thanks,

ICNU_DR_069 Attachment A Page 27 of 58
Laura Vickers
Manager, Operations Analytics

PO Box 3727 MSC-46
Spokane, WA 99220
1411 E Mission MSC-46
P 509.495-2904
C 509-475-2416
http://www.avistautilities.com
ICNU_DR_069 Attachment A Page 28 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Condosta, Kristie; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Graham, Jason; Howell, David; James, Dave; Johnson, Dan; Kensok, Jim; Kenyon, Alison; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Leija, Andy; Magruder, Mike; Marlowe, Andrea; Mecham, Mike; Myers, Stephanie; Parsons, Amy; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Eric; Ruppert, Vance; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Sweigart, Ken; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Whitby, Michael
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Howard, Bruce; Rosentrater, Heather; Stevens,
Margie; Vickers, Andy
Subject:Capital Planning Group Meeting Minutes 8/20/14 -- Please forward as needed
Date:Monday, August 25, 2014 8:14:32 AM
Attachments:image001.jpgCPG report aug14 meeting_post meeting_sent.xlsx
The Capital Planning Group (CPG) held a meeting on Wednesday, August 20. Attendees included:
Mike Broemeling, Jim Corder, Bryan Cox, Mike Faulkenberry, Bruce Howard, Andy Vickers, Margie
Stevens, Jeremiah Webster (FP&A support), Karen Schuh (Rates observer) and Alexis Alexander
(ALP). Not present: Heather Rosentrater

1) July 2014 year-to-date capital spending is under budget $13.5M and $20.2M under budget
excluding the growth overspend. (For comparison purposes, July 2013 YTD was over
budget $4.8M and under budget $0.9M excluding the growth overspend).

2) The CPG reviewed all new and pending requests for funding, and approved the following
requests:
Business Case/Project Amount
Colstrip Thermal Capital 784,583
Storms 7,000,000

3) With the release of $1.2M, including the above approved requests the expected spend is
over target by $5.1M. All other requests are still pending and are not yet approved (please
see attached file for details). The CPG has decided to wait another month before
requesting the reduction and/or deferral of currently planned capital projects/programs to
accommodate the overage. The CPG asks that all project managers review their project(s)
and if a project/program is not going to be completed in 2014 please release those funds,
otherwise the CPG will be asking that certain projects/programs be deferred and/or
reduced.

4) Capital prioritization for the 2015 planning cycle will continue during a special meeting
scheduled for August 25 at 10:00am.

Margie Stevens
Director, Financial Planning & Analysis

ICNU_DR_069 Attachment A Page 29 of 58

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19
Spokane, WA 99202
P 509.495.8978
C 509.993.0913
http://www.avistautilities.com

This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are
not an intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_069 Attachment A Page 30 of 58
From:Vickers, Laura
To:Vickers, Laura; Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Coulson, Rosemary; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Howard, Bruce; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Stevens, Margie; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Waples, Scott; Webb, Jeff; Weber, Scott; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Gustafson, Mark
Subject:Capital Planning Group 8/22/13 minutes - Please forward as needed
Date:Friday, August 23, 2013 11:19:48 AM
Attachments:image001.gif
2013 Potential Reductions.xlsx
CPG report aug13 meeting updates.xlsx

The Capital Planning Group (CPG) met on Wednesday, August 22nd.  Attendees included:  Al Fisher,
 Heather Rosentrater, Mike Faulkenberry, Bruce Howard, Andy Vickers, Karen Schuh, Laura Vickers,
 and Jeremiah Webster.  Not present: Mike Broemeling and Jim Corder. 

1) Thru July 2013 the capital budget is under spent $4.6M excluding variances from the
 Growth business case and Lucky Friday Substation rebuild (as approved by Mark Thies). 
 This variance is similar to last month.

2) The following projects/programs were approved:
$000’s
High Voltage Protection Upgrade                          $   165 – Need to complete remaining seven
 sites
             Gas Non Revenue Program                                            $1,000 – Spend ahead of historical;
 additional funds will be needed, but will be offset w/ another gas project
Aldyl-A Replacement                                                     $3,750 – Actual cost per foot is higher
 than budget.  Requested funds is to complete 2013 planned work of replacing 16.67m and 2127
 service tee transitions
SG Demonstration Project                                      $   258 – Additional funds are intended to
 complete scope of work requirements to Battelle; request was $358
     Total Approved Since Previous CPG Mtg             $5,173k

3) With $4.5M funds released, offset with $5.2M of capital approvals, our expected spend for
 2013 is currently $3.1M oversubscribed.  This excludes $0.7M of pending requests of
 which $0 is new this month.  Attached is a list of potential items that would be cut to help
 meet our capital budget.  This list is will continue to change as more information is
 available. 

4) There were no productivity requests this month.

5) The 2014-2018 capital prioritization process is currently on hold until capital targets are
 determined by senior management.  A total of $86M of new requests were submitted for
 2014.  We will resume capital prioritization in mid/late September. 

Please call me if you have any questions.
ICNU_DR_069 Attachment A Page 31 of 58
Thanks,

Laura Vickers
Manager, Operations Analytics

PO Box 3727 MSC-46
Spokane, WA 99220
1411 E Mission MSC-46
P 509.495-2904
C 509-475-2416
http://www.avistautilities.com

ICNU_DR_069 Attachment A Page 32 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; DeFelice, Dave; Faulkenberry, Mike; Howell, David; James, Dave; Kinney, Scott J; Lee, Julie; Magruder, Mike; Nitteberg, Kathy; Rosentrater, Heather; Schlothauer, Chris; Thorson, Neil; Vickers, Laura; Waples, Scott; Weber, Vicki; Wenke, Steve; Axworthy, Anne Marie; Matthews, Ana; Pike, Andrea; Inman, Mary
Subject:Capital Planning Group Sept 21st Meeting Minutes -- forward as needed
Date:Wednesday, September 26, 2012 12:44:00 PM

The Capital Planning Group met on Friday, September 21st to discuss 2012 and finalize the 2013
 Capital Long-Range Plan.   Attendees included: Jim Corder, Al Fisher, Bruce Howard, Heather
 Rosentrater, John Schwendener (via phone), Rick Vermeers and Margie Stevens. Not present: Tim
 Carlberg.  Special Guests:  Andrea Pike and Mary Inman.

1) The following productivity funding requests were discussed:
· The Mobile Outreach Vehicle that was previously approved for productivity
 was not approved by Mark Thies due to the uncertainty of obtaining
 incremental Liheap funding to support the IRR.  The project is to be considered
 as part of the regular capital budget.
· Both the CPC vehicles that operate on CNG and the CS2 capital additions were
 discussed.  The CS2 capital additions are considered a higher priority and will
 get funded before the CNG vehicles.  Margie will discuss with Mark Thies how
 to handle the requests.  If need be, the CPC vehicles will be deferred until
 2013.  More to come.

2) The Following items were reviewed and approved for spend in 2012:
High Voltage Protection for substations                         $43,875
Microwave Refresh                                                                 359,877
RTCCS Refresh                                                                           632,295
Mobility in the Field                                                                 400,000
Wood Pole Management                                                      635,000
Inspection Trucks                                                                       61,458
Mobile Outreach Vehicle                                                         71,500
Transformer Change Out Program                                    500,000
Total                                                                                           2,704,005

3) YTD through August, we are under spent $29M from budget (excluding Smart Grid, New
 Revenue, Compass). 

4) After all approvals and releases of funds we currently expect to be underspent by $374k.

5) The 2013 Long-range capital plan was discussed, reviewed and revised to achieve the
 stated targets. 

The 2013 Capital Plan is now posted on the Planning & Budget SharePoint site under “Business
 Cases\2013 5 year capital plan 9.25.12 (as slight adjustments are made the date of this file may
ICNU_DR_069 Attachment A Page 33 of 58
 change).  Budget entry for all years may now commence, however, final review and approval
 from the Officers and the Finance Committee of the Board will occur in October and
 November.  Budget input deadline for all years has been extended to October 5th.

Margie Stevens
Director, Financial Planning and Analysis
Phone: [phone] 
Fax: [phone] 
E-mail: [e-mail]

ICNU_DR_069 Attachment A Page 34 of 58
Business Case/Project $Amount
KFGS Ash Collector 150,000
Kettle Falls Water Supply 200,000
Transmission - Asset Management 1,043,000
Transmission - NERC Low Priority Mitigation 500,000
Structures and Improvements/Furniture 50,000
Mobility in the Field 30,000
Gas Non-Revenue Program 500,000
Gas PMC Program 125,000
Gas Regulator Stn Replacement Program 150,000
Base Load Thermal Plant 100,000
Hydro Safety Minor Blanket 23,000
Kettle Falls Diesel Fuel Station 250,000
Distribution Wood Pole Management (in-house crew work) 200,000
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Condosta, Kristie; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Graham, Jason; Howell, David; James, Dave; Johnson, Dan; Jones, Linda; Kensok, Jim; Kenyon, Alison; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Leija, Andy; Magruder, Mike; Marlowe, Andrea; Mecham, Mike; Myers, Stephanie; Parsons, Amy; Pike, Andrea; Plut, David; Quincy, Diane; Reding, Matt; Reidt, Jacob; Rosentrater, Eric; Ruppert, Vance; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Sweigart, Ken; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Whitby, Michael
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Howard, Bruce; Rosentrater, Heather; Stevens,
Margie; Vickers, Andy
Subject:Capital Planning Group Meeting Minutes 10/15/14 - please forward as needed
Date:Friday, October 17, 2014 4:25:36 PM
Attachments:image001.jpgCPG report oct14 meeting_post meeting_sent.xlsx

Due to numerous scheduling conflicts, the Capital Planning Group did not meet in September.

The Capital Planning Group (CPG) held a meeting on Wednesday, October 15. Attendees included:
Mike Broemeling, Jim Corder, Mike Faulkenberry, Bruce Howard, Heather Rosentrater, Andy
Vickers, Margie Stevens, Jeremiah Webster (FP&A support), Karen Schuh (Rates observer),
Stephanie Myers (ALP) and Jacob Reidt (Observer). Not present: Bryan Cox

1) September 2014 year-to-date capital spending is under budget $12.0M and $20.3M under
budget excluding the growth overspend. (For comparison purposes, September 2013 YTD
was over budget $8.6M and over budget $1.3M excluding the growth overspend). Margie
will be requesting Finance Committee approval of the growth overspend at the November
2014 meeting.

2) The CPG reviewed all new and pending requests for funding, and approved the following
requests:

ICNU_DR_069 Attachment A Page 35 of 58
Distribution Transformer Change-Out Program (in-house crew work) 500,000
Technology Expansion to Enable Business Process 400,000
Total Approved 4,221,000

3) With the release of $7.1M, including the above approved requests the expected spend is
over target by $2.2M. In order to cover this overage, the CPG is asking the for the release
of funds for any projects/programs that are not going to be completed in 2014. Project
managers should review projects YTD spending percent of the total expected spend (please
see the attached spreadsheet and refer to the Business Case Report tab). Projects with a
low percent spent are going to receive extra scrutiny by the CPG at the November meeting.
If the budget is still over target in November, certain projects/programs will be asked to
curtail spending.

4) The Capital Plan for 2015 has been completed, however the Officers will continue to review
components of the Plan. Final approval from the Finance Committee of the Board of
Directors is expected at their meeting to be held on November 13, 2014.

Thanks

Margie Stevens
Director, Financial Planning & Analysis

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19
Spokane, WA 99202
P 509.495.8978
C 509.993.0913
http://www.avistautilities.com

This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_069 Attachment A Page 36 of 58
From:Vickers, Laura
To:Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Coulson, Rosemary; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Gustafson, Mark; Howard, Bruce; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Stevens, Margie; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Scott; Weber, Vicki; Webster, Jeremiah; Wenke, Steve
Cc:Kalich, ClintSubject:Capital Planning Group 10/16/13 minutes - Please forward as needed
Date:Monday, October 21, 2013 3:19:32 PM
Attachments:image001.gifCPG report oct13 meeting - post meeting sent info.xlsx
The Capital Planning Group (CPG) met on Wednesday, October 16th. Attendees included: Mike Broemeling, Jim Corder, Heather Rosentrater,
Andy Vickers, Bryan Cox (substitute for Al Fisher), Karen Schuh, Laura Vickers, and Jeremiah Webster. Clint Kalich and Xin Shane were present
to answer questions on their productivity request. Not present: Bruce Howard, Mike Faulkenberry, and Al Fisher

1) Thru September 2013 the capital budget is over spent $1.3M (compared to original budget) excluding variances from the Growth
business case and Lucky Friday Substation rebuild. These numbers include capital spend related to Colstrip Unit 4 outage. However, if
we incorporate 75% of the Compass carryover and additional capital approved by Finance Committee (Board) for 2013, we would be
under spent by $5.4M YTD.

2) The following projects/programs were approved:

Business Case/Project Amount Information
CS2 Inlet Air Systems 10,000
10k in 2013, 500k in 2014: Replace the present air filters with a new system that is more effective
at particulate removal than the current system.
Turtle Replacement 80,000 The existing power line carrier system for reading meters has failed and is not repairable.
Fleet Budget 30,900 Grangeville UTV; increased flexibility instead of using a snow cat
Klamath Falls Lateral Purchase 45,000 Trailing costs, project complete
Technology Refresh to Sustain Business
Process 300,000 Revised Windows 7 project cost estimates
Distribution Minor Rebuild 1,600,000 Increased trouble work coupled with additional minor rebuild work
Gas Non-Revenue Program 1,000,000 Trending
Segment Reconductor and FDR Tie Program 200,000 Greenacres reconductor
Colstrip Generator Core Failure 862,000 Replace rotor due to outage in July (net of insurance proceeds in 2013)
Total 4,127,900

3) Given the time of the year, there was a lot of discussion prior to the meeting to refine expected spend estimates based on actual YTD
spend. With $6.7M funds released, offset with $4.1M of capital approvals, our expected spend for 2013 is currently $0.6M
oversubscribed. Although there are no pending requests, CPG has a list of shovel-ready work that can be activated in November should
there be any available funds in the next few weeks.

4) Clint Kalich provided an overview of the productivity request (addendum) for the Power Supply Optimization Project. After discussion,
CPG will forward to Mark Thies. The requested amount is $250,000.

5) Action Item for Business case owners: Please review the attached spreadsheet and verify that your business case expected spend is
consistent with your records (Expected Spend tab, column BR). If there is a discrepancy, please contact Jeremiah Webster and Laura
Vickers.

Please call me if you have any questions.
Thanks,

Laura Vickers
Manager, Operations Analytics

PO Box 3727 MSC-46
Spokane, WA 99220
1411 E Mission MSC-46
P 509.495-2904
C 509-475-2416
http://www.avistautilities.com

ICNU_DR_069 Attachment A Page 37 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Christie, Kevin; Condosta, Kristie; Cox, Bryan;
DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Graham, Jason; Howell, David; James, Dave; Johnson, Dan; Jones, Linda; Kensok, Jim; Kenyon, Alison; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Leija, Andy; Magruder, Mike; Marlowe, Andrea; Mecham, Mike; Myers, Stephanie; Newhouse, Kristina; Parsons, Amy; Pike, Andrea; Plut, David; Quincy, Diane; Reding, Matt; Reidt, Jacob; Rosentrater, Eric; Roys, Walter; Ruppert, Vance; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Sweigart, Ken; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Whitby, Michael; Conley, Kelly
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Howard, Bruce; Rosentrater, Heather; Stevens, Margie; Vickers, Andy
Subject:Capital Planning Group Meeting Minutes 11/19/14 - please forward as needed
Date:Monday, November 24, 2014 10:17:19 AM
Attachments:image001.jpgCPG report nov14 meeting_post meeting_sent.xlsx
The Capital Planning Group (CPG) held a meeting on Wednesday, November 19. Attendees
included: Mike Broemeling, Jim Corder, Bryan Cox, Mike Faulkenberry, Bruce Howard, Heather
Rosentrater, Margie Stevens, Jeremiah Webster (FP&A support), Karen Schuh (Rates observer),
Jacob Reidt (Observer), and Stephanie Myers and Kelly Conley for a portion of the meeting. Not
present: Andy Vickers

1) Stephanie Myers and Kelly Conley discussed the Web Redesign Project with the group
including the request to accelerate $2.0M of spend primarily related to iFactor from 2016
to 2015. After discussion, the CPG approved the acceleration of the $2.0M from 2016 to
2015. With this additional $2M, the 2015 Capital Budget is oversubscribed and offsets
will need to be found during 2015.

2) Jeremiah explained to the group a misunderstanding of requested spend for Aldyl-A funding
in an effort to keep the CPG informed. To the extent that variations in funding are needed
during 2015, those funding needs will be addressed by the CPG at that time.

3) A productivity request for Revenue Protections was discussed and a decision was deferred
to the December meeting to allow for more information to be gathered.

4) October 2014 year-to-date capital spending is under budget (excluding Project Compass)
$7.7M and $17.1M under budget excluding the growth overspend. (For comparison
purposes, October 2013 YTD was over budget $7.2M and under budget $2.1M excluding
the growth overspend).

5) The CPG reviewed all new and pending requests for funding, and approved the following
requests:

Business Case/Project Amount
Gas Non-Revenue Program 500,000
Gas PMC Program 50,000
Gas Regulator Stn Replacement Program 100,000
Cabinet Gorge Unit 1 Refurbishment 970,000
Gas Reinforcement Program 200,000
ICNU_DR_069 Attachment A Page 38 of 58
Substation - Distribution Station Rebuilds 428,082
Dist Grid Modernization 400,000
Worst Feeders 100,000
Total 2,748,082

6) With the release of $4.5M, including the above approved requests the expected spend is
over target by $0.4M. The CPG acknowledged that there is an expectation that some
currently funded projects are likely to come in under their expected spend and the budget
will likely not be overspent at year-end.

7) Margie gave an update on the Finance Committee meeting in which the 2015 Capital Plan
was approved. Additional funding for Compass was also approved with the expectation
that Compass will carryover a portion of the approved budget to 2015.

8) Margie reminded the CPG that business case sponsors and/or project managers will need to
accrue for any goods and services received prior to December 31, 2014.

Thanks

Margie Stevens
Director, Financial Planning & Analysis

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19
Spokane, WA 99202
P 509.495.8978
C 509.993.0913
http://www.avistautilities.com

This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_069 Attachment A Page 39 of 58
From:Vickers, LauraTo:Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Coulson, Rosemary; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Gustafson, Mark; Howard, Bruce; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; McClain, John; Myers, Stephanie; Olson, Tim; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Stevens, Margie; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Scott; Weber, Vicki; Webster, Jeremiah; Wenke, SteveSubject:Capital Planning Group 11/20/13 minutes - Please forward as neededDate:Monday, November 25, 2013 7:37:17 AMAttachments:image001.gifCPG report nov13 meeting_post meeting sent info.xlsx
The Capital Planning Group (CPG) met on Wednesday, November 20th. Attendees included: Mike Broemeling, Jim Corder, Bruce Howard, Mike
Faulkenberry, Al Fisher, Heather Rosentrater, Andy Vickers, Bryan Cox, Laura Vickers, and Jeremiah Webster.

1) Thru October 2013 the capital budget is under spent $2.1M (compared to original budget) excluding variances from the Growth business case
and Lucky Friday Substation rebuild. However, if we incorporate 83% of the Compass carryover and additional capital approved by Finance
Committee (Board) for 2013, we would be under spent by $9.5M YTD.

2) The following projects/programs were approved:

Business Case/Project Amount Other Information
Meter Minor Blanket

10,000 Conversion of Fairchild master meter
Transmission - Reconductors and Rebuilds 691,000 Revised cost to complete of two lines
Dollar Rd Service Center Addition & Remodel

54,000 Trailing costs: Unanticipated shelving and equipment costs
HVAC Renovation Project

670,000 Advancement of 2014 work, already complete
COF Long-Term Restructuring Plan

200,000
Unanticipated costs associated with the project, including out of scope permitting fees, security
system controls, HVAC control upgrades, and electrical subcontractor out of scope items.
Storms

525,000 Colville/Spokane wind storm MED 8/25 & 8/26 and trending for Nov and Dec
Repl Deteriorating Steel Gas Systems

150,000
$100,000 will be needed to cover existing overage expected by late November, $280,000 would
carry projects through December. CPG reduced request from $280k to $150k
Elec Replacement/Relocation

50,000 Reclaim part of previous release due to trending.
Gas PMC Program - Capital Replacements

60,000
Requested funds are to finish up Lewiston East Telemetry Project and Mechanical Chart
Replacement.
Gas Reinforcement

100,000 Appleway project was higher due to rocky conditions.
East Medford Reinforcement

60,000 Trailing costs. Complete and in-service.
Clearwater Sub Upgrade

50,000 Per October T&D Expected Spend document; offsets are provided within T&D
Colstrip Transmission/PNACI

14,000 Per October T&D Expected Spend document; offsets are provided within T&D
LiDar Mitigation Work

31,000 Per October T&D Expected Spend document; offsets are provided within T&D
Moscow 230 Substation Rebuild

500,000 Per October T&D Expected Spend document; offsets are provided within T&D
Substation - Asset Mgmt. Capital Maintenance

87,000 Per October T&D Expected Spend document; offsets are provided within T&D
Substation - Capital Spares

245,000 Per October T&D Expected Spend document; offsets are provided within T&D
Worst Feeders

142,000 Per October T&D Expected Spend document; offsets are provided within T&D
Spokane River License Implementation

1,058,000 Huntington Park
Coyote Springs LTSA

285,000 Mandatory spend based on unit run time.
Primary URD Cable Replacement

150,000 Projects already committed or in progress
Total

5,132,000

3) With $5.9M funds released, offset with $5.1M of capital approvals, our expected spend for 2013 is currently $0.1M under budget.

4) There was one productivity request this month: Additional $625k is needed to complete the Lancaster Interconnection project. After
discussion, CPG approved to forward the request to Mark Thies.

5) Action Item for Business case owners: Please review the attached spreadsheet and verify that your business case’s expected spend is
consistent with your records (Expected Spend tab, column BQ). If there is a discrepancy, please contact Jeremiah Webster.
ICNU_DR_069 Attachment A Page 40 of 58

Please call me if you have any questions.
Thanks,

Laura Vickers
Manager, Operations Analytics

PO Box 3727 MSC-46
Spokane, WA 99220
1411 E Mission MSC-46
P 509.495-2904
C 509-475-2416http://www.avistautilities.com

ICNU_DR_069 Attachment A Page 41 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; DeFelice, Dave; Faulkenberry, Mike; Howell, David; James, Dave; Kinney, Scott J; Lee, Julie; Magruder, Mike; Nitteberg, Kathy; Rosentrater, Heather; Schlothauer, Chris; Thorson, Neil; Vickers, Laura; Waples, Scott; Weber, Vicki; Wenke, Steve; Luders, Pam; Webb, Jeff
Cc:Carlberg, Tim; Corder, Jim; Fisher, Al; Howard, Bruce; Rosentrater, Heather; Schwendener, John; Stevens,
Margie; Vermeers, Rick
Subject:Capital Planning Group Meeting - Please forward as needed to interested parties
Date:Friday, September 07, 2012 11:32:31 AM

The Capital Planning Group met on Wednesday, September 5th to begin discussions regarding the
 2013 Capital Plan.   Attendees included: Tim Carlberg, Jim Corder, Al Fisher, Bruce Howard (arrived
 late), Heather Rosentrater, John Schwendener and Margie Stevens. Not present: Rick Vermeers

In addition to the 2013 Capital Plan preparations, the following items for the 2012 Capital Budget
 were included in the meeting:

1) Approval of a Wood Pole Management Inspector/Auditor truck for $41,700.  There was
 also some discussion about when a separate vehicle should be brought before the
 committee and if there is a way to more efficiently accommodate the needs of new hires
 (technology, vehicles, etc.).
2) Approval of the Tri City HP Gas Relocate for $600,000.  Jeff Webb was asked to add some
 additional details to the business case and that has been completed.

Due to the timing of the meeting there wasn’t any new information regarding actual results.

Margie Stevens
Director, Financial Planning and Analysis
Phone: [phone] 
Fax: [phone] 
E-mail: [e-mail]

ICNU_DR_069 Attachment A Page 42 of 58
Business Case/Project Amount
Distribution Wood Pole Management 400,000
Transmission - NERC Low Priority Mitigation 440,000
Transmission - NERC Medium Priority Mitigation 42,000
COF LngTrm Restruct Ph2 590,000
Dollar Rd Service Center Addition and Remodel 160,000
Capital Tools & Stores Equipment 30,000
Gas Deteriorated Steel Pipe Replacement Program 30,000
Gas Spokane St Bridge IP Main Project 20,000
Gas East Medford HP Main Reinforcement Project 615,000
AvistaUtilities.com and AvaNet Redesign 97,000
Aldyl A Replacement 250,000
Dist Grid Modernization 500,000
Substation - Distribution Station Rebuilds 188,000
Total $3,362,000
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Christie, Kevin; Condosta, Kristie; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Graham, Jason; Howell, David; James, Dave; Johnson, Dan; Jones, Linda; Kensok, Jim; Kenyon, Alison; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Leija, Andy; Magruder, Mike; Marlowe, Andrea; Mecham, Mike; Myers, Stephanie; Newhouse, Kristina; Parsons, Amy; Pike, Andrea; Plut, David; Quincy, Diane; Reding, Matt; Reidt, Jacob; Rosentrater, Eric; Roys, Walter; Ruppert, Vance; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Sweigart, Ken; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Whitby, Michael
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Howard, Bruce; Rosentrater, Heather; Stevens,
Margie; Vickers, Andy
Subject:Capital Planning Group Meeting Minutes 12/17/14 - please forward as needed
Date:Tuesday, December 23, 2014 10:55:18 AM
Attachments:CPG report dec14 meeting_2014.12.23_post meeting_sent.xlsximage001.jpg2014 Invoices to be Accrued.xlsx2014 YE Invoice Processing and Accruals.docx
The Capital Planning Group (CPG) held a meeting on Wednesday, December 17. Attendees
included: Mike Broemeling, Jim Corder, Bryan Cox, Mike Faulkenberry, Heather Rosentrater,
Margie Stevens, Andy Vickers, Jeremiah Webster (FP&A support), and Karen Schuh (Rates
observer). Not present: Bruce Howard

1) November 2014 year-to-date capital spending is under budget (excluding Project Compass)
$8.2M and $18.0M under budget excluding the growth overspend. (For comparison
purposes, November 2014 YTD was over budget $9.2M and under budget $1.4M excluding
the growth overspend).

2) The CPG reviewed all new and pending requests for funding, and approved the following
requests:

ICNU_DR_069 Attachment A Page 43 of 58
3) With the release of $7.5M, including the above approved requests the expected spend is
under target by $3.8M.

4) The CPG discussed a productivity request for purchasing Embotics software which is a
software tool that allows us to optimize server space. The software cost is approximately
$235,000 and has a CIRR of 22%. The CPG recommended to forward the request to Mark
Thies for final approval.

5) The CPG discussed and would like to sponsor a year-end capital celebration with
project/program sponsors in recognition of all the hard work and accomplishments during
2014.

6) The CPG would like to get a better understanding of “What does success look like” for the
capital budget. Margie has discussed this request with Mark Thies and he has agreed to
come to a future meeting.

Of final note: Business case sponsors and/or project managers will need to accrue for any
goods and services received prior to December 31, 2014 (please see attached memos for
details). All invoices need to be submitted to AP by noon, December 23rd.

Margie Stevens
Director, Financial Planning & Analysis

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19
Spokane, WA 99202
P 509.495.8978
C 509.993.0913
http://www.avistautilities.com
This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_069 Attachment A Page 44 of 58
Business Case/Project Amount
Distribution Wood Pole Management 400,000
From:Stevens, Margie
To:Stevens, Margie; Abrahamse, Bill; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Christie, Kevin; Condosta, Kristie; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Graham, Jason; Howell, David; James, Dave; Johnson, Dan; Jones, Linda; Kensok, Jim; Kenyon, Alison; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Leija, Andy; Magruder, Mike; Marlowe, Andrea; Mecham, Mike; Myers, Stephanie; Newhouse, Kristina; Parsons, Amy; Pike, Andrea; Plut, David; Quincy, Diane; Reding, Matt; Reidt, Jacob; Rosentrater, Eric; Roys, Walter; Ruppert, Vance; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Sweigart, Ken; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Whitby, Michael
Cc:Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Howard, Bruce; Rosentrater, Heather; Vickers,
Andy
Subject:RE: Capital Planning Group Meeting Minutes 12/17/14 - please forward as needed
Date:Tuesday, December 23, 2014 11:01:42 AM
Attachments:CPG report dec14 meeting_post meeting_sent.xlsximage001.jpg
The file attached to the original email contained actual results through today. I have attached the
file that has results through November 30, 2014.

Margie Stevens Phone: [phone]

From: Stevens, Margie Sent: Tuesday, December 23, 2014 10:55 AMTo: Abrahamse, Bill; Bowles, Eric; Calbick, Brad; Carrozzo, Steve; Christie, Kevin; Condosta, Kristie; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Dempsey, Tom C; DiLuciano, Josh; Evans, Heide; Gall, James; Garbarino, Marcus; Gfeller, Greg; Gibbs, Alicia; Gibson, John; Gonnella, Mike; Graham, Jason; Howell, David; James, Dave; Johnson, Dan; Jones, Linda; Kensok, Jim; Kenyon, Alison; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Leija, Andy; Magruder, Mike; Marlowe, Andrea; Mecham, Mike; Myers, Stephanie; Newhouse, Kristina; Parsons, Amy; Pike, Andrea; Plut, David; Quincy, Diane; Reding, Matt; Reidt, Jacob; Rosentrater, Eric; Roys, Walter; Ruppert, Vance; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Sweigart, Ken; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve; Whitby, MichaelCc: Broemeling, Mike; Corder, Jim; Cox, Bryan; Faulkenberry, Mike; Howard, Bruce; Rosentrater, Heather; Stevens, Margie; Vickers, AndySubject: Capital Planning Group Meeting Minutes 12/17/14 - please forward as needed

The Capital Planning Group (CPG) held a meeting on Wednesday, December 17. Attendees
included: Mike Broemeling, Jim Corder, Bryan Cox, Mike Faulkenberry, Heather Rosentrater,
Margie Stevens, Andy Vickers, Jeremiah Webster (FP&A support), and Karen Schuh (Rates
observer). Not present: Bruce Howard

1) November 2014 year-to-date capital spending is under budget (excluding Project Compass)
$8.2M and $18.0M under budget excluding the growth overspend. (For comparison
purposes, November 2014 YTD was over budget $9.2M and under budget $1.4M excluding
the growth overspend).

2) The CPG reviewed all new and pending requests for funding, and approved the following
requests:

ICNU_DR_069 Attachment A Page 45 of 58
Transmission - NERC Low Priority Mitigation 440,000
Transmission - NERC Medium Priority Mitigation 42,000
COF LngTrm Restruct Ph2 590,000
Dollar Rd Service Center Addition and Remodel 160,000
Capital Tools & Stores Equipment 30,000
Gas Deteriorated Steel Pipe Replacement Program 30,000
Gas Spokane St Bridge IP Main Project 20,000
Gas East Medford HP Main Reinforcement Project 615,000
AvistaUtilities.com and AvaNet Redesign 97,000
Aldyl A Replacement 250,000
Dist Grid Modernization 500,000
Substation - Distribution Station Rebuilds 188,000
Total $3,362,000

3) With the release of $7.5M, including the above approved requests the expected spend is
under target by $3.8M.

4) The CPG discussed a productivity request for purchasing Embotics software which is a
software tool that allows us to optimize server space. The software cost is approximately
$235,000 and has a CIRR of 22%. The CPG recommended to forward the request to Mark
Thies for final approval.

5) The CPG discussed and would like to sponsor a year-end capital celebration with
project/program sponsors in recognition of all the hard work and accomplishments during
2014.

6) The CPG would like to get a better understanding of “What does success look like” for the
capital budget. Margie has discussed this request with Mark Thies and he has agreed to
come to a future meeting.

Of final note: Business case sponsors and/or project managers will need to accrue for any
goods and services received prior to December 31, 2014 (please see attached memos for
details). All invoices need to be submitted to AP by noon, December 23rd.

Margie Stevens
Director, Financial Planning & Analysis

ICNU_DR_069 Attachment A Page 46 of 58

PO Box 3727 MSC-19
Spokane, WA 99220
1411 E Mission Ave. MSC-19
Spokane, WA 99202
P 509.495.8978
C 509.993.0913
http://www.avistautilities.com

This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_069 Attachment A Page 47 of 58
From:Stevens, MargieTo:Abrahamse, Bill; Bowles, Eric; Broemeling, Mike; Carrozzo, Steve; Christie, Kevin; Corder, Jim; Coulson, Rosemary; Cox, Bryan; DeFelice, Dave; Dehnel, Troy; Evans, Heide; Faulkenberry, Mike; Fisher, Al; Gfeller, Greg; Gustafson, Mark; Howard, Bruce; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; McClain, John; Myers, Stephanie; Olson, Tim; Pike, Andrea; Plut, David; Quincy, Diane; Reidt, Jacob; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Stevens, Margie; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Andy; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Scott; Weber, Vicki; Webster, Jeremiah; Wenke, SteveSubject:Capital Planning Group 12/18/13 minutes - Please forward as neededDate:Friday, December 20, 2013 3:27:00 PMAttachments:image001.gifCPG report dec13 meeting_post meeting.xlsx
The Capital Planning Group (CPG) met on Wednesday, December 18th. Attendees included: Mike Broemeling, Jim Corder, Bruce Howard (first half hour), Mike Faulkenberry, Al Fisher, Heather Rosentrater, Andy
Vickers, Bryan Cox, Margie Stevens, Laura Vickers, Jeremiah Webster, and Karen Schuh.

1) Through November 2013 the capital budget is under spent $1.4M (compared to original budget) excluding variances from the Growth items. However, if we incorporate 92% of the Compass carryover and
additional capital approved by the Board Finance Committee for 2013, we would be under spent by $9.6M YTD.

2) The following requests were approved:

Business Case/Project Amount Requester Other Information
Mobility in the Field 60,000 Andrea Pike Review yet to be submitted
Distribution Minor Rebuild 700,000 Julie Lee Increased trouble and minor rebuild work
Storms 150,000 Julie Lee Actual results + December average
Regulating Hydro 200,000 Steve Wenke
Higher than planned costs on some projects, (e.g., high cost of the treatment system project at
Cabinet)
Aldyl A Replacement 710,904 Michael Whitby Actual + Committed/Pending invoices
Clearwater Sub Upgrade 50,000 Mike Magruder Per November T&D Expected Spend spreadsheet
Dist Grid Modernization 313,000 Troy Dehnel Per November T&D Expected Spend spreadsheet
LiDar Mitigation Work 121,000 Ken Sweigart Per November T&D Expected Spend spreadsheet
Moscow 230 Substation Rebuild 300,000 Mike Magruder Per November T&D Expected Spend spreadsheet
Noxon Switchyard Rebuild 20,000 Mike Magruder Per November T&D Expected Spend spreadsheet
SCADA - SOO & BUCC 25,000 Greg Paulson Per November T&D Expected Spend spreadsheet
Spokane Electric Network 50,000 Dave James Per November T&D Expected Spend spreadsheet
Substation - Asset Mgmt. Capital Maintenance 395,000 Mike Magruder Per November T&D Expected Spend spreadsheet
Substation -New Distribution Stations 75,000 Mike Magruder Per November T&D Expected Spend spreadsheet
Worst Feeders 99,000 Dave James Per November T&D Expected Spend spreadsheet
Gas Reinforcement 70,000 Jeff Webb Due to rocky conditions at Appleway project
Gas Replacement Street & Highway 50,000 Jeff Webb True up of expected spend.
Chase Rd. Gate Station Installation 100,000 Jeff Webb Some material delivered early that was originally planned for 2014.
Fleet Budget 150,000 Chris Schlothauer Some of the CNG conversions dollars could not be transferred.
High Voltage Protection Upgrade 6,000 Jacob Reidt Trailing costs

3) The expected spend is currently expected to be $1.2M under spent after fund releases and approvals shown above.

4) There were four requests for productivity funding:

1. Coyote Springs 2: Additional request for $466,000. CPG recommended forwarding to Mark Thies for approval.
2. Enterprise Content Management: Requesting $650,000. CPG would like some additional information and revision of the business case presentation. Once this is completed the request will be
forwarded to Mark for approval.
3. Aclara License Purchase: Requesting $209,000. CPG would like the CIRR run over a 3 year period. If the revised CIRR meets the hurdle rate it can be forwarded to Mark for approval.
4. LMS Analytics: Requesting $400,000. CPG would like some more information and is deferring action until the January meeting.

5) The CPG was made aware of the additional transformers and protectors that will need to be purchased in excess of the 2014 growth budget.

6) The CPG is interested in a company-wide lessons learned session for capital project sponsors (Margie will follow-up).

Margie StevensDirector, Financial Planning & Analysis
PO Box 3727 MSC-19Spokane, WA 992201411 E Mission Ave. MSC-19Spokane, WA 99202
P 509.495.8978
C 509.993.0913http://www.avistautilities.com This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an intended recipient, please notify the sender and delete this email from your system. Thank you.
ICNU_DR_069 Attachment A Page 48 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; DeFelice, Dave; Faulkenberry, Mike; Howell, David; James, Dave; Kinney, Scott J; Lee, Julie; Magruder, Mike; Nitteberg, Kathy; Rosentrater, Heather; Schlothauer, Chris; Thorson, Neil; Vickers, Laura; Waples, Scott; Weber, Vicki; Wenke, Steve
Cc:Carlberg, Tim; Corder, Jim; Fisher, Al; Howard, Bruce; Rosentrater, Heather; Schwendener, John; Stevens,
Margie; Vermeers, Rick; Westenberg, Joe
Subject:Capital Requests and Release of funds
Date:Wednesday, August 08, 2012 9:07:28 AM
The Capital Planning Group meeting is scheduled for next Wednesday, August 15th. Please submit
capital requests to me by this Friday, August 10th (This will allow the CPG members an opportunity
to review requests prior to the meeting). Any requests received after 5:00pm this Friday will be
considered at the September meeting on Wednesday, September 19th. All requests need to be
submitted electronically to me with a signed hardcopy. If you are requesting a change to a current
business case, please complete a review template. If you need assistance with this process please
contact Joe Westenberg, x4759.

Please identify any capital projects/programs that are not expected to fully utilize budgeted funds
in 2012 so that those dollars can be re-allocated. Based on the information that we currently have,
we are projecting to be overspent for the year yet we continue to be significantly underspent year-
to-date.

We have a number of pending requests for additional funding that are likely to be put on hold until
additional funds are made available. So, please inform by Tuesday, August 14th of 2012 capital
funds that are not going to be utilized.

If this request needs to be forwarded to anyone not on the distribution please feel free to do so.
Thanks

Margie Stevens
Director, Financial Planning and Analysis
Phone: [phone]
Fax: [phone]
E-mail: [e-mail]

ICNU_DR_069 Attachment A Page 49 of 58
From:Stevens, Margie
To:Stevens, Margie; Abrahamse, Bill; Bowles, Eric; Cox, Bryan; DeFelice, Dave; Evans, Heide; Gfeller, Greg; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve
Cc:Broemeling, Mike; Corder, Jim; Faulkenberry, Mike; Fisher, Al; Howard, Bruce; Rosentrater, Heather; Vickers,
Andy
Subject:RE: Results of Capital Planning Group Meeting - Please forward as needed
Date:Wednesday, February 27, 2013 10:50:18 AM
Attachments:CPG report Feb13 post meeting to group.xlsx
I am attaching a new file with updated information. Please disregard the last file as additional
entries were made after the report was created.

Correction to below:
1) For January 2013, the capital budget is under spent $5.9M excluding the variances for
electric and gas new revenue.

Margie Stevens Phone: [phone]

From: Stevens, Margie Sent: Friday, February 22, 2013 5:35 PMTo: Abrahamse, Bill; Bowles, Eric; Cox, Bryan; DeFelice, Dave; Evans, Heide; Gfeller, Greg; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, SteveCc: Broemeling, Mike; Corder, Jim; Faulkenberry, Mike; Fisher, Al; Howard, Bruce; Rosentrater, Heather; Stevens, Margie; Vickers, AndySubject: Results of Capital Planning Group Meeting - Please forward as needed

The Capital Planning Group (CPG) met on Wednesday, February 20th. Attendees included: Mike
Broemeling, Jim Corder, Mike Faulkenberry, Bruce Howard, Heather Rosentrater, Andy Vickers,
Margie Stevens and Karen Schuh (Rates Representative—not a voting member). Not present: Al
Fisher.

2) For January 2013, the capital budget is under spent $6.9M excluding the variances for
electric and gas new revenue.

3) The Finance Committee (FC) of the Board approved $10M for productivity requests at the
November 2012 meeting and to date there have been no requests for productivity funds.

4) The FC approved $2.6M of carryover for Project Compass at the February meeting. Margie
also noted that the FC acknowledged with pleasure that the 2012 capital spend was not
significantly under budget which had been the case historically.

5) The CPG discussed the challenge of funding the additional spend of $6.1M ($8.7M spend in
excess of original budget less $2.6M of carryover) for project Compass in 2013.
ICNU_DR_069 Attachment A Page 50 of 58

6) The following projects were reviewed and approved (for list of pending requests, please
see attached information):
East Medford $340,000 Completion of 2012 work
Dollar Rd Svc Ctr $1,100,000 Completion of 2012 work
Base Load Thermal $1,000,000 KF maintenance needed due to
overspend for Colstrip (jt ownership with limited flexibility)
Post Falls Intake gate $500,000 Completion of 2012 work
Total $2,940,000
With this additional spend and Project Compass, the capital budget is currently
oversubscribed $9.1M.

7) The CPG would like new requests to identify by what date approval is necessary in order to
spend the requested amount prior to year-end.

8) The CPG discussed the need for identifying reduced spend in the capital plan early in the
year. The new review report will help with this process and is now available but not fully
populated. Jeremiah will help business case owners populate the review template over
the next couple of months. To the extent that not enough reductions are identified by
mid-year, the CPG will determine which previously planned spend will need to be cut to
achieve the spending target for the capital budget.

9) Margie reviewed the SharePoint site and explained the various reports that are available
to help manage the budget.

If you do not want to be included on this distribution list please let me know.

Margie Stevens
Director, Financial Planning and Analysis
Phone: [phone]
Fax: [phone]
E-mail: [e-mail]

ICNU_DR_069 Attachment A Page 51 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Carrozzo, Steve; Cox, Bryan; DeFelice, Dave; Evans, Heide; Gfeller, Greg; Howell, David; James, Dave; Kelley, Bill; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Quincy, Diane; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Storey, Clay; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve
Cc:Broemeling, Mike; Corder, Jim; Faulkenberry, Mike; Fisher, Al; Howard, Bruce; Rosentrater, Heather; Stevens,
Margie; Vickers, Andy
Subject:Results of April Capital Planning Group Meeting -- Please forward as needed
Date:Thursday, April 18, 2013 2:04:59 PM
Attachments:CPG report apr13 meeting post meeting sent info.xlsx

The Capital Planning Group (CPG) met on Wednesday, April 17th.  Attendees included:  Mike
 Broemeling, Jim Corder, Mike Faulkenberry, Bruce Howard, Heather Rosentrater, Andy Vickers,
 Margie Stevens, Karen Schuh (Rates Representative—not a voting member), Laura Vickers (FP&A),
 Jeremiah Webster (FP&A), Eric Bowles (Facilities) and Rod Staton (Facilities).  Not present: Al
 Fisher. 

1) For March 2013 year-to-date, the capital budget is under spent $2.0M excluding the
 variances for electric and gas new revenue. The CPG acknowledged that it is highly unusual
 to have such a relatively low actual-to-budget variance given what we have historically
 experienced.   

2) The CPG will recommend approval of the following productivity request to Mark Thies:

Weed Sprayer                    $26,200                Pending Mark’s approval

3) Eric Bowles and Rod Staton talked in detail about the costs associated with the Campus
 restructuring and the HVAC system.  They have requested an additional $2.7M to continue
 with the project.

4) The following projects were reviewed and approved (for list of pending requests, please
see attached information):
Rathdrum CT HGP          $260,000                Carryover from 2012
PF Intake Gate                $200,000                Completion of the project

With this additional spend, the capital budget is currently oversubscribed $5.3M.

5) The CPG spent a significant amount of time discussing the additional requests for
funding. Since the budget is currently oversubscribed and the March spend is only
$2.0M under spent, the group has decided that they will not be able to approve any
additional funding without the release of other funds. All business case owners are
being asked to review their projects/programs and identify funds that can be released.
Directors should work with their employees to supplement this process and help
prioritize and identify potential givebacks. If released funds are not identified by the
business case owners, the CPG may be in a position to request certain cuts.

If you do not want to be included on this distribution list please let me know.
ICNU_DR_069 Attachment A Page 52 of 58

Margie Stevens
Director, Financial Planning and Analysis
Phone: [phone] 
Fax: [phone] 
E-mail: [e-mail]

ICNU_DR_069 Attachment A Page 53 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Cox, Bryan; DeFelice, Dave; Evans, Heide; Gfeller, Greg; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve
Cc:Broemeling, Mike; Corder, Jim; Faulkenberry, Mike; Fisher, Al; Howard, Bruce; Rosentrater, Heather; Stevens,
Margie; Vickers, Andy
Subject:Results of Capital Planning Group Meeting - Please forward as needed
Date:Friday, February 22, 2013 5:35:01 PM
Attachments:CPG report Feb13 post meeting.xlsx
The Capital Planning Group (CPG) met on Wednesday, February 20th. Attendees included: Mike
Broemeling, Jim Corder, Mike Faulkenberry, Bruce Howard, Heather Rosentrater, Andy Vickers,
Margie Stevens and Karen Schuh (Rates Representative—not a voting member). Not present: Al
Fisher.

1) For January 2013, the capital budget is under spent $6.9M excluding the variances for
electric and gas new revenue.

2) The Finance Committee (FC) of the Board approved $10M for productivity requests at the
November 2012 meeting and to date there have been no requests for productivity funds.

3) The FC approved $2.6M of carryover for Project Compass at the February meeting. Margie
also noted that the FC acknowledged with pleasure that the 2012 capital spend was not
significantly under budget which had been the case historically.

4) The CPG discussed the challenge of funding the additional spend of $6.1M ($8.7M spend in
excess of original budget less $2.6M of carryover) for project Compass in 2013.

5) The following projects were reviewed and approved (for list of pending requests, please
see attached information):
East Medford $340,000 Completion of 2012 work
Dollar Rd Svc Ctr $1,100,000 Completion of 2012 work
Base Load Thermal $1,000,000 KF maintenance needed due to
overspend for Colstrip (jt ownership with limited flexibility)
Post Falls Intake gate $500,000 Completion of 2012 work
Total $2,940,000
With this additional spend and Project Compass, the capital budget is currently
oversubscribed $9.1M.

6) The CPG would like new requests to identify by what date approval is necessary in order to
spend the requested amount prior to year-end.

7) The CPG discussed the need for identifying reduced spend in the capital plan early in the
year. The new review report will help with this process and is now available but not fully
populated. Jeremiah will help business case owners populate the review template over
the next couple of months. To the extent that not enough reductions are identified by
ICNU_DR_069 Attachment A Page 54 of 58
achieve the spending target for the capital budget.

8) Margie reviewed the SharePoint site and explained the various reports that are available
to help manage the budget.

If you do not want to be included on this distribution list please let me know.

Margie Stevens
Director, Financial Planning and Analysis
Phone: [phone]
Fax: [phone]
E-mail: [e-mail]

ICNU_DR_069 Attachment A Page 55 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; DeFelice, Dave; Faulkenberry, Mike; Howell, David; James, Dave; Kinney, Scott J; Lee, Julie; Magruder, Mike; Nitteberg, Kathy; Rosentrater, Heather; Schlothauer, Chris; Schuh, Karen; Thorson, Neil; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Wenke, Steve; Proctor, Jeannette
Subject:Results of CPG Meeting - Please forward as needed
Date:Tuesday, November 27, 2012 8:50:00 AM

The Capital Planning Group met on Wednesday, November 21st.  Attendees included:  Jim Corder,
 Al Fisher, Bruce Howard, Heather Rosentrater, Rick Vermeers, and Margie Stevens.  Not present:
 Tim Carlberg and John Schwendener. 

1) The following items were reviewed and approved:
Mini Excavator Post St. Network                                            $75,000
Clinic Equipment (acceleration from 2013)                           46,000                   
Total approved                                                                            $121,000

2) YTD through October, we are under spent $29.7M from budget (excluding Smart Grid, New
 Revenue, Compass).  The CPG expects that there will be a fairly large amount of spend
 prior to the end of the year, especially in December due to accruals and expedited invoices.
 After some adjustments brought forward at the meeting and the above approvals, the
 expected spend is currently $254.9M or a $0.9M overspend of the $250M budget plus
 $4.0M in carryover for Next Gen Radio (excluding any spend for Nine Mile).

3)  There was some discussion about Nine Mile and the amount of spend that can be
 absorbed in 2012 which will impact the contract that is being finalized the week of Nov
 26th.  A final decision will be made after further discussion with Mark Thies.

4) There was discussion about how to involve the VPs sooner in the process than the final
 recommendation for the following year’s 5 year Plan. 

Margie Stevens
Director, Financial Planning and Analysis
Phone: [phone] 
Fax: [phone] 
E-mail: [e-mail]

ICNU_DR_069 Attachment A Page 56 of 58
From:Stevens, Margie
To:Abrahamse, Bill; Bowles, Eric; Carrozzo, Steve; Cox, Bryan; DeFelice, Dave; Evans, Heide; Gfeller, Greg; Howell, David; James, Dave; Kensok, Jim; Kinney, Scott J; Kopczynski, Don; Krogh, Cody; Lee, Julie; Magruder, Mike; Marlowe, Andrea; Myers, Stephanie; Pike, Andrea; Schlothauer, Chris; Schuh, Karen; Smith, Graham; Thackston, Jason; Thorson, Neil; Vermillion, Dennis; Vickers, Laura; Waples, Scott; Webb, Jeff; Weber, Vicki; Webster, Jeremiah; Wenke, Steve
Cc:Broemeling, Mike; Corder, Jim; Faulkenberry, Mike; Fisher, Al; Howard, Bruce; Rosentrater, Heather; Stevens,
Margie; Vickers, Andy
Subject:Results of March Capital Planning Group Meeting -- Please forward as needed
Date:Thursday, March 28, 2013 4:48:30 PM
Attachments:CPG report mar13 meeting info to group post meeting.xlsx
The Capital Planning Group (CPG) met on Wednesday, March 20th. Attendees included: Mike
Broemeling, Jim Corder, Bruce Howard, Heather Rosentrater, Andy Vickers, Margie Stevens, Karen
Schuh (Rates Representative—not a voting member) and Greg Loew (ALP). Not present: Mike
Faulkenberry and Al Fisher.

1) For February 2013 year-to-date, the capital budget is under spent $5.2M excluding the
variances for electric and gas new revenue.

2) The CPG discussed what level of materiality should be used for managing the over/under
spend of individual capital projects. Heather will work more with the T&D group over the
next month and report her findings at the next CPG meeting in April. Based on this
information the CPG will continue to evaluate the issue.

3) The CPG discussed whether the original budget or the expected spend should be used for
calculating earned value. The group decided that the original budget (spread can be
adjusted by month but the total by year should match the budget) should be used unless
re-baselining is approved by the CPG.

4) Margie recommended a cut-off date of the Friday before the meeting for all new spending
requests and review templates in order to give the CPG time to review the information
prior to the Wednesday meeting. The CPG agreed and Margie will send out a notice to
impacted individuals.

5) The following projects were reviewed and approved (for list of pending requests, please
see attached information):
Clearwater Sub $700,000 Required for a large customer

With this additional spend, the capital budget is currently oversubscribed $7.9M however,
there is an expectation of funds being released from Jackson Prairie Storage and the HVAC
project (follow-up will occur prior to the next meeting).

If you do not want to be included on this distribution list please let me know.

ICNU_DR_069 Attachment A Page 57 of 58
Margie Stevens
Director, Financial Planning and Analysis
Phone: [phone]
Fax: [phone]
E-mail: [e-mail]

ICNU_DR_069 Attachment A Page 58 of 58

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 069 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 5:9-11. Please provide, from 2006 to the present: a) all minutes from CPG meetings; and
b) a chart, graph, spreadsheet, or other form of presentation illustrating the amount of capital spending approved by the CPG each month.

RESPONSE:
Responses to the request are for 2012 to the present since the CPG originated in 2012.
a) Please see ICNU_DR_069 Attachment A
b) Please see ICNU_DR_069 Attachment B
c) Please see ICNU_DR_069 Attachment C

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 3/5/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 70 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 6:4-18, and 29:17-19. Are all of the “Planned Expenditures” listed in Table No. 1 the
original forecasted capital budgets for each year listed, as approved by the Board of Directors, and similar to the 2017 forecast originally approved in 2014? If no, please explain and provide the original forecasted
budgets.
RESPONSE:

Each year the Company prepares a five year budget. The Finance Committee of the Board approves the
upcoming year’s budget in the preceding November and reviews and approves the five year budget. The
amounts listed in Table No. 1 represent the original forecasted capital budgets as approved by the Finance
Committee of the Board each preceding November. There are small variances between the approved
amount and the amounts listed in Table 1, due to timing of the requested information, carryovers from previous years, etc.

The table on page 29 relates to 2017 transfers to plant. The 2017 transfers to plant relate to the 2017
capital expenditures included in the 2014 five year capital budget approved by the Finance Committee of
the Board.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 71 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 8:5-9:19. Does the Company agree that, throughout Avista’s 125-year history, the cost of
replacement equipment and facilities has always been more expensive than the same facilities installed in the past? If no, please provide explanation and support.
RESPONSE:

While the Company has not compared the cost change for every year to determine whether it has always been the case, in general terms the Company agrees that the cost today is higher than the cost in prior
years.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 072 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 27:1-11. Did the Company consider any studies comparing the customer benefits of: a)
continuing to use Washington standard meters, including the current $20.2 million book value of existing meters and 29-year estimate life expectancy; to b) replacing these existing meters with Advanced Meter
Infrastructure (“AMI”) meters having an estimated life expectancy of 15 years? If yes, please provide all
such studies.

RESPONSE: Yes, it did. Please see the Company’s response to ICNU_DR_075.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 073 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to Exhibit No.__(KKS-5). Please explain the difference between an “Owner” and “Sponsor”
listed on Business Case forms, including the qualifications, responsibilities, and duties of each position.
RESPONSE:
Typically the sponsor is the executive officer or vice president of the functional area that requested the
capital funding. And typically the owner is the internal director of the functional area that requested the capital funding. The specific qualifications, responsibilities and duties are in alignment with their specific
role in the Company as an officer, director or manager.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Don Kopczynski
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 074 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST: Please refer to 15:2-3. Please confirm that the 21-year life of the AMI project does not
represent the actual expected life of the AMI meters. If no, please explain.

RESPONSE: The assumed life of the AMI meters is 15 years for each annual vintage (the group installed in each year
of the project). The project life is 21 years since equipment will be installed over a five year period in
order to achieve full deployment in the Company’s Washington service territory. Also, the economic models assume a ½ year convention for depreciation calculations, so a 15-year lived project actually
extends over 16 years since year 1 and year 16 are a “half-year” for depreciation modeling purposes.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Don Kopczynski
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 075 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 15:8-9. Does the current net benefit estimate of $7.5 million over the life of the AMI
project account for the difference between the shorter estimated AMI meter life and the longer estimated Washington standard meter life? If yes, please identify how this difference was accounted for in Mr.
Kopczynki’s testimony, exhibits, or workpapers. If no, please recalculate estimate benefits/costs based on
the shorter AMI meter life.

RESPONSE: Yes, it does. The estimated lifetime net benefits of $7.5 million represents the value of the quantifiable
benefits and preliminary costs associated with the advanced metering project, when compared against the
‘base case’ of continuing to use the conventional electro-mechanical meters already in place. The analysis
takes into account the cost of retiring the conventional meters, as well as the shorter expected life of the
new digital meters. The analysis is provided in the financial model contained in the workpapers of Company Witness Mr. Kopczynski, titled “AMI Cost and Benefit Analysis,” under the tab titled “AMI
Financials.”

Page 1 of 4
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/15/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Don Kopczynski/Tara Knox
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 076 Supplemental TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to Exhibit No.__(DFK-5), page 23. Please provide Avista’s proposed: a) digital meter
installation schedule, according to rate schedule; and b) allocation of digital meter installation costs, per year, according to rate schedule.
RESPONSE:

The Company’s preliminary estimate of the expected capital costs associated with the Washington advanced metering project, by year, is provided in Exhibit No._(DFK-1T), Illustration No. 5, page 14.
The costs for the metering project will be allocated to each rate schedule based on the metering that is
ultimately installed for customers served under that rate schedule. The Company anticipates at this time
that the costs for the metering project will be principally applied to rate schedules other than schedule
025. This is the case because we expect that many of the industrial customers we serve will continue to be metered under the Company’s existing MV-90 program. The basis for the allocation of metering costs
among rate schedules is provided in Exhibit No._(TLK-2), page 5, lines 6-8, and in the related work
papers TLK-E-135-137.

SUPPLEMENTAL RESPONSE:
In the Company’s previous response, we referred to the initial preliminary capital estimate developed and
approved for the advanced metering project in late 2014, as presented in Exhibits No._(DFK-1T and
DFK-5). Avista has noted that its initial preliminary estimate would be revised through the course of implementation as new information is developed in support of the project, most notably, when we have
firm costs from vendors for various solutions. Though the Company has no firm pricing at this point, and
will not have firm prices for most of the required solutions until the end of 2015, and into early 2016, we
have made revisions to the initial preliminary capital and O&M estimates based on the best information
available to the Company at this time.
Capital Revisions
The table, below, presents the initial preliminary project capital cost categories, as described in Exhibit
No._(DFK-5), pages 20-23. The costs in the table show the initial preliminary budget as presented in Exhibit No._(DFK-5), and the costs reflecting the most-recent revisions, referenced above.

Page 2 of 4
Description July 2015 Revision Initial Budget
Electric Meters $ 35,829,062.40 $ 33,830,016.00
Electric Meter Labor - in house $ 9,054,202.59 $ 3,389,938.72
Electric Meter Labor - contract $ 7,464,774.25 $ 6,815,950.03
Gas Modules $ 8,942,246.42 $ 8,443,322.80
Gas Module Labor - contract $ 5,555,646.75 $ 4,261,977.50
Head End Hardware $ 4,922,650.48 $ 4,922,650.48
Head End Software $ 5,140,000.00 $ 859,650.00
Head End Labor - Internal $ 21,592,959.72 $ 9,075,925.85
Network Communications - Hardware $ 30,105,294.83 $ 26,152,769.50
Network Communications - Software $ 3,522,185.00 $ 3,015,100.00
Network Communications - Labor $ 19,938,151.52 $ 29,268,731.80
Customer Communications $ 4,500,000.00 $ 5,500,000.00
AFUDC $ 7,361,195.68 $ 6,591,694.62
Additional Project Costs (Spread Across All
Units) $ 1,624,231.37
Totals $ 165,552,601.00 $ 142,127,727.31
An additional change to the revised estimated capital costs, which is embedded in the revised cost
categories shown above, and in the project total of $165.6 million, is an increase in the financial
contingency for the project, in the amount of $5.8 million. A brief explanation of the reasons for the
changes in each capital cost category, is provided below.
Electric Meters – Increase in the equipment loading charges applied to the meters.

Electric Meter Labor / Avista – Upward revision of the estimate of the internal labor resources
required to install the advanced meters. Electric Meter Labor / Contract – Increase in the initial estimate of the contract labor resources
required for meter installation.
Gas Modules – Increase in the equipment costs associated with the natural gas modules.
Gas Module Labor / Contract – Increase in the initial estimate of the contract labor resources
required to install the natural gas modules. Head-End Software – Increase in the initial estimate for the meter data management system based
on more refined technical specifications, and recent discussions with potential vendors.
Head-End Labor / Avista – Increase in the initial estimate of labor resources, and a transfer of
labor from other areas, needed to install and integrate the meter data management system.
Network Communication Hardware – Increase in the initial estimate of the contract labor resources required for network installation.
Network Communication Software – Increase in the initial estimate of the network software costs.
Network Communication Labor – Reduction, representing a shift in the initial estimate of labor
resources to other elements of the project, such as Head-End Labor, above.
Customer Communications – Reduction in the initial estimate of the costs for customer communications required to support the project.
AFUDC – Increase reflecting the greater capital costs associated with the project.

Additional Project Costs – Recognition of additional costs associated with implementation of the
advanced metering system.

Page 3 of 4

In addition to changes in project costs by category, Avista also revised the initial preliminary
forecast of annual capital spending during each year of implementation. The illustration, below, shows the initial forecast of annual capital expenditures for the Washington advanced metering
project, as provided in Exhibit_No. (DFK-1T), page 14, and the most-recent revisions of the
forecast, as described above.

To determine the overall cost impact associated with these capital additions, Avista revised its initial
project financial model, provided in the workpapers of Company witness Mr. Kopczynski, under the tab
labeled “AMI Financials.” The revised model is provided as ICNU_DR_076 Supplemental Attachment A. As shown in the model in column “T,” lines 28 through 48, the overall cost impact related to the increase in estimated capital costs, measured as the change in the net present value of the overall project revenue
requirement, is $24.9 million, or approximately 10.9 percent.

Operations & Maintenance Costs The Company’s initial preliminary estimate of the annual O&M costs required to support the fully-
deployed project was $5,191,063, which was escalated at two percent annually over the life of the project.
Avista has made two revisions to this initial preliminary forecast. The estimate of the required O&M costs
has been increased from $5.19 million, above, to $5,400,023, which is also subject to the two percent annual adjustment. The second adjustment involves “phasing in” the full O&M costs over the period of the deployment of the advanced metering system. In its initial financial model, noted above, the Company
inadvertently applied the O&M costs, associated with the fully deployed advanced metering system, to
each year of the implementation of the project, resulting in an overestimate of the lifecycle operating costs
for the system. The net effect of these two O&M adjustments is a $20.8 million reduction (or approximately 9.1 percent) in the overall net present value of the revenue requirement associated with the advanced metering system. These two changes to the Company’s initial financial model are shown in
ICNU_DR_076 Supplemental Attachment B, in the “AMI Financials” tab, under column “N,” lines 28
through 48.

Page 4 of 4
Net Effect of Capital and O&M Revisions

The overall cost impact of these revisions in estimated capital and O&M costs, as described above, is an increase of $4.1 million in the overall net present value of the revenue requirement for the project, or 1.8
percent. Revisions to the Company’s initial financial model, reflecting the changes described above in the
estimated capital and O&M costs, are provided in ICNU_DR_076 Supplemental Attachment C, under the
“AMI Financials” tab. The Company is also continuing to refine its preliminary estimate of offsetting
quantifiable benefits. It is anticipated that those estimated benefits will increase.
In addition to the advanced metering project costs noted above, Avista is also in the process of developing
a business case for a network communications system that would support a variety of utility functions.
Some of these functions include distribution grid modernization and operation, SCADA telemetry to all
substations, physical and infrastructure security, field mobility workforce solutions, replace leased fiber and telecommunications facilities, and support of advanced metering in Washington, and subsequently in
Idaho. The Company believes the value associated with this network communications system will support
its development, likely irrespective of the benefits provided to advanced metering. However, because the
network communications project will have an association with the advanced metering system now being
deployed by the Company, we will evaluate the costs and benefits of each project in parallel to ensure the costs and benefits of the communications network are properly allocated. Avista is presently engaged in
the process of identifying use cases to be evaluated as part of the communications network project, and
subsequently, will be preparing a Capital Project Business Case for the program.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Don Kopczynski/Tara Knox
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 076 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST: Please refer to Exhibit No.__(DFK-5), page 23. Please provide Avista’s proposed: a)
digital meter installation schedule, according to rate schedule; and b) allocation of digital meter
installation costs, per year, according to rate schedule.
RESPONSE:
The Company’s preliminary estimate of the expected capital costs associated with the Washington
advanced metering project, by year, is provided in Exhibit No._(DFK-1T), Illustration No. 5, page 14. The costs for the metering project will be allocated to each rate schedule based on the metering that is
ultimately installed for customers served under that rate schedule. The Company anticipates at this time
that the costs for the metering project will be principally applied to rate schedules other than schedule
025. This is the case because we expect that many of the industrial customers we serve will continue to be
metered under the Company’s existing MV-90 program. The basis for the allocation of metering costs among rate schedules is provided in Exhibit No._(TLK-2), page 5, lines 6-8, and in the related work
papers TLK-E-135-137.

ICNU_DR_077 Attachment A Page 1 of 10
ICNU_DR_077 Attachment A Page 2 of 10
ICNU_DR_077 Attachment A Page 3 of 10
ICNU_DR_077 Attachment A Page 4 of 10
ICNU_DR_077 Attachment A Page 5 of 10
ICNU_DR_077 Attachment A Page 6 of 10
ICNU_DR_077 Attachment A Page 7 of 10
ICNU_DR_077 Attachment A Page 8 of 10
ICNU_DR_077 Attachment A Page 9 of 10
ICNU_DR_077 Attachment A Page 10 of 10

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Jennifer S. Smith
REQUESTER: ICNU RESPONDER: Jennifer S. Smith
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 077 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 18:1-3. Please provide all Director responses indicating time dedicated to utility and non-utility matters.
RESPONSE:

Please see ICNU_DR_077 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Smith/Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 078 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exhibit No.__(JSS-2) at 10, n.2. Please explain why reconciled Attrition Adjusted Total values more readily lend themselves to Ms. Knox’s cost of service analysis.

RESPONSE:

The cost of service study is performed at the FERC account level of detail. Ms Smith’s study workpapers
include specific account-by-account detail that allows for the account-by-account assignment of costs to rate
classes included in the cost of service study.

ICNU_DR_079 Attachment A Page 1 of 6
ICNU_DR_079 Attachment A Page 2 of 6
ICNU_DR_079 Attachment A Page 3 of 6
ICNU_DR_079 Attachment A Page 4 of 6
ICNU_DR_079 Attachment A Page 5 of 6
ICNU_DR_079 Attachment A Page 6 of 6

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 079 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 10:11-14. Does the Company have any basis for following the peak credit classification methodology, other than Ms. Knox’s reference to Docket No. UE-920499? If yes, please provide: a) all
studies considered by the Company in the preparation of this rate case which analyze (or that advocate
for/against) different classification methodologies; and b) a narrative response explaining the Company’s
policy and/or position on using different classification methodologies.
RESPONSE:
Please see ICNU_DR_079 Attachment A which is an excerpt from consulting economist Jim Lazar’s “Cost
of Service Analysis For the Electric and Natural Gas Industries” which discusses the history of the application of “peak credit” classification theory in electric cost of service studies before the Washington
Utilities and Transportation Commission. Subsequent to that history, Avista filed a cost of service study for
WUTC Docket No. UE-991606 with the Avista-specific peak credit methodology, which was found
acceptable by the Commission in that case. The Company has continued to provide analysis using this
methodology in all subsequent Washington cases either as the cost of service study exhibit or for comparison purposes as the “Prior Method”. As stated in my testimony, the load factor based peak credit methodology
filed in this case is a modification to the Avista-specific peak credit methodology that produces very similar
results.

The Company position regarding changes to its cost of service methodology is to generally maintain consistency over time. Improvements may be proposed, if supportable and necessary, but should always be
given careful consideration of the implications resulting from any change in methodology.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 080 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 10:11-14. Please confirm that, in approving the peak credit methodology for Puget in Docket No. UE-920499, the Commission did not accept the designation of the peak credit methodology to
be used as the standard in future proceedings (see 9th Suppl. Order at 8, n.5). If Avista cannot confirm,
please explain.

RESPONSE:
Footnote 5 on page 8 of the Ninth Supplemental Order from WUTC Docket No. UE-920499 states that the
Commission declined the “invitation to designate Puget’s model” as a standard for all companies.
Consequently, Avista in UE-991606 did not use Puget’s method for determining the peak credit, but instead presented the Avista-specific peak credit methodology that the Company had employed for filings during the 1980’s, which the Commission found acceptable.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 081 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 10:14-16. Please provide a narrative response explaining the Company’s policy and/or position as to the definitions of “peaks” and “peak credit” specific to Avista, as accepted by the
Commission.

RESPONSE:
The testimony referred to in this request beginning on line 11 reads as follows:

“the cost study follows the methodology established in Docket No. UE-920499 for Puget Sound Power and Light (now Puget Sound Energy). Production and transmission costs are classified into energy-related or demand-related by a peak credit analysis. The definitions of “peaks” and “peak credit”
specific to Avista were accepted by the Commission for Avista in Docket No. UE-991606 and confirmed
in Docket No. UE-050482.”

In this context, the purpose of the statement is to identify where the Company’s methodology in UE-991606 differed from the methodology in the Puget cost of service case UE-920499. The Company’s definitions are
as follows:
1 – Peak definition: In Docket No. UE-991606, Avista used the average of the twelve monthly
system coincident peaks to allocate demand-related production and transmission costs, instead of adopting
Puget’s highest 200 system peak hours for the same purpose. 2 – Avista-specific peak credit: In Docket No. UE-991606, Avista’s peak credit theory for
production and transmission costs was applied in essentially the same manner as the Company’s last case,
comparing replacement cost per kW for Avista’s various production plant types, rather than adopting the
one-half combustion turbine at 200 hours of operation unique to Puget’s system.
The Company continues to utilize the average of the twelve monthly system coincident peaks to allocate
demand-related production and transmission costs and the Avista-specific peak credit calculation is provided
in electronic work papers in this case as the “Prior Method” cost of service model run. Printouts of the
exhibit summaries from this model run are included in my hard copy work papers TLK-E_175 though TLK-
E-178 and a comparison of key elements of the Prior versus the Proposed study results as work paper TLK-E-183. The Company’s proposed load factor based peak credit methodology is also an Avista-specific peak
credit calculation as outlined in my testimony.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 082 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 11:15-17. Does the Company have any basis for applying the peak credit ratio to transmission costs, other than Ms. Knox’s testimony that “transmission costs have traditionally been
treated as an extension of the generation system” in Washington? If yes, please provide all studies
considered by the Company in the preparation of this rate case which provide support for the Company’s
application of the peak credit ratio to transmission costs.
RESPONSE:
Please see the response to ICNU_DR_079 and ICNU_DR_079 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 083 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 11:20-12:1. Has the Company considered using a 100% demand allocation of production capacity costs? If yes, does the Company consider it more simple and straightforward to calculate the
demand-related proportion of production costs using: a) a 100% demand allocation; or b) the system load
factor approach?

RESPONSE:
In the Company’s cost of service study 100% of production capacity costs are allocated by the average of the
12 monthly system coincident peaks which is a demand allocation. However, this request apparently refers
to the classification of total production functional costs into capacity-related (production capacity costs) versus energy-related (production energy costs). No, to my knowledge the Company has never considered
classifying all production costs as capacity-related. Even if the Company were to consider a straight fixed-
variable methodology to classify production costs, there would still be energy-related production costs that
would require identification.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 084 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 12:13-19. Please confirm that the Company considers it fair to shift costs toward the low load factor residential class, based upon an increase in overall production and transmission costs classified
as demand-related. If Avista cannot confirm, please explain why the Company has made the proposed
change described by Ms. Knox.

RESPONSE:
The Company believes that the methodologies used in the filed cost of service study appropriately assign
cost to the rate classes.
As shown on workpaper TLK-E-183, the negligible increase of $199,000 in overall costs assigned to the
residential class, which represents only 0.09% of present revenue, was associated with using the load factor
method vs. the replacement cost method. This is not considered a material shift, especially given the revenue
requirement to reach unity for the residential class is $46 million.
In Docket No. UE-140188, the difference between the two methods resulted in costs being shifted away from
residential customers, and in Docket No. UE-120436, like in this case, costs shifted toward the residential
class. In both cases the cost assignment differences were negligible.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 085 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exhibit No.__(TLK-2) at 3:10-11. Please reconcile the statement that “the transmission system is built not only for peak use, but also for everyday delivery of energy” with the testimony of Mr.
Ehrbar (Exhibit No.__(PDE-1T) at 12:7-8), that “the Company’s transmission … system is constructed to
meet the collective peak demand of its customers.”

RESPONSE:
Mr. Ehrbar is looking at it from an incremental perspective, where construction planning criteria is peak
driven. The embedded cost of service is assigning the cost of the entire system and considers the dual
purpose of the transmission system to provide energy every day, including at peak times.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 086 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exhibit No.__(TLK-2) at 3:19-22. Has the Company considered using a 4 CP allocation (or anything less than its 12 CP allocation) for either production or transmission demand-related costs,
given the statement by Ms. Knox that Avista experiences peaks in the winter and summer? If yes, please
provide all studies considered by the Company. If no, please provide a narrative response explaining the
Company’s policy and/or position on using a 12 CP despite acknowledging that existence of peaks in only
certain seasons. RESPONSE:

Although it is aware that there are other approaches to demand-related cost allocation, the Company prefers the 12 CP allocation for production and transmission demand-related costs. While higher in winter and
summer, peaks occur in every month and costs vary throughout the year. The twelve month average of the
system peaks is a relatively stable allocator from year to year, and is consistent with the fact that customers
are billed based on their monthly demand rather than an annual or seasonal determination. See also the
Company’s response to ICNU_DR_087.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 087 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exhibit No.__(TLK-2) at 3:21-22. Does the Company agree that use of a 4 CP allocation for production or transmission demand-related costs also “recognizes that customer capacity needs are not
limited to the heating season”?

RESPONSE:
The Company does not agree because a 4 CP allocation factor excludes 8 months of the year. As stated in
my testimony “careful management of capacity requirements is required throughout the year” (Exhibit
No.__(TLK-2) at 3:20-21).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/2/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 088 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

The following questions are directed to the testimony of Patrick D. Ehrbar:
Please refer to 3, n.1. Please recalculate Table 1, including the effect of the expiration of the ERM
rebate.
RESPONSE:

Proposed % Electric Increase by Schedule
Increase in Increase in
Billing Rates Billing Rates
Rate Schedule (As Filed)(With ERM Expiration)
Overall 6.7%8.3%
IC
N
U
_
D
R
_
0
8
9

A
t
t
a
c
h
m
e
n
t

A

Pa
g
e

1

o
f

1

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 089 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 11:1-3. Please quantify, on a Washington electric basis using comparative percentages and dollar amounts, the following assertions made by Mr. Ehrbar: a) the “substantial portion” of fixed
Company costs that do not vary with the amount of energy used by customers; and b) the “increasing”
fixed costs of operating and maintaining Avista’s electric system.

RESPONSE:

Provided as ICNU_DR_089 Attachment A is the final approved revenue, by rate schedule, used in the
Company’s current electric decoupling mechanism. On line 3, “Total Rate Revenue” is $503,128,000.
Of that amount, as shown on line 6, $119,941,115 or 24% is related to variable power supply as determined using the current retail revenue credit. By this measure, approximately 76% of the
Company’s costs do not vary with the amount of energy used by customers..

As it relates to the increasing fixed costs of operating and maintaining Avista’s electric system,
Company witness Ms. Andrews states at p. 4 of her direct testimony that costs are increasing due to the “continuing need to replace and upgrade facilities and technology we use every day to serve our
customers”. These costs, for example, are fixed costs that do not vary with customer usage but which
are necessary in order to provide safe and reliable service.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 090 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 12:5-6, regarding Mr. Ehrbar’s testimony concerning: a) the debatable classification of demand-related costs; and b) the continuation of demand charges at levels well below demand-related
costs. In light of this testimony, please provide a narrative response explaining why the Company
continues to use a peak credit allocation methodology which classifies costs mostly on an energy basis,
and only in small part on a demand basis.
RESPONSE:
This statement refers to the fact that the demand charges in the proposed rate design are well below the
demand-related costs in the cost of service study. The Company has consistently presented electric cost of service analysis utilizing a peak credit approach to classification of production and transmission costs since
the 1980’s. Please see the Company’s responses to ICNU_DR_079.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 091 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 12:7-8. In stating that Avista’s transmission system is constructed to meet the collective peak demand of its customers, does the Company agree that energy usage is not a causal component for
such construction? If no, please explain.

RESPONSE:
While the construction planning criteria is driven by the peak demand of its customers, its use is to transmit
energy to the Company’s distribution system. Therefore, energy usage is also a causal component for such
construction.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 092 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 12:9-12. Would the Company agree that higher demand charges will send a better price signal to customers to reduce peak demand, as opposed to higher energy charges? If no, please
explain why the Company is proposing higher demand charges to send a “proper price signal” to
customers to reduce peak demand.

RESPONSE:
Yes, the Company agrees that higher demand charges would send a better price signal. Ideally, as
stated on p. 29 ll. 17-18 of Mr. Ehrbar’s direct testimony, all demand-related costs should be recovered
in demand charges. In an effort to move towards that goal, the Company requested to increase
variable demand charges in this case by 8.3 percent.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 093 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 24:21-23. Please provide a list of all cost categories which the Company includes within the portion of Avista costs that “are fixed and do not vary with customer usage,” in addition to
the categories of distribution plant and operating costs listed.
RESPONSE:

With the exception of certain power supply costs (fuel, variable O&M, etc.), all of the costs related to generation, transmission, distribution, and other common costs, are generally fixed in nature, as they
do not vary with customer usage.

In the current electric decoupling mechanism, the variable power supply costs are determined using
the retail revenue credit. As described by Company witness Mr. Johnson, the Company has proposed a change to both the name of the retail revenue credit (proposed to be Load Change Adjustment Rate,
or LCAR), as well as the derivation of the LCAR (from the variable power supply components tracked
in the Energy Recovery Mechanism to the average wholesale market price of energy). For purposes of
decoupling, the costs that are excluded from the mechanism using the LCAR are fixed costs.
Please also see the Company’s response to ICNU data request 089.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 094 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 25:6-7. Please provide: a) a narrative response explaining the Company’s policy and/or position as to the “reasonable level” of fixed customer costs that the Company believes it is
appropriate to recover from customers; and b) all studies considered by the Company in support of this
portion of Mr. Ehrbar’s testimony.

RESPONSE:
As it relates to the fixed costs that are recovered in variable energy rates, while these fixed costs are
for the most part tracked through the decoupling mechanisms, the Company still believes that as long
as a portion of the Company’s fixed costs are recovered in volumetric rates, ultimately some
customers are being subsidized by other customers. The Company believes that its rate designs should be moved towards being more cost-based, i.e., variable costs are recovered in variable rates, demand
costs are recovered in demand charges, and fixed costs are recovered in basic charges. This is why the
Company proposed to increase the electric residential basic charge to $14 per month. The Company
has relied on its cost of service studies in support of this position.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 095 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 25:10-12. In considering residential rate increases, please provide a narrative response explaining the Company’s policy and/or position as to the comparative weight to: a)
customer understanding and acceptance of higher rates; and b) customer charges that more
accurately reflect the actual costs to serve customers.

RESPONSE:
Although the Company has not determined or assigned specific comparative weight to these two
issues, Avista believes both are important. Rates should be designed in such a manner that closely
reflects the cost to serve customers. As discussed on p. 25 of Mr. Ehrbar’s direct testimony, we
believe that customers understand that most of the costs associated with other utility-type services, such as cable, phone, water, sewer, etc., are fixed in nature, and therefore understand why these
services have a pricing structure that consists of a higher fixed charge and smaller variable rate.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 096 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 25:14-17. Please confirm whether the Company believes that most of the costs associated with Avista electric service in Washington are fixed. If no, please explain why Mr. Ehrbar
explains the Company’s proposed residential rate increase by reference to “other utilities/services” and
customers’ understanding of the fixed costs associated with these other utilities/services.

RESPONSE:
As discussed in Mr. Ehrbar’s direct testimony on page 11, lines 1-3, the Company believes that a
substantial portion of the Company’s costs do not vary with customer usage, and are therefore fixed in
nature, and that more of the Company’s costs should be recovered in fixed charges.
Please also see the Company’s response to ICNU_DR_089.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 097 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 26:17. Please explain what is meant by “even though their customer costs are not higher in the winter summer.” (Emphasis added).
RESPONSE:
The word “summer” was inadvertently included in that section of testimony. The testimony should
read “It results in almost all customers paying more “per-customer” related costs in the winter, even though their customer costs are not higher in the winter.”

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 098 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 26:9-17. As a result of the residential Basic Charge being priced below cost, please confirm that Schedule 25 customers pay higher “per-customer” related costs in winter, even though
Schedule 25 customer costs are not higher in winter. If Avista cannot confirm, please explain how Mr.
Ehrbar’s testimony should be understood for purposes of application to Schedule 25.

RESPONSE:
The testimony on page 26, lines 9-17 is directed primarily at electric and natural gas pricing for
residential customers.

The residential basic charge is one of the rate design components used to recover the revenue spread to residential customers. The level of the residential basic charge is independent from the per-customer
related costs recovered from Schedule 25 customers.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 099 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 26:11. Does the Company also consider rate spread a “zero sum game,” as with rate design? If no, please explain Mr. Ehrbar’s testimony at 26:16-17, stating that “almost all customers”
pay higher costs as a consequence of a Basic Charge that is priced below cost.

RESPONSE:
Yes, the Company would consider rate spread a zero sum game. The revenue requirement approved
by the Commission is allocated in some manner to the various rate schedules for recovery. If some
portion of the revenue requirement is not allocated to one schedule, it would by necessity be
allocated to other schedules.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 100 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 26:22-27:3. In referencing “the fixed costs of providing service” and “a utility’s facilities,” does the Company include production fixed costs (i.e., production plant investment) within the meaning
of those terms? If no, please explain.

RESPONSE:
Yes. Please see the Company’s response to ICNU_DR_093.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 101 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 27:4-6. Please provide a narrative response explaining the Company’s policy and/or position as to what constitutes a rate amount that is “substantially less” than an amount that covers
annual customer costs.
RESPONSE:

Page 27:4-6 refers to the basic charge for residential Schedules 1 and 101. As stated on pp. 25 and 26 of Mr. Ehrbar’s direct testimony, total customer allocated costs for Schedule 1 is $14.73 per month
and for Schedule 101 is $27.07 per month. The current basic charge for Schedule 1 is $8.50, and
$9.00 for Schedule 101. The basic charge for Schedule 1 is only 58% of what the Company’s cost of
service study shows it should be, and the basic charge for Schedule 101 is 33% of what it should be.
The Company considers those basic charge rates to be substantially less than what they should be.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 102 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 29:19-30:2. Does the Company agree that customers’ ability “to see and pay for the true cost of their utility service” requires payment of demand costs which “include costs associated with the
generation facilities”? If no, please explain.

RESPONSE:
Ideally customer charges, demand charges and energy charges would be designed to recover related
costs. Demand-related costs would include a portion of generation facility costs.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 103 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 31:18-19. To the extent that fixed production costs are being recovered on a variable energy basis under a peak credit classification methodology, does the Company agree that, on an inter-
schedule basis, “customers with higher use are subsidizing lower use customers”? If not, please explain
why “the problem of intra-schedule cross subsidization” (see 29:6) cannot also apply across rate
schedules, based on the same causation principle identified by the Company.
RESPONSE:
The assertion in this request is that the Company’s peak credit methodology does not adequately classify
production costs into energy or demand components. The Company believes that its peak credit methodology using the system load factor (the relationship of peak use to average use) is valid and
adequately classifies costs. The results from using this methodology are further supported by the Company’s
“prior” peak credit methodology which had very similar results. As such, the Company does not agree that,
on an inter-schedule basis, customers with higher use are subsidizing lower use customers.

Page 25
Figure 9 – Residential (WA) Winter vs. Summer

Figure 10 presents a summary of the achieved relative precision6 associated with the Residential
(WA) class analysis. The figure presents the percentage of time the achieved precision was at or
below the specific level. For example, 65% of all hours are at or below a precision of ±10.4%.
The majority of hours (i.e., 95% of all hours) were at or below ±12.6%.
6 Statistical precision is a measure of how much customer-to-customer variation there is in the data and is used to construct
boundaries around our estimates. In load research applications we typically target precision levels of ±10% for the majority of
hours in the analysis period.
ICNU_DR_104 ATTACHMENT A Page 1 of 2

Page 26

Figure 10 – Residential (WA) Achieved Relative Precision

Table 14 presents summary statistics for the Residential (WA) class load after applying losses
and reconciliation to the system load. The table displays class totals and includes the monthly
energy use, the timing of the class peak demand, the magnitude of the class peak demand, the
average demand, the load factor based on the class peak demand, the timing of the system peak
demand, the class demand at the time of system peak (i.e., coincident), and the coincidence
factor calculated as the coincident peak divided by the class peak.
Monthly load factors ranged from a low of 50% in September to a high of 73% in January. The
Residential (WA) class load is very coincident with the system peak displaying a system peak
coincidence factor of over 80% for all 12 months.
Table 14 – Residential (WA) Summary Statistics (Totals – MW)

Cumulative Distribution
Percent of Time Value is Below
0 %20 %40 %60 %80 %100 %
%
0.1
0.2
Month
Monthly
Energy
Use
(MWh)Class Peak Date
Class
Peak
Time
Class
Peak
Demand
(MW)
Average
Demand
(MW)
Load
Factor
(%)System Peak Date
System
Peak
Time
Class
Demand
@ System
Peak
(MW)
Coin-
cidence
Factor
(%)
Jul-13 224,439 Tuesday, July 02, 2013 7:00 PM 546 302 55%Tuesday, July 02, 2013 5:00 PM 498 91%
Aug-13 206,248 Sunday, August 11, 2013 7:00 PM 497 277 56%Wednesday, August 14, 2013 4:00 PM 440 89%
Sep-13 171,965 Sunday, September 15, 2013 6:00 PM 474 239 50%Thursday, September 12, 2013 5:00 PM 417 88%
Oct-13 194,630 Monday, October 28, 2013 7:00 PM 402 262 65%Wednesday, October 30, 2013 8:00 AM 388 96%
Nov-13 243,790 Thursday, November 28, 2013 11:00 AM 519 339 65%Thursday, November 21, 2013 6:00 PM 503 97%
Dec-13 310,637 Sunday, December 08, 2013 7:00 PM 668 418 63%Sunday, December 08, 2013 6:00 PM 667 100%
Jan-14 274,146 Monday, January 06, 2014 7:00 PM 508 368 73%Monday, January 06, 2014 8:00 AM 455 90%
Feb-14 264,080 Thursday, February 06, 2014 8:00 PM 625 393 63%Thursday, February 06, 2014 8:00 AM 611 98%
Mar-14 225,091 Saturday, March 01, 2014 12:00 PM 562 303 54%Saturday, March 01, 2014 7:00 PM 552 98%
Apr-14 175,970 Tuesday, April 01, 2014 8:00 AM 354 244 69%Wednesday, April 02, 2014 5:00 PM 320 90%
May-14 157,863 Wednesday, May 21, 2014 8:00 PM 319 212 67%Thursday, May 22, 2014 5:00 PM 265 83%
Jun-14 157,780 Monday, June 23, 2014 7:00 PM 364 219 60%Monday, June 23, 2014 8:00 AM 315 86%
Annual 2,606,638 Annual Class Peak 668 298 45%Annual System Peak 611 91%
ICNU_DR_104 ATTACHMENT A Page 2 of 2

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 104 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 32:12-19. Does the Company agree that Table 12 shows that residential customers have a peak winter demand? If no, please explain.
RESPONSE:
The information provided in Table 12 shows average monthly usage for residential customers and does
not show peak demand. The 2014 Load Study, discussed by Company witness Ms. Knox and provided in her workpapers demonstrates that the Company’s residential customers have their peak demand in the
winter. Provided as ICNU_DR_104 Attachment A are pages 25 and 26 of the Load Study Report.

On page 25 of the Report the “Class Peak Day” chart shows that Residential customers peak in the
winter, but also have a relatively high peak demand usage in the summer. The data for the “Class Peak Day” chart is provided on Page 26 of the Load Study. In particular, the class peak in the winter was 668
MW, while the summer class peak was 546 MW.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/2/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 105 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

The following questions are directed to the testimony of Patrick D. Ehrbar:
Please refer to 32, Table 12. Please provide monthly kWh information for all Washington electric
rate schedules in Washington, similar to that provided for Schedule 1 in Table 12.
RESPONSE: Please refer to ICNU_DR_105 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 106 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 33:16-18. Please confirm that the Company believes it is reasonable to establish rates based on available data that suggests the opposite of what “[t]raditional thinking might lead one to
believe.” If Avista cannot confirm, please provide a narrative response explaining the Company’s policy
and/or position as to the Company’s intended parameters for application of Mr. Ehrbar’s statements. If
Avista does confirm, please explain whether the Company would consider changing “traditionally” used
production and transmission methodologies for cost classification and/or allocation purposes (see Exhibit No.__(TLK-1T) at 10:11-11:17), based on available data presented by other parties in this proceeding.

RESPONSE:
The selected section of Mr. Ehrbar’s testimony relates to the data which show low-income customers tend to
use more electricity than other residential customers, and not related to the rates they pay. Please see the
Company’s response to ICNU_DR_079 which asked for the Company policy/position on changes to cost of
service methodologies.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 02/27/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 107 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 34:3-20. Has the Company considered any studies related to a potential correlation between rate subsidization and increased electricity demand by subsidized customers? If yes, please
provide any such studies.

RESPONSE:
The information provided on Page 34 of Mr. Ehrbar’s direct testimony is related to the usage data
suggests that limited income customers use more electricity than other residential customers. The
Company has neither conducted a study nor has information that would demonstrate that limited
income customers use more electricity because they have or can receive bill assistance through LIRAP or LIHEAP.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Mark T. Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 108 Supplemental TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 8:18-20. As soon as the Company’s current share repurchase program either terminates or expires, please provide program data including: a) total repurchased shares; b) total cost of repurchased
shares; and c) average cost per share.

RESPONSE:
Following the conclusion of the current share repurchase program, Avista will provide the requested
information as a supplemental response to this request. The current program is scheduled to expire on March
31, 2015.

SUPPLEMENTAL RESPONSE:
The share repurchase program expired on 3/31/15. Data for the 2015 repurchase program is as follows:

a) Total repurchased shares: 89,400
b) Total cost of repurchased shares: $2,919,781 c) Average cost per share: $32.66

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 3/2/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark T. Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 108 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 8:18-20. As soon as the Company’s current share repurchase program either terminates or
expires, please provide program data including: a) total repurchased shares; b) total cost of repurchased shares; and c) average cost per share.
RESPONSE:
Following the conclusion of the current share repurchase program, Avista will provide the requested
information as a supplemental response to this request. The current program is scheduled to expire on March 31, 2015.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 109 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 9:14-17. For 2011-2014, please provide an annual comparison of the overall level of
capital investment and the total amount of capital requests submitted by the Company’s various departments.

RESPONSE: Actual Capital
Year Investment* Total Requests Funded Requests Unfunded Requests
2011 $247 $291 $230 $61
2012 $262 $269 $250 $19
2013 $296 $320 $266 $54 2014 $352 $386 $331 $55

*Capital investments include productivity and strategic capital projects in which funding decisions are
made throughout the year and are not included in the initial requests for funding. Capital investments
in 2013 and 2014 also include spend in excess of the original request for customer hook-ups due to actual customer hook-ups exceeding the original forecasted number.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 110 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 9:19-20. Since 2005, has the Company ever chosen to fund all of the capital investment
projects proposed by the various Avista departments? If yes, please specify all applicable years. If no, what does the Company mean by Mr. Thies’s testimony that it has not “typically” chosen to fund all
proposed projects?

RESPONSE:
Since 2009, the Company has not funded all of the capital investment projects submitted by the various
departments. Prior to 2009, the various departments only submitted the highest priority projects that fully utilized their allocated portion of the capital budget.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 111 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 9:14-20. Since 2005, has there ever been a year in which the annual capital requests
submitted by the Company’s various departments were less than planned expenditures for the same year (see, e.g., Exhibit No.__(KKS-1T) at 6, Table No. 1)? If yes, please specify all applicable years.

RESPONSE: Since 2009, the Company’s annual capital requests exceeded the planned expenditures for the same year.
Prior to 2009, the various departments only submitted the highest priority projects that fully utilized their
allocated portion of the capital budget.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 112 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 10:3-8. In stating a range “including” six specified factors influencing yearly capital
investment levels, does the Company mean that there are additional factors which influence these yearly investments? If yes, please provide any additional factors that influence the Company.
RESPONSE:
Yes. Other factors would include, but not be limited to, the level of risk associated with delays in capital
expenditures, and the availability of skilled employee and contracted labor to complete the capital projects.
1

Electric Substations
2012 System Review

Rob Gray
Rodney Pickett
Tia Benjamin

Capital Asset Management
November 8, 2013

For Internal Use Only
ICNU_DR_113 Attachment A Page 1 of 47
2

Contents
Purpose ..................................................................................................................................... 3
Asset Summary .......................................................................................................................... 4
Capital Replacement and Maintenance .....................................................................................13
Key Performance Indicators (KPIs) ...........................................................................................20
Outages ....................................................................................................................................22
Programs ..................................................................................................................................25
Substation PCB Removal (SPCBr) ........................................................................................25
Selected KPIs and Metrics .................................................................................................26
Substation PCBs removed since 2010 ...............................................................................27
Power Transformer Replacement ..........................................................................................32
Voltage Regulator Replacement ............................................................................................34
Wood Substations Replacement (ER 2204) ..........................................................................37
Substation Air Switch Replacement (ER 2449) ......................................................................39
Projects in Design or Construction ............................................................................................41
System Planning Projects .........................................................................................................44
Data Integrity ............................................................................................................................45
References ...............................................................................................................................46

ICNU_DR_113 Attachment A Page 2 of 47
3

Purpose
This report provides the narrative portion of the annual review for Avista’s electric substations. The
intent is to present a “one-stop-shop” to become rapidly familiar with the substation capital assets,
performance, risks, ongoing asset management programs and projects, and summary
recommendations, as well as provide links to more detailed information. System reviews are meant to
serve a general audience from the perspective of long-term, balanced optimization of lifecycle costs,
system performance, and risk management. Consistent annual reviews provide the continuity required
for continuous improvement of capital asset management, as well as historical information useful for
rate case submissions.
The System Review and a workbook, providing supporting data, are kept in the same electronic
directory: c01m134\A Reports & Documentation \System Reviews

ICNU_DR_113 Attachment A Page 3 of 47
4

Asset Summary
Avista Utilities currently operates 161 substations consisting of –
21 transmission substations
30 transmission substations with distribution
108 distribution substations
2 foreign owned substations
The average age of the substations is almost 30 years. Figure 1 illustrates the age profile of the
substations. Data is taken from METS and is based on the age of the oldest power transformer
in each substation.
0
2
4
6
8
10
12
1 5 8 13 16 21 24 27 30 33 36 39 42 45 48 53 56 63 72
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
Substations in Age Bracket
Substns in Age Bracket

Figure 1.1: Substation Age Profile

Avista owned substations were categorized by voltages and function, discriminating between
substations, switching stations, and training substations. The foreign owned substations that Avista
operates, are not included. The count of stations in each of these categories is presented in Table 1.1.
ICNU_DR_113 Attachment A Page 4 of 47
5

Station
Type Qty.
230/115 7
230/115/24 1
230/115/13 4
230/13 2
115/34 3
115/24 6
115/23 1
115/21 6
115/13 107
115/12 1
115/4 2
13/34 1
13/24 1
13/4 2
13/2 2
Training 1
230 Sw.Sta. 2
115 Sw.Sta. 10
Table 1.1: Substations and Switching Stations by Voltage

METS was also queried to provide an account of major assets. Table 1.2 provides an account of these
assets. Figures 2 through 12 provide age profiles for these assets. The figures only reflect the
equipment where the Manufactured Year was listed.
Capital Asset Qty Units
Air switches 2 Units
Bushings 675 Units
Circuit switchers 137 Units
HV breakers 322 Units
LV breakers 640 Units
Power transformers 286 Units
Sub meters 705 Units
Surge arrestors 1 Units
SWGR breakers 501 Units
SVRs 1290 Units
Table 1.2: Substation Capital Assets

ICNU_DR_113 Attachment A Page 5 of 47
6

0
10
20
30
40
50
60
0 2 4 6 9 13 15 17 20 30 32 35 38 47 58 60 64
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
Air Switch Units in Age Bracket
Units in Age Bracket

Figure 1.2: Air switch Age Profile

0
5
10
15
20
25
30
35
0 1 2 3 4 6 31 34 40 52
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
Bushing Units in Age Bracket
Units in Age Bracket

Figure 1.3: Bushing Age Profile

ICNU_DR_113 Attachment A Page 6 of 47
7

0
2
4
6
8
10
12
14
0 3 5 12 14 16 18 20 22 24 30 32 34 37 39 41 44
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
Circuit Switcher Units in Age Bracket
Units in Age Bracket

Figure 1.4: Circuit Switcher Age Profile

0
5
10
15
20
25
30
35
40
0 2 4 6 8 11 13 15 18 20 26 29 31 33 35 37 39 42 45 47 53 55
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
HVB Units in Age Bracket
Units in Age Bracket

Figure 1.5: High Voltage Breaker Age Profile

ICNU_DR_113 Attachment A Page 7 of 47
8

0
1
2
3
4
5
6
7
8
9
10
0 2 4 6 8 11 13 15 18 20 26 29 31 33 35 37 39 42 45 47 53 55
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
230kV OCB Units in Age Bracket

Figure 1.6: 230kV Oil Circuit Breaker Age Profile

0
5
10
15
20
25
30
0 2 4 6 8 11 13 15 18 20 26 29 31 33 35 37 39 42 45 47 53 55
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
230kV GCB Units in Age Bracket

Figure 1.7: 230kV Gas Circuit Breaker Age Profile

ICNU_DR_113 Attachment A Page 8 of 47
9

0
5
10
15
20
25
0 2 4 6 8 11 13 15 18 20 26 29 31 33 35 37 39 42 45 47 53 55
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
115kV OCB Units in Age Bracket

Figure 1.8: 115kV Oil Circuit Breaker Age Profile

0
2
4
6
8
10
12
14
0 2 4 6 8 11 13 15 18 20 26 29 31 33 35 37 39 42 45 47 53 55
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
115kV GCB Units in Age Bracket

Figure 1.9: 115kV Gas Circuit Breaker Age Profile

ICNU_DR_113 Attachment A Page 9 of 47
10

0
10
20
30
40
50
60
70
80
90
100
0 2 4 6 8 11 13 15 17 19 21 26 28 31 33 35 37 39 41 43 45 47 82
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
LVB Units in Age Bracket
Units in Age Bracket

Figure 1.10: Low Voltage Circuit Breaker Age Profile

The 82 and 84 year old breakers were at the Bunker Hill Condenser Sub, and were actually
retired in June 2013. The next oldest breaker, are the two 55 year old PEM JE-30-D OCBs at
Beacon Hill.
0
1
2
3
4
5
6
7
8
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
PXF Units in Age Bracket
Units in Age Bracket

Figure 1.11: Power Transfomer Age Profile
ICNU_DR_113 Attachment A Page 10 of 47
11

0
0.5
1
1.5
2
2.5
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
AutoXfmr Units in Age Bracket
Units in Age Bracket

Figure 1.12: Auto Transformer Age Profile

0
20
40
60
80
100
120
140
0 2 4 6 8 11 13 15 17 19 21 24 26 28 30 32 34 36 38 40 42 44 46 48 53
Nu
m
b
e
r

o
f

U
n
i
t
s
Age Bracket
SVR Units in Age Bracket
Units in Age Bracket

Figure 1.13: Substation Voltage Regulator Age Profile

ICNU_DR_113 Attachment A Page 11 of 47
12

Notice the number of voltage regulators over 40 yrs of age. This is a matter of concern with potential
impacts to system performance.
For more details, see the summary spreadsheet and various sources located in the system review
information directory located at: c01m134\A_Reports & Documentation\System Reviews\Substations
ICNU_DR_113 Attachment A Page 12 of 47
13

Capital Replacement and Maintenance
Replacement costs, capital replacement spending trends and O&M spending trends are provided in the
following tables.
2012 Replacement
Costs
Average
Life (Years)
Per Year
Replacement
Substation
Table 2.1: Substation Replacement Costs

NAME OFFICE Number of
Substations
Percentage
of total
number
Replacement
Value per
Substation per
Year
Total per Year
by Office
Spokane SPC 42 24.00% $ 102,155 $ 4,290,528
Deer Park DPC 6 3.43% $ 102,155 $ 612,933
Colville COC 12 6.86% $ 102,155 $ 1,225,865
Davenport DAC 11 6.29% $ 102,155 $ 1,123,710
Othello OTC 10 5.71% $ 102,155 $ 1,021,554
Pullman/Moscow PAC 28 16.00% $ 102,155 $ 2,860,352
Coeur d'Alene CDC 17 9.71% $ 102,155 $ 1,736,642
Sandpoint SAC 15 8.57% $ 102,155 $ 1,532,331
Kellogg KEC 11 6.29% $ 102,155 $ 1,123,710
Grangeville GRC 11 6.29% $ 102,155 $ 1,123,710
Lewiston/Clarkston LCC 12 6.86% $ 102,155 $ 1,225,865
Table 2.2: Substation Replacement Costs by Office

Measure 2008 2009 2010 2011 2012
Capital Replacement Spending per Substation $24,753 $57,176 $62,478 $74,470 $60,736
Total Capital Spending per Substation $145,614 $134,684 $141,880 $170,165 $138,394
Capital Replacement Spending per Substation Goal $102,155 $102,155 $102,155 $102,155 $102,155
Percentage of Capital Spending was Planned 78% 85% 68% 75% 79%
Percentage of O&M Spending was Planned 18% 66% 96% 97% 89%
Table 2.3: Capital Replacement Spending Summary

ICNU_DR_113 Attachment A Page 13 of 47
14

78%
85%
68%
75%
79%
18%
66%
96%97%
89%
0%
20%
40%
60%
80%
100%
120%
$0
$20,000
$40,000
$60,000
$80,000
$100,000
$120,000
$140,000
$160,000
$180,000
2008 2009 2010 2011 2012
Substations -Capital Replacement Spending per Substation Substations -Total Capital Spending per Substation
Substations -Capital Replacement Spending per Substation Goal Substations -Percentage of Capital Spending was Planned
Substations -Percentage of O&M Spending was Planned

Figure 2.1: Capital Replacement History

ICNU_DR_113 Attachment A Page 14 of 47
15

Table 2.4: Capital Replacement Spending

ICNU_DR_113 Attachment A Page 15 of 47
16

Table 2.5: Capital Replacement Spending as Percentage

ICNU_DR_113 Attachment A Page 16 of 47
17

Table 2.6: Capital Replacement Spending Planned vs. Unplanned

ICNU_DR_113 Attachment A Page 17 of 47
18

Table 2.7: Capital Replacement Spending Planned vs. Unplanned as Percentage

Table 2.8: O&M Spending Planned vs. Unplanned

ICNU_DR_113 Attachment A Page 18 of 47
19

Table 2.9: O&M Spending Planned vs. Unplanned as Percentage

For more details, see the summary spreadsheet and various sources located in the information directory
located at: c01m134\A_Reports & Documentation\Metrics & Dashboard\Dashboard\2013\Supporting
Documents

ICNU_DR_113 Attachment A Page 19 of 47
20

Key Performance Indicators (KPIs)
The following KPIs have been developed and are in the process of refinement and monitoring according
to the listed frequency. A “unity box” measurement will be derived from selected KPIs and published
monthly. Note that a combination of lagging (results) and leading (action) indicators are listed.
Generally, it is expected that a strong focus on the right leading indicators will generate satisfactory
results after a given lag period. When this does not occur, deeper investigation and root-cause analysis
is justified, as something other than the expected causal relationship is potentially at play. More details
relevant to each KPI may be found in the Programs section of this report.
One of the principal goals of Asset Management is to optimally manage risk and performance relative to
capital investment and maintenance. The “sweet spot” of planned maintenance and capital
replacement activity compared to emergency repair costs, outages, lost profits and other principle
outcomes over time should be made clear, as well as predicted vs. actual outcomes for a variety of
scenarios which justify continuation or adjustment of ongoing programs and projects. As it stands, we
are unable to do this satisfactorily due to data unavailability. For example, emergency substation repair
and replacement work transacted under blanket accounts, safety incidents, and other similar activities
cannot be isolated to substation work. The Asset Management group will continue to strive for
improvement and capabilities to achieve this goal, and the implementation of Maximo should help to
alleviate this in coming years.
ICNU_DR_113 Attachment A Page 20 of 47
21

Satisfactory
Some Concern
Unsatisfactory
Assessment Indicator

Overall System Assessment

KPI Description Assessment Goal Frequency Units 2010 2011 2012 Remarks
Customer-Hours unplanned, extended outage due
to substation issues

55,000 annual
Customer-
Hours

91,659

116,009

67,752
# of customers of substation related unplanned
outages greater than 3 hrs

33,000 annual
Customer
Count

60,654

49,657

40,268
# of PCB equipment units removed 121 annual Number 75 123 87
Develop
program
# of older power transformers replaced 2 annual Number 2 1 1
Implement
program
# of older voltage regulators replaced 76 annual Number 55 66 49
Implement
program
# of older wood substations replaced 2 annual Number 1 2 1
# of older air switches replaced 20 annual Number 23 4 5

Table 3.1: Substation KPIs
ICNU_DR_113 Attachment A Page 21 of 47
22

Outages
The following information is taken from the number of sustained outages (longer than five minutes) for
Substation–type events per the annual reliability reports provided by Operations Management. More
detailed information may be taken from the system review’s summary spreadsheet or the reliability
reports themselves located at: c01m134\Reports & Documentation\Metrics & Dashboard\OMT Failure
Data\Quarterly
OMT Sub-Reason 2005 2006 2007 2008 2009 2010 2011 2012 Std
Dev
Average High
Limit
Bus Insulator 3 2 1 1.00 2.0 4
Highside Breaker 2 1 2 0.58 1.7 2.821
Highside Fuse 2 2 4 1.15 2.7 4.976
Highside
Swt/Disconnect
4 1.00 4.0 6
Lowside OCB/Recloser 1 1 2 6 8 4 2.88 3.7 9.417
Lowside
Swt/Disconnect
1 2 0.71 1.5 2.914
Relay Misoperation 6 3 1 1 5 7 2.56 3.8 8.958
Transformer 5 5 3 9 2.52 5.5 10.53
Recloser 3 1 4 2 4 11 3 2 3.11 3.8 9.961
Regulator 12 11 8 13 14 20 17 13 3.66 13.5 20.83
Total incl. distribution - 23 22 22 31 31 51 26 25 9.64 28.9 48.16
Total substation only. - 8 10 10 16 13 20 6 10 4.53 11.6 20.69

Table 4.1: Substation Related OMT Annual Events

ICNU_DR_113 Attachment A Page 22 of 47
23

0
10
20
30
40
50
60
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Nu
m
b
e
r

o
f

O
M
T

E
v
e
n
t
s
Year
Substation Related Outage Management Tool Events by Year
Total incl. distribution -
Total substation only. -

Figure 4.1: Substation Related OMT Event History

OMT Sub-Reason Total
Customer-
hours
Number of
Affected
Customers
Average
Outage
Duration
(hrs)
Average
Number of
Affected
Customers
Bus Insulator 8,338 7,085 1.77 1004
Highside Breaker 1,361 4,381 0.62 1163
Highside Fuse 2,411 2,222 3.25 272
Highside Swt/Disconnect 3 18 0.15 0
Lowside OCB/Recloser 63,471 28,074 2.91 1065
Lowside Swt/Disconnect 5,992 2,069 5.79 862
Relay Misoperation 15,410 32,302 0.83 1482
Transformer 17,348 22,213 1.00 872
Recloser 6,667 4,291 2.72 239
Regulator 113,460 36,948 4.95 436
Total incl. distribution - 234,461 139,603 23.99 7396
Total substation only. - 114,335 98,364 16.33 6721
Table 4.2: 2012 Substation OMT Event Duration and Affected Customers
ICNU_DR_113 Attachment A Page 23 of 47
24

The following information is taken from the number of longer sustained outages (longer than three
hours) for Substation–type events per the annual reliability reports provided by Operations
Management. Figure 4.2 illustrates the trends in Customer-Hours and the number of Customer
Affected. More detailed information may be taken from the system review’s summary spreadsheet or
the reliability reports themselves located at: c01m134\Reports & Documentation\Metrics &
Dashboard\Reliability Data\Reliability Data

-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
2008 2009 2010 2011 2012
Substation Related Outages
Customer-Hours
# of Customers Affected
Linear (Customer-Hours)
Linear (# of Customers Affected)

Figure 4.2: Substation Related Outage Customer Impact Trends
ICNU_DR_113 Attachment A Page 24 of 47
25

Programs
Substation PCB Removal (SPCBr)
In 2010, an assessment was completed of equipment containing Polychlorinated Biphenyls
(PCBs) within the Avista substation. PCBs are typically a minor constituent of oil. Within the
substations, the following equipment can potentially contain PCB contaminated oil: 1
Power transformers (PXFs)
Oil circuit breakers (OCBs) – both high voltage breakers (HVB) and low voltage
breakers (LVB)
Voltage regulators (SVRs)
Potential transformers (PTs)
Current transformers (CTs)
Station service transformers
Capacitors
Electro-mechanical (E-M) Relays
PCBs have been banned in the United States, since 1979, due to their toxicity and
pervasiveness in the environment. However, PCBs continued to be used in U.S. manufacturing
until 1981. PCBs were predominantly used in manufacturing from 1950 through the 1970s.1
Current regulations do not prohibit the use of equipment that contains PCBs. However, the
disposal, release or spill of PCB containing oil, is very tightly regulated. EPA regulates PCB
waste down to 50 ppm, under the Toxic Substances Control Act (TSCA). The Washington State
Dept. of Ecology can regulate PCB waste down to 2 ppm. 1 At present, PCB measurements of
less than 1 ppm are considered to be non-detectible (ND). 1
At Avista, almost 1700 pieces of equipment contain measurable PCBs. All of the substation
power transformers have been tested for PCBs. Transformers with over 50 ppm PCBs are
slated for removal. If a voltage regulator is brought in for repair, and tests for over 50 ppm
PCBs, it is replaced. Otherwise, it may be refilled with clean oil and put back into service.
Other pieces of substation equipment, that contain oil of over 50 ppm PCBs, are evaluated on a
case by case basis. They may be refilled with clean oil and put back into service. 1
There are a couple of considerations for a substation PCB removal program. There have been
cases, where equipment has been refilled with clean oil, initially tested at a PCB level of 0 ppm,
and then retested a few years later at 1 or 2 ppm. There are a couple of possible reasons for
this. One reason, may be that a an internal capacitor has failed, where the capacitor had
contained PCBs. Another possibility is that PCBs may have leached back out of winding
insulation.
ICNU_DR_113 Attachment A Page 25 of 47
26

Another consideration is the likelihood of new, tighter PCB regulations at both the Federal and
State level.
An example of the consequences of PCB spills, that are applicable to a utility, is that of Fluor-
Hanford and Twin City Metals. In 2007, these two companies agreed to pay a $85,000 fine
involving the mishandling of one transformer. This transformer contained approximately 50
gallons of oil with a PCB concentration of 250 parts per million (ppm).2 In the State of
Washington, any oil spill containing over 1 ppm, which reaches surface water, including storm
drains, is subject to large fines. Any oil spilled with over 500 ppm PCB concentration, is a
monumental problem. Decontamination or incineration is required of anything the oil contacts.
Selected KPIs and Metrics
Planning for a Substation PCB Removal program is in the initial phase.
Risks associated with PCB equipment would be reflected in the hazards and costs associated
with any spills. Risk is the product of the probability of an event and the cost of that event.
Probability of an spill would be a function of the quantity of PCB containing equipment. The
cost of a spill would be a function of the quantity of PCBs and the volume of PCB containing oil.
Costs would also be impacted by the potential pathway to water for the site.
Primary key performance indicators (KPIs) would then consist of:
Number of substation PCB equipment units removed versus equipment planned for
removal
This equipment is primarily tracked with the Major Equipment Tracking System (METS).
The replacement of substation station service transformers, containing PCB contaminated oil,
will be part of this program. However, these transformers are tracked within the Transformer
Change-Out Program (TCOP).
CTs and PTs are a bit of a special case. The suspect units are over 30 years old. The cost to
sample these units is more than 50 percent of their current value. 1
With the replacement of PCB containing equipment is replaced, the equipment inventory age
will also be reduced. This will produce the following benefits:
Reduced outage events, due to reduced equipment inventory age
Reduced transmission outage events, due to reduced equipment inventory age
Program performance metrics consist of:
Pounds or kilograms of PCB removed versus Pounds or kilograms of PCB planned for
removal
Gallons of PCB contaminated oil removed versus gallons planned for removal

ICNU_DR_113 Attachment A Page 26 of 47
27

Table 5.1 was developed to demonstrate existing metrics.
Satisfactory
Some Concern
Unsatisfactory
Assessment Indicator

Metric Description Assessment Goal Frequency Units 2010 2011 2012 Remarks
% of PCB equipment units removed 14%annual Percentage 8.8% 14.4% 10.2%Develop program
gal. of PCB contaminated oil removed 56 annual 1000 gal. 52.0 43.3 39.8 Develop program
% of PCB contaminated oil removed 11%annual Percentage 10.5% 8.7% 8.0% Develop program
lbs. of PCB removed 15 annual lbs. 7.49 10.67 15.58
Develop program, total PCB
inventory not fully known
% lbs. of PCB removed 27%annual Percentage 13.5% 19.1% 28.0%
Develop program, total PCB
inventory not fully known
Table 5.1: Substation PCB Removal Metrics
Additional program performance metrics might consist of:
Quantity of equipment containing PCB contaminated oil, within each of the following substation equipment types:
o PXF
o HVB
o LVB
o SVR - Itemized for sites with and without a pathway to water
Pounds or kilograms of PCB inventory reduced within each of the following types of substation equipment:
o PXF
o HVB
o LVB
o SVR
- Itemized for sites with and without a pathway to water
Volume of oil containing PCBs reduced within the following types of substation
equipment:
o PXF
o HVB
o LVB
o SVR
- Itemized for sites with and without a pathway to water
Equipment tested for PCB, planned versus actual
Energy savings for PXF and SVR change-outs
Goals were established using the past four years of data. Goals were calculated as the average
plus two times the std. deviation.
Substation PCBs removed since 2010
A commitment has been made to remove PCBs from the substations. A PCB removal program
is under development. In the mean time, PCBs have been remove through attrition, including
substation rebuilds. The following tables and graphs document the PCBs that have been
removed starting in 2010.
ICNU_DR_113 Attachment A Page 27 of 47
28

Equip Type 2010 2011 2012
Bushing 14 33 31
High-Voltage Circuit Breaker 5 18 0
Low-Voltage Breaker / Recloser 13 15 6
Power Transformer 14 9 17
Voltage Regulator 29 48 30
Total - 75 123 84
Table 5.2: Number of PCB equipment units removed

Equip Type Original
PCB
Equip.
Qty
PCB
Equip
Replaced
Pct PCB
Equip
Replaced
Bushing 86 78 91%
High-Voltage Circuit Breaker 53 23 43%
Low-Voltage Breaker / Recloser 117 36 31%
Power Transformer 139 45 32%
Voltage Regulator 462 112 24%
Total - 857 294 34%
Table 5.3: Percentage of PCB equipment units removed

Figure 5.1: Number of PCB equipment units removed
ICNU_DR_113 Attachment A Page 28 of 47
29

Equip Type 2010 2011 2012
Bushing 8 50.5 44
High-Voltage Circuit
Breaker
10025 6750 0
Low-Voltage Breaker /
Recloser
0 0 0
Power Transformer 41936 36025 28517
Voltage Regulator 0 464 0
Total - 51969 43290 28561
Table 5.4: Gallons of PCB contaminated oil removed

Equip Type Original
PCB Oil
Gal.
PCB Oil
Removed
Gal.
Pct PCB
Oil Gal.
Replaced
Bushing 102.5 102.5 100%
High-Voltage Circuit
Breaker
65897 16775 25%
Low-Voltage Breaker /
Recloser
0 0
Power Transformer 429587 125669 29%
Voltage Regulator 684 464 68%
Total - 496271 143011 29%
Table 5.5: Percentage of PCB contaminated oil removed

Figure 5.2: Gallons of PCB contaminated oil removed
ICNU_DR_113 Attachment A Page 29 of 47
30

Equip Type 2010 2011 2012
Bushing
4.02

6.46

13.53
High-Voltage Circuit
Breaker

0.10

0.22
0
Low-Voltage Breaker /
Recloser
0 0 0
Power Transformer 3.38 3.92 1.91
Voltage Regulator 0
0.07
0
Total -
7.49

10.67

15.44
Table 5.6: Pounds of PCB removed

Equip Type Original
PCB
Lbs.
PCB Lbs.
Removed
Pct PCB
Lbs.
Replaced
Bushing
24.01
24.01 100%
High-Voltage Circuit
Breaker

1.89
0.32 17%
Low-Voltage Breaker /
Recloser
0 0
Power Transformer
29.75
9.48 32%
Voltage Regulator
0.07
0.07 100%
Total - 55.72 33.87 61%
Table 5.7: Percentage of PCB pounds removed

ICNU_DR_113 Attachment A Page 30 of 47
31

Figure 5.3: Pounds of PCB removed

Note the implication of the high concentration of PCB in bushing oil. Much more PCB has been
removed with a handful of bushings, rather than the gallons of oil removed with the power
transformers.
For more details, see the summary spreadsheet and various sources located in the information directory
located at: c01m134\A_Assets\Substation & Major Apparatus\Integrated Programs\PCB Project\Data
ICNU_DR_113 Attachment A Page 31 of 47
32

Power Transformer Replacement
The 5 Year Budget Forecast and Program Descriptions for 2010 noted that 26 pct. of Avista’s
power transformers were over 40 years of age, and that replacing these would save $15,000
per year.
The program has not yet been implemented. However, many of the older transformers have
been replaced, in the course of substation upgrades. The replaced transformers, annual energy
savings and costs savings have been summarized in the table and figure below. Energy cost
savings are based on a levelized cost of $44.18/MWh.
Power Transformer Replacement Energy Savings
Levelized avoided cost
……………………………………………………………………………. $ 44.18 /MWH
High loss PXFs indentified in 2011 study
……………………………………….. 29

Achieved Energy Savings
Replacement Year 2010 2011 2012 Avg. Total
Replaced high loss PXFs 2 1 1 1.33 4
Pct. high loss PXFs replaced 6.9% 3.4% 3.4%
Annual energy savings, kWh 1,248,318 345,074 316,902 636,764 1,910,293
Annual cost savings $ 55,151 $ 15,245 $ 14,001 $ 28,132 $ 84,397

Projected Energy Savings
Replacement Year 2013 2014 2015 Avg.
Replaced high loss PXFs 3 3 3 3.0
Pct. high loss PXFs replaced 10.3% 10.3% 10.3%
Annual energy savings, kWh 658,253 2,397,761 1,459,959 1,505,324
Annual cost savings $ 29,082 $ 105,933 $ 64,501 $ 66,505
Table 5.8: Replaced & Projected Power Transformer Energy Savings

The power transformers that have been replaced include:
Sunset #1 (2010)
Chewelah #1 (2010)
Pullman #2 (2011)
Millwood #1 (2012)
Power transformers to be replaced or removed in the next few years include: Lucky Friday #1
(2013), Millwood #2 (2013), Moscow 230 Spare (2013), Noxon REA (2013), Blue Creek #1
(2014), North Lewiston #1 (2014), South Lewiston #1 (2015), Kooskia #1 (2015) and Kamiah.

ICNU_DR_113 Attachment A Page 32 of 47
33

-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
2010 2011 2012
En
e
r
g
y

S
a
v
i
n
g
s

[
k
W
h
/
y
r
]
High Loss PXF Replacement Energy Savings
Annual energy savings, kWh

Figure 5.4: Power transformer energy savings

Table 5.9 was developed to demonstrate existing metrics.
Satisfactory
Some Concern
Unsatisfactory
Assessment Indicator

Metric Description Assessment Goal Frequency Units 2010 2011 2012 Remarks
% of older power transformers replaced 6.9% annual Percentage 6.9% 3.4% 3.4% Implement program
Table 5.9: Power Transformer Replacement Metrics
ICNU_DR_113 Attachment A Page 33 of 47
34

Voltage Regulator Replacement
The 5 Year Budget Forecast and Program Descriptions for 2010 proposed a Substation Voltage
Regulator program. A total of 1,171 voltage regulators were identified in the substations and
distribution lines. Approx. 38 pct. of these were older than 30 years, but only 1 pct. were over
40 years old. A two tier program was proposed, which would replace the oldest regulators and
refurbish the newer regulators. Energy savings of $138,000 was estimated for replacing
regulators over 20 years old. On an average, regulators over 20 yrs of age draw 230 watts
more than newer regulators.
The program has not yet been implemented. However, many of the older voltage regulators
have been replaced, in the course of substation upgrades. The replaced voltage regulators,
annual energy savings and costs savings have been summarized in the table and figures below.
Energy cost savings are based on a levelized cost of $44.18/MWh.
Annual Voltage Regulator Energy Savings
Removal Year 2010 2011 2012 Total
Replaced VRs 55 66 49 170
Pct. VRs replaced 4.7% 5.6% 4.2% 14.5%
Energy savings
[kWh/yr]
110,814 132,977 98,725 342,516
Annual cost savings $
4,896
$
5,875
$
4,362
$
15,132
Table 5.10: Replaced Voltage Regulator Energy Savings

Figure 5.5: Replaced Voltage regulators

ICNU_DR_113 Attachment A Page 34 of 47
35

-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
2010
2011
2012
En
e
r
g
y

S
a
v
i
n
g
s

[
k
W
h
/
y
r
]
VR Energy Savings
Energy savings [kWh/yr]

Figure 5.6: Voltage regulator energy savings
ICNU_DR_113 Attachment A Page 35 of 47
36

Table 5.11 was developed to demonstrate existing metrics.
Satisfactory
Some Concern
Unsatisfactory
Assessment Indicator

Metric Description Assessment Goal Frequency Units 2010 2011 2012 Remarks
% of older voltage regulators replaced 6.5% annual Percentage 4.7% 5.6% 4.2% Implement program
Table 5.11: Voltage Regulator Replacement Metrics

ICNU_DR_113 Attachment A Page 36 of 47
37

Wood Substations Replacement (ER 2204)
As of 2010, there are at least 56 substations in the Avista system that are either all wood or
have a major portion of framework that is wood. This count includes installations with significant
horizontal structural wood framing. 35 of these wood substations were over 40 yrs old.
The System Wood Substation Rebuilds program was outline in the 2010 Asset Management 5
Year Plan and Budget Summary13. Since that time, some five wood substations have been
replaced, at a typical rate of one per year.
The replacement of wood substations have been summarized in the table and figure below.
Wood substations replaced
2009 2010 2011 2012 Total
1 1 2 1 5
3% 3% 6% 3% 14%
Table 5.12: Replaced Wood Substations

0
1
2
3
4
2009 2010 2011 2012
Wood Substations Replaced

Figure 5.7: Wood substation replacement history

These five rebuilt substations consist of Plummer (2009), Nez Perce (2010), Appleway (2011),
Deary (2011) and Orin (2012).
Estimated cost of wood substation replacement was $0.983M/substation in 2008, now projected
to $1.14M/substation in 2013, using 3% inflation. Minor rebuilds were estimated at
$29,540/station, projected to $34,240 in 2013.
ICNU_DR_113 Attachment A Page 37 of 47
38

Table 5.13 was developed to demonstrate existing metrics.
Satisfactory
Some Concern
Unsatisfactory
Assessment Indicator

Metric Description Assessment Goal Frequency Units 2010 2011 2012 Remarks
% of older wood substations replaced 5.7% annual Percentage 2.9% 5.7% 2.9%
Table 5.13: Wood Substations Replacement Metrics
The next wood structured substations targeted for rebuild are:
Lucky Friday, 2013
North Lewiston, 2014
Blue Creek, 2014
Stratford, 2015
Kooskia, 2015
South Lewiston, 2015
These are to be followed by Big Creek, Kamiah, and Valley. Capacity increase is needed at Big
Creek to serve expansion of the Sunshine Mining operation. Most of these will be at least
partial rebuilds, precipitated by power transformer replacements.

For more details, see the summary spreadsheet and various sources located in the information directory
located at: c01m134\A_Assets\Substation & Major Apparatus\Information\WoodSubs
and the summary file: c01m134\A_Reports & Documentation\System Reviews\Substations\Substations
yStructures Replaced.xls
ICNU_DR_113 Attachment A Page 38 of 47
39

Substation Air Switch Replacement (ER 2449)
The Substation Air Switch Replacement program deals with both planned and unplanned replacements.
Transmission air switches, located outside the substation, are covered by ER 2254.
Air switches may not operate properly when opened and flashover, possibly tripping the bus out. This
can be the result of a component failure (whips and vac-rupters) or the air switch may be out of
adjustment. Although most air switch mis-operations could be avoided with regular inspection and
maintenance there isn’t any planned. Maintenance would consist of blade adjustment, replacement of
live parts such as contacts and whips, and repair of ground mats.
Many air switches are operated remotely. In these instances, company personnel are not present to
observe the opening of the switch, so potential problems are not identified. A small problem could
progress to the point where a major failure may occur. A small amount of material is maintained in the
warehouse for emergency repairs, but many of the switches are old and parts are hard to find.
The age profile for substation air switches is displayed by Figure 1.2.
The air switches replaced since 2010 are displayed in the table and figures below.
Replaced Air Switches
Removal Year 2010 2011 2012 Total 2013
Replaced air switches 23 4 5 32 2
Pct. air switches
replaced
6.2% 1.1% 1.4% 8.6% 0.5%
Table 5.14: Replaced Air Switches

0
5
10
15
20
25
2010 2011 2012
Replaced Air Switches
Replaced air switches

Figure 5.8: Replaced Air Switches
ICNU_DR_113 Attachment A Page 39 of 47
40

Table 5.15 was developed to demonstrate existing metrics.
Satisfactory
Some Concern
Unsatisfactory
Assessment Indicator

Metric Description Assessment Goal Frequency Units 2010 2011 2012 Remarks
% of older air switches replaced 5.4% annual Percentage 6.2% 1.1% 1.4%
Table 5.15: Substation Air Switch Replacement Metrics
ICNU_DR_113 Attachment A Page 40 of 47
41

Projects in Design or Construction
The following tables shows the current substation projects managed by the Substation Design
Engineering group.
Transmitted Projects Date
Moscow City - Install Conduit & Fiber Jan-13
3rd & Hatch - 115 kV Relay Upgrades Jan-13
Old Town - Replace Battery Jan-13
Leon Jct. - Replace MOAS Battery & Cabinet Jan-13
Tenth & Stewart - Add 115 kV Bus Sect. Switch Feb-13
Hallett & White - Install HV Protection Feb-13
Dry Gulch - Add SCADA Points Feb-13
Glenrose - Install HV Protection Feb-13
Warden - A-308 Line Relay Upgrade Feb-13
Othello Switching Station - A-562 Line Relay Upgrade Feb-13
Lucky Friday - Rebuild - Increase Capacity Mar-13
Moscow City - Install HV Protection Mar-13
Turner - Install Voice Over IP (VOIP) Communication Mar-13
Fort Wright - Install Voice Over IP (VOIP) Communication Mar-13
South Pullman - Install Fiber for M23 Comms Mar-13
East Farms - Install HV Protection Apr-13
Millwood - Install Temp GCB and 115/62 kV XFMR Apr-13
Noxon 230 - BPA Comms Relocation Apr-13
Opportunity - Install HV Protection Apr-13
Lakeview - Replace Air Switches R-328 & R-329 Apr-13
Airway Heights - Replace Whips on A-82 at West Plains Apr-13
Benewah - 230 kV Line Comms Upgrade - Moscow Line Apr-13
Spangle - Replace Regulators - Feeder 442 May-13
Huetter - Install HV Protection May-13
Chester - Install HV Protection May-13
Prairie - Install HV Protection Jun-13
Liberty Lake - Install HV Protection/Replace Battery Jun-13
Cabinet-Rathdrum 230 - Remove Carrier Equipment Jun-13
Noxon 230 - Interchange Metering Upgrade Jun-13
Kettle Falls - Replace Regulators - 12F1, 12F2 Jul-13
Leon Jct. - Update MOAS A-143 for Autosectionalizing Jul-13
Mead - Install HV Protection Jul-13
Jaype - Replace OCR & Spill Gaps Aug-13
Pound Lane - Remove Landscaping/Replace Fence Aug-13
North Lewiston 115 - Replace XFMR - Rebuild Station Aug-13
Clearwater - Replace Generator 3 Metering Aug-13
Moscow 230 - Rebuild Substation Aug-13
Oden - Replace Bus Regulators with Feeder Regs Aug-13
Table 6.1: Transmitted Substation Construction Projects

ICNU_DR_113 Attachment A Page 41 of 47
42

Projects in Engineering Date
Odessa - Install 115 kV Cap Bank/Replace HV Fuses Oct-13
Clearwater - Replace 34UT2 Breaker/Switches Aug-13
Airway Heights - Replace Battery & New Battery House Aug-13
Beacon - Upgrade 13 kV - Switches/Breakers/Glass Aug-13
Nine Mile - Replace Battery Sep-13
Stratford - Rebuild Substation Mar-14
Greenacres - Preliminary Design Dec-13
Pound Lane - Replace XFMR Low Side Disc Switches Sep-13
Rathdrum - Replace Air Switches A-501, A-505 Sep-13
Grangeville - Replace Battery Sep-13
Holbrook - Upgrade SCADA Sep-13
Clearwater - Transmission Upgrades, A-217 & A-448 Sep-13
Little Falls - Install Panelhouse Dec-13
Tenth & Stewart - Upgrade 115 kV Equipment Nov-13
Lewiston Mill Road - New 115-13 kV Sub Dec-13
Ross Park - Install Bus Sectionalizing Switch Oct-13
Noxon 13 - Borderline Metering Upgrade Oct-13
Beacon - Replace Fence Nov-13
Moscow 230 - Install 115 kV Capacitor Banks Nov-13
Post Falls - 115 kV Line Relay Upgrade - A-211 Nov-13
Noxon 230 - New 230 kV Reactor Yard Mar-14
Ramsey - 115 kV Line Relay Upgrade - A-669 Dec-13
Beacon - Install Serveron Monitors Dec-13
Beacon - Upgrade SCADA/Integration System Dec-13
Deer Park - Change Phasing Dec-13
Post St. - Replace SMP's Dec-13
Kooskia 115 - Replace Transformer Dec-13
Opportunity - Install 3-115 kV Breakers Dec-13
Irvin - Design Switching Station Dec-13
Beacon - 115 kV Line Relay Upgrade - A-610 (Bell)Dec-13
Cabinet Gorge HED - Replace Station Service OCB 13C05 Dec-13
Waikiki - Install HV Protection Dec-13
Diamond - Replace HV Fuses/Reclosers/Regulators Dec-13
St. Maries - Install SCADA Dec-13
St. Maries - Replace Battery Dec-13
Upriver - Replace Metering Dec-13
South Pullman - 115 kV Relay Upgrade for Moscow Line Dec-13
Terre View - 115 kV Relay Upgrade for Moscow Line Dec-13
Latah Jct. - 115 kV Relay Upgrade for Moscow Line Dec-13
Tenth & Stewart - Replace XFMR 1; Upgrade 13 kV Dec-13
Moscow City - Replace Battery & Upgrade DC Dec-13
Deer Park - Borderline Metering Upgrade Dec-13
South Lewiston 115 - Replace XFMR - Rebuild Station Dec-13
St. John - Install Line Disconnects Dec-13
St. John - Install mSCADA Dec-13
Moscow City - Upgrade SCADA/Integration System Mar-14
Coeurshaft - Replace XFMR - Upgrade Station Dec-13
Table 6.2: Substation Design Projects
ICNU_DR_113 Attachment A Page 42 of 47
43

For more a current listing, see the current spreadsheet and various sources located in the budget
directory located at: c01m72\Budget\2013

ICNU_DR_113 Attachment A Page 43 of 47
44

System Planning Projects
There is considerable opportunity for more collaboration between Asset Management and System
Planning on capital asset risk assessments, analyses and development of long-term asset management
plans, where overlaps and synergistic opportunities present themselves. Risk = (probability) x
(consequence) of a given event.
Currently, there are no substation System Planning projects that are covered by Asset Management.

ICNU_DR_113 Attachment A Page 44 of 47
45

Data Integrity
The following table lists the various sources of information used for Asset Management purposes. Data
gathering from non-electronic sources, mining and cleaning of available information makes up a
disproportionately large amount of current work for Asset Management staff, on the order of 80% of
total work. Long term, in order to provide the most value to Avista, this needs to be reversed with 80%
applied to analyzing data and 20% to gathering data.
Status Data Source Notes/Comments
Maximo in implementation phase for substations

AWB simulations
under development; past simulations need to be updated
AutoCAD .tif drawings are digitized to AutoCAD as they become the subject
of an upgrade project
METS frozen in prep for Maximo implemenation, many fields not current
such as CB counters

Substations System Review
under development
Substation Construction Practices under development

Substation Estimating Tool under development, availability of current information depends
on scope of current projects, appears values are often simply
carried over from previous years
Engineering files vault
Engineering drawings e-vault drawings are not always available in .tif format for projects under
construction
Discoverer unwieldly to summarize costing across different substation
projects, difficult to isolate costs/activities to substations

OMT data mostly reliable info but some categories are mixed with
transmission, for example PMs that really are transmission related
are placed in subs

Substation Projects & Capital
Budget Spreadsheets
Table 7.1: Data Sources for Substations Asset Management

Discoverer provides financial and material usage information from the warehouse and financial systems.
Spending and material can be tracked to the ER and BI levels for Capital work and the MAC and Task
levels for Operations and Maintenance (O&M) work.
ICNU_DR_113 Attachment A Page 45 of 47
46

ICNU_DR_113 Attachment A Page 46 of 47
47

References
1) Pickett, Rodney, “2010 Substation Equipment PCB Analysis”, Avista, May 2010
2) EPA, “Fluor-Hanford and Twin City Metals agree to pay nearly $85,000 to resolve
federal PCB violations”, News Releases from Region 10, Nov.1, 2007
3) South Pullman SGDP Scope 2010-05-24.pdf (S:\Substations\SOUTH PULLMAN
115 (SPU)\Install SGDP Equipment\SPU SGDP Project Scope)
4) TVW Integration Design_201105(SGDP).doc (S:\Substations\TERRE VIEW 115
(TVW)\Install SGDP Equipment)
5) TUR Integration Design 2011 rev3.doc (S:\Substations\TURNER (TUR))
6) Pullman Rebuild 2010-05-25.pdf (S:\Substations\SGDP Pullman
Substations\Turner (old Pullman) Substation\Project Scope)
7) Terre View SGDP Scope 2010-05-25.pdf (S:\Substations\SGDP Pullman
Substations\Terre View Substation\Project Scope)
8) SGDP Substation Projects Summary 2013-01-10.pdf (S:\Substations\SGDP
Pullman Substations\Project Management\Monthly Spreadsheets)
9) Avista Utilities - Smart Circuit - Substation Scoping Memo.doc
(S:\Substations\SGIG\Scoping)
10) Ross Park - Scope Change Tracking.docx
11) Increasing SGIG scope at Sunset Substation.msg, email from Adam Newhouse
June 4, 2012
12) Francis and Cedar - Scope Change Tracking.docx
13) Madden, Glenn and Pickett, Rodney, “Asset Management 5 Year Plan and
Budget Summary 2010”, 5 Year Budget Forecast and Program Descriptions for
2010 rev 1.docx (H:\A_Reports & Documentation\5 Year Budget Forecast &
Program Description)

ICNU_DR_113 Attachment A Page 47 of 47
i

2013 Asset Management Distribution
Program Update

Amber Fowler, Rodney Pickett and Doug Forkner
11-15-2013

ICNU_DR_113 Attachment B Page 1 of 77

ii

Table of Contents
Introduction .................................................................................................................................................. 1
Purpose ......................................................................................................................................................... 1
Data Sources ................................................................................................................................................. 1
Standard Calculations ................................................................................................................................... 2
Review of OMT Data and Trends .................................................................................................................. 2
OMT Events per Year ................................................................................................................................ 2
SAIFI Trends by OMT Sub-Reasons ........................................................................................................... 8
OMT Sub-Reason Events High Limit ........................................................................................................ 10
AM Related Material Used by Electric Distribution Minor Blanket, ER 2055 ......................................... 17
Risk Action Curve Evaluation .................................................................................................................. 17
Specific Distribution Programs and Assets ................................................................................................. 19
Distribution Wood Pole Management (WPM)........................................................................................ 19
Selected KPIs and Metrics ................................................................................................................... 19
WPM Metric Performance .................................................................................................................. 22
WPM Model Performance .................................................................................................................. 22
WPM Summary ................................................................................................................................... 23
Wildlife Guards ....................................................................................................................................... 29
Selected KPIs and Metrics ................................................................................................................... 29
WILDLIFE GUARDS KPI Performance ................................................................................................... 30
WILDLIFE GUARDS Metric Performance ............................................................................................. 30
WILDLIFE GUARDS Model Performance ............................................................................................. 31
WILDLIFE GUARDS Summary .............................................................................................................. 31
URD Primary Cable .................................................................................................................................. 34
Selected KPIs and Metrics ................................................................................................................... 34
URD PRIMARY CABLE KPI Performance .............................................................................................. 35
URD PRIMARY CABLE Metric Performance ......................................................................................... 36
URD PRIMARY CABLE Model Performance ......................................................................................... 36
URD PRIMARY CABLE Summary .......................................................................................................... 37
URD Secondary Cable.............................................................................................................................. 37
Open Wire Secondary ............................................................................................................................. 37
Distribution Cutouts ................................................................................................................................ 37
ICNU_DR_113 Attachment B Page 2 of 77

iii

Distribution Air Switches ......................................................................................................................... 37
Distribution Mid-Line Reclosers .............................................................................................................. 37
Distribution Mid-Line Voltage Regulators............................................................................................... 38
Primary Conductors ................................................................................................................................ 38
Primary Connections ............................................................................................................................... 39
Secondary Conductors ............................................................................................................................ 39
Secondary Connectors ............................................................................................................................ 39
Distribution Transformers ....................................................................................................................... 39
Selected Metrics ................................................................................................................................. 39
Metric Performance ............................................................................................................................ 40
Summary ............................................................................................................................................. 40
Area and Street Lights ............................................................................................................................. 40
Riser Terminations .................................................................................................................................. 40
Dead End Insulators ................................................................................................................................ 41
Distribution Capacitors ........................................................................................................................... 41
9CE12F4 Partial Feeder Rebuild .............................................................................................................. 41
Selected KPIs and Metrics ................................................................................................................... 41
Partial Feeder Rebuild KPI Performance ............................................................................................. 41
Partial Feeder Rebuild Metric Performance ....................................................................................... 41
Partial Feeder Rebuild Model Performance ....................................................................................... 43
Partial Feeder Rebuild Summary ........................................................................................................ 43
Chance Cutouts ....................................................................................................................................... 44
Selected KPIs and Metrics ................................................................................................................... 44
Chance Cutouts KPI and Metric Performance .................................................................................... 44
Chance Cutouts Model Performance .................................................................................................. 45
Chance Cutouts Summary ................................................................................................................... 46
Distribution Vegetation Management (VM) ........................................................................................... 46
Selected KPIs and Metrics ................................................................................................................... 46
VM KPI Performance ........................................................................................................................... 47
VM Metric Performance ..................................................................................................................... 49
VM Model Performance...................................................................................................................... 51
VM Summary....................................................................................................................................... 51
ICNU_DR_113 Attachment B Page 3 of 77

iv

Distribution Grid Modernization Program .............................................................................................. 51
Selected Metrics ................................................................................................................................. 52
Metric Performance ............................................................................................................................ 55
Summary ............................................................................................................................................. 56
Asset Management Area Work plans for Electric Distribution ................................................................... 56
Spokane Area Work Plans ....................................................................................................................... 56
Palouse Area ........................................................................................................................................... 61
Coeur D’Alene Area ................................................................................................................................. 63
Lewis-Clark Area ...................................................................................................................................... 66
Big Bend Area .......................................................................................................................................... 69
Conclusion ................................................................................................................................................... 72

Figure 1, OMT Annual Number of Events and AM Related Event Trends and Trend Lines .......................... 7
Figure 2, OMT Events with and without Planned Maintenance or Upgrades .............................................. 8
Figure 3, Individual Sub-Reasons exceeding Quarterly High Limits ............................................................ 12
Figure 4, Top 10 Sub-Reasons with the Value of SAIFI Rising over Time .................................................... 13
Figure 5, 2012 OMT SAIFI Contribution by Sub-Reason ............................................................................. 14
Figure 6, 2012 OMT Sustained Outage Comparisons ................................................................................. 15
Figure 7, 2012 OMT Events by Sub-Reason ................................................................................................ 16
Figure 8, OMT Events and AM Related Material Used by ER 2055 by Year and their associated Trend
Lines ............................................................................................................................................................ 17
Figure 9, Customers Affected Per Event Exceeding Risk Action Levels ...................................................... 18
Figure 10, WPM OMT Event Trends ............................................................................................................ 24
Figure 11, WPM Contribution to Annual SAIFI value by Sub-Reason and Year .......................................... 25
Figure 12, Wood Pole Used by Summarized Activity .................................................................................. 26
Figure 13, Distribution Wood Pole Age Profile ........................................................................................... 27
Figure 14, WPM Model Projections vs Actual Usage for 2012 ................................................................... 28
Figure 15, Wildlife Guards Installed by Year and Expenditure Request ..................................................... 32
Figure 16, Wildlife Guards Usage by MAC for 2005-2010 .......................................................................... 33
Figure 17, URD Primary Cable OMT Events by Year ................................................................................... 36
Figure 18, All OMT Sub-Reasons except Maint/Upgrade for Feeder 9CE12F4 2002-2010 ........................ 42
Figure 19, Selected OMT Trends for AM Related Events with Upward Trends for Feeder 9CE12F4 ......... 43
Figure 20, Cutout/Fuse OMT Event Comparison between Actual, Projected without Action, and
Projected with Action ................................................................................................................................. 45
Figure 21, OMT Events Data Trends for Tree-Weather, Tree Growth, and Tree Fell Sub-Reasons............ 48
Figure 22, OMT Outage and Partial Outage Data Trends for Tree-Weather, Tree Growth, and Tree Fell
Sub-Reasons ................................................................................................................................................ 49
ICNU_DR_113 Attachment B Page 4 of 77

v

Figure 23, OMT Sustained Outages related to Grid Modernization ........................................................... 55
Table 1, OMT Events by Sub-Reason and Year ............................................................................................. 2
Table 2, OMT Outages and Partial Outages by Sub-Reason and Year .......................................................... 4
Table 3, Top Ten Trends Upward in OMT Data by Sub-Reason based on 2006-2012 data .......................... 5
Table 4, Top Ten Trends Downward in OMT Data by Sub-Reason based on 2005-2010 data ..................... 6
Table 5, SAIFI Trends by OMT Sub-Reason Average per Outage .................................................................. 9
Table 6, OMT Sub-Reasons Exceeding Annual High Limit ........................................................................... 11
Table 7, WPM KPI Goals by Year ................................................................................................................. 20
Table 8, WPM Metric Goals by Year ........................................................................................................... 21
Table 9, Wildlife KPI Goals for 2010 - 2015 ................................................................................................. 30
Table 10, Wildlife Metric Goals for 2010 - 2015 ......................................................................................... 30
Table 11, Worst Feeders for Squirrel related Events for 2010 - 2012 ........................................................ 31
Table 12, URD Cable - Pri KPI Goals ............................................................................................................ 35
Table 13, URD Cable - Pri Metric Goals ....................................................................................................... 35
Table 14, TCOP Metrics ............................................................................................................................... 40
Table 15, Chance Cutout Replacement KPI and Metric Goals .................................................................... 44
Table 16, Chance Cutout KPI and Metric Performance .............................................................................. 45
Table 17, Vegetation Management KPI Goals ............................................................................................ 47
Table 18, Vegetation Management Metric Goals ....................................................................................... 47
Table 19, VM KPI Performance ................................................................................................................... 48
Table 20, Tree-Weather OMT Events Metric for Vegetation Management ............................................... 50
Table 21, VM SAIFI Metrics ......................................................................................................................... 50
Table 22, VM Cost per Mile and All Vegetation Management Work Metric .............................................. 51
Table 23, Grid Modernization Program Objectives .................................................................................... 52
Table 24, Energy Savings based on 2013 Integrated Resource Plan .......................................................... 52
Table 25, OMT Sub-Reasons impacted by Grid Modernization .................................................................. 54
Table 26, Metric Performance for Grid Modernization Program ............................................................... 55

ICNU_DR_113 Attachment B Page 5 of 77
1

Introduction
As Avista incorporates more work and Asset Management (AM) Plans each year, Asset Management is
committed to monitor how these activities impact our systems and document the value created by the
programs. Reviewing the results of AM activities and system responses provides us with the feedback
necessary to learn and improve our plans and processes. These outcomes also help drive future work
when actions don’t yield the desired results or we find there is even more value of further work. In the
end, our commitment to continuous improvement require us to examine how we have impacted our
systems and learn from what has happened to make tomorrow’s plans and work better.
Purpose
This report documents the KPIs and metrics AM uses for the Distribution system and provides the results
for 2012. Some of the metrics provide a basis for comparing how an asset performed with a program
and how it would have performed without a program. The difference in performance provides an
estimate of the cost saving of the program. The estimated savings is only a snapshot in time and may
not represent the exact savings; it provides a relative comparison and supporting justification for AM
decisions made in the past. Other KPIs and metrics provide indications of how well an asset is
performing and help determine when further work is required. KPIs and metrics tracking also help
evaluate the accuracy of different AM models and determine when or if a model should be revised.
Data Sources
Information used in this report’s metrics comes from three sources: Annual Sustained and Momentary
outage data; Outage Management Tool (OMT) events; and Discoverer. The annual Sustained and
Momentary outage data is generated by the Distribution Dispatch Engineer each month in a
spreadsheet. The Sustained and Momentary outage data for years 2001 – 2007 was modified by AM to
align the reasons and sub-reasons to coincide with the current descriptions. While the Sustained and
Momentary outage data comes from OMT data and is a subset of OMT data, this data has been
scrubbed by the Distribution Dispatch Engineer to improve its accuracy.
The OMT tracks outages and customer reports of problems on the Distribution system, Substations, and
Transmission events that cause outages on the Distribution system. This data includes sustained
outages, momentary outages, and events without outages. Events that only cause a partial outage or no
outage at all do not show up in the Sustained and Momentary outage data, because the data does not
fit the definition of a sustained outage or a momentary outage. However, the OMT data is subject to
reporting an event more than once. The Distribution Dispatch Engineer reviews the data and strives to
prevent duplication by rolling events up and editing the data. However, some duplication still occurs.
OMT data is used to calculate number of outages, number of OMT events (outages, partial outages, and
non-outage events), outage duration, number of customers impacted, response times, System Average
ICNU_DR_113 Attachment B Page 6 of 77

2

Interruption Frequency Index (SAIFI) impacts, and System Average Interruption Duration Index
(SAIDI) impacts.
Discoverer provides financial, customer information, and material usage information from our
warehouse and financial systems. Spending and material can be tracked to the ER and BI level for
capital work and the MAC and Task for Operations and Maintenance (O&M) work.
Standard Calculations
See reference the “2013 General Metrics Data Collection and Analysis for System Reviews” for the
details and examples of how different measures and metrics are calculated.
Review of OMT Data and Trends
Examining the data in OMT reveals a lot of information helps Avista understand the condition of our
assets and shows some trends we can address. Below, we will examine various trends within OMT
Events per Year, SAIFI trends by OMT Sub-Reasons,
OMT Events per Year
Table 1 shows the past seven years of data out of OMT by Sub-Reason and allows trend analysis. OMT
Events represents cost and action for Avista, so it was selected as a basis for much of our trending.
However, OMT Outage data (shown in Table 2) can have a different trend than OMT Events. Since the
SAIFI analysis already includes outage data, AM selected to trend OMT Events and SAIFI contribution.
Based on Table 1, we identified the top 10 increasing and decreasing trends in OMT Sub-Reasons. The
Top 10 increasing trends in the number of OMT events by year is shown in Table 3 and the Top 10
decreasing trends in the number of OMT events by year is shown in Table 4.
Table 1, OMT Events by Sub-Reason and Year
OMT SUB-REASON 2006 2007 2008 2009 2010 2011 2012
Arrester 29 26 26 19 32 30 36
Bird 207 220 187 218 179 332 231
Bus Insulator 3 0 0 0 0 2 1
Capacitor 2 6 4 4 2 0 4
Car Hit Pad 70 88 129 139 105 98 105
Car Hit Pole 234 231 202 217 298 339 355
Conductor - Pri 68 59 51 42 64 81 110
Conductor - Sec 247 231 252 286 273 310 286
Connector - Pri 75 89 99 111 101 100 79
Connector - Sec 323 340 395 429 410 408 390
Crossarm-rotten 28 46 38 23 25 28 19
Customer Equipment 1047 1182 1475 1626 1458 1384 1434
Cutout/Fuse 263 272 234 197 217 176 209
Dig In 138 132 152 164 149 123 109
ICNU_DR_113 Attachment B Page 7 of 77

3

ICNU_DR_113 Attachment B Page 8 of 77

4

Table 2, OMT Outages and Partial Outages by Sub-Reason and Year
OMT SUB-REASON 2006 2007 2008 2009 2010 2011 2012
Arrester 28 25 22 18 31 30 32
Bird 204 215 178 213 175 322 225
Bus Insulator 3 0 0 0 0 2 1
Capacitor 0 3 2 4 1 0 3
Car Hit Pad 35 46 47 41 30 31 45
Car Hit Pole 132 133 104 104 135 131 158
Conductor - Pri 50 42 26 31 49 61 70
Conductor - Sec 128 102 107 117 104 126 124
Connector - Pri 62 71 88 102 84 82 59
Connector - Sec 189 224 246 272 263 270 267
Crossarm-rotten 20 38 28 11 20 24 17
Customer Equipment 764 897 1040 1205 1121 1034 1099
Cutout/Fuse 236 238 207 175 194 161 185
Dig In 95 99 103 104 88 75 64
Elbow 5 5 7 7 5 7 2
Fire 44 68 31 8 69 72 82
Forced 42 52 61 51 63 67 33
Foreign Utility 53 63 110 78 103 61 62
Highside Breaker 2 1 0 0 1 0 0
Highside Fuse 0 2 4 0 0 0 0
Highside Swt/Disconnect 0 0 0 0 0 0 0
Insulator 33 13 25 23 31 26 19
Insulator Pin 17 16 15 16 15 18 19
Junctions 2 1 0 0 1 0 2
Lightning 599 323 320 572 159 174 562
Lowside OCB/Recloser 1 1 2 6 8 3 0
Lowside Swt/Disconnect 1 0 0 2 0 0 0
Maint/Upgrade 222 331 342 534 1566 3331 2587
Other 293 301 252 247 275 261 282
Pole Fire 134 108 130 101 87 93 95
Pole-rotten 7 5 7 14 11 10 9
Primary Splice 0 3 1 0 1 1 0
Protected 8 9 16 17 7 4 5
Recloser 1 4 2 3 9 1 2
Regulator 10 8 11 10 16 14 10
Relay Misoperation 3 1 1 5 7 0 0
ICNU_DR_113 Attachment B Page 9 of 77

5

Table 3, Top Ten Trends Upward in OMT Data by Sub-Reason based on 2006-2012 data

The largest upward trend is our increase in maintenance and upgrade outages. We have implemented
many programs that increase our outages due to maintenance but decrease the number of outages due
to failures. It appears that Planned Work has had an impact on our outages. The outages that are
directly and indirectly affected by the Vegetation program, Wood Pole Management, and other planned
ICNU_DR_113 Attachment B Page 10 of 77

6

work have dropped out of the table. All of the results in Table 3 are at a level that a program is probably
not needed or outside the scope of an Asset Management Program.
Table 4 shows the Top 10 OMT Sub-Reasons with a downward trend. The largest downward trend is in
Wind event driven largely by the calmer storm seasons our region has experienced over the past few
years. The trend for Squirrel related outages in Table 4 show the results of adding Wildlife Guards
(WLG) on new installs and adding them to existing transformers as part of a WLG program and Wood
Pole Management. Our Cutout Replacement programs for Chance cutouts and bad cutouts identified by
Wood Pole Management have made a great impact on the number of cutout events. The URD cable
Replacement program for the first generation of unjacketed cable has paid great dividends when
compared to where it could have been without taking action at reducing URD Cable – Pri events. Adding
Lightning arresters on existing transformers as part of Wood Pole Management and other planned work
has aided in reducing the number of Lightning related outages. However, we have also experienced mild
storm years as well that has also impacted the lightning related events. Pole Fire events have several
sources but replacing cutouts, replacing wood arms with fiberglass, and the work of the Wood Pole
Management have had an impact on this Sub-Reason. The remaining Sub Reasons in the table have
trend downward but the changes are not material at this point in time.
Table 4, Top Ten Trends Downward in OMT Data by Sub-Reason based on 2005-2010 data

Top Ten Downward Trends
OMT Sub-Reason Slope Change per Year
Wind -127
Squirrel -98
Snow/Ice -37
URD Cable - Pri -25
Lightning -20
SEE REMARKS -14
Transformer - OH -14
Cutout/Fuse -11
Undetermined -9
Pole Fire -7

The overall trends in OMT Events are shown in Figure 1 along with the trends in AM related OMT Events
(see Appendix A of the “2013 Asset Management Electrical Distribution Program Review and Metrics”
and the table titled “List of AM Related OMT Sub-Reasons” to see which OMT Sub-Reasons are
considered AM Related). Based on Figure 1, Avista sees the number of events stabilizing compared to 5
years ago. The overall trend still shows an increase, but the trend for the past 4 appears to be stabilizing
around 13,000 events per year. However, Figure 2 shows that the number of OMT events representing
failures is actually on a downward trend over the past 5 years (see OMT Events w/o Maint/Upgrades for
this trend).
ICNU_DR_113 Attachment B Page 11 of 77

7

AM related OMT events are actually decreasing at a rate around 4%. Since the regional growth rates are
less than 2%, the decrease is most probably due to the increase in maintenance in the system and
replacement of aged infrastructure.

Figure 1, OMT Annual Number of Events and AM Related Event Trends and Trend Lines

y = 362.83x -716526
y = -113.03x + 230343
0
2000
4000
6000
8000
10000
12000
14000
16000
2006 2007 2008 2009 2010 2011 2012 2013
Total OMT Events by Year AM Related Total OMT Events
Linear (Total OMT Events by Year )Linear (AM Related Total OMT Events)
ICNU_DR_113 Attachment B Page 12 of 77

8

Figure 2, OMT Events with and without Planned Maintenance or Upgrades
SAIFI Trends by OMT Sub-Reasons
Examining how SAIFI changes each year is shown in Table 5. SAIFI values in Table 5 represent the annual
value each event contributes to the overall SAIFI number. For example, in 2005, the average Arrester
event in OMT added 0.000203395 to the overall SAIFI number for the year. While the number of
electrical customers does grow each year, the main driver for changes in the average SAIFI number per
event comes from the average numbers of customers affected by the event. Continuing our example
with Arresters, in 2005 Avista had 338,437 electrical customers and the average Arrester outage event
affected 271 customers, so the average SAIFI impact per event was 0.000203. In 2006, our electrical
customer count increased to 345,517 and the average number of customers affected by an Arrester
related outage jumped to 527, almost double the previous year and the average SAIFI impact due to
Arrester events rose to 0.000388. The result for SAIFI was an increase in the average impact to SAIFI in
2006 compared to 2005.
While most Sub-Reasons in OMT have fluctuating value around an average value over the past five
years, some Sub-Reasons have demonstrated a definite trend upward as shown in Figure 4Figure
4Figure 4. Figure 4Figure 4Figure 4 shows the top 10 Sub-Reasons based on the percentage change in
2012. Some of the items in Figure 4Figure 4Figure 4 had small numerical changes but the percentage
change was significant. The Elbow Sub-Reason is an example of this, because the number of OMT
0
2000
4000
6000
8000
10000
12000
14000
16000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Nu
m
b
e
r

o
f

O
M
T

E
v
e
n
t
s
Year
Total of Outage Management Tool Events by Year
Total of OMT Events by Year OMT Events w/o Maint/Upgrades
ICNU_DR_113 Attachment B Page 13 of 77

9

events was <10 in all years and the SAIFI value in 2005 was in the 10-6 range but moved steadily into the
10-4 range showing a dramatic percentage change over five years.
Figure 5, Figure 6Figure 6Figure 6, and Figure 7 illustrate the makeup of the overall SAIFI value, overall
OMT Sustained Outages, and OMT Events by Sub-Reasons. Figure 6Figure 6Figure 6 and Figure 7
generally show the same results but Figure 5 shows a different result because the number of customers
impacted by each Sub-Reason is different. For example, we have very few Transformer caused outages,
but they affect a large number of customers. So, Transformers show a significant impact to SAIFI in
Figure 5 but are insignificant on Figure 6Figure 6Figure 6 and Figure 7.
Table 5, SAIFI Trends by OMT Sub-Reason Average per Outage
Average SAIFI by Sub-Reason Event
OMT Sub-Reason 2006 2007 2008 2009 2010 2011 2012
Arrester 0.010961955 0.01336324 0.011896617 0.008745915 0.009230266 0.003380523 0.015245676
Bird 0.024434391 0.015658058 0.016111406 0.051184585 0.026835343 0.050143556 0.015659978
Bus Insulator 0.010865142 0 0 0 0 0.009016775 0.000463618
Capacitor 0 0.000954613 0.002953837 0.002533353 0.002842798 0 0.006147101
Car Hit Pad 0.004008913 0.004577603 0.003859152 0.003022983 0.001972404 0.00315424 0.004171572
Car Hit Pole 0.072635457 0.082729511 0.056285174 0.05623644 0.055741604 0.034563763 0.078829605
Conductor - Pri 0.018499731 0.021600264 0.011489151 0.025289327 0.013459389 0.025213018 0.024181701
Conductor - Sec 0.001247081 0.001383003 0.001479731 0.001086872 0.001923463 0.001952154 0.003857768
Connector - Pri 0.012843943 0.019175112 0.044761723 0.036707546 0.029390854 0.022841718 0.023941651
Connector - Sec 0.001489753 0.002766032 0.002171923 0.00158371 0.001764569 0.001927718 0.002095065
Crossarm-rotten 0.004762366 0.050334458 0.0252873 0.001820303 0.010791352 0.017452881 0.004106797
Customer
Equipment
0.00010476 7.49088E-05 0.000124802 8.77548E-05 8.43629E-05 4.18879E-05 0
Cutout/Fuse 0.037662682 0.015844599 0.024630616 0.020002232 0.029472485 0.014918168 0.027484801
Dig In 0.013822657 0.011935045 0.017879617 0.017426241 0.002911047 0.007751271 0.001543001
Elbow 7.04241E-05 0.000175223 0.001148975 0.001834192 9.54113E-05 0.000737521 2.50685E-05
Fire 0.003434279 0.017648049 0.001552322 0.000963714 0.000916016 0.001765849 0.004579849
Forced 0.026498934 0.022935126 0.037704074 0.041119919 0.026724006 0.011341762 0.01007956
Foreign Utility 0 4.62462E-05 0.000104966 9.67203E-06 0.06415389 1.9551E-05 1.10385E-05
Highside Breaker 0.005137229 0.005624164 0 0 0.001809346 0 0
Highside Fuse 0 5.79715E-06 0.003370373 0 0 0 0
Highside
Swt/Disconnect
0 0 0 0 0 0 0
Insulator 0.008319149 0.006320321 0.005329816 0.032674813 0.00947135 0.00767475 0.001619894
Insulator Pin 0.007745791 0.015949133 0.002512396 0.00073663 0.00609977 0.012718209 0.002646432
Junctions 0.000359708 0.000127537 0 0 5.63488E-06 0 0.002791077
Lightning 0.125091807 0.128468634 0.083469701 0.093833897 0.05153771 0.029986357 0.107700751
Lowside
OCB/Recloser
0.003589236 0.002156231 0.00501564 0.032172584 0.02327413 0.013159376 0
ICNU_DR_113 Attachment B Page 14 of 77

10

Average SAIFI by Sub-Reason Event
OMT Sub-Reason 2006 2007 2008 2009 2010 2011 2012
Lowside
Swt/Disconnect
0.004042156 0 0 0.001932028 0 0 0
Maint/Upgrade 0.067346483 0.056121124 0.073959603 0.146879337 0.115272977 0.131045664 0.093958391
Other 0.150591892 0.139200478 0.087814989 0.158240122 0.177318475 0.156583826 0.114257941
Pole Fire 0.124284188 0.071639978 0.085131634 0.056866386 0.108242728 0.087722138 0.058825288
Pole-rotten 0.002994252 0.000430513 0.000936218 0.001111959 0.002027401 0.002475849 0.001111378
Primary Splice 0 8.94841E-05 2.81903E-06 0 1.40872E-05 0.000227493 0
Protected 0.00227485 0.009257534 0.013300204 0.006434116 0.005438117 0.000105902 0.000523814
Recloser 3.83302E-05 0.001297214 0.001916203 0.003492427 0.002520587 0.000212125 8.36386E-06
Regulator 0.003510922 0.005390496 0.024938242 0.011105746 0.019517299 0.003012273 0.020486437
Relay
Misoperation
1.7681E-05 0.008228451 0.005720398 0.01961408 0.026993562 0 0
SEE REMARKS 0.019351895 0.015994757 0.032649991 0.017553605 0.0263254 0.022946333 0.024001629
Service 0.00113598 0.000501324 0.00054765 0.000382684 0.001512913 0.001254413 0.001425234
Snow/Ice 0.120736899 0.081725352 0.264038325 0.133791974 0.091003627 0.039682871 0.109703932
Squirrel 0.016993837 0.023857822 0.08015205 0.056647666 0.021425719 0.039013725 0.050207568
Switch/Disconnect 0.013598186 5.79715E-06 0.002055625 0.0165265 0.004582077 0 4.14971E-05
Termination 0.000203253 0.000467243 0.000867328 0.000227232 0.000152009 0.000173439 0.000637191
Transformer 0 0.009703026 0.023561073 0 0.002368376 0 0.026729531
Transformer - OH 0.004014128 0.007052431 0.01118744 0.00773242 0.002407314 0.017106495 0.004874802
Transformer UG 0.001399379 0.002360207 0.002263655 0.001051355 0.001704189 0.001165537 0.001438726
Tree 0.016868605 0.013180035 0.004975592 0.005575766 0.013288743 0.000938339 0.011356792
Tree Fell 0.098678253 0.076230149 0.057889379 0.048048112 0.092136448 0.062998204 0.067319172
Tree Growth 0.0038179 0.012134005 0.010881641 0.004394705 0.007012046 0.003838547 0.005569335
Underground 0 8.34231E-05 3.4203E-05 0 2.81744E-06 2.80426E-06 3.87453E-05
Undetermined 0.133189972 0.168118512 0.29086705 0.286489483 0.110134471 0.234672203 0.177748096
URD Cable - Pri 0.011201018 0.017483349 0.022121806 0.009632032 0.005903606 0.008770789 0.002422167
URD Cable - Sec 0.000792905 0.000815417 0.001058763 0.000945651 0.000953008 0.001467391 0.001544569
Weather 0.100863902 0.078263003 0.115917398 0.097935383 0.195547002 0.051231256 0.053674679
Wildlife Guard 0 0 0 8.47553E-06 0 0 8.35232E-06
Wind 0.555124223 0.232776552 0.220754073 0.115850205 0.291134088 0.089836161 0.195492335

OMT Sub-Reason Events High Limit
The second metric used to determine if we must examine a problem is the deviation from the
established mean discussed above for each OMT Sub-Reason. If the number of OMT events for a specific
Sub-Reason exceeds the OMT Sub-Reason Events High Limit (High Limit) AM will conduct an
investigation and try to explain why the annual values are exceeding the limit (see Appendix D of the
“2013 Asset Management Electrical Distribution Program Review and Metrics”). The High Limit is based
ICNU_DR_113 Attachment B Page 15 of 77

11

on the average of annual values for each Sub-Reason plus two standard deviations. This method is also
used to calculate the quarterly High Limit as well. The data for the average is the OMT Data for 2006
through 2010. For 2012, the following OMT Sub-Reasons exceeded their High Limit are shown in Table
6. We anticipated that Avista would exceed these limits due to natural deviations for events outside our
control and due the some cyclical nature we observe in our data. Our goal here is to help identify trends
in time to potentially address them if possible.
Table 6, OMT Sub-Reasons Exceeding Annual High Limit
OMT Sub-Reasons Exceeding their associated OMT
High Limit
Number of Years High Limit Exceeded
Car Hit Pole 3
Conductor - Pri 2
Fire 2
Maint/Upgrade 3
Other 1
Service 3
Transformer 1

Based on Table 6, we currently don’t see any issues requiring changes to our current plans. Most of the
issues identified above are outside our control. However, we currently monitor Car Hit Pole events
more closely and anticipate that some kind of action may be called for in the future.
Figure 3 shows the quarterly trends that feed into the annual trends for the OMT High Limit. For all
OMT Sub-Reasons, only three Sub-Reasons have had more than three quarters where they exceeded the
High Limit, Car Hit Pole with 9 quarters above the limit, Maint/Upgrades, and Service with 6 quarters
above the limit. This information is consistent with Table 6 above. We will continue to monitor Service
for potential future action, but it currently does not warrant a maintenance or replacement strategy.

ICNU_DR_113 Attachment B Page 16 of 77

12

Figure 3, Individual Sub-Reasons exceeding Quarterly High Limits
y = 0.1331x + 0.1794
0
1
2
3
4
5
6
7
8
9
10
20
0
5

-
1
20
0
5

-
3
20
0
6

-
1
20
0
6

-
3
20
0
7

-
1
20
0
7

-
3
20
0
8

-
1
20
0
8

-
3
20
0
9

-
1
20
0
9

-
3
20
1
0

-
1
20
1
0

-
3
20
1
1

-
1
20
1
1

-
3
20
1
2

-
1
20
1
2

-
3
Nu
m
b
e
r

o
f

S
u
b
-Re
a
s
o
n
s

e
x
c
e
e
d
i
n
g

A
v
e
r
a
g
e

l
e
v
e
l
s

b
y

2

St
a
n
d
a
r
d

D
e
v
i
a
t
i
o
n
s
Year -Quarter
Individual Sub-Reasons Exceeding Average Levels by 2 Standard
Deviations per Quarter
ICNU_DR_113 Attachment B Page 17 of 77
13

Figure 4, Top 10 Sub-Reasons with the Value of SAIFI Rising over Time
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
Top 10 OMT Sub-Reasons in growing Unreliability by SAIFI
Total
ICNU_DR_113 Attachment B Page 18 of 77

14

Figure 5, 2012 OMT SAIFI Contribution by Sub-Reason
Wind
14%
Undetermined
13%
Other
8%
Snow/Ice
8%
Lightning
8%
Maint/Upgrade
7%
Car Hit Pole
6%
Tree Fell
5%
Pole Fire
4%
Weather
4%
Squirrel
4%
Cutout/Fuse
2%
Transformer
2%
Conductor -Pri
2%
SEE REMARKS
2%
Connector -Pri
2%
Regulator
2%Bird
1%
Arrester
1%Tree
1%
Everything Else
5%
2012 SAIFI Contribution by OMT Sub-Reason
ICNU_DR_113 Attachment B Page 19 of 77

15

Figure 6, 2012 OMT Sustained Outage Comparisons
Maint/Upgrade 35.70%
Wind 9.70%
Undetermined
8.36%
Lightning
7.25%
Squirrel
4.54%
Snow/Ice 3.67%
Other 3.17%
Tree Fell 2.89%
Bird 2.73%
Cutout/Fuse 2.41%
Weather 2.09%
Car Hit Pole 1.86%
Transformer -OH 1.85%
Pole Fire 1.29%
Connector -Sec 1.10%
Fire 1.04%
Everything Else
10.34%
Sustained Events by OMT Subreason
ICNU_DR_113 Attachment B Page 20 of 77

16

Figure 7, 2012 OMT Events by Sub-Reason
Maint/Upgrade
25%
Customer Equipment
10%
Undetermined
7%
Foreign Utility
5%
SEE
REMARKS
4%
Other
3%Connector -Sec
3%
Squirrel
3%
Tree Fell
3%
Car Hit Pole
3%
Tree Growth
3%
Bird
3%
Weather
2%
Conductor -Sec
2%
Wind
2%
URD Cable -Sec
2%
Fire
2%
Service
1%
Lightning
1%
Cutout/Fuse
1%
Everything Else
14%
2012 OMT Events by Sub Reason
ICNU_DR_113 Attachment B Page 21 of 77
17

AM Related Material Used by Electric Distribution Minor Blanket, ER 2055
The Electric Distribution Minor Blanket, ER 2055, provides an opportunity to examine capital work that
replaces equipment for various reasons not associated with a specific job. This ER includes replacing
components known to be in bad order. By plotting the number of AM related material used in ER 2055
along with the number of OMT events each year, we see some interesting trends as shown in Figure
8Figure 8Figure 8. 2011 and 2012 saw some large swings compared to previous years. It is too early to
tell where the trends are headed, but a lot more work similar to Wood Pole Management was
accomplished in 2012 on aged and failing equipment and components than previously seen.

Figure 8, OMT Events and AM Related Material Used by ER 2055 by Year and their associated Trend Lines

Risk Action Curve Evaluation
For the year 2012, three different OMT Sub-Reasons exceeded the Risk Action Curve annual threshold
than we have seen the past two years, Car Hit Pole, Snow/Ice, and Transformer. Figure 9 shows the
Customer/Event values for 2007 -2012 as a bar chart and the Risk Action Curve thresholds for each year
as a line for all of the Sub-Reasons that have exceeded the Risk Action Curve at least two times. When
the bar chart value is above the limit line for a particular Sub-Reason, the Sub-Reason has exceeded the
threshold value. Examining 2012 on Figure 9, shows that all three Sub-Reasons exceeded the threshold
values by a small margin. For 2012, many of the past issues performed much better and those that
exceeded the Risk Action Curve seem to be an anomaly.
y = 362.83x -716526
y = -113.03x + 230343
y = 1844.9x -4E+06
0
5000
10000
15000
20000
25000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Total OMT Events by Year AM Related Total OMT Events
AM Distribution Minor Blanket Material Uage Linear (Total OMT Events by Year )
Linear (AM Related Total OMT Events)Linear (AM Distribution Minor Blanket Material Uage)
ICNU_DR_113 Attachment B Page 22 of 77
18

Figure 9, Customers Affected Per Event Exceeding Risk Action Levels
0
500
1000
1500
2000
2500
3000
0
500
1000
1500
2000
2500
3000
2007 2008 2009 2010 2011 2012
Av
e
r
a
g
e

N
u
m
b
e
r

o
f

C
u
s
t
o
m
e
r
s

a
f
f
e
c
t
e
d

p
e
r

E
v
e
n
t
Year
Car Hit Pole Lowside OCB/Recloser Other Pole Fire
Snow/Ice Transformer Relay Misoperation Car Hit Pole -Limit
Snow/Ice -Lmit Transformer -Limit
ICNU_DR_113 Attachment B Page 23 of 77
19

Specific Distribution Programs and Assets
In the following sections, AM reviews the different programs and work done to determine an AM action
plan for particular assets. Some plans indicated the current case or no action was the best approach and
others indicated there was an appropriate action for managing an asset. If a plan was implemented,
then the available information will be reviewed to determine how the plan has impacted the system.
Distribution Wood Pole Management (WPM)
The current WPM program inspects and maintains the existing distribution wood poles on a 20 year
cycle. Avista has 7,793 circuit miles of Distribution lines that is predominately overhead. The average
age of a wood pole is 28 years with a standard deviation of 21 years. Nearly 20% of all poles are over 50
years old and we have an estimated 240,000 distribution poles in the system. This means that about
48,000 poles are currently over 50 years old. Our inspection cycle allows us to reach approximately
12,000 poles each year. Along with inspecting the poles, we inspect distribution transformers, cutouts,
insulators, wildlife guards, lightning arresters, crossarms, pole guying, and pole grounds. The inspection
of these other components on a pole drives additional action to replace bad or failed equipment along
with replacing known problematic components. These additional inspection items have expanded the
current program beyond the original scope but have proven a cost effective way to address more than
just the wood pole issues.
Selected KPIs and Metrics
AM selected the number of OMT Events by Year related to WPM work and feeder miles of follow-up
work completed verses miles of feeders inspected as KPIs to monitor WPM. These KPI relate to
reliability performance, cost performance, and customer impacts. Our goal is to maintain or reduce the
number of OMT events related to WPM. The current plan optimized the inspection cycle based on cost,
so the impacts to reliability were addressed only as it related to costs. The goal for these KPI is to stay
below the number of events averaged over 2006 – 2010 for WPM Related OMT Events. See Table 7 for
the goal and for the actual value for 2012. The Goal for the KPI is the 5 year average value using 2006-
2010. The OMT Events KPI is a lagging KPI and an indication of how well past work has impacted
outages. The feeder miles of follow-up work completed verses miles of feeders inspected KPI is a
leading indicator and reflects how outages in the future will be impacted by the work. The number of
miles inspected is shown in Table 7 for the goals and actual values.
The feeder miles of follow-up work completed verses miles of feeders inspected KPI comes from the
annual Distribution WPM inspection plan and is the sum of all miles of the feeders completed in that
year. The completed number of miles for follow-up work on feeders comes from Asset Maintenance
based on their tracking of the work as it is completed. However, many poles are addressed by the
Distribution Grid Modernization Program which has not been included into the count. The purpose of
this metric is to evaluate how much backlog work is created each year in order to adjust future year’s
budgets. Based on analysis of the current backlog, a revised budget of ~$11 million was recommended
in 2014 to help catch up on the backlog of work.
ICNU_DR_113 Attachment B Page 24 of 77

20

Table 7, WPM KPI Goals by Year
KPI
Description
WPM Goal Related
number of OMT Events
Actual WPM
Related number
of OMT Events
Projected Miles
Follow-up Work
Actual Miles Follow-
up Work Completed
2009 1460 1320 500 372
2010 1460 1004 450 435
2011 1460 1004 459 333
2012 1460 1013 416 435
2013 1460 445 2014 1460 412 2015 1460 446 *Note: Beginning with 2012, the Actual Miles Follow-up Work Completed will include WPM and
Distribution Grid Modernization miles.
Metrics provide a more detailed review of WPM. WPM metrics involve more information and
calculations than the KPIs and include: WPM contribution to the annual SAIFI number; number of
distribution wood poles inspected; material usage for WPM by Electric Distribution Minor Blanket and
Storms; number of Pole-Rotten OMT Events; Crossarms-Rotten OMT Events; and actual material use
verses model predicted material use for WPM follow-up work (see Table 8). The WPM contribution to
the annual SAIFI number metric comes from data pulled out of OMT by Cognos and calculated the
average impact to SAIFI per event by Sub-Reason.
The average impact to SAIFI per WPM event is the sum of the average impact to SAIFI for Arresters,
Cutouts/Fuses, Crossarms, Insulators, Insulator Pins, Pole Fires, Poles – Rotten, Squirrels, Transformers-
OH, and Wildlife Guards. The average impact to SAIFI for WPM events is then multiplied by the number
of event causing an outage or partial outage (this is the sum of OMT events causing an outage or partial
outage for Arresters, Cutouts/Fuses, Crossarms, Insulators, Insulator Pins, Pole Fires, Poles – Rotten,
Squirrels, Transformers-OH, and Wildlife Guards). The goal for this metric is the five year average for
2005-2009. The purpose of this metric is to ensure WPM maintains the current reliability.
The number of Distribution System poles inspected metric measures the annual plan for inspecting
wood poles against how much work was actually completed. The AM plan calls for a 20 year inspection
cycle which was originally estimated to be ~12,000 poles per year. The AM plan also represents
inspecting 17.5 feeders a year. This metric ensures the WPM program meets the AM plan for
Distribution Wood Poles.
Material Usage for WPM By Electric Distribution Minor Blanket and Storms metric monitors other areas
outside of AM that may reflect trends for WPM. Key stock numbers (see Appendix B of the “2013 Asset
Management Electrical Distribution Program Review and Metrics”) are monitored in the Electric
Distribution Minor Blanket (ER 2055) and Electric Failed Plant – Storms (ER 2059). The number of stock
items used is tracked and compared to the average used in 2006-2010 as a baseline. The purpose is to
monitor for asset failures not indicated by OMT data, since not all failure information is captured by
OMT.
ICNU_DR_113 Attachment B Page 25 of 77

21

The final metric, material use verses model predicted material use, tracks the actual number of key
stock numbers (see Figure 14 for assets monitored) against what the AM model predicted. Discoverer is
used to pull stock number usage out for the applicable stock numbers and then they are compared to
the AM model predictions. The purpose of this metric is to measure the performance of the model to
predict the future outcomes. If the difference between the model predictions and actual values
becomes more than 30%, the model should be revised.

Table 8, WPM Metric Goals by Year
WPM KPI Performance
Figure 10 shows the trends in OMT events for the Sub-Reasons associated with WPM and generally the
trend in OMT events is downward. The major contributors (Cutouts/Fuses, Pole Fire, Squirrel, and
Transformer – OH) all showed a general trend downward over the past 5 years. Three of the four major
contributors showed improvements from 2009 (Pole Fire, Squirrel, and Cutouts) with the Squirrel sub-
reason dropping drastically in the last year. Overall, WPM is controlling the number of OMT events. The
leading indicator, Miles Follow-up Work Completed, shows we are falling behind in addressing issues
identified during the inspection. If this backlog continues to grow, it will begin to impact the number of
OMT events into the future. We plan to address the backlog by completing more Distribution Grid
Modernization work and increasing funding for the follow-up work in 2015.
Metric Description
Projected WPM Contribution To The Annual
SAIFI Number
Actual WPM
Contribution To The Annual SAIFI Number
Projected Number of Dist Poles
Inspected
Actual Number of Dist Poles
Inspected
Projected
Material Usage For WPM By Elec Dist Minor
Blanket and Storms
Actual Material
Usage For WPM By Elec Dist Minor
Blanket and Storms
2009 0.214024996 0.1863468 12600 13,161 14,391 18524
2010 0.208489356 0.19916836 12600 15,553 14,391 10266
2011 0.211022023 0.202462739 12600 13,324 14,391 12176
2012 0.211022023 0.16613099 12600 17,318 14,391 22202
2013 0.211022023 12600 14,391 2014 0.211022023 12600 14,391 2015 0.211022023 12600 14,391
Metric Description
Model Predicted
Material Use for WPM Follow-up Work
Actual Material Use for WPM Follow-up
Work
Projected
Number of Pole Rotten OMT Events
Actual
Number of Pole Rotten OMT Events
Projected
Number of Crossarm OMT Events
Actual Number of Crossarm OMT Events
2009 4792 7538 137 44 32 25
2010 4932 7904 137 37 32 23
2011 5010 28011 137 35 32 28
2012 6770 28120 137 52 32 19
2013 8592 137 32 2014 10566 137 32 2015 12606 137 32
ICNU_DR_113 Attachment B Page 26 of 77

22

The KPI “Actual Miles Follow-up Work Completed” provides an indication of what could happen to the
other metrics (see Table 7). Simply inspecting the poles does not improve the systems performance.
The follow-up work to the inspection needs to get completed. This metric shows follow-up work
carrying over into 2013. The driver for WPM is a 20 year inspection cycle and if allowed to fall behind,
the WPM follow-up work could become a major financial issue and reliability risk for future years. While
Cutouts/Fuses, Pole-Fire, Transformer – OH, and Squirrel Sub-Reasons have other programs to address
these issues, only the WPM program addresses Arrester, Crossarms, Insulator, Insulator Pin, Poles, and
Wildlife guard issues. The issues only addressed by WPM do not show the same improvement as the
issues addressed concurrently by other programs.
Grid Modernization work discussed later in this document also impacts the same metrics as WPM. For
2012, we revised the metrics and now include the miles of completed Grid Modernization work in the
Table 9Table 9Table 9 since the work is coordinated with WPM and intended to help address the
backlog in WPM.
WPM Metric Performance
The annual contribution to SAIFI trend improved in 2012 even further and remains below the five year
average value as shown in Table 8 and Figure 11. Overall, WPM has been effective at maintaining the
current level of reliability to our customers.
The number of Distribution poles inspected measures how well the program is performing against a 20
year inspection cycle. The goal is to inspect every feeder once every 20 years. The work to perform the
wood pole inspections is tracked based on the number of poles inspected. Using miles can work, but
different feeders have different pole densities per mile and the way the contractor bills for the
inspection work makes using the number of poles inspected easier. The results of the work exceeded
the planned number of inspections shown in Table 9Table 9Table 9. The completed inspections are
following the AM plan for WPM very nicely. Other work besides WPM has contributed significantly to
the number of poles inspected annually over the past two years. The Smart Grid project worked on a lot
of poles not part of WPM along with the Transformer Change Out Program and increased the numbers
of poles inspected in 2012.
Figure 12Figure 12Figure 12 shows how Avista’s use of Distribution Wood Poles changed with time. This
graph supports a growing number of pole and WPM related issues. Based on poles lasting 74 years
before they will be replaced on a planned basis, Avista would need to replace 3,200 poles per year at
equilibrium. We finally reached and exceeded 3,200 poles per year in 2012. Figure 13 shows how an
increasing number of poles are reaching 74 years so we anticipate replacing more than 3,200 poles each
year for many years. As shown in Table 8, we are using more material in WPM and the Electric
Distribution Minor Blankets to address our aging and failing equipment. We expect this trend to
continue for another 10 years before it stabilizes based on a model developed in 2012.
WPM Model Performance
The AM model for WPM provided a baseline for estimating the future costs of the follow-up work, but it
under predicted the number of components for Lightning Arresters and Wildlife Guards (see Figure 14
ICNU_DR_113 Attachment B Page 27 of 77

23

and Table 10). For our WPM, Lightning Arresters and Wildlife Guards are minor components compared
to poles, Crossarms, and Transformers, so when you ignore these two items, the model performed
within the 30% margin. Currently, we don’t plan on updating the model until we have a few more years
of data since this model was completed in 2012.
WPM Summary
The main message from the KPI and metrics for WPM is that we are moving in the right direction, but
we are falling behind and will need to complete work on more feeder miles to control the impact on
future reliability.

ICNU_DR_113 Attachment B Page 28 of 77
24

Figure 10, WPM OMT Event Trends
0
100
200
300
400
500
600
700
800
OM
T

E
v
e
n
t
s

b
y

S
u
b

R
e
a
s
o
n
OMT Sub Reason
WPM OMT Events by Sub Reason and Year
2008 2009 2010 2011 2012
ICNU_DR_113 Attachment B Page 29 of 77

25

Figure 11, WPM Contribution to Annual SAIFI value by Sub-Reason and Year
0
0.02
0.04
0.06
0.08
0.1
0.12
Annual SAIFI Contribution by Sub Reason
2008 2009 2010 2011 2012
ICNU_DR_113 Attachment B Page 30 of 77

26

Figure 12, Wood Pole Used by Summarized Activity
0
1000
2000
3000
4000
5000
6000
2005 2006 2007 2008 2009 2010 2011 2012 2013
Nu
m
b
e
r

o
f

P
o
l
e
s

U
s
e
d
Year
Distribution Wood Pole Replacement History and Trend
Number of poles Used Annually Poles Replaced WPM -Dist
ICNU_DR_113 Attachment B Page 31 of 77

27

Figure 13, Distribution Wood Pole Age Profile

0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
1910 1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020
Pe
r
c
e
n
t
a
g
e

o
f

P
o
l
e

P
o
p
u
l
a
t
i
o
n
Year Installed
Wood Pole Age Profile
ICNU_DR_113 Attachment B Page 32 of 77

28

Figure 14, WPM Model Projections vs Actual Usage for 2012
0
500
1000
1500
2000
2500
3000
3500
Poles Replaced
Crossarms Replaced
Steel Stubs
Lightning Arresters
Cutouts
Wildlife Guards
Actual vs. Model Projected Usage for WPM
Actual Modeled Projected
ICNU_DR_113 Attachment B Page 33 of 77
29

Wildlife Guards
Wildlife caused outages have a significant impact on electric service reliability to customers. The
improved outage tracking implemented in 2001 has consistently shown, within a percent or two either
way, that animal’s cause 19% of outages experienced by electric customers. While generally short in
duration, labor impacts to respond are significant. In 2010, Squirrels accounted for only 6% of all
sustained outages (see Table 9Table 9Table 9) which is a significant drop from 2009 value of 12%. This
trend downward has continued so in 2012 only 3% of sustained outages were caused by Squirrels.
When complete, it is estimated that O&M savings will be $220,000 per year in labor costs, assuming
guards are 80% effective. There will also be a capital benefit, because a small percentage of
transformers are damaged and must be replaced due to wildlife outages.
Selected KPIs and Metrics
The goal of the Wildlife Guards program is to reduce the number of Animal caused outages on the
distribution system. More specifically, the program targets reducing the number of squirrel caused
outages. Since the plan estimates that installing guards on the worst 60 feeders will reduce the number
of Squirrel caused outages by 50%. 2006 was selected as the starting point, because the work
performed that year was not influenced by the current AM plan as seen in Figure 15. The final goal was
a 50% reduction from the 2006 value of 902; however, this year’s value of 358 already exceeds the final
goal and has for the past three years.
The second KPI is the number of Distribution Feeders completed for the Wildlife Guard Installation
program. This KPI measures how effective we were at following the plan. The annual goal for the five
year program was 12 feeders a year but was modified each of the previous years based on available
budget. WPM is also installing wildlife guards as well and is on top of the number included here. The
WPM program does address some of these worst 60 feeders, but is not driven by this program. WPM’s
role in Wildlife Guards is to install them on the remainder of the Distribution system over the next 15
years on transformers or poles they work on for other reasons. Since the number of feeders completed
has nearly reached 60 feeders, Avista will drop this KPI in the near future.
The third KPI used is the percentage of sustained outages caused by Squirrels. This KPI provides a
relative impact squirrel related outages are having on the system and represents the future value of
installing Wildlife Guards on Distribution Transformers.
The only metric for Wildlife Guards is the annual avoided outage benefit from Squirrel related outages.
We estimate $82 in benefit for every outage avoided starting in 2011. Using this benefit per event, the
projected avoided outage benefit by year is the difference between 902 events in 2006 and projected
number of events for that year multiplied by $82. The goals by year for the next four years and for 2010
are shown in Table 10.
ICNU_DR_113 Attachment B Page 34 of 77

30

Table 9, Wildlife KPI Goals for 2010 - 2015
KPI
Description
Projected
Number of
Squirrel
OMT Events
Actual
Number of
Squirrel OMT
Events
Projected Number
of Feeders
Completed via
Program
Actual Number
of Feeders
Completed via
Program
Percentage of
sustained
outages caused
by Squirrels
2009 810 700 12 17 12.2%
2010 720 390 4 23 5.62%
2011 630 395 12 7 3.11%
2012 540 358 8 8 2.71%
2013 450 0
2014 450 0
2015 450 0

Table 10, Wildlife Metric Goals for 2010 - 2015
Metric
Description
Projected Avoided Outage Benefit due
to Squirrel Caused Outages
Actual Avoided Outage Benefit due to
Squirrel Caused Outages
2009 $36,000 $47,190
2010 $71,000 $157,466
2011 $22,000 $34,696
2012 $30,000 $37,935
2013 $37,000 2014 $37,000 2015 $37,000 *Note: Avoided costs were revised from $390 per event to $82 for 2011 and 2012 values. This change
was based on a review of costs.
WILDLIFE GUARDS KPI Performance
Installing Wildlife Guards has exceeded expectations so far and have cut into the number of OMT events
for Squirrels. The original model estimated costs were higher than actual costs because the model
assumed more guards would be needed. So, the saved money has been used to work on more feeders
than originally planned in the model. Based on Figure 15 and Figure 16, Wildlife Guard installations
made a big jump driven largely by work in Moscow to install the guards on the worst feeders in Avista’s
system for squirrel related outages in 2007. This work had an immediate impact on the number of
events in 2008 and 2009 (see Figure 8). In 2010, the program was funded along with WPM work to
install 1017 wildlife guards.
WILDLIFE GUARDS Metric Performance
The main purpose of the Avoided costs metric shown in Table 10 is to demonstrate the savings
associated with the work from the original model. In 2010, Avista saw savings nearly triple the
projected amount. Other work such as Electric Distribution Minor Blanket and WPM continue to install
Wildlife Guards on Distribution Transformers. However, the large increase in savings is most likely due
to the increase in the number of feeders completed in 2010.
ICNU_DR_113 Attachment B Page 35 of 77

31

WILDLIFE GUARDS Model Performance
The Wildlife Guard model over estimated the impact of the work performed (see Table 9Table 9Table 9),
so our performance has exceeded our expectations. This exceeds the goal of being within +/- 30% of the
actual value. However, since the program has accomplished its purpose, no further work is planned.
WILDLIFE GUARDS Summary
The Wildlife Guard program shows real cost savings over time. The work in WPM and other efforts to
install wildlife guards on Distribution Transformers will create even more savings into the future.
However, continuing a Wildlife Guard installation program is no longer justified. Examining Table 11
shows the current top 10 worst feeders represent 159 outages but only provides an opportunity to save
$3,500 annually (159 outages * 80% effectiveness * $82/3 years = $3,500 annually). At a cost of
~$360,000 to install Wildlife Guards on ten feeders, we estimate the time to payback the cost of
installation at 100 years. Continuing the program as a separate program no longer justifies future costs.

Table 11, Worst Feeders for Squirrel related Events for 2010 - 2012
Feeder Sustained
Outages
Momentary
Outages
Combined
Outages
Percentage
of all
Squirrel
related
Outages
Running
Percentage
WAK12F2 19 0 19 1.79% 1.79%
SLW1358 18 0 18 1.70% 3.49%
WAK12F1 17 1 18 1.70% 5.18%
PDL1203 17 0 17 1.60% 6.79%
CFD1210 15 1 16 1.51% 8.29%
CLV34F1 16 0 16 1.51% 9.80%
VAL12F1 14 1 15 1.41% 11.22%
OGA611 14 0 14 1.32% 12.54%
CHE12F1 13 0 13 1.23% 13.76%
CHW12F2 13 0 13 1.23% 14.99%

ICNU_DR_113 Attachment B Page 36 of 77
32

Figure 15, Wildlife Guards Installed by Year and Expenditure Request

-500
0
500
1000
1500
2000
2500
3000
Wildlife Guards Issued by ER and Year
2008 2009 2010 2011 2012
ICNU_DR_113 Attachment B Page 37 of 77

33

Figure 16, Wildlife Guards Usage by MAC for 2005-2010
0
500
1000
1500
2000
2500
3000
3500
4000
Wildlife Guard Issued by MAC and Year
2008
2009
2010
2011
2012
ICNU_DR_113 Attachment B Page 38 of 77

34

URD Primary Cable
URD Primary Cable replacement addresses aging underground primary distribution cable, commonly
referred to as URD (Underground Residential District). URD installation began in 1971. Over 6,000,000
feet of URD was installed before 1982. Outage problems exist on cable installed before 1982, cable
installed after 1982 has not shown the high failure rate of the pre-1982 cable. Programmed
replacement of the problem cable has been on-going at varying levels of funding since 1984. Emphasis
is on the original vintage of URD. That cable was not jacketed with a protective layer of insulating
material, neutral conductor was bare tinned copper concentric type construction on the outside of the
cable. Insulating material was vulnerable to water intrusion. Based on the historical data, we estimated
that approximately 72,000 feet of the pre-1982 cable remains in service as of January, 2013.
Historically, over 200 faults of primary cable happen annually. There have been as many as 264 primary
cable faults in 2003. During 2007 there were 168 primary faults. From 1992 faults increased from 2 per
10 miles of cable to 8 per 10 miles in 2005. The number of faults per mile has stabilized between 2005 –
2007 after steadily climbing between 1992 and 2005.
Funding for URD Primary Cable replacement was significantly increased in 2007 and began the current
program. The program had an original estimate of 5 years to complete but the funding has not matched
the original plan, but almost all of the work was accomplished over six years. The year 2012 represents
the last year of major funding for the program since the number of outages has significantly dropped
and the worst feeder for URD Cable – Pri failures only had two outages. We anticipate some low level of
funding to remain for the last of the cable as it fails to get the last remaining segments and will continue
to monitor the results.
Selected KPIs and Metrics
We selected two KPIs to track for URD Primary Cable replacement, URD Primary OMT Events and
number of feet replaced each year. The goals for each of these KPIs came from the trends observed
over the past few years and set a goal to complete the replacement of URD Primary cable in 2012. Table
12 shows the goals for each KPI by year. The OMT events reflect the impact to our system of past work.
The number of feet of URD Primary Cable replaced acts as a precursor to future OMT performance.
After the first generation of URD Primary Cable has been replaced, the second generation will need to
be monitored and plan established for addressing this vintage of cable.

ICNU_DR_113 Attachment B Page 39 of 77

35

Table 12, URD Cable - Pri KPI Goals
KPI
Description
Projected URD
Cable - Primary
OMT Events
Actual URD
Cable -
Primary OMT
Events
Projected
Number of
Feet Replaced
Actual Number of Feet
Replaced
2009 143 136 178000 213,000
2010 119 93 178000 217,883
2011 94 95 178000 225,823
2012 70 72 178000 117,247
2013 45 0 2014 45 0 2015 45 0

The selected metric for URD Primary Cable is the avoided costs due to cable faults. The savings is based
on a projected number of failures without the program of around 600 events per year. Each event on
average costs ~$2,680 due to the duration of the outage and the number of people involved in
correcting the fault. While this indicator is based on a projection, it provides a reasonable estimate of
the return on investment for the money spent to replace this vintage of cable. Table 13 projects the
anticipated avoided outage benefit by year for the estimated number of avoided outages.
Table 13, URD Cable - Pri Metric Goals
Metric
Description
Projected Avoided Outage
Benefit due to URD Cable - Pri
Caused Outages
Actual Avoided Outage Benefit
due to URD Cable - Pri Outages
2009 $1,038,613 $1,056,113
2010 $1,228,275 $1,295,225
2011 $1,368,561 $1,352,648
2012 $1,516,159 $1,481,504
2013 $1,744,539
2014 $1,898,311
2015 $1,997,052
URD PRIMARY CABLE KPI Performance
For 2012, the performance for URD Primary Cable met expectations and performed well. Table 12
shows that for both URD Cable – Pri events exceeded expectations. Figure 17 shows a steadily declining
trend in the number of events. If the trend continues, Avista should reduce the number of events to less
than 50 events in 2013. However, if the second generation of URD Primary Cable begins failing at an
ICNU_DR_113 Attachment B Page 40 of 77

36

increasing rate, it would signal the next round of cable replacements. We do have some faults in newer
cables and anticipate that this will be true for several years to come. Iif these faults begin to
significantly increase over time, we will have to begin replacement of this cable since the earliest of the
second generation cable is now approaching 30 years old.

Figure 17, URD Primary Cable OMT Events by Year

URD PRIMARY CABLE Metric Performance
The projected savings and estimated savings due to avoided outage costs for Avista came in very close
as seen in Table 13. The current program is performing as expected.
URD PRIMARY CABLE Model Performance
This AM model is an early vintage model and given the cash flow, did not match the model, it has
generally predicted performance reasonably well. The model performed sufficiently well. Because of
the good performance and limited remaining time for the program, the model will be retained as is and
the program allowed to expire once all of the first generation URD Primary Cable has been replaced.
0
20
40
60
80
100
120
140
160
180
URD Cable -Pri
OM
T

E
v
e
n
t
s

b
y

Y
e
a
r
URD Primary Related OMT Events by Year
2008 2009 2010 2011 2012
ICNU_DR_113 Attachment B Page 41 of 77

37

URD PRIMARY CABLE Summary
Several people have worked hard on this program and it is now nearing completion. We anticipate
another round of URD Cable replacements in the future, but we don’t have any evidence that we have
reached the end of life on the second generation of URD Cable. The program has succeeded in reducing
O&M costs by avoiding long and costly outages. Since all of the work to replace the cable comes from
capital spending, the program is a great example of how capital spending can reduce O&M. However,
operations continue to find more cable than estimated remaining, so future funding is recommended to
only cover planned work on known cable.
URD Secondary Cable
URD Secondary Cable does not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Open Wire Secondary
Open Wire Secondary does not have a planned AM program, so no specific metrics or KPIs have been
identified. While this area covers secondary conductors and connections, OMT does not provide any
direct link to Open Wire Secondary. Previous analysis indicated that this program was not financially
justified. However, future indication may drive us to re-evaluate the situation. We do anticipate that
the Distribution Grid Modernization Program will address many of these issues. The general metrics
discussed above for number of OMT Events (Table 1) and the associated action level; Risk Action Curve
limits; and requests by responsible parties will determine in the future if a plan will be developed or if
action is needed. In summary, this asset will be monitored to determine if and when planned actions
are needed.
Distribution Cutouts
Distribution Cutouts are addressed by the WPM program discussed above.
Distribution Air Switches
Distribution Air Switches do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Distribution Mid-Line Reclosers
For the Mid-Line Reclosers, no maintenance or planned replacement is recommended over the next 10
years. Feeder Reclosers are not easily accessible as in a substation, so any maintenance on them is
equivalent to a planned replacement. Our analysis indicates that any planned replacement program is
not cost effective for our customers. Further analysis will be performed to ensure this is the correct
approach, but until information is available, no change in our current approach is recommended.
ICNU_DR_113 Attachment B Page 42 of 77

38

The Smart Grid work has replaced and installed new Mid-Line Reclosers and switches that now provide
monitoring and remote operations. We have plans to analyze these new devices to determine a
maintenance and replacement strategy specifically for Smart Grid devices.
The general metrics discussed above for number of OMT Events (Table 1) and the associated action
level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a plan
will be developed or if action is needed. In summary, this asset will be monitored to determine if and
when planned actions are needed.
Distribution Mid-Line Voltage Regulators
Avista’s distribution system includes 1,171 Voltage Regulators located in substations and out on the
distribution feeders. The age profile has a large portion of regulators around 30 years old with ~38% of
all voltage regulators being over 30 years old but only 1% greater than 40 years old. When regulators
fail, they will cause an outage 81% of the time and add 0.005 to the overall SAIFI value per event. The
average outage duration for regulator failures is 2.7 hours. On average, 30 to 40 regulators per year
come to the shops for repair, refurbishment, or replacement for a variety of reasons. Some come in
because of failures but many are brought in because of changes and other work to be refurbished and
re-used. On older voltage regulators, we have also seen that they have higher losses, and by replacing
them, Avista could save an estimated $138,000 in energy savings on regulators over 20 years old.
AM analyzed four cases in detail in 2010 to find the best program for managing the voltage regulators.
We examined the current case, replacing all the regulators with new regulators at a specific interval,
refurbishing/rebuilding all regulators, and finally replacing the older regulators and refurbishing the
newer regulators. The analysis identified a program that replaces the oldest regulators and refurbishing
the new ones as the best approach to manage the regulators. The replace/rebuild program provides an
8.37% IRR compared to a 5.00% IRR for the base case. The plan will replace an average of 50 Voltage
Regulators per year in the near term. Then the newer Voltage Regulators will be refurbished when they
reach 35 years old or come in from the field for other reasons.
Due to a lack of craft resources, this program has not been implemented and remains in a monitoring
mode. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine if and when the
plan will be implemented or modified.
Primary Conductors
Primary Conductors do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
ICNU_DR_113 Attachment B Page 43 of 77

39

Primary Connections
Primary Connections do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Secondary Conductors
Secondary Conductors do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Secondary Connectors
Secondary Connectors do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
Distribution Transformers
In 2011, Avista implemented the Transformer Change Out Program (TCOP) to replace all Distribution
Transformers containing PCB’s followed by replacing all pre-1981 transformers. The driver for the
program is to reduce the risks associated with PCB’s in transformers and improve the overall electric
distribution system by eliminating higher loss transformers.
The program has two strategies associated with it. The first strategy is to eliminate all transformers
containing or potentially containing PCB’s. The initial focus was on areas near water sources and now
has moved to all transformers containing PCB’s as the water regions are done. These transformers have
specific work plans to remove them from the system. The second strategy uses the Wood Pole
Management program to remove all pre-1981 transformers as part of their follow-up work on a feeder.
The first strategy work should be completed in 2016 and the Wood Pole Management work should have
all the pre-1981 transformers replaced by 2036.
Selected Metrics
Table 14 shows the metrics selected for TCOP. The number of transformers changed out represents the
reduction of future risk from PCB’s. It also provides a leading indicator of how many future transformer
failures we may experience. The energy savings represents the value of changing out the less efficient
transformers and quantifies the approximate amount of energy saved each year by replacing less
efficient transformers with more efficient ones.

ICNU_DR_113 Attachment B Page 44 of 77

40

Table 14, TCOP Metrics
Year
Planned
Number of
Transformers
Changed Out
Actual Number of
Transformers
Changed Out
Planned Energy
Savings from
Transformers
(MWh)
Actual Energy Savings
from Transformers
(MWh)
2012 2,687 2,529 2,304 2,430
2013 2555 2,304
2014 2930 2,304
2015 305
2015 –
Pad/Subm 2,030 1,447
2016 –
Pad/Subm 2,335
Note: values in red have negatively missed the goal.

Metric Performance
While we removed fewer transformers than anticipated, the ones removed were significantly older and
provided more energy savings than anticipated. Both metrics were within 5% of the target and TCOP is
providing the anticipated benefit.
Summary
The TCOP is accomplishing it objectives and reducing Avista’s and customer’s risks associated with
Distribution transformers containing PCB’s and providing energy savings.
Area and Street Lights
Asset Management converted the existing area and street light data into our Geographical Information
System (GIS) in 2012 and will continue the work through 2014. This work will update and correct the
existing information and provide a platform to convert our High Pressure Sodium (HPS) lights to Light
Emitting Diode (LED) fixtures in the future. The recent cost and reliability improvements in LED lights
have made converting lights to LED fixtures cost effective. We anticipate replacing the 100 watt HPS
street lights to LED fixtures in 2015, once a rate schedule for LED lights has been approved for use.
Until a conversion program is implemented, no KPI’s or metrics have been established to monitor area
or street lights.
Riser Terminations
Riser Terminations do not have a planned AM program, so no specific metrics or KPIs have been
identified. The general metrics discussed above for number of OMT Events (Table 1) and the associated
action level; Risk Action Curve limits; and requests by responsible parties will determine in the future if a
plan will be developed or if action is needed. In summary, this asset will be monitored to determine if
and when planned actions are needed.
ICNU_DR_113 Attachment B Page 45 of 77

41

Dead End Insulators
Dead end Insulators do not have a planned AM program outside of work identified as part of Wood Pole
Management, so no specific metrics or KPIs have been identified. The general metrics discussed above
for number of OMT Events (Table 1) and the associated action level; Risk Action Curve limits; and
requests by responsible parties will determine in the future if a plan will be developed or if action is
needed. In summary, this asset will be monitored to determine if and when planned actions are
needed.
Distribution Capacitors
Distribution Capacitors do not have a planned AM program, so no specific metrics or KPIs have been
identified. Smart Grid work has added switch capacitors to our system but our initial analysis did not
indicate any maintenance or replacement strategy was justified. The general metrics discussed above
for number of OMT Events (Table 1) along with the associated action level; Risk Action Curve limits; and
requests by responsible parties will determine in the future if a plans are needed. In summary, this
asset will be monitored to determine if and when planned actions are needed.
9CE12F4 Partial Feeder Rebuild
This program was created to integrate several AM programs into a comprehensive program to address
feeder’s issues at one time and then not have to return to the feeder for several years. This program
combined WPM, re-conductoring, transformer replacement and reconfiguration, Wildlife Guards,
Vegetation Management, and other work that fit. While the project created a list of feeders along with
a priority ranking, the only work funded was on Ninth and Central Substation feeder 12F4 in Spokane.
The main drivers for the project were energy savings efficiency for the redesign portion of the work and
integrated AM work to gain labor efficiency.
In 2011, Avista implemented a Feeder Upgrade Program based on this work that will be discussed
below. We retained this program here to provide a place to document the results of the work
competed in 2009.
Selected KPIs and Metrics
Since the program was a one year project, the only metric selected is the number of OMT events
associated with the feeder. No KPI was selected since there are no further actions planned or
anticipated on this feeder. We did not develop an OMT performance metric when the model was
created, but we will monitor the OMT results to see how the work impacted the feeder’s reliability.
Avista’s crews completed the work on the feeder at the end of 2009 along with the WPM inspection and
Vegetation Management work.
Partial Feeder Rebuild KPI Performance
No KPI’s were selected nor tracked for this program.
Partial Feeder Rebuild Metric Performance
Since the work on Feeder 9CE12F4 was completed in 2009, we monitor the OMT data for the feeder to
see how reliability is impacted. Figure 18 shows the trends and shows that the work has made a
ICNU_DR_113 Attachment B Page 46 of 77

42

significant impact on the feeder’s performance driving the number of OMT events to their lowest levels
in recent records. Along with Figure 18, Figure 19 provides a baseline and trends on specific measures
we anticipated the work would impact. Based on the available OMT data for 2012, the work did impact
performance but the real benefit took three years to realize. While weather does impact these
numbers, the impact on equipment failures is clearly improved.

Figure 18, All OMT Sub-Reasons except Maint/Upgrade for Feeder 9CE12F4 2002-2010
0
10
20
30
40
50
60
70
80
2000 2002 2004 2006 2008 2010 2012 2014
All OMT Sub-Reasons Except Maint/Upgrade
ICNU_DR_113 Attachment B Page 47 of 77

43

Figure 19, Selected OMT Trends for AM Related Events with Upward Trends for Feeder 9CE12F4
Partial Feeder Rebuild Model Performance
The model did include some projections for future performance, but we have selected not to evaluate
this model. The actual work performed exceeded the scope of the model, since it included Open Wire
Secondary work. The AM model had predicted a work cost of $1.1 million excluding the following: WPM
inspection costs, Vegetation Management, and Open Wire Secondary work. The total cost of modeled
portion of the project came in at $1.1 million and an additional $1 million work of work was added on
top of this. In future models, all of the work will need to factor the lessons learned into the model to
improve costs projections.
Partial Feeder Rebuild Summary
The 9CE12F4 feeder performed very well in 2012, but we anticipate 2013 and 2014 will see more
Vegetation Management issues as the feeder approaches its five year cycle for Vegetation Management
work. Based on previous work on Vegetation Management models, the first year after clearing a feeder
results in some infant mortality type vegetation issues. When a line is cleared, some of the remaining
vegetation is weaker because it no longer has the other branches or vegetation that provided additional
support. This results in some vegetation issues that first year after clearing when the weaker structures
fail under windy or other loading situations. Usually years 2-3 between clearings have the lowest
number of vegetation issues and then years 4-5 see a buildup of issues as the next clearing approaches.
0
1
2
3
4
5
6
7
8
9
2006 2007 2008 2009 2010 2011 2012
Growing OMT Trends for AM Related Events on 9CE12F4
Connector -Sec 9CE12F4 Crossarm-rotten 9CE12F4 Lightning 9CE12F4 Pole-rotten 9CE12F4
Service 9CE12F4 Snow/Ice 9CE12F4 Squirrel 9CE12F4 Tree Fell 9CE12F4
Tree Growth 9CE12F4 URD Cable -Sec 9CE12F4 Weather 9CE12F4
ICNU_DR_113 Attachment B Page 48 of 77

44

Chance Cutouts
This program focused on replacing a particular brand of cutout showing signs of premature failure. The
bulk of the work was completed in 2007 and 2008. However some outlying areas did not participate as
planned and had some remaining into 2012. The program and associated funding was spent on
replacing several cutouts in the system and did replace the anticipated number of cutouts. However, an
initial assumption of how many cutouts remain was too low, so the actual number in the field was
higher. The work of WPM and other types of work has effectively eliminated the remaining Chance
cutouts. The future cutout failures will come from all the non-Chance cutouts and should levelize
around 150 events per year.
Selected KPIs and Metrics
The goal of the Chance Cutouts was to save money. The KPI selected is the annual projected avoided
outage benefit shown in Table 15Table 15Table 15. The estimated benefits are quite substantial and
anticipated making a large impact on cutting the number of failures. The only action that can be taken
in the future is through the WPM program, so the KPI and Metrics will be lagging indicators.
The selected metric is the number of OMT events. While normally OMT events are the KPI, it was
selected as the metric since the project was funded with Productivity money and is reported quarterly
as an estimate of the cost savings. Table 15Table 15Table 15 shows the goals for the number of OMT
events under the “Projected OMT Events w/ Action” column.
Table 15, Chance Cutout Replacement KPI and Metric Goals
Year Projected OMT Events w/o
Action
Projected OMT Events
w/ Action
Projected Annual
Avoided Outage
Benefit
2009 380 91 $654,000
2010 430 78 $671,000
2011 480 106 $665,000
2012 510 80 $640,000
2013 550 152 $579,000
2014 560 152 $524,000
2015 560 152 $524,000

Chance Cutouts KPI and Metric Performance
Both the KPI’s and Metrics shown in Table 16Table 16Table 16, failed to meet their goal. Two factors
appear to be contributing to the lower than expected results. While the Chance cutouts did remain in
the system, a larger portion of the failures came from all the other cutouts than anticipated. The model
appears not to have accurately predicted the number of failures due to other types of cutouts in the
early phases of the work. However, we appear on track to achieve 150 failures a year based on WPM
work and Feeder Upgrade work addressing other issues with cutouts.

ICNU_DR_113 Attachment B Page 49 of 77

45

Table 16, Chance Cutout KPI and Metric Performance
Year
Projected OMT
Events w/o
Action
Projected
OMT Events
w/ Action
Actual
Number of
OMT Events
Projected
Annual
Avoided
Outage
Benefit
Measured
Annual
Avoided
Outage
Benefit
Percent
Model
Error
2009 380 91 197 $654,000 $ 366,000 216%
2010 430 78 217 $671,000 $ 438,780 278%
2011 480 106 176 $665,000 $577,600 166%
2012 510 80 209 $640,000 $583,338 261%
2013 550 152 $579,000
2014 560 152 $524,000
2015 570 152 $524,000
Note: values in red have negatively exceeded the goal.

Figure 20, Cutout/Fuse OMT Event Comparison between Actual, Projected without Action, and Projected
with Action
Chance Cutouts Model Performance
The model performance for Chance Cutouts provided a good indication of the trends but failed to
accurately predict the trends. The model for future cutout analysis will need to be updated and
improved to better predict future trends. The method of completing the work also caused the actual
values to deviate from the model. The differences in actual work compared to projected mainly comes
from the number of Chance Cutouts remaining in the system was more than anticipated as an
0
100
200
300
400
500
600
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Projected OMT Events w/o Action Projected OMT Events w/ Action
Actual Number of OMT Events Linear (Actual Number of OMT Events)
ICNU_DR_113 Attachment B Page 50 of 77

46

assumption. Another contributing factor comes from the worse than expected performance of other
cutouts. The model, however, for Chance Cutouts will not be changed since the bulk of the work has
already been completed and any remaining work is to be picked up by WPM.
Chance Cutouts Summary
In summary, the Chance Cutout replacement program has succeeded in reducing the number of failures
due to this type of cutout. While it has not created the savings originally hoped for, the program
continues to save Avista a significant amount of money each year.
Distribution Vegetation Management (VM)
Our Vegetation Management program maintains the distribution system clear of trees and other
vegetation. This reduces outages caused by trees and to a lesser extent squirrel caused outages. Our
Distribution System runs for 7,793 circuit miles in Washington, Idaho, and a little in Montana. While the
Vegetation Management program does cover work on the Transmission System and the High Pressure
Gas Pipeline system, the purpose here is to only look at the Distribution System.
For the Distribution System, our analysis has shown that a pro-active maintenance program provides the
best value to our customers. While our past practices were a four and seven year cycle based on
location and had a reduced clearing diameter, our analysis has indicated a five year clearing cycle at a
normal clearing distance has some advantages.
The purpose of Vegetation Management is to meet regulatory compliance, provide the best value to our
customers, and maintain current reliability. The current Vegetation Management program added
herbicide spraying and enlarged the risk tree programs to further improve vegetation management.
Both of these additions strive to improve the performance of the system by reducing vegetation related
events.
Selected KPIs and Metrics
For Vegetation Management (VM), we selected one leading KPI and a lagging KPI. The leading KPI is the
number of Distribution Feeders miles managed each year. This indicates how well the actual work
matches the planned work and the model. The results of the work in VM should directly impact the
number of Tree Growth and Tree Fell events in OMT which is the lagging KPI. The number of Tree
Growth events and Tree Fell events are summed for each year and compared to the AM models
predictions if the plan is followed. The goals for each KPI by year are shown in Table 17Table 17Table
17. The AM model for Tree Growth events and Tree Fell events shows varying KPI’s for each year due
the strict following of the 5 year cycle based on when the feeder was last done.
For a VM metric, we selected the number of Tree-Weather OMT events by year and SAIFI impacts. As
seen in Figure 21, there is a definite relationship between weather events and VM. We assume that
improvements in VM results should impact the number of Tree-Weather OMT events and set a goal
shown in Table 18Table 18Table 18. The goal for Tree-Weather events is based on the AM models
average value over a 10 year period. This metric was not included as a KPI, because weather events are
very unpredictable and random in nature. Once the relationship has been better established, it may
become a KPI.
ICNU_DR_113 Attachment B Page 51 of 77

47

Another metric selected for monitoring is the cost per mile for VM on the distribution feeders. While no
goals have been established, this will measure how effective our AM spending gets the work done and
how much work is required to clear the lines. The costs per mile should drop in future years, because
the amount of work required to clear them should drop after reaching a 5 year cycle. Inflation and other
escalators will drive costs up in the future to counter the reduced workload, but the net effect remains
an open question. The total number of miles of all planned work was modified in 2011. Beginning in
2011, the costs per mile calculation includes all planned work and not just the miles cleared. So, the
total number of miles for all planned work was included in the metrics.
Table 17, Vegetation Management KPI Goals
KPI
Description
Miles of Vegetation
Management Completed
OMT Events due to
Tree Fell + Tree Grow
2009 1,560 556
2010 1,560 540
2011 1,560 500
2012 1,560 520
2013 1,560 630
2014 1,560 780
2015 1,560 845
Table 18, Vegetation Management Metric Goals
Metric
Description
OMT Events due
to Tree-Weather
SAIFI -
Tree Fall
SAIFI - Tree
Grow
SAIFI - Tree
Weather
2009 166 1.40E-07 8.84E-08 1.34E-05
2010 166 1.40E-07 8.84E-08 1.34E-05
2011 166 1.40E-07 8.84E-08 1.34E-05
2012 166 1.40E-07 8.84E-08 1.34E-05
2013 166 1.40E-07 8.84E-08 1.34E-05
2014 166 1.40E-07 8.84E-08 1.34E-05
2015 166 1.40E-07 8.84E-08 1.34E-05

VM KPI Performance
Both Figure 21 and Figure 22 shows the same trends for Tree Growth, Tree Fell, and Tree Weather. The
number of OMT events due to Tree Growth and Tree Fell were below the 10 year average and above the
five year cycle projections. The number of miles completed in VM will cause the number of events in
the future to continue and exceed projected five year cycle values. Table 19Table 19Table 19 shows the
results. The number of OMT events remains above the values for 5 year cycle plan but less than the
2009 plan. We did clear enough miles in 2011 to exceed a five year cycle but slipped back to less than a
five year cycle in 2012. Until we have a well entrenched five year cycle, we will continue to realize more
ICNU_DR_113 Attachment B Page 52 of 77

48

vegetation related events than projected by the five year cycle plan. However, we do see the number of
events improving and still anticipate clearing enough miles in 2013 to align with a five year cycle.
Table 19, VM KPI Performance
Year
Projected Tree
Growth + Tree
Fell OMT
Events – 2009
Plan (Current)
Projected Tree
Growth + Tree
Fell OMT
Events – 5
Year Cycle
Actual
Number
of OMT
Events
Projected
Annual
Miles
Managed
Actual
Annual
Miles
Managed
w/o Risk
Tree or
Spraying
Percent
Model
Error
2009 1120 556 765 1,220 790 65.6%
2010 620 540 836 1,560 1,304 83.6%
2011 790 500 727 1,560 1,747 92%
2012 1210 520 712 1,560 1,296 59%
2013 1390 630 1,560
2014 1400 780 1,560
Note: values in red have negatively exceeded the goal
* This model error is for the current plan model and not the 5 year cycle model

Figure 21, OMT Events Data Trends for Tree-Weather, Tree Growth, and Tree Fell Sub-Reasons

Tree Fell, 470 Tree Fell, 390 Tree Fell, 506
Tree Fell, 392 Tree Fell, 377
Tree Growth, 443
Tree Growth, 375
Tree Growth, 330
Tree Growth, 335 Tree Growth, 335
Weather, 564
Weather, 357
Weather, 895
Weather, 325 Weather, 314
0
200
400
600
800
1000
1200
1400
1600
1800
2000
2008 2009 2010 2011 2012
Nu
m
,
b
e
r

o
f

T
r
e
e

G
r
o
w
t
h
,

W
e
a
t
h
e
r
,

T
r
e
e

F
e
l
l

O
M
T

E
v
e
n
t
s
Year
ICNU_DR_113 Attachment B Page 53 of 77

49

Figure 22, OMT Outage and Partial Outage Data Trends for Tree-Weather, Tree Growth, and Tree Fell Sub-
Reasons
VM Metric Performance
The Tree-Weather OMT Events for 2012 continued to show improvement and were below the AM
model projects (see Table 20Table 20Table 20). With the addition of herbicide spraying and enhanced
risk tree work, we must update the Vegetation Management models before we have better projections.
The SAIFI contribution for 2012 was higher than anticipated by the model as seen in Table 21Table
21Table 21. However, the trend for SAIFI for Tree Growth, Tree Fell, and Weather continue to improve
(Table 5). The biggest reason for the difference between the projected SAIFI and actual SAIFI comes
from the model. The next revision to the model will need to improve the projection of SAIFI to more
accurately reflect the actual values.
The cost per mile for VM in 2012 was $3,272. We need to update the Vegetation Management model to
address changes in the program and help understand the impact to our system. Table 22Table 22Table
22 shows the current information.
Tree Fell, 255
Tree Fell, 186 Tree Fell, 234 Tree Fell, 215 Tree Fell, 229
Tree Growth, 101
Tree Growth, 101
Tree Growth, 77 Tree Growth, 71 Tree Growth, 93
Weather, 358
Weather, 273
Weather, 620
Weather, 178
Weather, 170
0
100
200
300
400
500
600
700
800
900
1000
2008 2009 2010 2011 2012
Nu
m
b
e
r

o
f

T
r
e
e

R
e
l
a
t
e
d

O
M
T

P
a
r
t
i
a
l

O
u
t
a
g
e
s

Year
Tree Fell Tree Growth Weather
ICNU_DR_113 Attachment B Page 54 of 77

50

Table 20, Tree-Weather OMT Events Metric for Vegetation Management
Year
Projected Tree-Weather
OMT Events – 2009 Plan
(Current)
Projected Tree-
Weather OMT
Events – 5 Year
Cycle
Actual Number of
Tree-Weather OMT
Events
Percent Model
Error
2009 420 166 357 85%
2010 80 50 620 775%
2011 220 70 325 148%
2012 580 70 314 54%
2013 800 170
2014 1120 430
Note: values in red have negatively exceeded the goal.

Table 21, VM SAIFI Metrics
Year
SAIFI – Tree Fall
Projected
(Current)
SAIFI – Tree
Grow
Projected
(Current)
SAIFI – Tree
Weather
Projected
(Current)
SAIFI – Tree
Fall Actual
SAIFI – Tree
Grow Actual
SAIFI – Tree
Weather
Actual
2009 1.40E-07 8.84E-08 1.34E-05 0.000251196 4.65439E-05 0.000374485
2010 1.40E-07 8.84E-08 1.34E-05 0.000376171 7.26157E-05 0.000337983
2011 1.40E-07 8.84E-08 1.34E-05 0.000299004 6.08985E-05 0.000281085
2012 1.40E-07 8.84E-08 1.34E-05 0.000284774 6.55877E-05 0.000239443
2013 1.40E-07 8.84E-08 1.34E-05 2014 1.40E-07 8.84E-08 1.34E-05 Note: values in red have negatively exceeded the goal.

ICNU_DR_113 Attachment B Page 55 of 77

51

Table 22, VM Cost per Mile and All Vegetation Management Work Metric
Year Actual Annual Miles
Managed all work
Cost per Mile of VM
2009 N/A $6,575
2010 N/A $2,990
2011 3,455 $2,612
2012 3,364 $3,272
2013
2014

VM Model Performance
The AM model for Distribution VM was revised in 2010, but the recent changes to the work performed
and errors experienced justify updating the model. We anticipate completing the update in 2014.
VM Summary
Depending on how you evaluate the program, VM is currently not getting enough miles completed each
year to achieve the goal of a 5 year cycle. The costs per mile may be too high and/or the current funding
levels are too low and the impacts of herbicide spraying and enhanced risk tree work modify the
meaning of work per mile. Vegetation Management’s performance does show continued improvement
but further analysis will provide an opportunity to re-evaluate our current performance and update
future expectations.
Distribution Grid Modernization Program
Avista initiated a Grid Modernization Program designed to reduce energy losses, improve operation, and
increase the long-term reliability of its overhead and underground electric distribution system. The
program includes replacing poles, transformers (Pad Mount, OH & Submersible), cross arms, arresters,
air switches with steel arms, grounds, cutouts, riser wire, insulators, conduit and conductors in order to
address concerns related to age, capacity, high electrical resistance, strength, and mechanical ability.
The program also includes the addition of wildlife guards, smart grid devices, switched capacitor banks,
balancing feeders, removing unauthorized attachments, replacing open wire secondary, and
reconfigurations.

When funded to a level that allows 5-6 feeders to be upgraded per year, the continuous program
represents a 60 year interval to upgrade all the feeders in Avista’s system and coordinates all of its
activities with Avista’s Wood Pole Management. The objectives of the Grid Modernization Program are
listed in Table 23.
ICNU_DR_113 Attachment B Page 56 of 77

52

Table 23, Grid Modernization Program Objectives
Objective Objective Description
Safety Focus on safe practices for crew work by designing work plans to avoid safety risks
Reliability Replacing aging and failed infrastructure that has a high likelihood of creating an
unplanned crew call-out
Energy Savings Replace equipment that has high energy losses with new equipment that is more
energy efficient and improve the overall feeder energy performance
Operational
Ability
Replace conductor and equipment that hinders outage detection and install smart
grid devices that enable isolation of outages

Selected Metrics
Since Feeder Upgrade impacts the same KPI’s as WPM, we include them in WPM KPI’s above. The
metrics selected for Feeder Upgrades represent the program’s performance. The metrics selected
include miles of work completed, OMT sustained outages on feeders with Grid Modernization work
completed, and energy savings provided by completed work.
Based on Avista’s 2013 Integrated Resource Plan dated August 31st, 2013, Table 5.3 and Table 5.4, the
realized and anticipated energy savings by identified feeders is shown in Table 24. From Table 24, we
calculated that the power saved per mile of work is 1.38 kW.
Table 24, Energy Savings based on 2013 Integrated Resource Plan
Feeder Energy Savings (MWH) OH Circuit Miles
NE12F3 115 13.09062
RAT231 91 52.25448
OTH502 21 0.783542
M23621 151 28.388
DVP12F2 35 39.1079
HAR4F1 69 12.0028
BEA12F3 167 9.854272
FWT12F3 121 10.5042
TEN1255 249 12.27521
ROS12F1 267 18.93558
SPI12F1 162 91.80389
TUR112 101 24.33467
9CE12F4 601 17.04767
WIL12F2 1403 105.5954
BEA12F1 972 24.80689
F&C12F2 570 20.6956
BEA12F5 885 15.66515
TUR113 76 5.098

Total 6056 502.2438
KW per Mile 1.376471

ICNU_DR_113 Attachment B Page 57 of 77

53

The miles of work planned is ultimately driven by the approved budget and generally can only be
projected for 5 years. In order to maintain a 60 year cycle, Avista would need to address an average of
137 miles per year of overhead circuit miles. This would result in an average of 188 kW of power savings
each year.
For tracking the impacts of the work on outages, we will monitor the following OMT sub-reasons shown
in Table 25Table 25Table 25. While the Grid Modernization will affect all of the sub-reasons listed in
Table 25Table 25Table 25, the sub-reasons identified as potentially avoidable represent the most direct
impact of the work. So we assume that the number of OMT sustained outages will be reduced by 0.1
outages per mile of overhead work completed. Based on the data shown in Figure 23, the average
number of OMT events that could potentially been avoided over the last 5 years is 773. Dividing 773
outages by the number of circuit miles yields 0.1 outages avoided per mile of work. So, the annual
anticipated number of OMT sustained outages will be the average value of outages minus the number of
OMT outages avoided by performing the work.

ICNU_DR_113 Attachment B Page 58 of 77

54

Table 25, OMT Sub-Reasons impacted by Grid Modernization
OMT Sub-Reason Potentially Avoidable
Arrester Yes
Capacitor Yes
Conductor - Pri Yes
Conductor - Sec Yes
Connector - Pri Yes
Connector - Sec Yes
Cross arm - rotten Yes
Cutout/Fuse Yes
Elbow Yes
Insulator Yes
Insulator Pin Yes
Lightning No
Pole Fire No
Pole - rotten Yes
Recloser Yes
Regulator Yes
Snow/Ice No
Switch/Disconnect Yes
Transformer - OH Yes
Transformer UG Yes
Undetermined No
Weather No
Wildlife Guard Yes

ICNU_DR_113 Attachment B Page 59 of 77

55

Figure 23, OMT Sustained Outages related to Grid Modernization
Metric Performance
The results of the first years work are shown in Table 26Table 26Table 26. The year 2012 marks the
beginning of the program, so the results will only partially reflect the actual results. The number of
miles actually completed missed the goal of 95 and the energy savings fell short of its goal as well. We
will continue with the program as allowed by the budgets and continue to monitor the results for a few
more years before considering any significant changes to the plan.
Table 26, Metric Performance for Grid Modernization Program
Year
Planned Miles
for
Modernization
(Miles)*
Actual Miles
Completed
(Miles)
Anticipated
Power
Savings
(kW)*
Realized
Power
Savings
(kW)
Anticipated
Number of
Sustained
Outages
Realized
Number of
Sustained
Outages
2012 95 82 127 39.4 2340 2331
2013 137 188 2327
2014 137 188 2313
2015 137 188 2300
2016 137 188 2286
2017 137 188 2272
0
500
1000
1500
2000
2500
3000
3500
4000
2000 2002 2004 2006 2008 2010 2012 2014
Nu
m
b
e
r

o
f

S
u
s
t
a
i
n
e
d

O
u
t
a
g
e
s
Year
OMT Sustained Outages related to Grid Modernization
Number of Grid Modernization Related Sustained outages Average Std Dev -Low Potentially Avoidable Outages
ICNU_DR_113 Attachment B Page 60 of 77

56

*Note: The planned or anticipated values may be modified to match approved work plans for each year
that more accurately align with the actual work planned.
Summary
The Grid Modernization Program began in earnest in 2012 and represents feeder replacement work and
upgrades founded on smart grid work. We need to examine a few more years’ worth of data before
drawing any conclusions.
Asset Management Area Work plans for Electric Distribution
Spokane Area Work Plans
The feeders listed here represent the current plans and are subject to change based on several factors.
These are provided for planning purposes only.
Grid Modernization
 2013
 BEA12F5
 NE12F3
 2014
 -
 2015
 ROS12F1
 WAK12F2
 2016
 BEA12F3
 FWT12F3
 2017
 F&C12F6
 2018
 BEA12F2

 2019
 -

ICNU_DR_113 Attachment B Page 61 of 77

57

Vegetation Management
 2013
 3HT12F1
 3HT12F2
 3HT12F3
 3HT12F4
 3HT12F5
 3HT12F6
 3HT12F7
 3HT12F8
 9CE12F1
 9CE12F2
 9CE12F3
 9CE12F4
 BKR12F1
 BKR12F3
 C&W12F1
 C&W12F2
 C&W12F3
 C&W12F4
 C&W12F5
 C&W12F6
 MIL12F1
 MIL12F2
 MIL12F3
 MIL12F4
 NW12F1
 NW12F2
 NW12F3
 NW12F4
 NW13T23
 RDN12F1
 RDN12F2
 WAK12F1
 WAK12F2
 WAK12F3
 WAK12F4
 2014
 BKR12F2
 DEP12F1
 DEP12F2
 EFM12F1
 EFM12F2
 H&W12F1
 H&W12F2
 SUN12F1
 SUN12F2
 SUN12F3
 SUN12F4
 SUN12F5
 SUN12F6
 2015
 BEA12F1
 BEA12F2
 BEA12F3
 BEA12F4
 BEA12F5
 BEA12F6
 BEA13T09
 F&C12F1
 F&C12F2
 F&C12F3
 F&C12F4
 F&C12F5
 F&C12F6
 NE12F1
 NE12F2
 NE12F3
 NE12F4
 NE12F5
 OPT12F1
 OPT12F2
 PST12F1
 SIP12F1
 SIP12F2
 SIP12F3
 SIP12F4
 SIP12F5
 SLK12F1
 SLK12F2
 SLK12F3
 VAL12F2
 2016
 AIR12F1
 AIR12F2
 CHE12F1
 CHE12F2
 CHE12F3
 CHE12F4
 CLA56
 INT12F1
ICNU_DR_113 Attachment B Page 62 of 77

58

 INT12F2
 L&S12F1
 L&S12F2
 L&S12F3
 L&S12F4
 L&S12F5
 LOO12F
 LOO12F2
 MLN12F2
 SE12F1
 SE12F2
 SE12F3
 SE12F4
 SE12F5
 2017
 COB12F1
 COB12F2
 FWT12F1
 FWT12F2
 FWT12F3
 FWT12F4
 GLN12F1
 GLN12F2
 LIB12F1
 LIB12F2
 LIB12F3
 LIB12F4
 MEA12F1
 MEA12F2
 MLN12F1
 PVW241
 ROS12F1
 ROS12F2
 ROS12F3
 ROS12F4
 ROS12F5
 ROS12F6
 2018
 -
 2019

ICNU_DR_113 Attachment B Page 63 of 77

59

Wood Pole Management Inspection
 2013
 3HT12F1
 3HT12F3
 3HT12F5
 3HT12F6
 3HT12F7
 3HT12F8
 C&W12F2
 C&W12F3
 C&W12F4
 C&W12F5
 C&W12F6
 NW12F 1
 NW12F2
 NW12F3
 NW12F4
 NW13T23
 2014
 AIR12F3
 BEA12F3
 FWT12F3
 L&S12F1
 L&S12F2
 L&S12F3
 L&S12F4
 L&S12F5
 ROS12F1
 2015
 CHE12F1
 CHE12F2
 CHE12F4
 CLA56
 H&W12F1
 H&W12F2
 MLN12F1
 MLN12F2
 NE12F1
 NE12F2
 NE12F4
 2016
 BEA12F2
 F&C12F1
 F&C12F2
 F&C12F3
 F&C12F4
 F&C12F5
 F&C12F6
 LIB12F2
 LIB12F4
 SE12F3
 WAK12F2
 2017
 9CE12F1
 9CE12F2
 9CE12F3
 BEA12F4
 BEA12F6
 BEA13T19
 GLN12F1
 OPT12F1
 OPT12F2
 ROS12F2
 ROS12F4
 ROS12F5
 ROS12F6
 2018
 FWT12F2
 FWT12F4
 INT12F1
 INT12F2
 WAK12F1
 WAK12F3
 WAK12F4
 2019
 -

ICNU_DR_113 Attachment B Page 64 of 77

60

Wood Pole Management Follow-Up
 2013
 -
 2014
 3HT12F1
 3HT12F3
 3HT12F5
 3HT12F6
 3HT12F7
 3HT12F8
 C&W12F2
 C&W12F3
 C&W12F4
 C&W12F5
 C&W12F6
 NW12F 1
 NW12F2
 NW12F3
 NW12F4
 NW13T23
 2015
 AIR12F3
 BEA12F3
 FWT12F3
 L&S12F1
 L&S12F2
 L&S12F3
 L&S12F4
 L&S12F5
 ROS12F1
 2016
 CHE12F1
 CHE12F2
 CHE12F4
 CLA56
 H&W12F1
 H&W12F2
 MLN12F1
 MLN12F2
 NE12F1
 NE12F2
 NE12F4
 2017
 BEA12F2
 F&C12F1
 F&C12F2
 F&C12F3

 F&C12F4
 F&C12F5
 F&C12F6
 LIB12F2
 LIB12F4
 SE12F3
 WAK12F2
 2018
 9CE12F1
 9CE12F2
 9CE12F3
 BEA12F4
 BEA12F6
 BEA13T19
 GLN12F1
 OPT12F1
 OPT12F2
 ROS12F2
 ROS12F4
 ROS12F5
 ROS12F6
 2019
 FWT12F2
 FWT12F4
 INT12F1
 INT12F2
 WAK12F1
 WAK12F3
 WAK12F4

ICNU_DR_113 Attachment B Page 65 of 77

61

Palouse Area
The feeders listed here represent the current plans and are subject to change based on several factors.
These are provided for planning purposes only.
Grid Modernization
 2013
 TUR113
 2014
 M23621
 2015
 M23621
 2016
 TUR112
 2017
 TUR112
 2018
 TUR112
 2019
 -

Vegetation Management
 2013
 GAR461
 M15511
 M15512
 M15513
 M15514
 M15515
 M23621
 NMO521
 NMO522
 PAL311
 PAL312
 SPA442
 SPU121
 SPU122
 SPU123
 SPU124
 SPU125
 2014
 DIA231
 DIA232
 JUL661
 LAT421
 LAT422
 2015
 DER651
 DER652
 JUL662
 RSA431
 TKO411
 TKO412
 2016
 EWN241
 ROK451
 TUR111
 TUR112
 TUR113
 TUR114
 TUR115
 TUR116
 TUR117
 TVW131
 TVW132
 2017
 ECL221
 ECL222
 LEO611
 LEO612
 POT321
 POT322
 WOR471
 2018
 -
 2019
 -

ICNU_DR_113 Attachment B Page 66 of 77

62

Wood Pole Management Inspection
 2013
 -
 2014
 GAR461
 TUR112
 2015
 -
 2016
 JUL661
 JUL662
 LEO612
 M23621
 ROK451
 2017
 POT321
 POT322
 TUR116
 2018
 -
 2019
 -

ICNU_DR_113 Attachment B Page 67 of 77

63

Coeur D’Alene Area
The feeders listed here represent the current plans and are subject to change based on several factors.
These are provided for planning purposes only.
Grid Modernization

 2013
 CDA121
 RAT231
 2014
 CDA121
 2015
 RAT231
 2016
 -
 2017
 APW114
 2018
 -
 2019
 -

Vegetation Management

 2013
 BIG411
 BIG412
 BIG413
 BLU321
 HUE141
 HUE142
 LKV341
 LKV342
 LKV343
 LKY551
 OSB522
 STM631
 STM632
 STM633
 2014
 BLA311
 CDA121
 CDA122
 CDA123
 CDA124
 CDA125
 OGA611
 OLD721
 OLD722
 OSB521
 PF211
 PF212
 PRV4S40
 SPL361
 2015
 APW111
 APW112
 APW113
 APW114
 APW115
 APW116
 AVD151
 AVD152
 CKF712
 IDR251
 IDR252
 IDR253
ICNU_DR_113 Attachment B Page 68 of 77

64

 PF213
 SAG742
 WAL542

 WAL543
 WAL544
 WAL545
 2016
 CGC331
 CKF711
 DAL131
 DAL132
 DAL133
 DAL134
 NRC352
 RAT231
 RAT233
 SAG741
 SPT4S21
 SPT4S22
 SPT4S23
 SPT4S30
 2017
 BUN422
 BUN423
 BUN424
 BUN426
 MIS431
 ODN731
 ODN732
 PIN441
 PIN442
 PIN443
 PRA221
 PRA222
 PVW243
 2018
 -

Wood Pole Management Inspection
 2013
 APW112
 APW113
 LKV341
 LKV342
 LKV343
 SAG741
 2014
 APW111
 APW115
 APW116
 IDR252
 SAG742
 2015
 IDR251
 IDR253
 SPT4S22
 SPT4S23
 SPT4S30
 2016
 APW114
 PVW243
 2017
 BIG411
 BIG412
 PIN441
 RAT233
 2018
 PRV4S40
 2019
 -

ICNU_DR_113 Attachment B Page 69 of 77

65

Wood Pole Management Follow-Up
 2013
 -
 2014
 APW112
 APW113
 LKV341
 LKV342
 LKV343
 SAG741
 2015
 APW111
 APW115
 APW116
 IDR252
 SAG742
 2016
 IDR251
 IDR253
 SPT4S22
 SPT4S23
 SPT4S30
 2017
 APW114
 PVW243
 2018
 BIG411
 BIG412
 PIN441
 RAT233
 2019
 PRV4S40

ICNU_DR_113 Attachment B Page 70 of 77

66

Lewis-Clark Area
The feeders listed here represent the current plans and are subject to change based on several factors. These
are provided for planning purposes only.
Grid Modernization

 2013
 -
 2014
 -
 2015
 -
 2016
 TEN1255
 2017
 -
 2018
 HOL1205
 ORO1280
 2019
 -

ICNU_DR_113 Attachment B Page 71 of 77

67

Vegetation Management
 2013
 COT2401
 COT2402
 DRY1208
 DRY1209
 2014
 LOL1359
 SLW1316
 SLW1348
 SLW1358
 SLW1368
 TEN1253
 TEN1254
 TEN1255
 TEN1256
 TEN1257
 2015
 HOL1205
 HOL1206
 HOL1207
 JPE1287
 LOL1266
 N131222
 N131321
 PDL1201
 PDL1202
 PDL1203
 PDL1204
 WEI1289
 2016
 CFD1210
 CFD1211
 GRV1271
 GRV1272
 GRV1273
 GRV1274
 KAM1291
 KAM1292
 KAM1293
 KOO1298
 KOO1299

 2017
 CRG1260
 CRG1261
 CRG1263
 NEZ1267
 ORO1280
 ORO1281
 OROR1282
 SWT2403
 WIK1278
 WIK1279
 2018
 -
 2019
 -

Wood Pole Management Inspection
 2013
 -
 2014
 LOL1266
 LOL1359
 2015
 JPE1287
 2016
 COT2402
 HOL1205
 N131222
 ORO1280
 SWT2403
 2017
 -
 2018
 KAM1291
 KAM1292
 KAM1293
 2019
 -

ICNU_DR_113 Attachment B Page 72 of 77

68

Wood Pole Management Follow-Up

 2013
 -
 2014
 -
 2015
 LOL1266
 LOL1359
 2016
 JPE1287
 2017
 COT2402
 HOL1205
 N131222
 ORO1280
 SWT2403
 2018
 -
 2019
 KAM1291
 KAM1292
 KAM1293

ICNU_DR_113 Attachment B Page 73 of 77

69

Big Bend Area
The feeders listed here represent the current plans and are subject to change based on several factors. These
are provided for planning purposes only.
Grid Modernization
 2013
 WIL12F2
 SPI12F1
 DVP23F2
 2014
 SPI12F1
 WIL12F2
 2015
 SPI12F1
 OTH502
 2016
 SPI12F1
 SPR761
 2017
 DAV12F2
 HAR4F1
 SPR761
 2018
 DAV12F2
 HAR4F1

Vegetation Management
 2013
 ARD12F1
 CLV34F1
 CLV12F2
 CLV12F3
 CLV12F4
 HAR4F1
 HAR4F2
 KET12F1
 RIT731
 RIT732
 2014
 ARD12F2
 KET12F2
 LIN711
 ORI12F1
 ORI12F2
 ORI12F3
 WAS781
 WIL12F1
 WIL12F2
 2015
 FOR12F1
 GIF34F1
 LL12F1
 ODS12F1
 SOT521
 SPI12F2
 SPR761
 VAL12F3
 2016
 FOR2.3
 GIV34F2
 L&R511
 ROX751
 SOT522
 SOT523
 SPI12F1
 VAL12F1
 2017
ICNU_DR_113 Attachment B Page 74 of 77

70

 CHW12F1
 CHW12F2
 CHW12F3
 CHW12F4
 DVP12F1
 DVP12F2
 GRN12F1
 GRN12F2
 GRN12F3
 L7R512
 LF34F1
 OTH501
 OTH502
 OTH503
 OTH505
 2018
 -
 2019
 -

ICNU_DR_113 Attachment B Page 75 of 77

71

Wood Pole Management Inspection
 2013
 DVP12F2
 GIF34F1
 WAS781
 2014
 GIF34F1
 2015
 SOT522
 2016
 -
 2017
 OTH501
 OTH503
 OTH505
 SPR761
 2018
 CHW12F1
 CHW12F4
 FOR12F1
 FOR2.3
 2019
 -

Wood Pole Management Follow-Up
 2013
 -
 2014
 DVP12F2
 GIF34F1
 WAS781
 2015
 GIF34F1
 2016
 SOT522
 2017
 -
 2018
 OTH501
 OTH503
 OTH505
 SPR761
 2019
 CHW12F1
 CHW12F4
 FOR12F1
 FOR2.3

ICNU_DR_113 Attachment B Page 76 of 77
Palouse Regional Assessment
72

Conclusion
In this report, we documented and examined the KPIs and metrics AM selected for the Distribution
system and provided the results for 2010. Some of the metrics compared how an asset performed with
a program and how it would have performed without a program. The difference in performance provide
an estimate of the cost saving and value of an AM program. While the exact savings are impossible to
calculate in most cases, it provides a relative comparison and supporting justification or motivation for
change in AM decisions made in the past. Other KPIs and metrics provided indications of how well an
asset performed and help determined if further work is required. Some AM models clearly need more
work to better predict future conditions and will be scheduled in the future if it makes sense.
ICNU_DR_113 Attachment B Page 77 of 77

2013 Underground Equipment Inspection Asset
Management Plan

Requirements
WAC 296-24-95605 provides direction for marking the exterior of padmount transformers used in underground distribution applications. These warning markings are prescribed for the safety of the general public as well as utility crews who will be
working with the equipment. Additional markings are defined by Avista Utilities
construction standards to aid in location and identification of equipment by service
crews.
In addition, IEEE C57 provides direction regarding enclosure integrity for padmount equipment. The concept of “enclosure integrity” is intended to prevent unauthorized or
unintentional access to energized components of the distribution system. Enclosure
integrity must be addressed not only by equipment manufacturers, but also in the
installation and maintenance of padmount equipment.
Various jurisdictional codes, e.g, WAC 468-34-130 350, provide direction for locating padmount equipment along roadways. Other codes provide direction for locating
padmount equipment adjacent to buildings, other utility equipment, and other structures.
Finally, WAC 296-24-95605 provides direction for ensuring that the area around
padmount equipment is kept free from obstruction so that the equipment can be accessed for maintenance or replacement.
The National Electric Safety Code (NESC C2-2007) provides direction for grounding
padmount equipment.
Avista Utilities’ in-house Material and Construction Standards are prepared and
checked to conform to the requirements of external standards such as those cited above. To the greatest extent possible, in-house standards also consider installation and maintenance of system components in a way to achieve best system reliability and
lowest life-cycle cost. Occasionally, cumulative effects of the environment or actions of
other parties may negatively affect the way padmount equipment was installed, A
common example is installation of a padmount distribution transformer where the soil subsequently settles unevenly and leaves the transformer leaning.
Background
In the recent past, casual (“drive-by”) observation of our underground distribution
equipment has been done by both Operations and Engineering staff. Observations have
ICNU_DR_113 Attachment C Page 1 of 7

indicated a high percentage of equipment with missing or damaged marking decals. In some cases, equipment has been obscured by property owners intending to improve
the esthetics of their properties. Time, weather, and/or other circumstances have in
some cases affected the installation of equipment to the extent that operation, safety,
and reliability may be compromised. During the course of the inspection, we expect to find some older devices in service which are no longer acceptable for use in our system. Examples are transformers filled with insulating oil containing PCBs, or live-front
equipment.
Recent review of decal marking shows a weakness in keeping the decals readable and
construction standards have been modified to include an internal marking on new equipment. A check should be done on in-service equipment, and the internal warning decal should be installed as needed.
The driving force behind the padmount equipment inspection plan is the age of the
facilities that have now been in service over 20 years and need to be inspected. As
noted above, padmount equipment must be opened to ensure that all required markings
are in place. In making a commitment to perform this inspection on a broad basis, we recognized that further inspection of the physical and electrical integrity of these devices
would present only a small incremental effort. If the inspection teams are provided with
the proper materials and tools, many corrective actions may be made while on-site,
reducing the overall time and cost for the inspection and corrective action.
Inspection
When inspection of an item of padmount equipment identifies damaged, obscured, or missing marking decals, those shall be replaced immediately. If the equipment is
covered, or obscured by vegetation or other landscaping, the inspection team will
remove vegetation or other landscaping to facilitate a complete inspection and note this
fact and report to the Project Manager who is responsible for ensuring that the
appropriate corrective action is undertaken. In the case of mechanical or functional discrepancies, the inspection team should immediately report the irregularity to the
Project Manager, who will then arrange for appropriate corrective action to be
undertaken as soon as practical. The inspection team will not ordinarily be responsible
for making mechanical or functional (electrical) repairs or replacements unless they are
appropriately qualified and equipped.
When decals are replaced, those replacements do not need to be recorded in the
inspection record, unless a unique identifying marking, such as a transformer stencil
number, is replaced. If an identifying marking is found which does not correspond to the
identification recorded in AFM, that discrepancy shall be resolved before completing the
inspection and any changes shall be noted in the inspection record. Any mechanical irregularity shall be noted in the inspection record, even if accepted as-found. Any mechanical or electrical repair or replacement shall be noted in the inspection record
ICNU_DR_113 Attachment C Page 2 of 7

Trends and Analysis
There are 36,000 Padmount transformers system wide and 12,500 Junction Enclosures (data pulled from AFM). Issues were better defined during the short pilot project (see
Table 1).

Pilot Data
4 weeks 1 Journeymen
474 Transformers
120 Junctions Enclosures

Table 1, Failure types

During the pilot approximately 95% of the equipment visited needed to have the decals
updated. The equipment needed to be re-decaled due to several factors. Equipment
may have been decaled under a previous standard, improperly decaled, weather and age may cause the decal to be illegible or missing, and some were destroyed by
property owners. This issue was the biggest concern from AEGIS. Several other issues
were more defined through the pilot that have the potential to have a large impact.
Clearance issues were a problem in 1/3 of the transformers visited. These issues
include overgrown vegetation, walls, rocks and decorations within the clearance zone. The vegetation issue appeared to be the biggest clearance zone issue. There were
also four high risk issues that were more prevalent than expected. Many of the pads
had openings in them. Some of these openings were due to the type of pad, and are
smaller in size, but other pads were cracked or broken. Both opening types have the
potential to allow unauthorized access to our equipment. Missing or failed pentabolts were an issue. Some of the pentabolts were stripped or broken off within the equipment
while others were completely missing, both cases require a crew to replace the bolt
which can be a time consuming process. Although most of the paint failures were
cosmetic, a small percentage of the equipment with paint failures was at the rusting
through stage. Equipment at this stage may need to be completely replaced rather than simply repainted. Another issue with any paint failure is the possibility of lead based
paint having been used on the equipment by the manufacturer. This will require testing
before the equipment can be scraped for repainting. Also a small percentage of the
equipment was unlevel. These can be re-leveled by a crew; however, some of these
will be unlevel in such a way that the relief valve may leak oil. For the few leaking pieces of equipment some type of clean up would need to occur.

Failure
Types
Improperly
Decaled
Clearance
Issues
Unlevel Failed
Pentabolt
Paint
Failure
% 96% 35% 3% 8% 8%
ICNU_DR_113 Attachment C Page 3 of 7

Table 2, Estimate of Material

One of the trends seen within the model is an increasing cost to maintain the padmount
equipment due to the increasing age of the equipment. The age profile used for the analysis is the age of the transformers from the pilot (see Figure 1).
Figure 1, Age Profile of Padmount Transformers used in the pilot and analysis

Alternatives Examined
For this analysis, we examined two different cases. The Base Case analyzes the
system as if each failure would require a corrective maintenance action. This is not a
typical Base Case analysis, however, as it doesn’t truly represent the current state.
This type of Base Case more accurately represents how we would mitigate these issues if a program was not put in place. The second case, called the 5 year Inspection Plan, inspects pad mount equipment on a 5 year cycle. The final case represents a 10 year
inspection cycle.
0%
2%
4%
6%
8%
10%
12%
0 10 20 30 40 50 60 70
%
o
f

T
o
t
a
l

Transformer Age
Age Profile
Decals Transformers Pads Pentabolts
Ground/
Neutral/
Clamp
5 year plan
units/year 10,000 800 230 800 550
ICNU_DR_113 Attachment C Page 4 of 7

Key Assumptions and Data
Most of the data used in the analysis came from the short pilot and feedback from the pilot inspector and Distribution Engineering. Failure costs, labor and time for the
inspection were all gathered through the pilot. The pilot was conducted over 4 weeks in
multiple locations around the city of Spokane. The locations were selected to help
diversify the age of the equipment. Risk costs and follow up costs were not established
through the pilot. The risk and follow up costs were derived through feedback from the pilot inspector, Distribution Engineering and Asset Management assumptions. Sub
transformers were not considered in this program as nearly all of them are being
inspected and possibly changed out through TCOP (Transformer Change-Out
Program).

Model Results
For each of the cases, we developed and ran a model to help compare the risks,
resource needs, and financial impacts of each case. Examining all of these factors,
Avista selects the best strategy from the three different cases (see Table 3 and Figure 2).

Table 3, Financial Comparisons
Model Customer IRR Levelized Gr. Mar.
Requirement
Base Case 1.88% $5,993,219
5 Year Inspection Plan 13.56% $3,622,985
10 Year Inspection Plan 13.50% $3,637,417

ICNU_DR_113 Attachment C Page 5 of 7

Figure 2, Cumulative Cost Comparisons
Selected Strategy
Given that most of the padmount equipment requires some kind of decal update the 5
Year Inspection Plan would be the quickest and most efficient strategy for the first cycle. After a 5 year cycle has been completed the cycle should be extended to 10 years to
best suit the failure curve data gathered from the pilot.

Pro Forma
A five year plan to inspect and maintain our padmount equipment will add $1.6 million
per year to the current capital spending for the first five years (see Table 4).

$
$20
$40
$60
$80
$100
$120
$140
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19
Mi
l
l
i
o
n
s

Year
Base Case - with effects 5 Year Inspection Plan - with effects
10 Year Inspection Plan - with effects
ICNU_DR_113 Attachment C Page 6 of 7

Table 4, Pro Forma
Year Capital
Spending/Budget
O&M
Spending/Budget
First 5 Years $1,600,000 $800,000

Summary
In summary, the selected strategy for managing padmount equipment is to quickly and
efficiently inspect through a cycle and then began a program that continues to meet
NESC code, decreases our risk and positively impacts our aging equipment by replacing failed equipment on a planned basis.
ICNU_DR_113 Attachment C Page 7 of 7

Avista Utilities Asset Management

Proposed Protocol for Managing Select Aldyl A Pipe
in Avista Utilities‟ Natural Gas System

Kristen D. Busko, P.E.
Natural Gas Asset Management Engineer

Originally published
February 23, 2012

Revised
April 11, 2013

© 2012 Avista. All Rights Reserved. Contents shall not be reproduced without the express
written consent of Avista.

ICNU_DR_113 Attachment D Page 1 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 2

REVISION CONTROL

DATE REVISION REVISED BY

Author‟s Acknowledgement: Without the efforts and involvement of Larry La Bolle,
Avista‟s Director of Federal and Regional Affairs, the successful development of this
document would not have been possible.
ICNU_DR_113 Attachment D Page 2 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 3

Proposed Protocol for Managing Select Aldyl A Pipe in Avista
Utilities’ Natural Gas System

Executive Summary

Avista Utilities (Avista) is proposing to undertake a twenty-year program to systematically
remove and replace select portions of the DuPont Aldyl A medium density polyethylene
pipe in its natural gas distribution system in the States of Washington, Oregon and Idaho.
None of the subject pipe is “high pressure main pipe,” but rather, consists of distribution
mains at maximum operating pressures of 60 psi and pipe diameters ranging from 1¼ to 4
inches. As part of this program, Avista will re-make connections of select Aldyl A service
piping, ½ and ¾ inch diameters, where tapped to steel main piping. Further, Avista notes
that while there have been concerns with the integrity of steel pipe in other parts of the
country in recent years, the steel pipe in its system, including steel service risers, is being
managed to protect its long-term reliability and performance and is outside the scope of this
program.

In recent years, Avista experienced two incidents on its natural gas system that prompted
the Washington Utilities and Transportation Commission and the Company to better
understand the potential long-term reliability of Aldyl A pipe. Results of these
investigations, which were aided by new tools developed for Avista‟s Distribution Integrity
Management Plan (“DIMP” or “Integrity Management”), corroborated reports for similar
Aldyl A piping around the country as supporting the development of a protocol for the
management of this gas facility. The following report highlights the history of DuPont‟s
Aldyl A natural gas pipe and summarizes DuPont and Federal Agency communications
that are relevant to this proposed program. The report documents the Aldyl A pipe in
Avista‟s natural gas system and describes the analysis of the types of failures observed in
this pipe, and the evaluation of its expected long-term integrity. Finally, the report
describes the results of Avista‟s work to establish the framework for the proposed protocol
for the management of Aldyl A pipe in its natural gas system.

ICNU_DR_113 Attachment D Page 3 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 4

Table of Contents
I. History of DuPont Aldyl A Piping Systems ............................................................................ 6
DuPont Introduces Natural Gas Polyethylene Pipe – 1965 .......................................... 6
The Phenomenon of “Low Ductile Inner Wall” ........................................................... 6
DuPont Communicates Potential Issues to Aldyl A Customers ................................... 6
1982 Letter ...................................................................................................... 6
1986 Letter ...................................................................................................... 7
DuPont Substantially Improves Aldyl A Pipe .............................................................. 7
Common Classifications of Aldyl A Pipe ..................................................................... 8

II. Federal Bulletins on Brittle-Like Cracking in Plastic Pipe ................................................. 9
National Transportation Safety Board .......................................................................... 9
Objectives of the Board‟s Investigation .......................................................... 9
Phenomenon of Premature Brittle-Like Cracking ......................................... 10
Board Findings on the Three Identified Safety Issues .................................. 10
Pipeline and Hazardous Materials Safety Administration .......................................... 13
1999 Bulletins ................................................................................................ 13
2002 Bulletin ................................................................................................. 13
2007 Bulletin ................................................................................................. 13

III. 2009 Distribution Integrity Management Program .......................................................... 13
Objectives and Approach ............................................................................................ 14

IV. 2011 Call to Action – Transportation Secretary LaHood ................................................ 14

V. Avista’s Experience with DuPont Aldyl A Piping Systems ................................................ 15
Spokane and Odessa Incidents .................................................................................... 15
Expert-Recommended Protocol for Managing Aldyl A Pipe in Relation to
Reported Soil Conditions .............................................................................. 16
Evaluation of Leak Survey Records .............................................................. 17
Pipe Replacement Projects in 2011 ............................................................... 17

VI. Avista Distribution Integrity Management Program ....................................................... 17

VII. Analyzing Modes of Failure in Avista’s Aldyl A Pipe ..................................................... 18
Towers and Caps ........................................................................................... 19
Rock Contact and Squeeze-Off ..................................................................... 20
Services Tapped from Steel Mains ................................................................ 20
Avista‟s Aldyl A Services ............................................................................. 21
Understanding the Significance of Leaks in Aldyl A Pipe ......................................... 21
Frequency and Potential Consequence .......................................................... 21
The Complication of Brittle Cracking in Aldyl A Pipe ................................. 22

VIII. Reliability Modeling of Avista’s Aldyl A Piping ............................................................ 22
Availability Workbench Software .............................................................................. 23
Reliability Forecasting ................................................................................................ 23
ICNU_DR_113 Attachment D Page 4 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 5

Forecasting the Reliability of Aldyl A Piping ............................................................ 23
Forecasting Results ..................................................................................................... 24
Forecast Piping Failures ................................................................................ 24
Dependability of Forecasting Future Failures ............................................... 24
Understanding the Significance of Cumulative Failure Curves .................... 25
Prudent Management of Anticipated Failures ............................................... 25
Priority Aldyl A Piping ................................................................................. 26

IX. Formulation of a Management Program for Priority Aldyl A Pipe ................................ 26
Priority Aldyl A Piping in Avista‟s System ................................................................ 27

X. Other Aldyl A Pipe Replacement Programs ....................................................................... 28
Aldyl A Pipe in the Pacific Northwest ........................................................................ 28
Established and Emerging Programs for Aldyl A Pipe Replacement......................... 28
Developments of Interest ............................................................................................ 29

XI. Designing Avista’s Replacement Protocol for its Priority Aldyl A Pipe ......................... 30
Systematic Replacement Program .............................................................................. 30
Time Horizon ................................................................................................ 30
Prudent Management of Potential Risk ......................................................... 30
Prioritizing the Work ..................................................................................... 31
Twenty-Year Proposal ................................................................................... 31
Initial Optimization ....................................................................................... 32
Responsive Replacement Program ............................................................................. 33
Dr. Palermo‟s Assessment of the Proposed Protocol for Managing Avista‟s Priority
Aldyl A Piping ........................................................................................................ 33

XII. Application of Avista’s Washington State Study Results to Aldyl A Pipe in the States
of Oregon and Idaho ............................................................................................................. 34

XIII. Resource Requirements and Expected Cost ................................................................... 34
Staffing ........................................................................................................................ 34
Capital Costs ............................................................................................................... 35

XIV. Regulatory Developments Since Original Publishing Date
Washington State Pipeline Replacement Policy Statement UG-120715…………….35

ICNU_DR_113 Attachment D Page 5 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 6

I. History of DuPont Aldyl A Piping Systems

Modern polyethylene pipe products are corrosion-free, lightweight, cost-effective, highly-
reliable, and can be installed quickly and efficiently. For these reasons, it has for decades
been the „standard for the industry‟ and is the predominant choice used in natural gas
distribution systems. As with any revolutionary product line, polyethylene piping systems
have undergone continuous and rigorous testing and product improvement. Such is the
case with DuPont‟s Aldyl A piping systems, as very briefly summarized below.
DuPont Introduces Natural Gas Polyethylene Pipe – 1965

Along with other manufacturers, DuPont began to use polyethylene resin to produce plastic
piping for a variety of purposes. The resin was produced from ethylene molecules
combined together in repeating patterns to form larger molecules called „polymers‟, hence
the name „polyethylene.‟ DuPont‟s product designed specifically for use in the natural gas
industry was marketed under the name “Aldyl A.” The initial resin used in production of
Aldyl A pipe, Alathon 5040, was manufactured from 1965 to 1970. DuPont changed the
resin in 1970 to improve Aldyl A‟s resistance to rupture during pressure testing. This
improved formulation, known as Alathon 5043, was the primary resin used in DuPont‟s
Aldyl A pipe from 1970 until 1984.
The Phenomenon of “Low Ductile Inner Wall”

Shortly after changing its polyethylene resin in 1970, DuPont detected a manufacturing
issue highlighted during laboratory testing of Aldyl A pipe. DuPont learned that its
manufacturing process was resulting in some of the pipe having a property described as
“Low Ductile Inner Wall.” “Ductility” is the ability of a material to withstand forces that
alter its shape without it losing strength or breaking. A „highly-ductile‟ material can be
bent, flexed, pressed or stretched without cracking or losing strength because, unlike brittle
materials, it can redistribute the forces of stress concentration. Low Ductile Inner Wall, or
as it often appears “LDIW,” results when the inner surface of the Aldyl A pipe becomes
brittle, promoting the formation of cracks and premature failure. In early 1972, DuPont
changed its manufacturing process to eliminate this phenomenon, but estimated that 30 –
40% of the pipe it produced in 1970, 1971 and early 1972 was affected, primarily in pipe
diameters from 1¼ inches to 4 inches.
DuPont Communicates Potential Issues to Aldyl A Customers
1982 Letter

In 1982, DuPont sent a letter to its natural gas customers, noting that two of its gas utility
customers had reported a low frequency of leaks in Aldyl A pipe manufactured prior to
1973 (See Attachment 1). These leaks were reported as “slits” occurring where the pipe
was in “point contact with rocks.” DuPont noted these two utilities had increased the
frequency of leak surveys where rock may have been part of the backfill around the pipe,
and encouraged other Aldyl A customers to consider the same. This letter was the genesis
ICNU_DR_113 Attachment D Page 6 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 7

of what would become a continuing focus on the pipe vintage known as “pre-1973 Aldyl
A.”
1986 Letter

DuPont‟s second letter to its Aldyl A pipe customers was sent in 1986, focusing again on
pre-1973 Aldyl A pipe (See Attachment 2). The letter focused on results of newly-
developed (elevated temperature) testing methods that allowed DuPont to more-accurately
estimate the longevity of this vintage pipe, in diameters of 1¼ inches and larger. Test
results showed that „Aldyl A pipe manufactured prior to 1973 had certain limitations that
were not previously-shown by then-available, state-of-the-art testing methods.‟ The
limitations were described as a reduction in pipe service life caused by: 1) “rock
impingement” or pressure from rock points directly on the pipe (as mentioned in their 1982
letter), and 2) the use of squeeze-off practices. The term “squeeze-off” refers to the current
and long-standing construction practice of mechanically pressing in polyethylene pipe
walls to temporarily stop the flow of gas during work on a line that is in service. DuPont
further noted that average ground temperature surrounding the pipe, in the ranges of 60 to
70 degrees (F), had a major bearing on its ultimate expected service life. Finally, DuPont
recommended that operators should reinforce the pipe, using clamps that surround the pipe
at squeeze points, in order to extend the life of its Pre-1973 Aldyl A.
DuPont Substantially Improves Aldyl A Pipe

DuPont made a significant change to its Aldyl A resin formulation in 1984. The improved
resin, known as Alathon 5046-C, was marketed as “Improved Aldyl A”, and significantly
improved the performance of Aldyl A pipe in its resistance to „Slow Crack Growth‟ and
overall long-term integrity. Slow Crack Growth, or as it‟s often abbreviated, SCG,
describes the progression of a crack that begins with „crack initiation‟ or the formation of a
crack in the inner wall of the pipe. The crack then progresses through the pipe wall,
usually over period of many years, until it finally breaks through the outer surface of the
pipe, resulting in failure.

Again, in 1988, DuPont announced another advance in its Aldyl A pipe resin with the
introduction of Alathon 5046-U. This change in resin formulation increased the resistance
of the pipe to slow crack growth by another order of magnitude. In addition, because of the
high „molecular efficiency‟ of this new resin, its density was also reduced, which allowed
for much greater ductility in the pipe. This product, the last of the DuPont Aldyl A
materials that Avista would install, was also marketed as Improved Aldyl A. A summary
of DuPont Aldyl A pipe produced between 1965 and 1992 is presented below in Table 1.
Information includes the year of manufacture, resin formulation, relative resistance to slow
crack growth (stress rupture testing at 80° C / 120 psig for accelerated life testing), and
summary notes.

ICNU_DR_113 Attachment D Page 7 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 8

Table 1. DuPont Aldyl A Pipe 1965 - 1992

Years of
Manufacture Resin
Rupture
Resistance* Notes
1965 - 1970 Alathon 5040 Initial Product Marketed as “Aldyl A”

1970 - 1972 Alathon 5043 10 hours Resin Improvement and Low Ductile Inner Wall

1970 - 1984 Alathon 5043 100 hours Resin Improvement

1984 - 1988 Alathon 5046-C 1000 hours Resin Improvement-- Sold as “Improved Aldyl A”

1988 - 1992 Alathon 5046-U 10,000 hours Resin Improvement --“Improved Aldyl A”

*Illustrates the order of magnitude difference found from accelerated life testing of resins

Common Classifications of Aldyl A Pipe

Based on the characteristics of the different vintages of Aldyl A pipe, there would emerge
over time, from DuPont‟s 1982 letter going forward, three age-groupings recognized by the
manufacturer, natural gas industry, and regulators as relevant in the reliability management
of this pipe.

Pre-1973 Aldyl A – Pipe manufactured through 1972, from the first two resin
formulations, and including pipe having low ductile inner wall.

Pre-1984 Aldyl A – Aldyl A pipe manufactured from Alathon 5043 resin, but only that
pipe manufactured after 1972 and through 1983.

1984 and Later Aldyl A – Pipe manufactured from the improved Alathon 5046-C and
5046-U resins.

Aldyl A Service Pipe - Small-diameter (less than 1¼ inches) Aldyl A service piping is
often treated or managed differently than larger-diameter Aldyl A pipe of the same vintage.
This is because the small-diameter pipe has been assessed by industry experts as being
more resistant to brittle-like cracking than larger-diameter pipe due to its greater flexibility.
Further, small-diameter Aldyl A pipe has been confirmed as being free of the Low Ductile
Inner Wall properties present in late 1970 through early 1972 vintage piping.

ICNU_DR_113 Attachment D Page 8 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 9

II. Federal Bulletins on Brittle-Like Cracking in Plastic Pipe

National Transportation Safety Board

In April 1998, twelve years after DuPont‟s second letter to customers, the National
Transportation Safety Board (Board) published a comprehensive safety bulletin describing
their investigation of natural gas pipeline accidents involving polyethylene pipe that had
cracked in a “brittle-like” manner (See Attachment 3). The bulletin focused primarily on
accidents related to an early plastic pipe manufactured by Century Utility Products
(Century), produced from Union Carbide resin. In its review, findings, and in its Safety
Recommendations, however, the Board concluded that in addition to the Century pipe,
much of the polyethylene pipe produced for gas service from the 1960s through the early
1980s may be susceptible to brittle cracking and premature failure, further noting that
vulnerability of this material to premature failure could represent a serious potential hazard
to public safety.

The Board‟s bulletin represented a seminal work on the vulnerability of early plastic pipe
to brittle-like cracking because it analyzed and integrated – for the first time – reports from
the technical literature, manufacturers‟ communications, industry expert opinions, the
experience of pipeline operators and regulators‟ accident reports. Because the bulletin
provided a clear understanding of the drivers of failure in older polyethylene pipe, we have
included a fairly detailed synopsis in this report.
Objectives of the Board’s Investigation

Following the Board‟s investigation of over a dozen serious incidents, it undertook an
effort to evaluate whether the existing pipeline accident data was sufficient for assessing
the long-term performance of plastic piping. The office of Research and Special Programs
Administration of the National Transportation Safety Board compiled the relevant accident
data, but found it to be insufficient for this purpose. Lacking adequate data for the larger
assessment, the Board instead focused on estimating the likely frequency of brittle-like
cracking, focusing on published technical literature, industry expertise, and work with
several gas system operators. From this review, the Board launched a special investigation
with the objectives to address three safety issues related to polyethylene gas service pipe:

1. Vulnerability of plastic piping to brittle-like cracking
2. Adequacy of available guidance to pipeline operators regarding installation and
protection of plastic pipe tapped to steel mains
3. Performance monitoring as a possible way to detect unacceptable performance
in piping systems

ICNU_DR_113 Attachment D Page 9 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 10

Phenomenon of Premature Brittle-Like Cracking

The Board‟s survey suggested that early plastic piping may be “susceptible to premature
brittle-like cracking under conditions of stress intensification.” The term „stress
intensification‟ refers to localized pressure on the pipe wall created by such conditions as
rock contact or significant bending of the pipe. The phenomenon of brittle-like cracking
was characterized by the failure processes described above, beginning with the initiation of
cracks on the inner wall of the pipe at the pressure or stress point, followed by slow crack
growth that progressed under normal pipeline operating pressures (much lower than the
pressure required to rupture the pipe). The process culminated with the crack reaching the
outside wall of the pipe, showing up as a very tight, slit-like opening on the surface,
running generally parallel with the length of the pipe. Premature brittle-like cracking was
believed, at the time of the Board‟s safety bulletin, to require relatively high and localized
stress on the pipe resulting from sharp or excessive bending, soil settling, rock
“impingement” (point or contact pressure on the pipe), improperly installed fittings, and
dents or gouges to the pipe surface. The term „brittle-like cracking‟ was used to describe
this failure process because the pipe showed no signs of being bulged or deformed where
the cracks occurred.
Board Findings on the Three Identified Safety Issues
Issue 1: Vulnerability of Plastic Piping to Brittle Cracking

Long-Term Strength of Early Pipe was Overrated - In the early 1960s the industry had
very little long-term experience with plastic pipe, and consequently, developed laboratory
testing procedures to forecast the expected service life of piping. Early testing results
suggested that polyethylene pipe would exhibit a relatively constant, or „straight line‟
gradual decline in strength over time. These tests and underlying assumptions were
subsequently incorporated as standards for the industry and in related federal requirements.

As the industry gained experience, however, the straight-line assumptions of these early
procedures began to be challenged through the development of new testing methods, where
pipe strength was assessed under conditions of elevated temperature (such as the testing
referenced in DuPont‟s 1986 letter to customers). Results of the elevated-temperature
testing showed that the decline in strength of early plastic pipe was not gradual or linear as
had been assumed, but instead, began to accelerate or drop below the straight line,
especially after twelve years. The Board concluded that the early testing procedures may
have overrated the strength and resistance to brittle-like cracking of the polyethylene pipe
manufactured for the gas industry from the 1960s through the early 1980s.

Long-Term Ductility was Overrated - Another important assumption about early plastic
pipe, based on short-term testing, was that it would retain its ductile properties long term.
The assumption of long-term ductility had important safety ramifications since it allowed
plastic pipe systems to be designed to withstand stresses generated primarily by internal
pressure and to give less consideration to the impacts of external stresses such as bending.
Unfortunately, the early testing methods did not properly identify the evidence of the
“ductile to brittle” transition that was occurring early in the life of the pipe. Consequently,
ICNU_DR_113 Attachment D Page 10 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 11

the tests did not distinguish pipe failures resulting from a loss in ductility. The Board noted
that this loss of ductility was also observed in the older piping of several manufacturers,
those other than Century Utility Products.

Pipeline Operators had Insufficient Notification - The Board noted that premature
brittle-like cracking was a complex phenomenon that had not been systematically
communicated to the industry, and hence, had not been fully-appreciated by pipeline
operators. The Board recognized pipe manufacturers as commonly offering technical and
safety assistance to operators, and occasionally, formal reports on their materials. But,
because the information on the potential weakness of their products was also mixed with
information publicizing its best performance characteristics, the message was not clear.
The Board also noted that the Federal Government had not provided relevant information
to gas system operators, and concluded that operators had insufficient notification that
much of their early polyethylene pipe may have been susceptible to premature brittle-like
cracking. Finally, the Board went on to recommend that the polyethylene pipe
manufacturers‟ organization, the Plastics Pipe Institute, advise its members to notify
pipeline operators if any of their materials indicate poor resistance to brittle-like failure.
Issue 2: Adequacy of Guidance for Connecting Plastic Pipe to Steel Mains

Critical Understanding of Stress on Pipe - The Board observed that the premature
transition of plastic piping from a ductile to a brittle state appeared to have little observable
adverse impact on the serviceability of plastic pipe, except where the pipe was subjected to
external stresses, such as excessive bending, earth settlement, dents or gouges to the pipe
surface, and improper installation of fittings, etc. Of those sources of stress, a key factor
identified in the Board‟s bulletin was earth settlement, but particularly in cases where
plastic piping was connected to more rigidly anchored fittings, such as steel main pipe.
Because the physical properties of plastic and steel respond differently under the same
conditions, such as to temperature change and ground settlement, the slight movements of
each type of pipe in the ground will be different. This difference in movement can result in
significant stress at the point of connection between the plastic and steel piping.

Much of the Guidance to Operators was Insufficient or Ambiguous - In addition to
pipeline operators having insufficient guidance on the overall issue of the vulnerability of
plastic pipe to brittle cracking, as noted above, the Board also observed that much of the
available guidance to operators on how to limit stress on the pipe during installation was
inadequate or ambiguous. This was particularly the case with the stress associated with the
tapping of plastic service piping to steel mains, where the Board concluded that many of
those connections may have been installed without adequate protection from external
stress. The Board went on to identify several instances where safety requirements did not
fully incorporate safety recommendations, resulting in ambiguity for pipeline installers and
regulators. Other highlights of the Board‟s findings were the many cases where the
applicable regulations applying to pipeline installation lacked any performance
measurement criteria. Noting that the Office of Pipeline Safety considered many of its
safety regulations to be performance-oriented requirements, the Board rebutted this in
stating that “many are no more than general statements of required actions that do not
establish any criteria against which the adequacy of the actions taken can be evaluated.” A
ICNU_DR_113 Attachment D Page 11 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 12

particular example was the regulation that “requires gas service lines to be installed so as to
minimize anticipated piping strain and external loading,” and yet it contained no
performance measurement criteria for establishing compliance. Finally, the Board went on
to note cases where the inadequacy of pipe manufacturers‟ instructions also contributed to
the lack of a clear understanding of methods to limit stress on plastic pipe during
installation.
Issue 3: Monitoring of Plastic Pipe to Determine Unacceptable Performance

The Board‟s final objective was focused on performance monitoring of pipeline systems as
the key to effectively managing the vulnerable piping types identified in the bulletin. In
this discussion, the Board focused on the accident in Waterloo, Iowa in 19941, in
highlighting the very real challenges of designing effective pipeline monitoring programs.
The Board stated that before the accident, the pipeline operator had developed a limited
capability to monitor and analyze the condition of its system. It concluded however, that
the systems the operator had developed for tracking, identifying, and statistically treating
plastic piping failures did not permit an effective analysis of system failures and leak
history, noting that their methods of handling of pipe data masked the high failure rates of
the subject Century pipe. While the operator did re-evaluate its monitoring data after the
accident, and subsequently identified the high failure rates of Century Pipe, the Board
opined that the problem could have been detected earlier (before the accident) if the data
had been properly analyzed in the first place. Finally, the Board concluded that an
effective monitoring program would have allowed the operator to implement a pipe
replacement program that might have prevented the accident.

In the second case, the Board noted that while the operator had added capabilities to its
pipe-monitoring protocols, it had still not chosen parameters needed to provide adequate
analysis of its plastic piping system failures and leak history. The bulletin went on to note
examples of the many types of additional parameters needed to enable the effective
tracking, identifying, and properly describing system failures and leak history.

The Board concluded that in light of the key findings in its bulletin, that gas system
operators may need to be advised once again of the importance of complying with Federal
requirements for piping system surveillance and analyses. Regarding the monitoring of
older piping, the Board identified the necessity to analyze factors such as piping
manufacturer, installation date, pipe diameter, operating pressure, leak history,
geographical location, modes of failure, location of failure, etc. Finally, the Board noted
that an effective monitoring program would require the evaluation of pipe material and
installation practices to provide a basis for the planned and timely replacement of piping
that indicates unacceptable performance.

1 In October, 1994, a natural gas leak and explosion at Midwest Gas Company in Waterloo, Iowa, resulted in
6 fatalities and 7 injuries. The cause of the incident was identified as the failure of a ½ inch diameter service
pipe cracking in a brittle-like manner at a connection to a steel main.
ICNU_DR_113 Attachment D Page 12 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 13

Pipeline and Hazardous Materials Safety Administration
1999 Bulletins

The first two of several advisory bulletins related to the Board‟s 1998 Safety Bulletin
(above), were published by the Office of Pipeline Safety, now known as the Pipeline and
Hazardous Materials Safety Administration (Administration), in March 1999 (See
Attachment 4). The bulletins, which were issued as advisories to pipeline owners and
operators, provided an abstract of the findings of the Board‟s 1998 investigation and
advised that much of the plastic pipe manufactured from the 1960s through the early 1980s
may be susceptible to brittle-like cracking. The advisories concluded with the
recommendation to owners and operators to identify all pre-1982 plastic pipe installations,
analyze leak histories, evaluate potential stresses to pipe, and to develop appropriate
remedial actions, including pipe replacement, to mitigate any risks to public safety.
2002 Bulletin

This bulletin, as with the prior advisories, reiterated to natural gas pipeline owners and
operators the susceptibility of older plastic pipe to premature brittle-like cracking (See
Attachment 5). But, for the first time, this advisory specifically named DuPont‟s pre-1973
Aldyl A pipe (Low Ductile Inner Wall) as being susceptible to brittle cracking. The
bulletin also depicted several environmental and installation conditions that could lead to
premature, brittle-like cracking failure of the subject pipe, and described recommended
practices to aid operators in identifying and managing brittle-like cracking problems.
2007 Bulletin

This bulletin, again, served to review and recap the findings of the prior bulletins, advising
natural gas system operators to review the earlier statements (See Attachment 6). In
addition, the advisory recapped results of the ongoing effort of the American Gas
Association to identify trends in the performance of older plastic pipe. The advisory
reported that the data, at that point, could not assess failure rates of individual plastic pipe
materials, but did support what was historically known about the susceptibility of older
plastic piping to brittle-like failure, including the addition of specific materials to the list,
such as Delrin insert tap tees.
III. 2009 Distribution Integrity Management Program

The Administration published the final rule establishing integrity management
requirements for gas distribution pipeline operators in December 2009. Though the
effective date of the rule was February 2010, operators were given until August 2011 to
write and implement their Distribution Integrity Management Plan.

ICNU_DR_113 Attachment D Page 13 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 14

Objectives and Approach

Among other objectives, the program was intended to overcome two key weaknesses in
pipeline safety management that were identified in the National Transportation Safety
Board‟s 1998 bulletin (above): 1) correct weaknesses in federal regulations, particularly in
the Office of Pipeline Safety, by establishing true measurement criteria for establishing
safety compliance, and 2) establish systematic protocols for pipeline data collection,
analysis, and interpretation, that helps ensure accurate integrity assessment and appropriate
remediation.

The concept of Integrity Management grew out of a demonstration project of the Office of
Pipeline Safety designed to test whether allowing operators the flexibility to allocate safety
resources through risk management was effective in improving pipeline safety and
reliability. Integrity management requires operators, such as natural gas distribution
companies, to write and implement Integrity Management Programs (IMPs) to assess,
evaluate, repair and validate the integrity of pipeline segments. The program contains the
following elements:
Knowledge
Identify Threats
Evaluate and Rank Risks
Identify and Implement Measures to Address Risks
Measure Performance, Monitor Results, and Evaluate Effectiveness
Periodically Evaluate and Improve Program
Report Results
The Integrity Management approach uses historical leak data and other facility information,
along with the input of subject-matter experts, to identify individual threats to a gas system.
These threats are then analyzed to predict the likelihood and consequences of failure. Each
threat is then ranked by priority, followed by the development of a plan to reduce or
remove those risks as deemed necessary.
IV. 2011 Call to Action – Transportation Secretary LaHood

Finally, in April 2011, U.S. Transportation Secretary LaHood issued a Call to Action to all
pipeline stakeholders in conjunction with the effective application of the Distribution
Integrity Management Program (See Attachment 7). The Call to Action was aimed at the
more than 2.5 million miles of liquid and gas pipelines of both federal and state
jurisdiction, including transmission and distribution facilities, calling on owners and
operators, the pipeline industry, utility regulators and state and federal partners to:

Evaluate risks on pipeline systems;
Take appropriate actions to address those risks, and
Requalify subject pipeline systems as being fit for service.

ICNU_DR_113 Attachment D Page 14 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 15

The centerpiece of the Call to Action is the “Action Plan” of the Board and Administration.
The focus of the Action Plan is to accelerate the rehabilitation, repair, and replacement of
high-risk pipeline infrastructure, calling on pipeline operators and owners to take
“aggressive efforts… to review their pipelines and quickly repair and replace sections in
poor condition.” To buttress this Call to Action, Secretary LaHood has asked Congress to
increase maximum civil penalties for pipeline violations, to close regulatory loopholes,
strengthen risk-management requirements, add more inspectors, improve data reporting and
help identify potential pipeline safety risks early.
V. Avista’s Experience with DuPont Aldyl A Piping Systems

Avista has approximately 12,500 miles of natural gas piping in its service territories in the
States of Washington, Oregon and Idaho. Like dozens of other gas utilities, Avista adopted
plastic pipe as an excellent alternative to steel, and consequently, the broad majority of
Avista‟s pipe is polyethylene (about 8,500 miles) of various types, ages and brands,
including DuPont‟s Aldyl A.

Avista began installing DuPont Aldyl A in 1968 and discontinued its use in 1990 when
DuPont sold their production to Uponor. Of the various vintages and formulations of Aldyl
A pipe in its system, Avista has estimated quantities in the following amounts, in diameters
of ½” to 4”:

Pre-1973 Aldyl A (1965-1972 resins) 190 Miles
1973-1984 resins 960 Miles
1985-1990 resins 919 Miles

Avista noted the advisory bulletins of the Board and Administration in 1998, 1999 and
2002, but since it had no documented trends in the types of failures highlighted, continued
to manage its Aldyl A pipe according to established monitoring standards for leak survey
and sound operations practices.
Spokane and Odessa Incidents

In recent years, however, Avista experienced two natural gas incidents2 resulting in injuries
and property damage that signaled possible changes in leak patterns in its Aldyl A piping.
The first incident occurred in 2005 at a commercial site in Spokane. This event involved
the failure of 1976-vintage Aldyl A pipe caused by bending-stress resulting from poor soil
compaction around the pipe that was performed by a non-Avista excavator in 1993. The
post-incident investigation judged the resulting leak to be an anomaly that could have been
prevented with proper care by that third-party excavator.
The second incident, at a residence in the town of Odessa, Washington, in late 2008, was
determined to be the result of rock pressure on the 1981-vintage Aldyl A pipe that occurred

2 The Pipeline and Hazardous Materials Safety Administration defines a natural gas “incident” as a release of
gas that results in any of the following: a fatality or personal injury that requires in-patient hospitalization;
property damage of $50,000 or greater, or the loss of greater than 3 million cubic feet of gas.
ICNU_DR_113 Attachment D Page 15 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 16

during the initial installation. Avista signed a settlement agreement with staff of the
Washington Utilities and Transportation Commission as an outcome of the investigation of
this incident. Under terms of the agreement, which was subsequently approved by the
Commission, Avista increased the frequency of its residential leak survey on pre-1984 resin
(pre-1987 installed) Aldyl A natural gas mains in its Washington jurisdiction, from once
every five years to annually. In addition, whenever it is excavating in the vicinity of Aldyl
A natural gas mains in Washington, Avista will also report on the soil conditions
surrounding the pipe, and identify appropriate and reasonable remedial measures, as
necessary. Avista retained the consulting services of Dr. Gene Palermo to help develop its
approach for managing Aldyl A pipe, in relation to the soil conditions reported.
Expert-Recommended Protocol for Managing Aldyl A Pipe in Relation to
Reported Soil Conditions

Dr. Palermo is a nationally-recognized expert on the plastic pipe used in natural gas
systems, and in particular, Aldyl A piping. He has worked in the plastic pipe industry for
over 35 years, which includes 19 years with the DuPont Corporation in its Aldyl A natural
gas pipe division.

Dr. Palermo also served as the Technical Director for the Plastics Pipe Institute from 1996
through 2003 and served on the Institute‟s Hydrostatic Stress Board for over 20 years. Dr.
Palermo has served on a variety of gas industry committees, has trained gas industry
practitioners and regulators, and has received numerous awards of merit for his outstanding
individual contribution to the natural gas plastic-piping industry. He is the only person to
receive both the American Society of Testing and Materials - Award of Merit, and the
American Gas Association - Platinum Award of Merit. Dr. Palermo is president of his
consulting firm, Palermo Plastics Pipe Consulting.

Dr. Palermo reviewed the content of Avista‟s settlement agreement with the Commission to
become familiar with its requirements, specifically with regard to managing Aldyl A piping
found in soils that would currently not meet standard criteria for bedding and backfill. Dr.
Palermo‟s review and expertise provided the basis for his recommended protocol for
management of Avista‟s Aldyl A piping found in rocky soils. (See Attachment 8):

1. All Aldyl A pipe manufactured prior to 1984 should be evaluated for replacement in
the following manner:
a. If the pipe has Low Ductile Inner Wall properties, Avista should
immediately begin a prioritized pipe replacement program.
b. If the pipe is installed in soil with rocks larger than ¾ inch, Avista should
immediately begin a prioritized pipe replacement program.
c. If the pipe is installed in sandy soil or in soil with rocks up to ¾ inch in size,
the pipe should remain in service and normal leak surveys per DOT Part 192
should be followed.
2. All Aldyl A pipe manufactured during or after 1984 should also be evaluated.

a. If the pipe is installed in soil with rocks larger than ¾ inch in size, Avista
should evaluate the pipe and consider replacing it if they begin to experience
ICNU_DR_113 Attachment D Page 16 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 17

rock impingement failures, and should conduct leak surveys more frequently
than required by DOT Part 192, until replacement.
b. If this pipe is installed in sandy soil or in soil with rocks up to ¾” in size, the
pipe should remain in service and normal leak surveys should be followed.
Evaluation of Leak Survey Records

Following the Odessa incident, Avista was also asked to review five years of leak survey
records in Washington State to look for possible emerging patterns in the health of its Aldyl
A piping system. Avista organized the leak survey information and then conducted several
evaluations, which were organized under three general objectives, listed below.

1. Analyze the modes or observed types of failures in Aldyl A pipe;
2. Forecast the expected long-term integrity of Aldyl A piping;
3. Identify potential patterns in the overall health of this piping to aid in the design of
a more-focused management protocol for Aldyl A pipe.

Avista used newly-available asset-management tools to conduct these assessments,
including its recently-implemented Integrity Management approach for identifying and
analyzing potential threats to its natural gas system. This approach is suited for just such
an analysis, having the capability to determine potential patterns in the overall health of a
piping system that might not have been otherwise evident through conventional data
review. The analysis of the historic leak survey data, including the observation of several
new Aldyl A material failures and leaks, did point to the development of a possible trend.
Pipe Replacement Projects in 2011

Another outcome of this heightened focus on Aldyl A leaks was Avista‟s decision to
replace several thousand feet of its Aldyl A main in 2011. In Odessa, Avista increased the
frequency of leak surveys on its gas system to once per quarter and mobilized a pipe
replacement program that removed all of the pre-1984 Aldyl A main pipe from the gas
system in the town. During that project, which was conducted from June to December
2011, nearly 32,000 feet of Aldyl A main pipe were replaced. Other Aldyl A replacement
projects in 2011 removed an additional 7,000 feet of this priority pipe. Together, these
projects had a capital cost of approximately $2.7 million.

VI. Avista Distribution Integrity Management Program
As described briefly above, the Integrity Management approach, now required by law,
begins with the aggregation of historical leak-survey data and other facility information
relevant to Avista‟s natural gas piping system. Then, in conjunction with the input of
subject matter experts, individual threats to Avista‟s gas system are identified. These
threats are analyzed to predict the likelihood and consequences of failure associated with
each threat, based on the specific operating environment, system makeup, and history of
Avista‟s natural gas system. Each threat is then ranked relative to all others to identify, by
priority, those with the greatest hazard potential. From that priority list, measures are
ICNU_DR_113 Attachment D Page 17 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 18

developed to reduce or remove those risks as deemed necessary. These mitigating
measures are often referred to as “accelerated actions” because they may be above and
beyond the minimum requirements of applicable federal and state codes. These accelerated
actions can range from increased frequency of maintenance and leak surveys to full
replacement programs for certain gas facilities. Finally, the mitigating measures will be
reviewed to evaluate their effectiveness in reducing threats to the gas system, and the
program will then be adjusted as necessary based on those outcomes.
Integrity Management requires the use of geographically-based analytical software to
complete many of the required program elements. Like many utilities, Avista is using the
Geographic Information System (GIS) platform developed and supported by
Environmental Systems Research, Inc. (ESRI), as the geographic and analytical engine for
conducting its gas system evaluations under the Integrity Management program. ESRI is a
pioneer and world leader in developing and supporting geographic software products for a
broad range of global business sectors, including utilities. Since Avista had already created
a comprehensive GIS layer, or database, for its gas facilities, it made sense to add
analytical capabilities to this platform in complying with the Integrity Management
program requirements.
VII. Analyzing Modes of Failure in Avista’s Aldyl A Pipe

In tackling the first objective of the assessment of its Aldyl A piping, Avista aggregated the
gas leaks resulting from Aldyl A material failures found in its gas system in Washington
State from late 2005 through March 2011. The sample included 113 material failures that
were evaluated and summarized by component to offer an understanding of the specific
failure modes for Aldyl A pipe. The „modes‟ or types of material failures categorized are
shown below in Figure 1.

ICNU_DR_113 Attachment D Page 18 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 19

Figure 1. Modes or types of material failures documented in a sample of 113 leaks in
Avista’s Aldyl A piping in Washington State, December 2005 through March 2011.

Towers and Caps

The largest percentage of material failures in the sample occurred in Towers and Caps,
referring to failure of the service tapping tee itself, shown below in Figure 2. In these
cases, the pressure applied to the tee as the cap was tightened onto the body during initial
installation has resulted in slow crack growth and failure of the tower body, the cap, or the
Delrin® insert many years later. Additionally, the saddle fusion point of the tower to the
main pipe is another frequent point of failure in this assembly. The unavoidable stresses
created during standard installation (using factory recommended procedures) have led to
brittle cracking in these components many years later. This phenomenon clearly
demonstrates the susceptibility of certain resins of Aldyl A piping to tend to fail by brittle
cracking due to the slow crack growth initiated during installation.
Figure 2. External features and internal components of a typical Aldyl A service tee, as
fused to Aldyl A main pipe.

ICNU_DR_113 Attachment D Page 19 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 20

Rock Contact and Squeeze-Off

The second-most common material failure observed in Avista‟s Aldyl A pipe was due to
localized, brittle cracking in Aldyl A mains that resulted from rock impingement – rock
pressure directly on the pipe, or places where „squeeze-off‟ was applied over the pipe‟s
service life. These failures are very typical for certain resins of Aldyl A main pipe, having
been consistently reported by other utilities since before the time of DuPont‟s 1986 letter.
As described earlier, when these external stresses (rock impingement or squeeze-off) cause
the pipe to fail, it always begins with crack initiation on the inside surface of the pipe wall,
eventually resulting in slow crack growth that propagates toward the outer wall of the pipe,
and finally, through-wall failure. These failures generally appear as short, tight cracks in
the outer wall of the pipe that run either parallel, or slightly off-parallel with the length of
the pipe. A typical failure in Aldyl A main pipe, showing a crack through the pipe wall as
it appears on both the inner and outer surfaces, is shown below in Figure 3.
Figure 3. Typical brittle-like crack through the wall of Aldyl A pipe, resulting from rock
contact directly on the pipe.

Although the duration of the stress caused by rock contact with the pipe is very different
from that associated with squeeze-off, they both result in the same pattern of crack
initiation and slow crack growth leading to failure of the pipe. Other sources of external
stress that can result in brittle failure of Aldyl A pipe, as mentioned earlier in the report,
include bending of the pipe, soil settlement, dents or gouges to the pipe, and improper
installation of fittings.
Services Tapped from Steel Mains

The third most-common failure in Avista‟s sample occurred where small diameter Aldyl A
service pipe is tapped from steel main pipe. In this application, a steel service tee is welded
to the steel main pipe and the small-diameter Aldyl A service pipe is then connected to a
mechanical transition fitting on the tee, as pictured below in Figure 4.

ICNU_DR_113 Attachment D Page 20 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 21

Figure 4. Typical polyethylene service tapped from a steel main.

It is at this transition point, between the rigid steel fitting and the more-flexible Aldyl A
service pipe, that brittle-like cracking has been observed. This failure mode in older plastic
pipe is well understood, and was one of the three study objectives reported by the National
Transportation Safety Board in its 1998 bulletin, summarized earlier in this report.
Avista’s Aldyl A Services

Avista believes its Aldyl A “service” piping, apart from cracking at the connection with the
tee on steel main pipe, has no greater tendency to fail than its other polyethylene service
piping, and at this point in time, should not be managed differently than other plastic
service pipe (frequency of leak survey, etc.). Consequently, Avista is not planning to
systematically replace Aldyl A service pipe as it replaces main pipe and rehabilitates
service connections at steel tees. Avista is using the Integrity Management model,
however, to track and analyze service leaks going forward to determine if the reliability of
Aldyl A service piping changes in ways that warrant a different approach.

Understanding the Significance of Leaks in Aldyl A Pipe
Frequency and Potential Consequence

Analysis of the material failures of Aldyl A pipe provides the opportunity to put these leaks
into perspective with other types of leaks on Avista‟s natural gas system. As part of the
development of the Integrity Management Plan, five years of leak data were analyzed for
Avista‟s three-state service territory. The data included nearly 17,000 individual leaks,
which were categorized according to the underlying threats to the natural gas system as
required under Integrity Management. As a point of comparison of the significance of leak
types, the data included in excess of 2,000 leaks associated with the failure of gas system
equipment, such as valves, fittings and meters. Only 153 leaks, however, were identified as
resulting from „material failures‟ of Aldyl A piping in the three states. Looking simply at
Aldyl A leaks as part of the aggregate of all system leaks, one might conclude that Aldyl A
pipe failures pose a limited potential for hazard relative to the threat of other system leaks.
In fact, while gas equipment leaks are more likely to occur, their potential consequence is
often minimal. A thorough understanding of this difference is one of the most important
requirements and outcomes of any effective Integrity Management Plan analysis.

ICNU_DR_113 Attachment D Page 21 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 22

Review of the leak-history data shows the vast majority of equipment leaks as occurring
typically with shut-off valves and gas meters, located either above ground or in locations
that allow free-venting of gas to the atmosphere. Consequently, these types of leaks have a
low potential to result in an incident posing harm. Through public awareness programs,
people have become familiar with the odor of venting gas and tend to quickly call Avista to
make repairs; this is especially true if the venting gas can be associated with visible gas
valves or meters. By contrast, Aldyl A failures and the associated leaks occur almost
entirely underground, out of sight, often in populated areas, and occasionally in the
proximity of buildings that are not actually connected to the natural gas system. Without
visible facilities, natural gas may have an unexpected presence in the environment that
allows people to dismiss slight gas odors. This reduced awareness allows gas from these
undetected leaks to have the significant potential to migrate into buildings before it can be
identified and reported. This is especially true in winter when the ground is saturated,
frozen or snow covered, and in areas of full pavement and concrete finishes. Of the
roughly 2,000 equipment leaks reported in the five years of data reviewed, none resulted in
gas incidents. By comparison, two of the relatively-small number of Aldyl A material
failures resulted in gas migrating into buildings undetected, and upon accidental ignition,
resulted in harmful incidents.
The Complication of Brittle Cracking in Aldyl A Pipe

The common mode of failure for Aldyl A materials, brittle-like cracking, can also present
special problems compared with leaks in other gas piping, such as corrosion in steel gas
pipe. Corrosion leaks tend to begin with the failure of a very minute area in the pipe wall,
which then begins to release a very minute amount of natural gas. These leaks then tend to
progress very slowly and in a stable and somewhat predicable way over time. These types
of leaks, while never positive, are more likely to be detected by modern gas-detection
equipment when they are at a stage where the release of gas is relatively minor. By
contrast, leaks in Aldyl A piping tend to first appear as substantial (high gas volume) leaks
that appear in a very short time period. This is due to the nature of brittle cracking, where
the crack can progress very slowly from the inner wall of the pipe toward the outer wall
without any release of gas, until the pipe finally splits open, resulting in a substantial
failure. Additionally, unlike the prevention or even suspension of corrosion problems in
steel pipe through effective protection methods, there is no way to halt undetected progress
of slow crack growth in brittle Aldyl A pipe.
VIII. Reliability Modeling of Avista’s Aldyl A Piping

Avista‟s Asset Management Group performed reliability modeling for several classes of its
natural gas pipe in order to assess the long-term performance of its Aldyl A piping,
compared with steel pipe and newer-vintage plastic pipe. Reliability analysis comes from
the discipline of „reliability engineering‟ and is a foundational asset management tool that
provides a forecast or prediction of the future performance of a piece of equipment (pipe, in
this instance). The predicted asset performance then provides the basis for the application
of other asset management tools, allowing the development of the ultimate maintenance or
ICNU_DR_113 Attachment D Page 22 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 23

replacement strategies that optimize asset cost with any number of other factors, such as
availability for service or risk avoidance.
Availability Workbench Software

Avista developed reliability forecasts for its Aldyl A and other piping using Availability
Workbench™ software. This „off the shelf software‟ was introduced by Isograph, Ltd., the
world‟s leader in reliability analysis software. Availability Workbench was first introduced
in 1988, and is used to support asset decision making in over 7,000 sites around the world
and across a range of industries, including Aerospace, Automotive, Chemical, Defense,
Electronics, Manufacturing, Mining, Oil and Gas, Power Generation, Railways, and
Utilities. Avista‟s version of the model was released in 2009.
Reliability Forecasting

Availability Workbench has four modules, one of which, the Weibull module, is used to
create reliability forecasts (curves) for an asset. Reliability curves for gas piping are
generated from input data that include pipe inventory (type, brand, footage, location, soil
conditions, etc.), current age of piping, historic and current failure information and repair
data. Avista uses predominantly its own historical data for these inputs, but when they
must be estimated, they are vetted by subject matter experts within the company. The
model integrates pipe age and failure and repair data, and then by applying a conventional
Weibull-curve mathematical model, it produces probability curves that represent the
expected failure rates over time for each failure mode, such as the brittle-like cracking
associated with Aldyl A services tapped to steel mains. The reliability curves represent
how quickly the rest of the pipe is at risk of failing, shown as the percentage of failures
expected each year over time.
Forecasting the Reliability of Aldyl A Piping

The objective of Avista‟s reliability modeling was to forecast expected failures for
elements of Avista‟s Aldyl A piping system, compared with that of steel and latest-
generation polyethylene pipe. The observed Aldyl A failure modes, discussed above,
including leak data for other types of gas pipe in Avista‟s system, provided high-quality
leak and age information for the reliability modeling. Forecasting was performed for the
following pipe „classes‟ in Avista‟s system.

a. Aldyl A Main pipe of Pre-1984 manufacture (Alathon 5040 and 5043 resins,
including low ductile inner wall pipe)
b. Aldyl A Main pipe manufactured during 1984 and after (Alathon 5046-C and
5046-U resins)
c. Aldyl A Services Tapped to Steel Main (Bending Stress Services)
d. Steel pipe
e. Newer Polyethylene pipe (1990 and later)
To perform the modeling, the data for these pipe classes must be input as discrete elements,
which are described as follows:

ICNU_DR_113 Attachment D Page 23 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 24

Main Pipe - Analyzed using 50-foot segments as discrete modeling elements.

Services Tapped from Steel Mains - Avista identified 16,000 such services in its system,
also referred to as „bending stress tees.‟ For the reliability modeling, the individual service
is the discrete element.

Forecasting Results
Forecast Piping Failures

Results of the forecast modeling, for the pipe classes evaluated, are represented as „curves‟
showing the percentage of the amount of each pipe class that is projected to fail in each
year of the forecast time period. The resulting reliability curves are shown in the graph
below in Figure 5.

Figure 5. The expected failure rates for several classes of pipe in Avista’s system, as
forecast by Availability Workbench Modeling. The “Steel” curve is obscured by the
“Newer Polyethylene” curve, both of which are essentially flat lines.

The failure curves show dramatic differences in the expected life for the pipe classes
evaluated. The difference in expected life between the Aldyl A products as a group,
compared with that of steel and newer-generation plastic pipe, is particularly evident.
Striking also, are the expected performance differences among the classes of Aldyl A pipe
evaluated, providing some clear trends useful in designing remediation strategies.
Dependability of Forecasting Future Failures

ICNU_DR_113 Attachment D Page 24 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 25

The reliability forecast is essentially a mathematical calculation of the „chance‟ of future
failure and decisions of significant risk and financial magnitude are based, at least in part,
on that result. Importantly though, the forecast has a „real numbers‟ foundation in the
actual leak data, records of material failure and repair, and the relationship of those events
with time. For Aldyl A pipe, the model is using observed endpoints in the life of the pipe
resulting from a loss in ductility and slow crack growth, for example, and integrating that
with other data to forecast future expected failures. Comparatively, the relatively rare
observed failures in steel pipe and newer-generation plastic pipe are reflected in their
nearly-flat cumulative failure curves. The value of using proven reliability forecasting
approaches and widely-adopted software is derived from their ubiquitous application across
reliability-critical industries, and their continuous testing, evaluation, and support. Finally,
as Avista adds new data in coming years for pipe failures of all material classes, including
Aldyl A, it serves to increase the statistical power of the forecast results.
Understanding the Significance of Cumulative Failure Curves

Although the failure curves for the different classes of pipe differ significantly over the
long term, as mentioned, the failure rates also appear to remain below one percent for the
first 45 years for Aldyl A services tapped to steel main, and for 65 years for Pre-1984 Aldyl
A main pipe. Since the weighted average age for Aldyl A pipe in Avista‟s system is 32
years, it would appear that we might have ample time before the failure rate would start to
rise substantially for Pre-1984 Aldyl A main pipe. Using the Pre-1984 main pipe in
Washington as an example, the failure curve estimates that when this pipe is 65 years old
that approximately one percent of it will fail in that single year. Given that Avista has 328
miles of this vintage pipe in Washington, that mileage equals nearly 35,000 discrete
elements (50-ft sections) in the forecast model. The one percent failure, then, translates to
346 leaks in that 65th year. To put this failure rate into perspective, consider the 113 leaks
documented (primarily on Pre-1984 main pipe) over the past five years in Washington
state. The 113 leaks equal an average of 22.6 leaks per year, or an annual failure rate of
0.06 percent. Since it is expected that the number of hazardous leaks and incidents would
increase proportionally with the increase in total leaks, then it‟s easy to imagine just how
unacceptable the pipe performance would be at an annual failure rate of one percent.
Prudent Management of Anticipated Failures

To carry this point further, if we “zoom-in” on the curves we can gauge the significance
of the change in failure rate that is expected ten years from today. At that point the
weighted average age of Aldyl A pipe in Avista‟s system will be 42 years, and the expected
failure rate for Pre-1984 Aldyl A main pipe in that year will be just over one-tenth of one
percent (0.12%), or 42 leaks in that year. This failure rate, while still just a tiny fraction of
the one percent rate used in the example above, represents almost a doubling of the average
annual rate for the past five years (22.6), a time when two of the documented leaks resulted
in injury and property incidents and dozens more were categorized as hazardous leaks3,

3 The Pipeline and Hazardous Materials Safety Administration defines a “hazardous leak” as an unintentional
release of gas that represents an existing or probable hazard to persons or property and requires immediate
repair or continuous action until the conditions are no longer hazardous.
ICNU_DR_113 Attachment D Page 25 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 26

timely repaired. The critical point in this example is the understanding that failures in
buried natural gas piping can be prudently managed only when they are occurring at very
low rates. Otherwise new leaks in the system occur too frequently to be detected by even
annual leak surveys of the entire system, resulting in an increase in the likelihood of
hazardous leaks and the potential for harmful incidents.
Priority Aldyl A Piping

Every pipeline operator strives to install and maintain a safe, reliable and cost-effective
system. While the goal is complete system integrity, it is impossible to avoid having any
leaks, especially on large systems such as Avista‟s with over 12,000 miles of mains and
several hundred thousand services. Regulators and the industry acknowledge this reality
through the adoption of standardized leak-survey methodologies, and recognized pipe
remediation practices.

While leaks are inherent on a system, there are circumstances where the expected failure
rate of a particular pipe begins to rise compared with that of other piping and industry
norms. We have demonstrated that such is the case for portions of the Aldyl A pipe in
Avista‟s system, and accordingly, we have determined these classes to be at-risk of quickly
approaching a level of reliability that is unacceptable and in need of proactive remediation.
It‟s for this reason that Avista refers to these pipe classes as “Priority Aldyl A piping.”
IX. Formulation of a Management Program for Priority Aldyl A Pipe

The timely application of Avista‟s Integrity Management approach to its recent and
ongoing leak analysis and its reliability modeling results, including Dr. Palermo‟s review,
and the experience gained in three priority pipe-replacement projects in 2011, has prompted
Avista to formulate a protocol for systematically managing its Aldyl A pipe. The following
categories are useful classifications for Avista‟s definition of “priority Aldyl A pipe”4:

1. Aldyl A gas services tapped to steel main pipe
2. Pre-1973 Aldyl A main pipe
3. Pre-1984 Aldyl A main pipe

Avista has determined these classes of pipe are at risk of approaching unacceptable levels
of reliability without prompt attention. Accordingly, Avista believes the decision to
formulate a management program for its priority Aldyl A pipe is both timely and prudent,
and is consistent with results of our leak investigations, Integrity Management principles
and the recent Call to Action of Secretary LaHood. The decision is also consistent with the
prior federal bulletins on this subject and with the decisions of other similarly-situated
utilities that have implemented similar pipe-replacement programs. Finally, given the
significant amounts of priority Aldyl A pipe on Avista‟s system, commencing a protocol
4 Each class noted above is subject to material failures due to concentrated stresses such as rock impingement,
bending stresses, squeeze off, and failures of service towers and caps.
ICNU_DR_113 Attachment D Page 26 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 27

now provides us greater opportunity to manage these facilities in a prudent and cost-
effective manner.

Priority Aldyl A Piping in Avista’s System

Main Pipe - Avista has approximately 12,500 miles of natural gas main pipe in its service
territories in the States of Washington, Oregon and Idaho. Approximately seventeen
percent of this total, or 2,000 miles, is Aldyl A pipe of all classes and sizes. Proportions of
various classes of piping in Avista‟s system, including priority Aldyl A pipe (pre-1973 and
pre-1984 mains) is shown below in Figure 6.

Figure 6. Avista’s priority Aldyl A pipe, shown as a proportion of the different pipe
classes in Avista’s natural gas system (items 2 and 3 from the list above).

ICNU_DR_113 Attachment D Page 27 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 28

Gas Services - Avista has approximately 314,000 natural gas services, of which
approximately 16,000, or five percent, are Aldyl service pipe tapped to steel main pipe,
shown below in Figure 7 as priority Aldyl A services.

Figure 7. Avista’s priority Aldyl A gas services (tapped from steel mains), shown as a
proportion of Avista’s total gas services.

X. Other Aldyl A Pipe Replacement Programs
Aldyl A Pipe in the Pacific Northwest

Through general conversation with our colleagues in western gas utilities, Avista believes it
has a substantially greater proportion of Aldyl A pipe in its system than do our neighboring
Pacific Northwest gas utilities. The proportions of Aldyl A in Avista‟s system (or of any
other brand of early polyethylene pipe), however, is not a reflection of the unique
purchasing practices of Avista, since plastic pipe quickly became the standard of the
industry and the predominant pipe installed by utilities across the county. However, the
proportions of early plastic pipe in a system do tend to track with the amount of system
growth that gas utilities experienced during the 1970s and early 1980s. For Avista, this
was a time of particularly rapid expansion of its natural gas system (from the Spokane
metro area to outlying communities in its Washington and Idaho service territories), and
consequently, the proportion of early Aldyl A pipe in our system reflects this period of
expansion.

Established and Emerging Programs for Aldyl A Pipe Replacement

Two western utilities, Southwest Gas and Pacific Gas & Electric, have significant Aldyl A
pipe management programs either well underway or anticipated, which are very briefly
summarized below.

ICNU_DR_113 Attachment D Page 28 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 29

Southwest Gas – Responding to a fatality incident in the early 1990s, Southwest Gas
entered into a settlement agreement with the Corporation Commission of Arizona to
conduct additional leak monitoring and pipeline remediation (See Attachment 9). By the
late 1990s, Southwest Gas had replaced 74 miles of Aldyl HD (high density) main pipe
covered by the agreement, and had replaced another 648 miles of Aldyl A pipe based on its
leak survey monitoring results. In 2005, Southwest Gas had another injury and property
incident on their system involving Aldyl A pipe, and implemented an additional pipe
replacement program in the vicinity of the incident. Southwest Gas has also worked
closely with staff of the Public Utilities Commission of Nevada in the monitoring and
replacement of what the Commission refers to as “aging” and “high risk” natural gas pipe,
including Aldyl A pipe (See Attachment 10).

Pacific Gas & Electric - After some very high-profile natural gas incidents in 2011 that
involved Aldyl A piping, Pacific Gas & Electric has announced plans to replace all the Pre-
1973 Aldyl A pipe in its system (See Attachment 11). The utility reportedly has 7,907
miles of Aldyl A pipe of all classes in its system, which is about 19 percent of its gas
system inventory. By comparison, Avista‟s Aldyl A pipe stock is about 16 percent of its
system. Pacific Gas & Electric‟s planned replacement of its Pre-1973 Aldyl A pipe
represents a massive effort because the utility plans to remove and replace the 1,231 miles
of pipe in a proposed timeframe reported as in the range of three years, and at a cost said to
exceed $1 billion, but that has not yet been formalized. There is some question regarding
the selection of only pre-1973 Aldyl A for replacement in PG&E‟s system, since at least
one recent high-profile incident was reported on newer vintage (still pre-1984) Aldyl A.
Developments of Interest

US Congresswoman Jackie Speier of California has been raising the awareness of Congress
and Transportation Secretary, LaHood, in two separate actions. First, in May 2011, Speier
sponsored House Resolution 22 entitled the “Pipeline Safety and Community
Empowerment Act of 2011.” The legislation provided for citizens being able to easily
access pipeline maps and safety-related information from pipeline owners, prescribed
certain changes in pipeline monitoring requirements, and called for the addition of physical
safety devices to existing pipelines. The bill is currently under consideration by the House
Committees on Transportation and Infrastructure, and Energy and Commerce.

In October 2011, Speier wrote to Secretary LaHood calling on him to direct the Pipeline
and Hazardous Materials Safety Administration to “take immediate action to address the
long-known safety risks associated with pre-1973 Aldyl-A plastic pipe manufactured by
DuPont.” She went on to advocate for the removal of this pipe from use in the U.S., and to
commend Pacific Gas & Electric for its planned removal of all of its pre-1973 Aldyl A
pipe. Citing the DuPont letters to customers, federal safety bulletins, and the Waterloo
incident, she chided Congress for not taking action, and urged the Secretary to immediately
do so (See Attachment 12).
ICNU_DR_113 Attachment D Page 29 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 30

XI. Designing Avista’s Replacement Protocol for its Priority Aldyl A
Pipe

Avista modeled two different approaches to the replacement program, one that was
systematic, based on an established timeframe and one that was responsive to problem
areas as they were identified.

Systematic Replacement Program
Time Horizon

Determining the appropriate length of time over which to replace the Priority Aldyl A pipe
involves the optimization of several factors, including: 1) the overall urgency from a
reliability and safety perspective, both present and forecast; 2) potential consequences; 3)
the impact of more intensive leak survey methods to better identify priority facilities in
need of replacement and in helping reduce the potential for harmful incidents; 4) the ability
to effectively prioritize specific projects to better ensure facilities in greatest need are
addressed earliest; 5) the availability of equipment and labor resources needed to conduct
the work, and the ability to coordinate the work with Avista‟s ongoing construction
programs; 6) program efficiency, and 7) the degree of rate pressure placed on customers,
both in absolute terms and in relation to other reliability and safety investments required
across the natural gas and electric business. Ultimately, Avista must ensure that
management and removal of its Aldyl A pipe is conducted in a way that shields our
customers from imprudent risk, while at the same protecting them from the burden of
unnecessary costs.
Prudent Management of Potential Risk

Avista believes it is important to establish for our customers and other stakeholders that
while there can never be „zero risk‟ associated with the program, the potential risk can be
prudently managed. On one hand, a replacement program carried out over a very short
timeframe cannot prevent the occurrence of all leaks forecast to occur over the course of
the program. But at the other extreme, it‟s clear that setting a replacement timeline that‟s
too lengthy would likely result in safety, reliability and financial consequences for our
customers and our business that could be regarded as unacceptable. Avista believes the
timeline for the replacement program should optimize the factors mentioned above in a
way that reduces the risk associated with Aldyl A pipe to the range of „prudent risks‟
associated with the myriad other electric and gas facilities and practices that are used to
serve the energy needs of utility customers. Avista‟s treatment of its Aldyl A pipe will be
managed to comport with these sound business practices.

ICNU_DR_113 Attachment D Page 30 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 31

Prioritizing the Work

As important as the replacement timeline in prudently managing the reliability of Avista‟s
Aldyl A piping, is the ability of the Asset Management and Distribution Integrity
Management staff to partner in effectively prioritizing the pipe-replacement activities in a
way that minimizes the potential for hazardous leaks. Results of the Availability
Workbench modeling provide some support in prioritization but do not take into account
factors such as soil conditions or the proximity to buildings or people. Obviously, a leak
occurring in a vacant field will have little, if any, consequence and will likely be detected
and repaired during the next leak survey. By contrast, the potential hazard of a leak
increases with its proximity to people and structures, so replacing pipe that has a high
probability of leaking and is located in populated areas is first priority.

Avista‟s Integrity Management approach provides the analytical tools that integrate key
knowledge and information needed to effectively prioritize replacement activities based on
the potential hazard. In the prioritization process, each segment of Aldyl A pipe in Avista‟s
system is assigned a relative risk ranking, based on its age, material, soil conditions,
construction methods, and its maintenance history. This information is then loaded into
Avista‟s GIS database containing the gas system maps. These maps contain a “layer” of
grid squares (50 feet per side) that correspond with sections of the Aldyl A pipe. Each
square is known as a “raster” and each raster contains all of the risk-related information
that was loaded into the GIS system, as associated with the Aldyl A pipe at that precise
geographic location.

Next, the software integrates the historic leak information for Aldyl A pipe on Avista‟s
system with the risk data associated with each of the Aldyl A pipe segments, and predicts
the geographic areas (via the risk rasters) where Aldyl A pipe failures are expected to be
greatest. In the last step, the software integrates the results for expected failures with
information for each risk raster that identifies the potential consequence of a leak on that
segment (i.e. the proximity of that raster to buildings and people, and the population
density/sensitivity of those structures). The end result is a color-coding of the rasters that
provides a visual picture of where on the gas system that both the potential likelihood of a
leak, and the potential consequence of a leak, are greatest. This approach provides Avista
with a comprehensive and objective means of identifying Aldyl A pipe that has the highest
priority for replacement.
Twenty-Year Proposal

Avista modeled various time horizons for the replacement program, up to a timeline of 30
years, and determined a replacement horizon in the range of twenty years to represent an
optimum timeframe for removing and replacing its priority Aldyl A pipe. Shortening the
timeline was found to have increasing cost impacts to customers but with little
improvement in the numbers of expected facility failures. Lengthening the timeline past
twenty years, however, was found to result in a substantial increase in the number of
material failures expected. A replacement timeline of 25 years, for example, resulted in
more than a doubling of the number of leaks expected when compared with the twenty year
horizon. Under the twenty year replacement program, the number of material failures each
ICNU_DR_113 Attachment D Page 31 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 32

year is expected to increase slightly until 2017, at which time the cumulative effect of
priority piping replaced since 2012 begins to check the failure count and then drive it
toward zero over the remaining course of the program (Figure 8).

Figure 8. Expected numbers of material failures in Avista’s priority Aldyl A piping in two
cases: Replacement Case - piping replaced over a twenty year horizon in the manner
proposed by Avista in this report, and Base Case – assumed that priority piping was not
remediated under any program.

Importantly, Avista is not suggesting that experiencing an increase in leaks on our system
is “acceptable” per se, in particular, after having had two harmful incidents in the past few
years. What we are saying, however, is that by using the Integrity Management model to
prioritize work activities in the manner described above, Avista believes it can manage the
forecast Aldyl A leaks in a way that significantly reduces their potential occurrence in areas
that could result in harm. Under this approach, Avista believes it can prudently manage the
replacement of priority Aldyl A pipe with the goal to avoid harmful incidents, and at a
reasonable rate impact for our customers.
Initial Optimization

Importantly, Avista‟s proposal for a 20-year replacement program represents an
optimization based on the information we have available today. Any number of factors
could change as the work proceeds over the first few years that could result in a „new‟
optimum time horizon. Avista will be collecting new leak survey and other information
each year, and will continue to use its Asset Management models to further refine expected
trends and potential consequences, making program adjustments as appropriate.

0
100
200
300
400
500
600
2010 2015 2020 2025 2030 2035
Fo
r
e
c
a
s
t

N
u
m
b
e
r

o
f

L
e
a
k
s
Year
Base Case Replacement Case
ICNU_DR_113 Attachment D Page 32 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 33

Responsive Replacement Program

Avista also modeled a very-different pipe replacement strategy to provide a further
measure of the efficacy of the systematic replacement program. This scenario, referred to
as the Responsive Case, was essentially a reactive approach where pipe remediation and
replacement activities would be driven by leak survey results and the magnitude of leak
consequences. Under this case, it‟s expected that pipe replacement activity would
commence at a lower level than in the systematic case, but would also vary significantly
from year to year, depending on patterns of detected leaks and their consequences.
Ultimately, however, the expected activity and spending levels would far exceed both the
annual and cumulative costs of the systematic approach. This is because pipe segments are
not replaced ahead of actual material failure (as happens in the structured case) and so the
resulting work activity more generally follows the geometrically-increasing numbers of
material failures expected over time. This scenario was easily judged as failing to provide
an appropriate measure of prudence, including system safety, reliability, cost-efficiency, or
business risk. Without a prioritized replacement protocol in place, Avista would be
resigned to replacing pipe in response to serious leaks and potential incidents, after-the-
fact, rather than with foresight.

From a practical standpoint, Avista believes that by managing the replacement of its
priority Aldyl A pipe in a systematic way it can prudently manage potential risks and
impacts to its customers and other stakeholders, plan for and use construction resources
most efficiently, and plan more effectively for the capital and expense requirements
necessary for the effort. This is clearly the case when compared with a responsive
approach.

Dr. Palermo’s Assessment of the Proposed Protocol for Managing Avista’s
Priority Aldyl A Piping

Following Avista‟s Integrity Management evaluations of failure trends in its Aldyl A
piping, and the development of its proposed protocol, we invited Dr. Palermo to review the
completed protocol and to judge, from his expert perspective, the overall effectiveness and
adequacy of the program. Dr. Palermo completed his review in February 2012, and judged
Avista‟s protocol to be highly responsive and appropriate to the management needs of the
priority Aldyl A pipe in Avista‟s system. In particular, he noted his support for Avista‟s
priority focus on pre-1973 Aldyl A pipe, and on the plan to remove and replace its pre-
1984 Aldyl A mains. He further noted his agreement with Avista‟s priority for remediating
Aldyl A services tapped to steel main pipe, and to the protocol of “managing in place”
existing Aldyl A service piping between the mains and meters. Finally, Dr. Palermo agreed
with the proposed twenty-year replacement time horizon for Avista‟s priority Aldyl A pipe,
noting the reliability modeling results, and the effectiveness of Avista‟s increased leak
survey and application of Integrity Management information, tools and analysis in
prioritizing pipe replacement activities. Dr. Palermo reviewed and approved this
affirmation prior to the finalization of this report.
ICNU_DR_113 Attachment D Page 33 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 34

XII. Application of Avista’s Washington State Study Results to Aldyl
A Pipe in the States of Oregon and Idaho

Forty-six percent of Avista‟s Aldyl A main pipe is currently in service in the State of
Washington, and coincidentally, so are 46% of Avista‟s Aldyl A services tapped to steel
mains. Since Avista‟s leak survey study and subsequent modeling results are based on
Washington State data, then it follows that the expected results are most applicable to this
jurisdiction. The degree to which the reliability modeling results are applicable to Avista‟s
Aldyl A pipe in the States of Oregon and Idaho depend on factors such as the age of the at-
risk pipe and on the known similarity of conditions under which the pipe was installed,
including method (trenching or plowing), backfill material, compaction and squeeze-off
practices, soil conditions and ambient soil temperature, etc. Avista is aware of at least
some general differences among state jurisdictions, including more favorable soil
conditions in Oregon, newer pipe materials, and construction techniques potentially more
favorable to low-ductility pipe. A contributing complication, too, is the relatively large
amount of pipe of unknown age and material in service in Oregon. This territory was
acquired by Avista from a utility that did not have a consistent practice of mapping
services, and some existing maps were lost before the purchase. As a result, Avista is
conservatively managing this pipe as if it was priority Aldyl A pipe, until the time that
these segments are verified by records review and possible field verification.

Most important to this discussion, however, is the fact that Avista is using its Integrity
Management model to integrate leak survey and other data to develop the priority pipe
replacement activities for each year of the program. Since comparable leak survey data
from priority Aldyl A pipe in Idaho and Oregon will be included in the prioritization
analysis, then regardless of any differences that do affect the expected reliability of the
Aldyl A pipe, that inherent reliability will be automatically integrated into the modeling,
ensuring that Avista is systematically replacing the pipe at greatest risk, regardless of the
jurisdiction. Finally, since the Medford and Grants Pass, Oregon, service territory offers a
12-month construction season, Avista will be able to continuously mitigate priority Aldyl A
piping within that area when northern territories are effectively unable to continue working.
XIII. Resource Requirements and Expected Cost
Staffing

Avista‟s proposed Aldyl A pipe replacement project represents a major undertaking, even
when spread over a twenty-year horizon. In addition to the scope of the effort, there‟s
added complexity in efficiently managing the project, since Avista‟s territory extends from
Bonners Ferry, Idaho to Ashland, Oregon, a distance of over 650 miles. Each year, the
deployment of equipment and inspection and construction personnel will have to be
adjusted across this service area in response to the sites identified for highest-priority pipe
replacement in any given year. Avista is planning to coordinate with contractors to manage
much of this construction, and since this project represents a long-term construction
ICNU_DR_113 Attachment D Page 34 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management April 11, 2013 35

commitment, it is expected that the pool of contractors bidding for this work will be
substantial, resulting in advantageous pricing and flexibility of field labor.

Though much of the physical construction will be accomplished through the use of
contractors, there will still be a need to increase Avista‟s internal staffing to manage the
flow of information, quality assurance, mapping, and related project documentation.
Quality assurance is a critical project element that Avista will rigorously control. Effective
remediation of Avista‟s priority Aldyl A pipe is a critically-important corporate objective,
and we must continually ensure that sound inspection, training and auditing delivers the
results we expect. Finally, the pipe replacement activities themselves will often have
disruptive effects on our customers and others. Avista will carefully coordinate customer
and community communications and notifications in an effort to minimize the effects of
any disruptions.
Capital Costs

Avista‟s analysis and planning effort is projecting capital costs just over $10 million
annually from the year 2013 – 2032. Actual costs will vary somewhat depending on the
prioritization of piping to be replaced each year, among other factors, and the calculated
amounts will also be subject to annual inflation. Avista is planning to spend approximately
$5 million in capital on this program in 2012, and $8 million in 2013, allowing for effective
planning with contractors, hiring Avista staff, and developing a solid project management
foundation for years 2013 and beyond.

XIV. Regulatory Developments Since Original Publishing Date
Washington State Pipeline Replacement Policy Statement UG-120715

Over the summer of 2012 the Washington State Utilities and Transportation Commission
launched an investigation into potential facility replacement projects that may be pending
among the natural gas distribution operators within its jurisdiction. This investigation
included information sharing and live testimony to the Commission by various operators,
and Avista was an active participant in these efforts.

As of December 2012, Avista‟s Protocol document has been accepted by the UTC as an
effective method of analysis and the resulting recommendations for the long-term
management of this facility have been acknowledged as a reasonable and prudent path
forward. See Attachment 13 for the full content of the UTC Statement.
ICNU_DR_113 Attachment D Page 35 of 35
Avista
–
Nine
Mile
Hydroelectric
Dam
Upgrade
Maintenance
Cost
Modeling

ISSUE
DATE:
November
2012

DOCUMENT
NO:
356-005

Report
Prepared
By:

Michael
Byers

Senior
Reliability
Engineer

Report
Approved
for
Issue
By:
Jason
Ballentine

Engineering
Manager

ICNU_DR_113 Attachment E Page 1 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
EXECUTIVE
SUMMARY

This
report
presents
the
results
from
the
analysis
undertaken
as
part
of
the
Avista
Nine

Mile
Hydroelectric
Dam
Upgrade
Project.

The
intent
of
this
study
was
to
predict
the

plant
maintenance
costs
for
four
potential
Plant
configurations
over
the
next
75
years

utilizing
AvSim+,
a
module
of
Availability
Workbench
(AWB).

These
predicted
costs

would
then
be
inputted
into
Avista’s
proprietary
methodology
for
analyzing
the
financial

viability
of
the
stated
configurations.

To
support
this
study,
four
configurations
were
considered:


Base
Case:
Maintenance
of
the
Nine
Mile
Hydroelectric
Dam
Facility
as
it
is
currently

configured
with
two
4
MW
horizontal
units
and
two
8
MW
horizontal
units.

Unit
1
is

inoperable,
Unit
2
is
partially
operable
at
2
MW,
and
Units
3
and
4
are
fully
operable

at
8
MW
each.

For
the
purpose
of
this
study,
it
is
assumed
that
this
configuration
will

remain
the
same
throughout
the
life
of
the
facility
with
no
major
upgrades

considered.

Option
5a:
Maintenance
based
on
the
upgrade
of
Units
1
&
2
with
two
new
8
MW

Seagull
units.

Option
5b:
Maintenance
based
on
all
four
units
being
upgraded
to
new
8
MW

Seagull
units.

Additionally,
all
supporting
plant
services,
e.g.
A/C
Station
Service,
etc.,

are
upgraded.

Option
4:
Maintenance
assuming
a
completely
new
Powerhouse
with
five
new,

vertical
12MW
units.

Please
note
that
the
configurations
listed
above
are
labeled
to
match
that
of
the
project

documentation
provided
by
Avista.


Reliability
Block
Diagram
(RBD)
models
were
constructed
from
equipment
and
electrical

diagram
drawings,
input
from
experienced
Avista
engineers
and
crafts,
and
an
existing

AvSim+
model
of
the
Avista
Little
Falls
Hydroelectric
Dam
facility.

Life
and
maintenance

information
for
each
asset
was
gathered
primarily
through
interviews
with
Avista

engineers
and
crafts.

Total
Maintenance
Cost
by
Configuration
values
were
calculated
using
annual
Escalation

Rates
of
2.0%
for
Labor,
2.6%
for
Equipment,
2.6%
for
Spares,
and
2.0%
for
Outage

(Consequence)
Costs;
Calculated
Costs
are
Net
Present
Value
(NPV)
with
a
Discount
Rate
of

0%.

These
values
are
detailed
in
Table
1.

ICNU_DR_113 Attachment E Page 2 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Configuration Labor

Cost

Equipment

Cost

Spares

Cost

Total

Maintenance
Cost

Base
Case
$42.72M
$23.19M
$34.06M
$99.97M

Option
5a
$53.43M
$29.91M
$47.33M
$130.67M

Option
5b
$48.30M
$29.85M
$42.74M
$120.89M

Option
4
$40.29M
$28.48M
$69.56M
$138.33M

Table
1:
Predicted
Maintenance
Costs
Overview
Total
Costs,
which
includes
Lost
Production
costs
based
on
a
penalty
of
$40/MW-h,
are

detailed
in
Table
2.

Configuration
Total


Maintenance
Cost

Lost
Production

Cost

Total

Cost

Base
Case
$99.97M
$31.82M
$131.86M

Option
5a
$130.67M
$28.20M
$159.00M

Option
5b
$120.89M
$25.49M
$146.51M

Option
4
$138.33M
$42.35M
$180.71M

Table
2:
Total
Predicted
Costs
Overview

As
shown
in
Table 2,
the
lowest
overall
Total
Cost
option
versus
the
Base
Case
is
Option

5b.

Configuration Mean
Availability
Mean
Capacity
Max
Capacity

Base
Case
99.301%
10.94
MW
18
MW

Option
5a
99.850%
19.88
MW
32
MW

Option
5b
99.899%
19.94
MW
32
MW

Option
4
99.894%
37.45
MW
60
MW

Table
3:
Mean
Availabilities
and
Capacities
Overview

Mean
Availability
and
Mean
Capacity
over
the
75
year
timeframe
for
each
configuration
is

listed
in
Table
3.

The
Max
Capacity
is
the
maximum
output
the
design
is
capable
of

producing;
this
assumes
that
the
equipment
is
fully
operational
and
reservoir
water
levels

are
at
the
maximum.

ICNU_DR_113 Attachment E Page 3 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Contents
1 INTRODUCTION ....................................................................................................1
1.1 Objective ..................................................................................................................1
1.2 Scope ........................................................................................................................11.3 Acronyms and Abbreviations ...................................................................................1
1.4 Data ..........................................................................................................................2
1.5 Assumptions .............................................................................................................4
2 AVAILABILITY
SIMULATION
MODEL ................................................................5
2.1 Methodology ............................................................................................................5
2.2 Study Software .........................................................................................................52.3 Building the Reliability Block Diagram (RBD) .......................................................52.4 Model Construction ..................................................................................................6
2.5 Specification & Modeling Philosophy .....................................................................6
2.6 Definitions ................................................................................................................6
3 RESULTS .................................................................................................................7
3.1 Overall Results .........................................................................................................73.2 Base Case Results ....................................................................................................8
3.3 Option 5a Results ...................................................................................................10
3.4 Option 5b Results ...................................................................................................12
3.5 Option 4 Results .....................................................................................................14
4 CONCLUSIONS ......................................................................................................17
5 RECOMMENDATIONS .........................................................................................18
6 APPENDIX
1:
RELIABILITY
BLOCK
DIAGRAMS .............................................19
7 APPENDIX
2:
LABOR
RATES .............................................................................21
ICNU_DR_113 Attachment E Page 4 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
List
of
Figures

Figure
1:
Failure
Model
Development
–
Failure
Rate .................................................................. 2
Figure
2:
Typical
Beta
Values ......................................................................................................... 2
Figure
3:
Failure
Model
Development
–
Task
Definition ............................................................. 3
Figure
4:
Example
RBD ................................................................................................................... 5
Figure
5:
Base
Case
Predicted
Total
Costs
by
Year ...................................................................... 8
Figure
6:
Base
Case
Components
Contribution
to
Total
Cost ..................................................... 9
Figure
7:
Option
5a
Predicted
Total
Costs
by
Year .................................................................... 11
Figure
8:
Option
5a
Components
Contribution
to
Total
Cost.................................................... 12
Figure
9:
Option
5b
Predicted
Total
Costs
by
Year .................................................................... 13
Figure
10:
Option
5b
Components
Contribution
to
Total
Cost ................................................. 14
Figure
11:
Option
4
Predicted
Total
Costs
by
Year .................................................................... 15
Figure
12:
Option
4
Components
Contribution
to
Total
Cost ................................................... 16
Figure
13:
Base
Case
RBD ............................................................................................................ 19
Figure
14:
Option
5a
RBD ............................................................................................................. 19
Figure
15:
Option
5b
RBD ............................................................................................................ 20
Figure
16:
Option
4
RBD .............................................................................................................. 20
List
of
Tables
Table
4:
Acronyms
&
Abbreviations ............................................................................................. 1
Table
5:
Maintenance
Cost
Overview ............................................................................................ 7
Table
6:
Total
Cost
Overview ......................................................................................................... 7
Table
7:
Mean
Availabilities
and
Capacities
Overview ................................................................ 8
Table
8:
Historical
Maintenance
Costs
(Provided
by
Avista) ...................................................... 9
Table
9:
Top
20
Spares
with
High
Waiting
Times ...................................................................... 10
Table
10:
Maintenance
Cost
Overview ........................................................................................ 17
Table
11:
Total
Cost
Overview ..................................................................................................... 17
Table
12:
Labor
Rates ................................................................................................................... 21
Table
13:
Equipment
Rates .......................................................................................................... 21
Disclaimer

Note:

This
report
is
not
to
be
copied
or
distributed
in
any
form
outside
Avista
without
the

consent
of
Avista
or
ARMS
Reliability.

Although
every
effort
has
been
made
by
ARMS
Reliability
to
ensure
the
accuracy
and
completeness
of

this
document
and
reported
results,
no
warranty,
express
or
implied
is
made
by
ARMS
Reliability
as
to

the
accuracy
or
completeness
of
the
documentation
or
reported
results.
Any
decisions
made
as
a
result

of
the
information
in
this
report
are
at
the
sole
discretion
of
the
reader.

ICNU_DR_113 Attachment E Page 5 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 1
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
1 INTRODUCTION

1.1 Objective

The
intent
of
this
study
was
to
predict
the
overall
Maintenance
Spending
and
Lost

Production
Costs
for
the
Nine
Mile
Hydroelectric
Dam
facility
over
the
next
75
years
for
the

current
configuration
and
three
proposed
alternate
configurations.

This
study
will
be

achieved
by
constructing
a
Reliability
Block
Diagram
model
for
each
configuration
using

AvSim+,
a
module
of
the
Availability
Workbench
software.

1.2 Scope

The
RBD
models
include
major
operational
equipment
for
the
Nine
Mile
Hydroelectric
Dam.


Unplanned
failures,
scheduled
maintenance,
delayed
failure
responses
and
buffers,
and

opportunistic
maintenance
have
been
included.

The
following
configurations
were
considered:

Base
Case:
Maintenance
of
the
Nine
Mile
Hydroelectric
Dam
Facility
as
it
is
currently

configured
with
two
4MW
horizontal
units
and
two
8MW
horizontal
units.

Unit
1
is

inoperable,
Unit
2
is
partially
operable
at
2MW,
and
Units
3
&
4
are
fully
operable
at

8MW
each.

For
the
purpose
of
this
study,
it
is
assumed
that
this
configuration
will

remain
the
same
throughout
the
life
of
the
facility
with
no
major
upgrades

considered.

Option
5a:
Maintenance
based
on
the
upgrade
of
Units
1
&
2
with
two
new
8
MW

Seagull
units.

Option
5b:
Maintenance
based
on
all
four
units
being
upgraded
to
new
8
MW

Seagull
units.

Additionally,
all
supporting
plant
services,
e.g.
A/C
Station
Service,
etc.,

are
upgraded.

Option
4:
Maintenance
assuming
a
completely
new
Powerhouse
with
five
new,

vertical
12MW
units.

1.3 Acronyms
and
Abbreviations

Abbreviation Explanation

AvSim+
Availability
Simulation
Software
Module

AWB
Availability
Workbench
Software

MW
Megawatts

MW-h
Megawatt-hour

PM
Preventative
Maintenance

RBD
Reliability
Block
Diagram

Unit
One
complete
turbine
and
generator
system.

Table
4:
Acronyms
&
Abbreviations


ICNU_DR_113 Attachment E Page 6 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 2
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
1.4 Data

The
Nine
Mile
Hydroelectric
Dam
model
is
a
dominant
failure
mode
model
in
which
failure

data
is
specified
for
only
the
dominant
failure
modes
of
each
asset;
however,
when
more

than
one
strong
failure
mode
exists
for
an
asset,
additional
blocks
were
employed.

This

data
was
collected
primarily
through
interviews
with
Avista
engineers
and
crafts.

The
following
screen
captures
demonstrate
how
this
equipment
data
was
inputted
into
the

availability
model.

Figure
1:
Failure
Model
Development
–
Failure
Rate

Eta:

Characteristic
Life.

This
is
the
age
in
hours
at
which
63.2%
of
the
population
will
fail
if

no
maintenance
was
performed.

In
the
figure
above,
this
would
represent
148,920
hours

for
the
Unit
4
turbine
runners.

Beta:

Shape
Parameter.

This
parameter
represents
the
predictability
of
the
failure
mode:

Beta
<
1
–
Infant
Mortality
Failure

Beta
=
1
–
Random
Failure

Beta
>
1
–
Wear-out
Failure

Figure
2:
Typical
Beta
Values

ICNU_DR_113 Attachment E Page 7 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 3
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Task
Duration:

This
is
the
amount
of
time
the
equipment
is
unavailable
from
production
to
perform
the

maintenance
task.

In
the
figure
below,
this
would
represent
5040
hours
(30
weeks)
to

replace
runners.

Resources:
This
represents
the
number
of
resources,
type
of
resources
(labor,
equipment,
and
spares),

and
the
number
of
hours
required
for
each
resource
to
perform
the
maintenance
task.

In

the
figure
below,
four
Electric
Crewmembers
for
a
total
of
40
hours
would
be
required.


Appendix
2
details
the
labor
and
equipment
costs
by
type.

Figure
3:
Failure
Model
Development
–
Task
Definition

ICNU_DR_113 Attachment E Page 8 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 4
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
1.5 Assumptions

The
purpose
of
a
model
is
to
represent
the
behavior
of
a
system
and
facilitate
predictions.

A

model,
by
definition,
is
a
simplification
of
a
physical
system.

As
a
result,
only
components

or
characteristics
of
the
physical
system
that
are
relevant
to
the
system
behavior
are

included
within
the
model.

Governing
assumptions
are
required
to
fully
understand
the

model’s
structure,
interdependencies,
and
to
interpret
results.

The
general
assumptions
used
in
generating
the
Nine
Mile
Hydroelectric
Dam
models
are:


Only
dominant
failure
modes
for
each
component
are
considered;

All
failures
are
independent
from
other
failures,
i.e.
conditional
failures
are
not

modeled;

Assumes
a
consistently
executed
preventative
maintenance
plan
as
defined
by

Avista,
i.e.
preventative
maintenance
follows
the
current
Avista
plan
and
is
not

necessarily
optimized;

All
components
are
repaired
when
they
fail,
i.e.
components
are
not
permanently

decommissioned
when
they
fail;

Each
repair
returns
the
item
to
a
“good
as
new”
condition
after
maintenance;

Repair
times
are
the
actual
downtime
of
the
equipment
while
the
Labor
times
are

based
on
actual
“Tool
Time”
of
the
crafts
where
the
crafts
only
work
one,
40
hours-
per-week
shift;

Supervision
is
not
included
as
a
labor
type.

Therefore
no
time
or
cost
has
been

allocated;

Predicted
results
contain
annual
Escalation
Rates
of
2.0%
for
Labor,
2.6%
for

Equipment,
2.6%
for
Spares,
and
2.0%
for
Outage
(Consequence)
Costs

NPV
calculations
assume
a
0%
discount
rate.

ICNU_DR_113 Attachment E Page 9 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 5
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
2 AVAILABILITY
SIMULATION
MODEL

2.1 Methodology


2.2 Study
Software

AvSim+
is
an
availability
simulation
and
system
optimization
tool
developed
specifically
to

handle
complex
systems
with
inter-dependencies
and
redundancies.
Components
are

assigned
probabilistic
failure
behaviors,
repair
times
and
inter-dependency
rules.

AvSim+

then
dynamically
simulates
a
life-cycle
with
a
set
of
predicted
failures,
repairs
and
other

events
based
on
the
probabilities
defined
previously.

Several
life-cycles
are
simulated
to

provide
a
statistically
valid
estimate
of
total
system
performance.

2.3 Building
the
Reliability
Block
Diagram
(RBD)

The
reliability
block
diagram
is
a
diagrammatic
representation
of
the
plant
systems,

subsystems,
and
assets
arranged
in
a
way
that
indicates
the
impact
of
equipment
failure
on

system
performance;
the
RBD
does
not
necessarily
follow
a
Plant
Flow
Diagram
or

Manufacturing
Process
Flowchart.

Reliability
Block
Diagrams
reduces
complex
systems

into
a
collection
of
components
that
are
either
in
series
or
parallel
to
one
another.

RBD
Diagrams
can
quickly
and
easily
become
overly
large
and
complex.

This
disallows
one

from
understanding
the
overall
structure
of
the
model
and
from
easily
displaying
the
model

within
a
report.

For
these
reasons
AvSim+
provides
a
powerful
nesting
feature,
which

allows
the
user
to
nest
components
within
a
block
to
create
a
separate
sub-system.
Each

sub-system
can
represent
a
complex,
independent
system.

An
example
of
a
very
simple

system
and
sub-system
RBD
diagram
is
given
in
Figure
4.

Figure
1
–
RBD
Example

Figure
4:
Example
RBD

Parallel
sub-system
with
redundancy
Series
system
with
no
redundancy
ICNU_DR_113 Attachment E Page 10 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 6
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
2.4 Model
Construction

Avista
had
previously
completed
an
RBD
model
of
their
Little
Falls
Hydroelectric
Dam.

This

provided
the
starting
point
for
the
Nine
Mile
Hydroelectric
Dam
Base
Case
model
structure.


The
RBD’s
were
refined
using
mechanical
and
electrical
drawings
of
the
facility
along
with

input
from
Avista
engineers
and
crafts.

A
high
level
summary
RBD
along
with
a
full
detailed
copy
of
the
RBD
is
attached
as

Appendix
1
at
the
end
of
this
report.

2.5 Specification
&
Modeling
Philosophy

Simulation
Parameters

Simulation
Duration:

75
years

Number
of
Simulations:
4

The
simulation
cycled
through
seventy-five
years
of
operations;
this
duration
was
specified

by
Avista
to
accommodate
their
financial
outlook
requirements.

The
model
was
simulated

four
times
to
reduce
statistical
anomalies
to
a
satisfactory
level
(less
than
0.5%
error).



2.6 Definitions

Labor
Cost:

Labor
Costs
include
all
labor
types
required
to
perform
the
actual
repairs
or

Preventative
Maintenance
activities.

The
predominant
Labor
types
are
Mechanical
or

Electrical
crews.

Hourly
rates
for
each
Labor
type
were
provided
by
Avista.

Equipment
Cost:
Costs
associated
with
supporting
equipment
and
tools
for
Labor
to

perform
the
required
tasks.

Equipment
includes
assets
such
as
trucks,
trailers,
cranes,
etc.


Hourly
rates
for
each
Equipment
type
were
provided
by
Avista.

Spare
Cost:
Spares
are
replacement
components
for
the
plant.

Spares
can
either
be

stocked,
purchased
when
needed
or
a
repair
of
an
existing
component.

Examples
of
Spares

for
the
Nine
Mile
Hydroelectric
Dam
are
turbine
runners,
voltage
regulators,
circuit
breaker

components,
transformers,
etc.

Spare
costs
were
based
on
a
combination
of
historical
costs

or
recent
quotes
provided
by
Avista.

Maintenance
Cost:
The
sum
of
Labor,
Equipment,
and
Spare
Costs.

Consequence
Cost:
Lost
electrical
production.

This
is
based
on
$40
per
MW-h
as
specified

by
Avista.

Total
Cost:
The
sum
of
Maintenance
Cost
and
Consequence
Cost.

ICNU_DR_113 Attachment E Page 11 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 7
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
3 RESULTS

3.1 Overall
Results

Table
5
and
Table
6
summarize
the
predicted
costs
associated
with
each
plant

configuration.

As
shown,
the
lowest
cost
configuration
versus
the
Base
Case
is
Option
5b.

Configuration Labor

Cost

Equipment

Cost

Spares

Cost

Total

Maintenance
Cost

Base
Case
$42.72M
$23.19M
$34.06M
$99.97M

Option
5a
$53.43M
$29.91M
$47.33M
$130.67M

Option
5b
$48.30M
$29.85M
$42.74M
$120.89M

Option
4
$40.29M
$28.48M
$69.56M
$138.33M

Table
5:
Maintenance
Cost
Overview

Configuration
Total


Maintenance
Cost

Lost
Production

Cost

Total

Cost

Base
Case
$99.97M
$31.82M
$131.86M

Option
5a
$130.67M
$28.20M
$159.00M

Option
5b
$120.89M
$25.49M
$146.51M

Option
4
$138.33M
$42.35M
$180.71M

Table
6:
Total
Cost
Overview

Total
Maintenance
Costs
for
Option
5a
increased
significantly
over
that
of
the
Base
Case.


This
can
be
attributed
to
the
increase
in
the
number
of
Units
being
utilized
in
Option
5a;

recall
that
in
the
Base
Case,
Unit
1
is
permanently
disabled
and
is
not
accruing
costs.

Total
Maintenance
Costs
for
Option
5b
decreased
slightly
over
that
of
Option
5a.

This
is

due
to
all
four
units
being
brand-new
for
this
configuration,
i.e.
no
components
are
near

end-of-life.


Additionally,
it’s
assumed
that
several
nuisance
failure
modes
have
been

engineered
out
of
the
system,
e.g.
Sediment
Bypass
System
impact
on
turbine
runners,
etc.


Option
4
was
the
highest
Total
Maintenance
Cost
and
Total
Cost
Option
versus
that
of
the

Base
Case.

Though
the
design
of
Option
4
with
the
use
of
vertical
units
is
inherently
more

efficient
and
more
reliable
than
the
horizontal
unit
design,
the
fact
that
these
units
are

significantly
larger
in
capacity
makes
all
the
repairs
and
spares
more
expensive.

In
other

words,
these
units
are
much
larger
than
those
in
the
other
options
and,
as
a
result,
the
labor

required
to
perform
tasks
and
the
cost
of
spares
has
increased
substantially.

Additionally,

since
the
capacity
is
higher,
downtime
becomes
more
expensive
and
contributes
to
the

Total
Cost.

ICNU_DR_113 Attachment E Page 12 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 8
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Configuration Mean
Availability
Mean
Capacity
Max
Capacity

Base
Case
99.301%
10.94
MW
18
MW

Option
5a
99.850%
19.88
MW
32
MW

Option
5b
99.899%
19.94
MW
32
MW

Option
4
99.894%
37.45
MW
60
MW

Table
7:
Mean
Availabilities
and
Capacities
Overview

Table
7
details
the
predicted
Mean
Availabilities
and
Mean
Capacities
for
each
of
the

configurations.

Each
of
the
Options
has
approximately
the
same
Mean
Availability

compared
to
one
another.
The
Base
Case
is
approximately
0.5%
less
than
the
Options.

This

is
due
to
how
sensitive
the
Base
Case
configuration
is
to
downtime
from
Units
3
&
4
which

provides
the
bulk
of
the
system’s
capacity.

The
Max
Capacity
is
the
maximum
output
the
design
is
capable
of
producing;
this
assumes

that
the
equipment
is
fully
operational
and
reservoir
water
levels
are
at
the
maximum.

The

Mean
Capacity
takes
into
account
seasonal
reservoir
levels
in
addition
to
outages.


3.2 Base
Case
Results

Figure
5
details
the
Maintenance
Costs
by
Year
(the
graphs’
time
axis
is
in
hours)
for
the

Base
Case.

Since
an
Escalation
Rate
was
utilized
for
labor,
equipment,
spares,
and

consequence
costs,
Maintenance
Costs
will
gradually
increase
over
time.


Figure
5:
Base
Case
Predicted
Total
Costs
by
Year

$0
$1,000,000
$2,000,000
$3,000,000
$4,000,000
$5,000,000
$6,000,000
$7,000,000
$8,000,000
1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73
Consequence
Spares
Equipment
Labor
ICNU_DR_113 Attachment E Page 13 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 9
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
2005
2006
2007
2008
2009
2010
2011

Maintenance

Spending
$339.7K
$230.4K
$320.6K
$536.4K
$347.2K
$262.2K
$637.2K

Table
8:
Historical
Maintenance
Costs
(Provided
by
Avista)

Predicted,
near-term
Maintenance
Spending
as
shown
in
Figure
5
is
comparative
to

historical
spending
by
Avista
as
detailed
in
Table
8.

Figure
6:
Base
Case
Components
Contribution
to
Total
Cost

Figure
6
details
the
largest
contributors
to
Total
Cost,
which
includes
Maintenance
Costs

and
Consequence
Costs.

The
second
Generator
Step-Up
Transformer
(GSU)
is
the
top

contributor
due
to
the
high
cost
and
long
lead-time
for
a
spare.

Voltage
regulators
also

contributed
significantly
to
the
Total
Cost.

Like
the
GSU,
Voltage
Regulators
are
costly.


Additionally,
the
current
installed
Voltage
Regulators
are
obsolete
and
unavailable
which

contributes
not
only
to
cost
but
to
the
lead-time
for
replacement.

Both
Bearing
Labyrinth

Seals
and
Wicket-Gate
Bushings
contributed
significantly
to
the
Total
Cost
as
well.

Both
of

these
components
fail
relatively
often
during
a
75
year
period
and
are
labor-intensive
to

repair.

Contribution
0 2E+05 4E+05 6E+05 8E+05 1E+06 1.2E+06 1.4E+06 1.6E+06
Contribution to Cost
GSU #2
Unit 3 VoltageRegulator
Unit 4 Wicket Gate
Bushing Failure
Unit 3 Turbine ThrustBearing Laby Seals
Unit 4 VoltageRegulator
Unit 4 Turbine ThrustBearing Laby Seals
Unit 3 Wicket GateBushing Failure
Unit 4 CB.17
Unit 3 CB.18
HPU #2 Flexible Hoses
Trash Rake System.2
Unit 4 GovernorLinkage Binding
Unit 3 HeadgateCylinder
Unit 3 GovernorLinkage Binding
Unit 4 GeneratingWinding Failure
Unit 3 CB.5
Unit 4 Turbine DSBearing Oil PD Pump
Unit 4 HeadgateActuating Cylinder
Unit 3 Generator Minor
Fault
Unit 4 CB.5
Co
m
p
o
n
e
n
t
ICNU_DR_113 Attachment E Page 14 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 10
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Component Description
Total
Time
Waiting
for

Spares

Number
of
Predicted

Failures

125
VDC
Battery
3
125
VDC
Battery
3
9855
4.5

Station
Service
UPS
Battery.1
Battery.1
9307.5
4.25

125
VDC
Battery
1
125
VDC
Battery
1
8212.5
3.75

Unit
2
Voltage
Regulator
Unit
2
Voltage
Regulator
7665
1.75

Unit
3
Voltage
Regulator
Unit
3
Voltage
Regulator
7665
1.75

125
VDC
Battery
2
125
VDC
Battery
2
7665
3.5

Unit
4
Voltage
Regulator
Unit
4
Voltage
Regulator
4380
1

Unit
2
CB.17
Charging
Spring
Motor
3528
3.5

Unit
4
CB.17
Charging
Spring
Motor
3024
3

Unit
3
CB.18
Charging
Spring
Motor
3024
3

GSU
#2
Up
Transformer
2286.79
0.75

Unit
3
Air
Brake
Strap
Unit
3
Air
Brake
Strap
1554
9.25

Unit
2
Air
Brake
Strap
Unit
2
Air
Brake
Strap
1419.03
8

GSU
#1
Up
Transformer
1377.76
0.5

Unit
4
Air
Brake
Strap
Unit
4
Air
Brake
Strap
1344
8

125
VDC
Battery
Charger
2
125
VDC
Battery
Charger
2
1277.5
1.75

Unit
2
CB.20
remove
and
install
the

breaker

1260
1.25

Pump
Bearing
Oil
PD
Pump
1120.75
17.75

Unit
2
CB.5
Synchronizing
Check
Relay
1095
1.5

Unit
2
CB.32
Terminal
Assembly
1008
1

Table
9:
Top
20
Spares
with
High
Waiting
Times

Given
the
current
spares
stocking
strategy
employed
by
Avista,
several
components
do
not

have
readily
available
spares
on-the-shelf.

As
evident
in
Table
9,
there
are
high
waiting

times
for
certain
spares
in
response
to
a
failure.

Parts
associated
with
the
Battery
Back-Up

System,
Voltage
Regulators
and
Circuit
Breakers
had
long
lead-times
before
parts
were

available.

However,
the
GSU’s
had
the
biggest
impact
on
over-all
system
Availability;
as
a

result,
it
is
recommended
to
consider
obtaining
a
spare.

3.3 Option
5a
Results

Figure
7
details
the
Maintenance
Costs
by
Year
(the
graphs’
time
axis
is
in
hours)
for

Option
5a.

Since
an
Escalation
Rate
was
utilized
for
labor,
equipment,
spares,
and

consequence
costs,
Maintenance
Costs
will
gradually
increase
over
time.

ICNU_DR_113 Attachment E Page 15 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 11
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Figure
7:
Option
5a
Predicted
Total
Costs
by
Year

The
costs
are
comparable
to
the
Base
Case
although
slightly
higher.

This
is
due
to
the

introduction
of
an
additional
unit
which
requires
maintenance
and
other
activities
which

add
to
the
overall
Maintenance
Cost.

Additionally,
the
capacity
has
been
increased
over
the

Base
Case
which
makes
downtime
even
more
costly.

$0
$1,000,000
$2,000,000
$3,000,000
$4,000,000
$5,000,000
$6,000,000
$7,000,000
$8,000,000
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73
Consequence
Spares
Equipment
Labor
ICNU_DR_113 Attachment E Page 16 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 12
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Figure
8:
Option
5a
Components
Contribution
to
Total
Cost

As
with
the
Base
Case,
and
for
the
same
reasons,
GSU’s,
Voltage
Regulators,
Wicket-Gate

Bushings,
and
Bearing
Labyrinth
Seals
contributed
greatly
to
the
Total
Cost
for
Option
5a.


However,
it
was
predicted
that
Turbine
4
runners
would
be
the
greatest
contributor
to
cost.


This
makes
sense
since
Turbine
4
receives
the
brunt
of
sediment
erosion
damage
as
its

primary
failure
mode;
also,
turbine
runners
are
very
costly.

Another
set
of
components
that
contributed
heavily
to
the
Total
Cost
are
the
Units
3
and
4

Generator
Windings.

Both
of
which
are
already
17
years
old
and
are
predicted
to
fail
once

each
within
the
next
75
years.

Generator
Windings
replacements
are
costly
and
labour-
intensive.


3.4 Option
5b
Results

Figure
9
details
the
Maintenance
Costs
by
Year
(the
graphs’
time
axis
is
in
hours)
for

Option
5b.

Since
an
Escalation
Rate
was
utilized
for
labor,
equipment,
spares,
and

consequence
costs,
Maintenance
Costs
will
gradually
increase
over
time.

Contribution
0 2E+05 4E+05 6E+05 8E+05 1E+06 1.2E+06
Contribution to Cost
Unit 4 Turbine Runners
GSU #2
Unit 3 Generating
Winding Failure
GSU #1
Trash Rake System.2
Unit 4 GeneratingWinding Failure
Unit 4 Turbine ThrustBearing Laby Seals
Unit 3 Wicket GateBushing Failure
Unit 2 Wicket GateBushing Failure
Unit 2 VoltageRegulator
Unit 1 Wicket Gate
Bushing Failure
Unit 2 Turbine ThrustBearing Laby Seals
Unit 4 Generating MajorFault
Unit 1 GeneratingWinding Failure
Unit 3 Turbine ThrustBearing Laby Seals
Unit 2 GeneratingWinding Failure
Unit 1 Turbine ThrustBearing Laby Seals
Unit 3 VoltageRegulator
HPU #1 Flexible Hoses
Unit 4 VoltageRegulator
Co
m
p
o
n
e
n
t
ICNU_DR_113 Attachment E Page 17 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 13
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Figure
9:
Option
5b
Predicted
Total
Costs
by
Year

The
cost
profile
is
very
similar
to
Option
5a
although
slightly
less
in
Total
Cost
over
the

course
of
75
years.

The
decreased
costs
are
a
result
of
all
equipment
being
upgraded
with

new
components
which
eliminates
the
end-of-life
failures
exhibited
in
Option
5a
for
Units
3

&
4.

$0
$1,000,000
$2,000,000
$3,000,000
$4,000,000
$5,000,000
$6,000,000
$7,000,000
$8,000,000
1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73
Consequence
Spares
Equipment
Labor
ICNU_DR_113 Attachment E Page 18 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 14
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Figure
10:
Option
5b
Components
Contribution
to
Total
Cost

As
seen
in
Figure
10,
the
top
contributors
to
Total
Cost
are
similar
to
that
of
Option
5a.

As

stated
previously,
the
only
notable
difference
is
that
the
overall
Total
Cost
is
lower
for
the

reasons
mentioned.

3.5 Option
4
Results

Figure
11
details
the
Maintenance
Costs
by
Year
(the
graphs’
time
axis
is
in
hours)
for

Option
4.

Since
an
Escalation
Rate
was
utilized
for
labor,
equipment,
spares,
and

consequence
costs,
Maintenance
Costs
will
gradually
increase
over
time.

Contribution
0 2E+05 4E+05 6E+05 8E+05 1E+06 1.2E+06
Contribution to Cost
Unit 4 Turbine Runners
GSU #2
Unit 3 GeneratingWinding Failure
GSU #1
Trash Rake System.2
Unit 4 GeneratingWinding Failure
Unit 4 Turbine ThrustBearing Laby Seals
Unit 3 Wicket Gate
Bushing Failure
Unit 2 Wicket GateBushing Failure
Unit 2 VoltageRegulator
Unit 1 Wicket Gate
Bushing Failure
Unit 2 Turbine ThrustBearing Laby Seals
Unit 4 Generating MajorFault
Unit 1 GeneratingWinding Failure
Unit 3 Turbine ThrustBearing Laby Seals
Unit 2 GeneratingWinding Failure
Unit 1 Turbine ThrustBearing Laby Seals
Unit 3 VoltageRegulator
HPU #1 Flexible Hoses
Unit 4 VoltageRegulator
Co
m
p
o
n
e
n
t
ICNU_DR_113 Attachment E Page 19 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 15
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Figure
11:
Option
4
Predicted
Total
Costs
by
Year

Option
4
is
most
costly
configuration
and
is
due
to
the
type
of
equipment
utilized.

Large,

vertical
units
are
more
costly
for
which
to
purchase
spares
and
to
maintain;
this
adds
to
the

overall
Maintenance
Costs.

It
should
be
noted
that
the
first
20
years
are
comparably
lower

in
costs
than
that
of
the
other
options
since
vertical
units
are
inherently
more
reliable
and

efficient.

However,
once
the
end-of-life
failures
begin,
the
cost
to
maintain
the
system

increases
significantly
as
evident
in
Figure
11.

$0
$1,000,000
$2,000,000
$3,000,000
$4,000,000
$5,000,000
$6,000,000
$7,000,000
$8,000,000
1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73
Consequence
Spares
Equipment
Labor
ICNU_DR_113 Attachment E Page 20 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 16
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Figure
12:
Option
4
Components
Contribution
to
Total
Cost

The
only
notable
difference
in
the
top
contributors
from
that
of
the
other
options
is
the

addition
of
the
runner
hubs.

These
components
are
complex,
expensive
and
labour-
intensive.

Otherwise,
the
typical
components
like
turbine
runners,
voltage
regulators,
and

windings
comprise
the
list
of
top
contributors.

Contribution
0 2E+05 4E+05 6E+05 8E+05 1E+06 1.2E+06 1.4E+06 1.6E+06
Contribution to Cost
Unit 4 Turbine Runners
Unit 2 VoltageRegulator
Unit 5 GeneratingWinding Failure
Unit 2 Turbine Runners
Unit 3 GeneratingWinding Failure
Unit 4 GeneratingWinding Failure
Unit 3 Turbine Runners
Unit 5 Turbine Runners
Unit 5 Static ExciterFailure
Unit 1 Turbine Runners
Unit 1 Hydraulic Runner
Hub
Unit 3 Hydraulic RunnerHub
Unit 4 Turbine.5
Unit 2 GeneratingWinding Failure
Trash Rake System.2
Unit 5 Hydraulic Runner
Hub
Unit 1 GeneratingWinding Failure
Unit 1 VoltageRegulator
Unit 4 Static ExciterFailure
Unit 2 Static ExciterFailure
Co
m
p
o
n
e
n
t
ICNU_DR_113 Attachment E Page 21 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 17
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
4 CONCLUSIONS

This
project
was
solely
tasked
to
understand
the
Maintenance
Costs
for
the
Nine
Mile

Hydroelectric
Dam
as
it
is
currently
configured
and
for
three
optional
configurations.

In

that
respect,
the
study
was
successful
in
understanding
which
option
is
the
least
costly

versus
that
of
the
Base
Case.

Option
5b
is
the
least
expensive
option
for
both
Maintenance

Costs
and
Total
Costs.
Configuration Labor

Cost

Equipment

Cost

Spares

Cost

Total

Maintenance
Cost

Base
Case
$42.72M
$23.19M
$34.06M
$99.97M

Option
5a
$53.43M
$29.91M
$47.33M
$130.67M

Option
5b
$48.30M
$29.85M
$42.74M
$120.89M

Option
4
$40.29M
$28.48M
$69.56M
$138.33M

Table
10:
Maintenance
Cost
Overview

Configuration
Total


Maintenance
Cost

Lost
Production

Cost

Total

Cost

Base
Case
$99.97M
$31.82M
$131.86M

Option
5a
$130.67M
$28.20M
$159.00M

Option
5b
$120.89M
$25.49M
$146.51M

Option
4
$138.33M
$42.35M
$180.71M

Table
11:
Total
Cost
Overview

During
the
course
of
this
study,
two
major
opportunities
to
improve
the
overall
health
of

the
Nine
Mile
Hydroelectric
Dam
facility
along
with
the
Maintenance
Program
become

apparent.

These
opportunities
are
recommended
and
detailed
below:

Perform
an
RCM
study
to
devise
an
optimized
Maintenance
Strategy
for
all
major

assets.

Currently,
an
Annual
Maintenance
Checklist
exists
but
several
of
the
PM

tasks
are
not
effective
in
capturing
or
mitigating
failures.

Perform
a
Spare
Optimization
study
for
all
major
assets.

It
was
apparent
that
at
a

minimum
a
spare
GSU
should
be
considered.

These
opportunities
have
the
potential
to
improve
reliability
for
the
Nine
Mile
Facility

regardless
of
which
configuration
Avista
decides
upon.
ICNU_DR_113 Attachment E Page 22 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 18
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
5 RECOMMENDATIONS

Avista
should
consider
a
variety
of
measures
in
response
to
this
analysis
such
as:

1. Assess
and
update
the
Reliability
and
Maintainability
information
used
as
input

data
in
the
models
simulated
and
re-simulate
as
required.

2. Use
the
models
to
evaluate
alternative
maintenance
shutdown
plans
and
assess
the

impact
on
availability,
capacity,
costs
and
labor
requirements.

3. Validate
the
labor,
equipment,
spare
parts
and
Consequence
cost
assumptions
on

an
ongoing
basis.

4. Assess
the
Critical
Items
outlined
in
the
Results
segment
of
this
report.

5. Input
data
from
Vendor
packages
as
they
become
available.

6. Utilize
the
models
to
develop
detailed
maintenance
strategies.

ICNU_DR_113 Attachment E Page 23 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 19
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
6 APPENDIX
1:
RELIABILITY
BLOCK
DIAGRAMS

Figure
13:
Base
Case
RBD

Figure
14:
Option
5a
RBD
ICNU_DR_113 Attachment E Page 24 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 20
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
Figure
15:
Option
5b
RBD

Figure
16:
Option
4
RBD

ICNU_DR_113 Attachment E Page 25 of 26
Nine
Mile
Hydroelectric
Dam
Upgrade

Maintenance
Cost
Model
Document No: 356-005 Page 21
ISSUE DATE: NOVEMBER 2012 REVISION NO: 0
7 APPENDIX
2:
LABOR
RATES

Labor
Type Hourly
Rate
Call-Out
Cost

Concrete
Contractor
$0
$300,000

Dive
Crew
Contractor
$450.00
$0

Dredging
Contractor
$0
$300,000

Electric
Crew
$51.23
$68.94

Environmental
Engineer
$49.31
$0

Mechanical
Engineer
$56.11
$75.51

NDT
Contractor
$300.00
$0

Plant
Specialist
$51.51
$69.32

Relay
Crew
$53.50
$72.01

Structural
Crew
$51.72
$69.60

Table
12:
Labor
Rates

Equipment
Type Hourly
Rate
Call-Out
Cost

Class
46
4x4
Pick-Up
$4.06
$32.50

Class
55
Crew
Truck
$88.42
$116.67

Class
79
Crane
$347.37
$458.33

Class
86
Small
Trailer
$0.43
$0.72

Crane-Barge
$450.00
$0

DGA
Analysis
$0
$155.25

Table
13:
Equipment
Rates

ICNU_DR_113 Attachment E Page 26 of 26
Wood Pole Management – Inaccessible Pole Material Comparison
Background
Regardless where they are located, the majority of the poles in Avista’s electric distribution system are cedar
and in inaccessible locations, these wood poles present installation problems associated with their weight and
size. Asset Management conducted analysis which investigated at the relative cost advantages of installing
lightweight modular composite distribution poles in the place of failed wood poles. This report discusses the
results of this comparison.
Alternatives Evaluated
In order to fully evaluate the financial impacts of using each of these types of poles, Avista analyzed four
different scenarios as follows:
Base Case – Wood Poles
Inaccessible poles representing 15% (36,900) of the total number of poles in Avista’s 246,000
distribution pole system, where poles that fail or do not meet code requirements are either
reinforced with a steel stub or replaced with another equivalent cedar wood pole. Inspections of
these poles are competed on 20 year intervals.
Alternative 1 – Composite Poles
Inaccessible poles representing 15% (36,900) of the total number of poles in Avista’s 246,000
distribution pole system, where poles that fail or do not meet code requirements are either
reinforced with a steel stub or replaced with a composite pole. Inspections of these poles are
competed on 20 year intervals.

ICNU_DR_113 Attachment F Page 1 of 8
Description and Characteristics of Potential Alternatives
1. Cedar Wood Pole
Cedar wood poles are the most common pole in Avista’s electric distribution system and substantial
failure data has been collected over many years. Based on existing data, the Mean Time to Failure
(MTTF) of a cedar pole is 76 years, although there a general perception among some employees
within our organization that poles installed within the last 15-20 years are not lasting this long.
Cost - $607
Current Inspection Interval - 20 years
Current Inspection Cost - $32/pole
Mean Time to Failure – 76 yrs

2. Composite
Polyurethane resin composite poles are maintenance free poles that are impervious to corrosion,
rot and pest infestation. They assemble in multiple sections (Fig 1,2) and can be hand carried into
the site by a single individual (Fig 3).
Cost - $2,600
Estimated Inspection Interval - 20 years
Estimated Inspection Cost - $32
Estimated Life Time Increase – ~50+ years

Fig 1
ICNU_DR_113 Attachment F Page 2 of 8

Fig 2

Fig 3
Composite Pole Assumptions
Avista has a large body of failure data on the wood poles in our distribution system, which allows us to predict
with great accuracy how long a wood distribution pole is statistically expected to last. However, neither Avista
nor the industry as a whole has a great deal of information regarding how long composite poles are expected to
last. For the purposes of this analysis, Asset Management is relying on the manufacturers estimated lifetime
estimate of 125 years. In order to construct the estimated failure data for composite poles, the existing data
points were used to fit a curve that was similar in shape to the failure curve of wood poles (Fig 4) but with the
Mean Time to Failure (MTTF) increased by approximately 50 years to match this approximation (Fig 5).

ICNU_DR_113 Attachment F Page 3 of 8

Fig 4

Fig 5
Weibull Curve closely
approximates actual failure data
B50 Value indicates that the
MTTF for wood poles is
approximately 76 yrs
Weibull Curve extended beyond
existing failure data to represent
the estimated life characteristics
of composite poles
B50 Value indicates that the
MTTF for wood poles is
approximately 125 yrs
ICNU_DR_113 Attachment F Page 4 of 8
Analysis Results
Composite poles have a higher purchase price than a comparable wood pole, so there would be an initial cost
increase in the first few years after beginning to install this alternative. Based on the assumption that these
poles will last longer than a standard wood pole, the increased lifetimes will eventually begin to offset the higher
initial purchase price. The results of the analysis show that the initial investment into this type of pole would be
recovered 52 years after beginning a program that replaces failed inaccessible wood poles with composite poles
(Fig 6). The financial performance of the composite poles is compared to wood poles in Fig 7.

Fig 6

Fig 7
ICNU_DR_113 Attachment F Page 5 of 8
Recommendations
Based on the results of this analysis, Asset Management makes the following recommendations:
1. Make contact with other utilities that have installed composite poles and get further feedback on the
material and determine if the material is suitable for our needs.
2. Begin to replace inaccessible failed wood poles with composite poles on a limited basis (approximately
10 poles per year) and document the installation times and lifetime performance characteristics.
3. Evaluate the installation procedure required for composite poles and determine if any addition training
needs to be implemented
4. Monitor pricing for composite poles and begin to install more composite poles if their cost comes down
in the future.
Resource/Budget Effects – Composite Pole Installation/Inspection
Since the current cost of a composite pole is 330% higher than a comparable wood pole, an initial increase in the
annual budget would be required to begin a program to replace any wood pole with a composite equivalent.
This increased annual cost will gradually decrease as the advantage of the additional life, reduced maintenance
and reduced installation equipment requirements of these new poles is realized. The annual effects on the
budget for replacing all failed inaccessible poles in the system are outlined in Fig 8a. The annual budget effects
of conducting a test case of 10 poles per year is outlined in Fig 8b.

Fig 8a Fig8b
ICNU_DR_113 Attachment F Page 6 of 8
Appendix – Labor Predictions

Appendix – Effects Predictions

ICNU_DR_113 Attachment F Page 7 of 8
Appendix – Spares Predictions

ICNU_DR_113 Attachment F Page 8 of 8
Kris Busko 4/24/12

1

Corrosion Threats to Avista’s Aging Steel Pipeline System
Introduction
Avista endeavors to maintain a safe and reliable natural gas distribution system so that its facilities
perform optimally throughout their life and provide the best value for customers, employees and
investors. High-profile incidents in other parts of the country have led to escalating regulatory scrutiny
of the nation’s gas distribution system, and Avista is continuing to foster a culture of compliance with all
aspects of federal and state laws through these rapidly-changing times. Avista is meeting the needs of
its aging natural gas infrastructure through the diligent application of sound installation and
maintenance practices, and with the 2011 implementation of the federally-mandated Distribution
Integrity Management Program (DIMP), Avista will continue to collect information about its natural gas
facilities and will examine trends and potential failure points within the system. When failure trends are
observed, Avista will respond appropriately to avert the potential risk of harm to life and property.
As a result of the DIMP and Asset Management analyses of the gas system, Avista believes that its
earliest steel pipe facilities are sound and current methods of monitoring and protection from corrosion
are appropriate. A systematic replacement of early steel pipe is not needed simply because it is “old,”
but rather, the current practice of site-specific response to pipe segments discovered to be unreliable is
endorsed. Historically, excessively problematic pipe segments (regardless of age) have been removed
from service and pose no further threat, and no conclusions can be drawn about potential corrosion on
other segments of the same era from those localized actions. Unlike certain eras of Aldyl A polyethylene
pipe, which is considered to be an at-risk facility due to its inherent material properties and is currently
undergoing systematic, prioritized replacement in Avista’s system, steel piping is expected to last for
indefinite periods when properly constructed, operated within established maximum allowable
pressures, and when appropriate cathodic protection and maintenance systems are applied. That said,
there are still opportunities for greater understanding within this framework.
Given that the earliest steel facilities were in service for decades before Avista acquired them or applied
modern cathodic protection to them, it may be valuable to gather an even greater understanding of the
current condition of the oldest steel pipes in service. To gain this knowledge, Asset Management
recommends that testing should be conducted for the earliest installations in order to gather
information on the possible effects of the many years this pipe was in service without cathodic
protection. By gaining knowledge of the current condition of this pipe and the effects of earlier
maintenance practices, Avista will have even greater confidence in the assertion that this pipe will
continue to provide safe and reliable service well into the future. The methods, advantages and
limitations of this testing are discussed within this document.
It is important to note that this discussion specifically covers the threat of corrosion to the oldest steel
pipe remaining in service within Avista’s gas distribution territory. Threats from inadequate
construction welds or fabrication methods, steel material failures such as ERW seam defects, or a survey
of localized threats from possible stray current sources were not part of this analysis.
ICNU_DR_113 Attachment G Page 1 of 15
Kris Busko 4/24/12

2

Avista’s Steel Installation History
Avista has over 12,500 miles of pipe installed in Washington, Idaho, and Oregon, serving approximately
320,000 customers. Of those 12,500 miles, nearly 4000 miles is steel from ½ to 20 inches in diameter,
installed from 1931 to today.
Figure 1. Proportion of material types within Avista’s natural gas system.

Most of the steel system was acquired from other operators, among them Ritzville, Goldendale, and
Stevenson in Washington, and all of the Oregon service areas. More than half of Avista’s steel piping is
in Washington State. The proportion of steel pipe in service within each state is reflected in Figure 2.
Figure 2. Distribution of steel pipe among the three states Avista serves.

The oldest steel pipe remaining in service in Avista’s territory was installed in 1931 in LaGrande, Oregon.
Limited steel commodity availability and the austerity of the Great Depression and World War II years
Polyethylene
68%
Steel
32%
System Materials
Washington
Oregon
Idaho
2120 miles
54%
1112 miles
28%
719 miles
18%
Proportion of Steel
ICNU_DR_113 Attachment G Page 2 of 15
Kris Busko 4/24/12

3

had the effect of restricting the broad expansion of the use of steel piping and natural gas distribution
during the Oregon system’s infancy, and it was not until the 1950’s that growth began to accelerate.
The Oregon territory underwent several changes of ownership before Avista acquired the Medford,
Klamath Falls, Roseburg, and LaGrande systems in 1991.
In Avista’s northern territory, natural gas suppliers did not complete the construction of their
transmission pipelines into Eastern Washington and Northern Idaho until 1956, and Avista (then named
Washington Water Power) acquired the distribution system served by the original Spokane Natural Gas
Company in 1958.
The age profile for all steel within Avista’s three-state territory is shown in Figure 3, including 257 miles
of unknown-age steel pipe. Note that only 51 miles of pre-1956 steel pipe remains in service, all of
which is in Oregon.
Figure 3. Age profile of steel pipe for all states, including 257 miles of steel pipe of unknown age.

Interestingly, nearly half of the 51 miles of pre-1956 steel pipe in all of Oregon exists in a single
construction area; in Klamath Falls. 25 miles of 1932-vintage steel exists in this construction area alone
(Figure 4). Over the past 10 years Klamath Falls Operations has removed portions of this aging steel
when areas of leaks occur and as road projects have conflicted with the pipelines. Similarly, 9 miles of
1931 pipe exists in LaGrande (Figure 5), and efforts have been made year over year to replace sections
that have become unreliable. The pace of removal has been at a bit more than 1 mile per year in
Oregon for the past decade, representing over $3 million in system upgrades over this time frame.
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
10%
0
50
100
150
200
250
300
350
Mi
l
e
s

I
n
s
t
a
l
l
e
d
Year Installed
Age Profile of Steel Pipe
51 mi. total
298 mi. in 1956
257 mi. unknown age
ICNU_DR_113 Attachment G Page 3 of 15
Kris Busko 4/24/12

4

Figure 4. Klamath Falls construction area, 1932 steel pipe shown only, 25 miles.

Figure 5. LaGrande construction area, 1931 steel pipe shown only, 9 miles.

The fact that such large quantities of the earliest steel exists within just two construction areas is
advantageous. Operations and Cathodic Protection personnel living and working in those areas are very
familiar with the systems and can identify trends of failure and are able to monitor the health of the
systems very efficiently. Additionally, as Avista moves to develop testing programs to understand the
current state of the steel pipe, there will be fewer test sites needed to gain valuable knowledge about a
large proportion of the oldest pipe facilities. Rather than having small segments scattered throughout a
large area, the compact-nature of these particular steel installations allows for these efficiencies.
Historical Cathodic Protection
The Distribution Integrity Management Program has assembled the known historical methods of
cathodic protection for the systems which are now under Avista’s jurisdiction. Because most of the steel
system was acquired from other operators and often historical records were lost, there is uncertainty
ICNU_DR_113 Attachment G Page 4 of 15
Kris Busko 4/24/12

5

around the origination of the earliest cathodic protection (CP) systems. Note--there is no remaining
1930 steel in Oregon, the oldest steel in service is 1931 vintage.
Figure 6. Summary of cathodic protection history for facilities now maintained by Avista, excerpted from
the2011 Distribution Integrity Management Program manual.

1971 Law
The Department of Transportation Code of Federal Regulations (CFR) maintains jurisdiction over gas
distribution facility construction and maintenance practices. 49 CFR 192, Subpart I, states that all buried
metallic pipe installed after July 31, 1971, must be properly coated and have a cathodic protection
system designed to protect the pipe in its entirety. Further, all newly constructed metallic pipelines
must be coated before installation and must have cathodic protection in place within one year after
ICNU_DR_113 Attachment G Page 5 of 15
Kris Busko 4/24/12

6

construction. Prior to the implementation of this law, the application of CP could often be spotty or
ineffective. Adding to the difficulty in collecting the definitive history and understanding of the
evolution of Avista’s natural gas distribution system is that most of Avista’s steel system was acquired
from other operators. Therefore, it is difficult to identify precisely when “effective cathodic protection”
came to exists across the system. There is, however, a remarkable comparison that can be made that
clearly demonstrates the benefit of this vital activity over time.
A Snapshot of Historical Corrosion Leaks
The Oregon natural gas system was most recently owned by California-Pacific Utilities until Avista
acquired it in 1991. As a comparison snapshot of the effectiveness of the 1971 CP mandate, a look at
the annual report for corrosion leaks for Oregon offers a significant understanding of the enormous
strides cathodic protection has made in assuring the safe and reliable operation of steel piping. The
1971 annual report for California-Pacific Utilities reflected 116 corrosion leaks on the 1930-1939 steel
pipe found just within the single year of 1971 (2.36 leaks per mile for just the 1930-1939 decade’s pipe).
There were 316 corrosion leaks that year total in Oregon for all steel pipe up to the 1971 installation
year. It is quite extraordinary that only a single decade’s vintage had over 1/3 of the total leaks,
especially since the footage of pipe installed during the 1930’s was far less than during the post-WWII
years. By comparison, the 2010 Avista annual report noted only 2 corrosion leaks discovered that year
in Oregon for all pipe, 1931-2010, or 0.0018 leaks per mile in the state. Many thousands of miles of
steel pipe were added to the system between 1939 and 2010 and yet the corrosion leak count is a tiny
fraction of what it had once been. Effective CP methods, including retaining a technical staff of specially
trained individuals dedicated to monitoring steel facilities, have contributed to the dramatic drop in
corrosion leaks in the last 40 year period. The following information provides details to the activities
that have contributed to this resounding success story.
Modern Cathodic Protection Requirements
Avista has developed a maintenance matrix for steel piping and related steel facilities, consisting of
those actions required by 49 CFR 192, Subpart I, the Washington Administrative Code, and its own
internal standards developed through the evolution of best practices for its facilities. Figure 7 identifies
these minimum requirements for different types of facilities. This ongoing activity assures that Avista’s
steel facilities and appurtenances receive near-constant monitoring.
Whenever signs of inadequate cathodic protection are found through the activities listed (with no leak
present), remedial action must be taken within 90 days of discovery. Corrosion leaks found during leak
surveys or trouble calls from the public are managed like other types of leaks in terms of urgency and
method of repair, but have the addition of a review by cathodic technicians (on site whenever possible)
to identify root cause and to review any potential development of failure trends for the leak areas.
ICNU_DR_113 Attachment G Page 6 of 15
Kris Busko 4/24/12

7

Figure 7. Excerpt of Avista’s Gas Standards Manual, Section 5.0, Maintenance Timeframes. Those
actions pertaining to cathodic protection are shown, including frequency and mandate reference.
Activity Frequency DOT 49 CFR
192 Reference
WAC
Reference
Avista
Gas
Standards
Reference
Cathodic Technicians and the Nature of Corrosion Leaks
49 CFR 192, Subpart I, requires that corrosion control procedures must be carried out by, or under the
direction of, persons qualified in pipeline corrosion control methods. In 2003, Avista went beyond this
basic mandate and hired its first National Association of Corrosion Engineers (NACE) certified technician
to lead its cathodic protection group, and has since required that each member of the CP staff acquire
various levels of NACE certification and education. Further, each team member is assigned certain
districts within Avista’s service territory which allows for a continuity of knowledge and consistent
responsibility across a wide geography. The technicians are able to monitor the systems and compare
various data point readings for signs of changing conditions which prompt them to act before corrosion
leaks occur. Corrosion failures are investigated by this trained staff to understand root cause, such as
whether the event was preceded by external galvanic or stray current damage, and through the
identification of short-circuits introduced by the public. Since corrosion is very much a product of the
environment in which facilities exist, it is only through real understanding and constant monitoring of
that environment that the health of steel facilities can be assured. See Figure 8 and 9 for examples of
the various conditions identified and remediated by cathodic technicians before they became sources of
corrosion leaks. Figures 10 and 11 also illustrate the localized nature corrosion failures, also attributable
to outside influences rather than an intrinsic failure of the steel piping itself.
ICNU_DR_113 Attachment G Page 7 of 15
Kris Busko 4/24/12

8

Figure 8. A metal watering can bridges the necessary isolation between a customer’s equipment and
Avista facilities, drawing cathodic protection from Avista’s system over to downstream piping. This short
circuit of Avista’s impressed protective current, if left as found, could result in inadequate corrosion
prevention to Avista’s steel service line and facilities beyond. “Shorts” of this kind can be difficult to find,
requiring specialized knowledge to identify and trace to their source.

Figure 9. When faltering readings were found at an area rectifier (used to impress a protective current
to prevent corrosion), a cathodic survey was conducted on a 4” high pressure pipeline. The damage
shown is due to “stray current,” a localized phenomenon where currents from nearby sources compete
with Avista’s protection, causing heavy areas of metal loss to pipe. In this case, a nearby petroleum
pipeline’s protective system interfered with Avista’s system. Historically, damage like this may have
been misidentified as 3rd-party contact, looking like scraped pipe. Avista’s cathodic technicians identified
the true cause and halted the interference which prevented further damage and serious consequences.

The customer’s piping
begins here Avista’s piping,
(includes the meter)
ICNU_DR_113 Attachment G Page 8 of 15
Kris Busko 4/24/12

9

Figure 10. Nearby foreign utilities can interfere with Avista’s cathodic protection system. A dielectric
(non-conductive) pad is placed between facilities to prevent shorting.

Figure 11. Stray current from a phone line has caused metal loss on this 2” diameter, 1958-vintage steel
distribution line. Damage like this can occur on steel pipe of any age. This corrosion failure was
discovered during leak survey.

Dielectric pad
separates facilities
ICNU_DR_113 Attachment G Page 9 of 15
Kris Busko 4/24/12

10

Industry Comparisons and Historical System Development
In 2011, the American Gas Association collected benchmarking data for corrosion rates. Figure 12
shows Avista’s relative leak rate per mile of steel for 2010 as compared to other utilities in North and
South America (utility names are coded for confidentiality). Note that while the 2010 industry median is
lower than the 2005 benchmark, Avista is well below either reference point. Avista’s modern cathodic
protection methods are certainly factors in this excellent industry ranking, but the fact that Avista has a
relatively modern system and has smaller quantities of steel in use overall are advantageous
characteristics that also play a beneficial role. Simply stated, less steel to manage yields better results.
The benchmark is not only due the relatively large quantity of polyethylene distribution piping in Avista’s
system, but also the complete lack of cast iron facilities in our service territories. These characteristics
are attributable to the period of history in which Avista’s system was developed and constructed, with
the broad use of polyethylene coinciding with population growth and the wide-spread adoption of
natural gas for residential and commercial use in the Pacific Northwest beginning in the 1960’s.
Figure 12. American Gas Association benchmarking study of corrosion rates for various natural gas
operators across North and South America.

Historical Leaks & Pipe Replacement
As mentioned previously, when leaks have been found in unusually high quantities on specific pipe
segments, Operations has acted to replace the problem segments. Figure 13 shows a normalized leaks-
per-mile chart for all steel pipe in Avista’s system. Note that while early vintage piping may appear to
have large quantities of leaks represented as ‘spikes’ in the graph, these events are attributable to a few
leaks found over a single segment of pipe. Those troublesome segments have been removed and as
0
50
100
150
200
250
300
0.1
3
0.1
5
0.1
7
0.2
9
0.3
9
0.5
4
0.5
9
0.7
5
0.8
1
0.8
3
0.9
6
1.1
2
1.5
1
1.5
9
1.6
3
1.6
3
1.7
5
1.8
2
1.9
1
2.1
6
2.2
0
2.2
1
2.2
2
2.2
9
2.3
4
2.4
0
2.7
5
2.7
8
3.3
8
3.9
1
4.0
3
4.4
0
4.6
8
5.9
6
6.3
8
6.8
0
8.1
2
8.2
6
8.3
5
10
.
8
4
13
.
0
4
13
.
7
6
14
.
2
3
16
.
6
7
19
.
8
3
19
.
9
4
22
.
0
7
22
.
2
4
23
.
9
7
27
.
7
6
28
.
8
9
31
.
5
3
31
.
5
7
77
.
1
4
14
1
.
2
3
20
6
.
5
6
24
3
.
2
0
AGBL AS BK BG BR BCAR Z ADCD AT BX CGAX BV O AO U P I WBMBAAM K BI AK AVAWCA BP BF BW L C D AFAN AJ AY F APAQAZBH BS V CHBE AAAH M T N BB AIIn
s
t
a
n
c
e
s

o
f

C
o
r
r
o
s
i
o
n

F
o
u
n
d

U
n
d
e
r
g
r
o
u
n
d

p
e
r

1
0
0

m
i
l
e
s

o
f

U
n
d
e
r
g
r
o
u
n
d

Ca
t
h
o
d
i
c
a
l
l
y

P
r
o
t
e
c
t
e
d

M
a
i
n
s

a
n
d

S
e
r
v
i
c
e
s

Company Code
Instances of Corrosion Found Underground per 100 Miles of Underground Cathodically Protected Mains and
Services by Company
2006 Median 2010 Median
Avista’s data reflects 0.0039
leaks per mile for all ages of
steel, in all service areas
ICNU_DR_113 Attachment G Page 10 of 15
Kris Busko 4/24/12

11

stated previously, no assumptions can be made on the balance of that era of pipe if it is not contiguous
to the leaky sections. Figure 14 repeats the earlier Age Profile graph to illustrate the relatively minute
quantity of leaks found in the 1956-current period, and how it correlates to the enormous quantities of
pipe installed during that time period.
Figure 13 & 14. Normalized leaks per mile for all ages of Avista’s steel facilities, with lower graph once
again showing quantities of pipe installed as a direct comparison.

0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
10%
0
50
100
150
200
250
300
350
Mi
l
e
s

I
n
s
t
a
l
l
e
d
Year Installed
Age Profile of Steel Pipe
51 mi. total
298 mi. in 1956
257 mi. unknown age
1953: One leak
over the total 1,400
ft in system
1944: All leaks on this pipe were on
Beatty St. in Medford which was
replaced, 700 ft remains in Medford
1941: All leaks on this pipe
were on one 1100 ft section of
pipe on Modoc Rd. in Medford
which was replaced, 1400 ft
remains throughout entire
system
Very low leaks per mile
are due to very large
quantities installed
ICNU_DR_113 Attachment G Page 11 of 15
Kris Busko 4/24/12

12

Asset Management Modeling Steel Piping
Asset Management performed modeling using Availability Workbench software to identify what the
expected reliability is for this pipe, and to test various assumptions for continuing with the current
practice of as-needed replacements as well as scenarios for systematic replacements. The existing steel
was modeled using 50-ft segments as the traditional discrete modeling elements for pipe.
Five years worth of corrosion failures were studied for data covering the years 2006-2010,
encompassing 49 leaks. 38 of the 49 failures were discovered through organized leak survey or
atmospheric corrosion patrols (rather than trouble calls from the public), and 35 of the 49 leaks were
identified as non-hazardous (grade 2 or 3). None of the corrosion leaks studied resulted in harmful
incidents involving injuries or property damage, though for modeling purposes some consideration was
given to the likelihood that a major negative incident could result at some point in the future, modeled
at approximately 1 out of 1000 leaks.
Given that the quantity of pre-1956 steel pipe remaining in service is only 1.2% of the entire steel
system, the results obtained from modeling were initially difficult to decipher. As noted within this
report, the post-1956 pipe has exceedingly low corrosion-leaks-per-mile characteristics, and by including
this data in the model it showed that the system on the whole has the potential to last exceedingly long
periods of time (more than 250 years). The vast quantities of newer, ‘healthy’ pipe obscured any
conclusions that should be drawn about early vintage pipe.
When the pre-1956 pipe is isolated, modeling results indicate that while this family of existing older pipe
is expected to last well beyond 100 years, even this data could be challenged in that several of the noted
failures on the oldest facilities have occurred on pipe that has since been removed from service, posing
no further risk on its own, and its failures say nothing about the health of any other segment of pipe of
the same age (refer again to Figures 11 and 12). Ultimately, by studying the known leaks for the last five
years, root cause and reliability analysis has identified that the expected future corrosion failures of pre-
1956 steel pipe is not necessarily related to age, but rather that failures are expected to continue to
occur in more random ways. Modern corrosion failures are often attributable to outside influences like
stray current, isolation, or shorts in the system, which are site-specific and often unpredictable.
Given that there is nothing intrinsically wrong with vintage steel when maintained appropriately, the
random and site-specific nature of corrosion failures, and that Avista has successfully managed
‘problem’ segments effectively to date, a “run-to-failure” scenario is far superior to replacing the oldest
steel piping simply based on its age. Corrosion failures occur in small numbers, are readily identifiable,
and the vast majority are non-hazardous, smaller leaks when they do occur. Given these parameters,
there was no scenario modeled for systematic replacement of steel pipe that added substantial safety
for the public or returned an agreeable financial IRR for customers.
With this information as a baseline, Avista may now turn its attention to gathering greater
understanding of the current health of its oldest steel pipe in an effort to build further confidence in this
assertion and more aggressively identify any areas that could become a concern in the future, to further
understand and identify possibly hidden risks to the facility.
ICNU_DR_113 Attachment G Page 12 of 15
Kris Busko 4/24/12

13

Current Condition of the Oldest Pipe
As part of site-specific, Operations-identified replacements of leaking segments of steel, regardless of
age, most often the process for replacement includes the installation of new piping adjacent to the
existing facility and then abandonment of the leaking pipe. As part of the process it is rare to expose
large sections of failed pipe, and therefore the overall condition of the pipe segment remains unknown.
Were there several other sections between leak points that were just about to fail? How much
corrosion is present overall? Historically, especially in the pre-DIMP era, precise knowledge of exact
failure conditions for any facility that was subsequently replaced has been of questionable value; since it
is removed from the system there was not much use in retaining forensic details.
While the low rates of current corrosion failures and remarkable decrease in corrosion leaks since 1971
is precisely the desired outcome of an effective CP system, Avista must consider that the application of
modern cathodic protection may have effectively “pushed pause” on some existing rate of pipeline
decay in its system. Given how long the oldest pipe was in service in the pre-CP era, it is not difficult to
imagine that there could be steel pipes in existence that have experienced some level of wall-thinning
due to corrosion over many years, but with the application of modern CP have halted in their decay.
Regular leak surveys and ongoing cathodic testing provide a level of understanding of areas that are
already leaking or have the potential to do so, but more information could be acquired though specific
site testing. Avista’s Lead Cathodic Technician, Gary Douglas, has suggested the use of test coupons as a
viable method to sample the conditions around the oldest pipe in service to understand the status of
those facilities. Test coupons (Figure 15) are small samples of steel that are buried in the same
environment as the pipe under study. Test leads are brought above ground so pipe-to-soil readings can
be taken and the rate of decay of the unprotected test coupon can be recorded. After several months
(the length of time can vary), the coupon is retrieved and measured to assess the rate of metal loss.
That metal loss can then be projected onto the known quantity and surface area of the pipe in that
same test zone.
Figure 15. Farwest Corrosion Control Company’s test coupon components.

Limitations of Testing
As stated previously, corrosion is very site-specific. Nearby facilities, soil resistivity and ground moisture
each can play a role in corrosion risks for steel piping. Therefore, even test results discovered using
Test coupon
and PVC holder
(buried),
0.50” diameter
x 0.86” long
coupon
Test leads are
routed to surface
for in situ
measurements
ICNU_DR_113 Attachment G Page 13 of 15
Kris Busko 4/24/12

14

corrosion coupons is not to be taken as the final word on pipe condition. If test results indicate that
there is the potential for metal loss in any particular area, further steps must be taken to identify
conditions in that vicinity. The areas of concern should be exposed and physically measured to
determine the pipe wall thickness and an assessment made on the true condition of the pipe.
Alternatively, if the test coupons show little or no deterioration, normal protection and maintenance
practices must continue as before.
Repairs and Accelerated Actions
If pipe is found to have corrosion on inspection, several methods of repair are permitted by Avista’s Gas
Standards Manual. Metal loss is measured in the field typically through the use of pit gauges (see Figure
16), though other non-destructive testing methods such as X-Ray or ultrasound may also be used.
Figure 16. A pit gauge is a simple way to measure corrosion and mechanical defects (dents) in pipe.

For distribution piping operating at less than 100 psig, 50% or more of the pipe wall must be lost to
initiate a repair. For pipelines operating between 100-500 psig but at less than 20% of specified
minimum yield strength (SMYS), 20% metal loss is permitted. For piping that operates at greater than
20% SMYS or above 500 psig, just 10% metal loss is allowed before repairs are initiated. Avista’s Gas
Standards Manual, Specification 3.32, Repair of Steel Pipe, has extensive information regarding methods
of repair; replacement is not always required depending on the amount of the deterioration found.
Summary
The threat of corrosion on Avista’s 4,000 miles of steel distribution piping, including its oldest, pre-1956
steel, is ever-present and is often unpredictable. However, Avista’s corrosion control methods are
appropriate and are serving the system well, and therefore no broad systematic replacement program
for the oldest steel in service is necessary based on its age alone. As demanded by Distribution Integrity
Management Program approach, each segment of pipeline in Avista’s system must be assessed for all
known threats, regardless of its age, including threats arising from inadequate construction welds or
fabrication methods, material failures such as ERW seam defects, and localized stray current sources. It
is only by a thorough understanding of all system threats that any particular facility’s fitness for service
may be judged. Site-specific, Operations-driven replacements of steel segments that become unreliable
due to the aggregate risk from these threats are the current norm and have occurred at a pace that has
ICNU_DR_113 Attachment G Page 14 of 15
Kris Busko 4/24/12

15

proven to be effective. The ability to continue this responsive management of Avista’s aging steel
facilities is necessary to maintain this level of risk management.
To enhance Avista’s knowledge of its facilities, particularly those with years of service in the non-CP era
or with limited construction documentation, Asset Management recommends local site testing in the
areas of oldest steel piping. This testing can give Avista additional information to determine the present
condition and wall thickness of the pipeline, and as necessary, this information can then be used to
initiate further direct assessments or prioritized, specific site-replacement actions. Fitting well with the
philosophy of responsive facilities management, any replacement actions would be driven toward those
facilities that are shown to require updating, not just undertaking a broad “old pipe” replacement
program. With continued diligence in the application of Distribution Integrity Management monitoring
and analysis methods and taking reasonable actions to replace unreliable facilities when appropriate,
Avista’s steel natural gas system is expected to continue to operate reliably into the foreseeable future.
ICNU_DR_113 Attachment G Page 15 of 15
Kris Busko 6/14/12

1

ERT Replacement Strategy Development
Introduction
Encoder Receiver Transmitters (ERTs) are electro-mechanical devices that allow utility meters to be read
remotely. Unlike electric meters, which have an obvious source of power available, natural gas meter
ERTs (Figure 1) are driven by lithium batteries. These batteries discharge over relatively long periods of
time and must eventually be replaced. Asset Management was asked by Gas Engineering to study
Avista’s current age profile of ERTs and make recommendations for a replacement timeline that
maximizes the assets’ value while levelizing the cost and resource impacts of continually refreshing
these devices.
Figure 1. Typical Itron brand Encoder Receiver Transmitter (ERT) in use on a natural gas meter. Lacking
a ready-source of power like electric meters, gas ERTs are operated by a lithium battery.

Avista has been using Itron brand ERTs of varying model numbers since 1992, and is continuing to
pursue automatic meter reading whenever practical. For various reasons, the initial goal of full ERT
deployment by the year 2010 has not been achieved for the approximately 320,000 residential and
commercial gas customers to date, but as of April 2012 there are nearly 233,000 natural gas ERTs in use
across Washington, Idaho, and Oregon. The ability to remotely query meters has proven valuable to
both Avista and customers by limiting billing errors associated with misread meters, avoiding employee
exposure to risk from disgruntled customers and biting dogs, and by eliminating the need to access
customers’ property each month to obtain a traditional site-to-site meter read. Avista has been able to
reduce their meter reading staff and has offered new opportunities to the majority of those displaced
workers. While the benefits of ERT use are manifold, these devices, like other utility components, have
a limited useful life and must be managed appropriately.
The primary goal in studying this facility is to levelize the annual budget and resource requirements for
ERT replacements. Additionally, spatial data will be reviewed to determine if there is a way to move
toward geographic efficiencies in any future replacement program. Figures 2 and 3 detail the age profile
of ERTs in Avista’s system, and Figure 4 indicates the distribution of ERTs by state.

ICNU_DR_113 Attachment H Page 1 of 22
Kris Busko 6/14/12

2

Figure 2. The chart below show the age profile of ERTs in Avista’s system since the last broad
replacement of 1999-and-older units performed in 2009. Approximately 233,000 ERTs are in use today.

Figure 3. Shown another way, the table below indicates how many ERTs were installed each year. The
large quantities installed in 2004 and 2005 could prove problematic to replace in a single future year.

3,
9
2
3

11
,
1
7
2

12
,
9
8
6

20
,
2
5
1

60
,
3
0
1

12
1
,
8
4
0

13
7
,
9
0
1
16
8
,
2
1
4

18
0
,
6
9
5
21
9
,
0
1
4

22
5
,
2
8
7

23
2
,
9
3
3

23
2
,
9
8
1

0
30,000
60,000
90,000
120,000
150,000
180,000
210,000
240,000
270,000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Cumulative Number of Gas ERTs Installed by Year
3,923 7,249
1,814
7,265
40,050
61,539
16,061
30,313
12,481
38,319
6,273 7,646
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Quantity of ERTs Installed Each Year
ICNU_DR_113 Attachment H Page 2 of 22
Kris Busko 6/14/12

3

Figure 4. The distribution of ERTs by state in Avista’s system.

Engineering Report of 2006 and Replacement Project of 2009
Per the Engineering Report submitted in partial fulfillment of the requirement for his degree of Master
of Engineering and Technology Management in 2006 (Attachment 1, noted further as the “2006
Report”), Chief Gas Engineer Mike Faulkenberry analyzed Avista’s ERT assets to determine the
appropriate age for replacement. This 2006 Report referenced the Itron-provided field study data that
indicates the mean life of their ERTs were 19.4 years with a standard deviation of 3.4 years. An analysis
was included as part of the 2006 Report which identified the consequence of failures and the return on
investment for various ERT-replacement approaches. The idea of replacing the battery only rather than
the full ERT unit was dismissed early on, since (per Itron) other components of ERTs begin to fail before
another battery refresh is needed. Those non-battery failures would then require urgent corrective
action which would obliterate any initial savings found from a battery-only replacement approach.
The 2006 Report considered the expense of completing urgent replacements of failed units in the field
(described as the “reactive” replacement model), including Avista’s labor and the expense of creating an
estimated bill for the affected customer (noted as $10). Comparisons were made between this and the
proactive approach of planned replacement prior to unit failure, both using Avista labor and using
contractor labor. The best-case scenario employed a contract workforce, and the estimated expenses
for this approach are noted below, including overhead loading expenses:
2006 Report Estimated Planned Replacement Costs, Per Unit
SUM $52.13
These financial considerations, combined with the Itron failure data, led Avista to conclude that
maximum benefit would be achieved by replacing the ERTs once they are 10 years of age, using
Washington Idaho Oregon
54,308
76,565
103,064
ERT Distribution by State
ICNU_DR_113 Attachment H Page 3 of 22
Kris Busko 6/14/12

4

contractor resources, at an overall cost of $52.13 per unit. This approach was believed to provide the
maximum useful life of ERT units while minimizing the customer disruption and burden of a run-to-fail
model (described in the 2006 Report as a “fall down maintenance” approach).
With this conclusion in hand, Avista launched a project in 2009 to replace all year 1999-and-older ERTs
in the system, approximately 34,900 units in total. A contractor was hired to perform this work and the
project was completed in that same year. The 2009 actual project expenses for this ERT replacement
project were as follows, including overhead loadings:
2009 Actual ERT Replacement Costs, Per Unit
SUM $64.59
The actual project expenses in 2009 were $64.59 per ERT replaced. Even considering a reasonable rate
of inflation, actual expenses were well beyond that originally predicted in the 2006 Report. This is
partially due to the absence of disposal and project management expenses in the original estimate, but
these omissions are nearly offset by the price paid per ERT in 2009 (including loadings) which was
significantly less than originally predicted in 2006. The major difference in cost is because the actual
contractor labor of 2009 was three times the 2006 estimate. Per the 2009 project manager, the
contractor selected was the low bidder among several, but the work was still completed per scope and
with few complications or quality issues. Therefore it must be assumed that future contractor expenses
will typically be near this level with some degree of inflation. Ultimately, the 2006 Report return on
investment (ROI) analysis assumed a lower total replacement cost per unit and therefore the incentive
to take action and replace units earlier and avoid the expense of failures was pronounced.
The 2006 Report’s conclusion to replace units at 10 years of age was not turned into a recurring budget
item to manage the asset for the long term, so there are currently many units older than 10 years of age
in service. Given that the program did not continue and the actual expenses were far in excess of the
original estimates, it is prudent to re-examine those conclusions and the timing of replacements.
Further, given that the age profile of ERTs currently in service has some significant peak installation
years, the goal must be redefined to not only discover at what age units provide the best lifecycle value,
but how to turn the management of this asset into a levelized, manageable recurring program for
overall system maintenance.
2012 Asset Management Analysis
In the development of this modern Asset Management study, Itron’s conclusions of ERT battery life
cycle were not challenged nor studied specifically relative to Avista’s climate. Itron’s original study did
indicate that there may be some variation in battery life for utilities in colder climates and that there is a
likely a variation in life cycle specific to the placement of ERTs on northern (shaded) or southern (sunny)
ICNU_DR_113 Attachment H Page 4 of 22
Kris Busko 6/14/12

5

exposures of buildings. Unfortunately for Avista, a detailed study is not feasible at this time since Avista
currently does not record ERT failures specifically and with enough detail to identify failure modes and
weather exposure location. ERT retirement data has been collected to some degree but this
information is purged regularly so it does not extend far enough historically to be meaningful for
modern analysis. Perhaps this information will be collected as Avista revises its Work Management
System (WMS) over the next several years and a specific study of Avista’s ERT failure rates could be
conducted. Until that time the best available data includes purchase histories for ERTs, which is the
source of the age profile information noted previously in Figure 2.
Levelized Approach Starting Point
Recall that one of the goals of this analysis is to convert the existing age profile of installation years into
a levelized rate of unit refresh that can be projected consistently each budget season. To determine a
starting point of what number of units should be removed annually to achieve the lowest cost, a simple
analysis was performed against the known age profile of existing ERTs. Given the new understanding of
actual costs based on the 2009 project, this simple analysis identified that 14 years of age was a good
starting point to test the return on several levelized replacement scenarios. For the current 233,000
units in service, 16,700 ERTs must be removed annually to meet this 14 year refresh guideline and
effectively reset the “peak installation” effects. At that pace, it would take several years to replace the
ERTs originally installed in 2004 and 2005 alone (more than 100,000 units in just those two years), but
once the units are refreshed in a levelized way there will be a calming of those peaking effects. This
phenomenon is true for any levelized effort; it will take a few years to move through the largest
populations but the long term effect will be to introduce new populations that have near-level
quantities within them.
The 16,700 unit annual replacement cycle is a good place to start but cannot be taken as the final verdict
for this program since the true costs of ERT replacements include not only the capital expense of
replacing equipment but also O&M effects of estimated bills needed when ERTs don’t provide usage
information for customer billing. Given that, a full Availability Workbench modeling and ROI analysis
was performed to confirm what service age offers the ideal mix of reliability and useful life for ERTs, as
well as determine what levelized program could be adopted to flatten out the annual population of ERTs
requiring refresh, and the impacts of undertaking that levelized program.
Current Modeling Assumptions
Capital vs. O&M: During the course of this analysis, the initial assumptions were that the unplanned
replacement of ERTs were a combination of Capital and O&M—the ERT unit itself is a capital purchase
and the labor and vehicle expenses needed to replace this failed device would be O&M. In fact, that has
been how Avista has managed this relatively low-frequency occurrence failure, and it has largely been of
no consequence because the small populations of ERTs have not produced large quantities of failures.

In developing this asset management analysis, however, it was discovered that ERTs are a retirement
unit within Avista’s utility accounting system, and therefore any effort involved in their replacement, as
well as the unit itself, can be capitalized. This is significant. If the non-capitalized expense from
ICNU_DR_113 Attachment H Page 5 of 22
Kris Busko 6/14/12

6

unplanned replacement consists of only a small administrative cost for estimated billing, then a run-to-
failure option appears viable. However, there is a certain operational criticality that must be
considered. Avista may be able to manage several hundred, even a couple of thousand, unplanned ERT
replacements over the course of the year without experiencing major changes in personnel or vehicle
demands, and without an increase in customer complaints. However, when the very large populations
of ERTs begin to fail at a rate of more than 20,000 units a year, this can’t be managed in an ad hoc way
and will quickly overwhelm currently available resources. Additionally, since a major goal of this analysis
is to discover what levelized replacement is needed to create a predictable program, run-to-failure
scenario must be discarded because it simply does not meet that goal. However, through the process of
studying this and the understanding that this activity should be capitalized, Avista now has the
opportunity to correct its accounting methods to reflect this effort as a capital upgrade to the system.
Additionally, by segregating this work within its own budget number, Avista can collect meaningful data
on the precise costs of unplanned ERT replacements which will prove beneficial to further studies.

Reactive, corrective replacements: For the 2012 analysis, current labor and equipment rates were used
to account for Avista gas servicemen replacing units as they fail, though for this analysis they are
considered capital expenses instead of the former O&M items. These expenses include 20 minutes of
hourly wage for wrench time to replace the ERT on site, plus a corrective callout amount that accounts
for the average travel time paid in wages for trouble calls within Avista’s territory. The reconfirmed
administrative effects costs of creating estimated bills and ERT disposal costs were included at $10.61,
reflecting a 2% inflation of the 2009 costs. There are no project management expenses included since
the labor loadings include the cost of dispatch and supervision for field personnel.

The current price for ERTs remains very close to the 2009 number, at $40.35 per unit. There are no
safety effects due to failed ERTs for either the public or Avista personnel, since a failed ERT is essentially
an inconvenience. There is no release of natural gas associated with a discharged battery, and
estimated bills are generally accurate considering most users have significant historical usage to rely
upon for calculations, though the risk of lost revenue must not be dismissed. Again, it can be assumed
that continued billing estimates also have an operations-criticality tipping point embedded within; if
Avista experiences many hundreds of estimated billings per year, there may be an expectation that this
will become a regulatory problem as the likelihood of customer complaints to the utility commissions
will increase, and the potential for lost revenue becomes even more likely. At this time, however, that
tipping point remains unknown.
Considering only the factors known, today’s estimated cost to send Avista personnel to replace a failed
unit in the field is $190.42, much higher than estimated in 2006 due to the inclusion of true vehicle
expenses, actual historical travel time wage information, and unit disposal. Again, these figures are
based on the known history of Avista expenditures for other types of service work and represent a more
sophisticated analysis than could be performed previously. With specific accounting changes regarding
ERT management, and as well with the implementation of a new Work Management System, Avista will
be in a position to gather better data in the future which will help to confirm or adjust this value. A
table showing the breakdown of these expenses is noted below.
ICNU_DR_113 Attachment H Page 6 of 22
Kris Busko 6/14/12

7

2012 Reactive ERT Replacement Costs, Per Unit
SUM $190.42
Proactive, planned replacements: For the 2012 analysis, it was agreed with Gas Engineering that any
planned replacement strategy would likely be performed using contractor resources. Therefore the
2009 contractor and project management labor expenses were used with a 2% annual inflation applied,
as well as the inclusion of disposal costs. The contractor price includes vehicles so there are no separate
equipment costs. The price for ERTs is again $40.35 per unit based on 2012 inventory costs. When
totaled, the modern expense for a proactive replacement of ERTs is expected to be $66.05 per unit.
2012 Proactive ERT Replacement Costs, Per Unit
SUM $66.05
As noted previously, ERTs are considered capital items regardless of whether they are installed in a
reactive, failed-replacement mode or as part of a proactive, planned-replacement system. And again, it
is now understood that travel time and wrench time for ERT replacements, whether planned or
unplanned, should be capitalized.
Modeling Results and Return on Investment
When the above parameters are modeled using Availability Workbench software and then exporting
these modeling results to an ROI spreadsheet calculation, the best rate of return can be achieved if ERTs
can be replaced at exactly 14 years of age, representing no departure from the original rough-cut
estimate used to find a levelized starting point of 16,700 units. While this is encouraging, it has already
been stated that is impractical to remove every ERT at any exact “birthday” year of service, especially a
large-quantity installation year like the 2005 family of more than 61,000 units. This, combined with the
desire to levelize budgets and resource impacts, led to further study of a range of alternatives. The 14
year ideal was compared against a 10-year replacement option as recommended in the 2006 Report,
and a 17 year option to help understand how beneficial the birthday-year removal concept was, and
with that, levelized quantities were also compared: both 19,417 units refreshed annually (a 12 year
program) and 23,300 units annually (a 10 year program). The table below shows the resulting ROI
analysis.
ICNU_DR_113 Attachment H Page 7 of 22
Kris Busko 6/14/12

8

Case Studied Internal Rate of Return Levelized Gross Margin Reqmnt
19,417 units annually 6.10% $1,458,286
At 14 years old 6.42% $1,405,217
Resource and Budget Planning Outside of the Replacement Program
Since the ideal removal at 14 years of age is not viable, the best alternative is to replace 19,417 units
annually in a program that begins in the year 2015. The reason this is more successful than the original
tested scenario of 16,700 units can be traced again back to the peak installation years’ phenomenon and
the ability of a more aggressive pace of replacement to remove some effects from unscheduled
replacements due to field failures. Said another way, in the original starting scenario of 16,700 units
annually there will still be many hundreds of other failures occurring outside that levelized program if
the Itron failure data holds true. While contractors are managing the basic program of refreshing units,
there will still be an increasing demand for in-house resources to deal with other failures until the
peaking effects of large populations can be removed. Figure 5 is a graphic of failures predicted to occur
annually beyond the 16,700 scheduled replacements.
ICNU_DR_113 Attachment H Page 8 of 22
Kris Busko 6/14/12

9

Figure 5. ERT failures predicted to occur outside a levelized replacement program of 16,700 units per
year. These failures are above and beyond the planned program, including predicted failures that will
occur prior to the start of the program in 2015.

Currently, Avista services fewer than 300 failed ERTs annually, which is a direct result of small
populations of relatively young ERTs in current service. As these units age and the failure curve
properties manifest, there will be a proportionate increase in the demand for unscheduled service visits
outside the planned replacement system. In the year 2023, as shown above, Avista can expect to
manage an extra 4,000 failed units on an unscheduled basis on top of 16,700 planned unit replacements
during that single year alone. This could prove detrimental to planning efforts for both personnel
resources and budgeting, and would have an administrative impact as well as a significant demand for
service personnel time. The recommended planned replacement program of 19,417 units annually
offers some relief but the effect of large populations is still pronounced, as shown in Figure 6.
Figure 6. Predicted ERT failures that will occur outside a levelized replacement program of 19,417 units
per year. These failures are above and beyond the planned program, and includes the time between
2012 and the proposed program start of 2015.

0
1000
2000
3000
4000
5000
ER
T

F
a
i
l
u
r
e
s

Year
Annual Failures Beyond 16,700 Planned Replacements
0
1000
2000
3000
4000
5000
ER
T

F
a
i
l
u
r
e
s

Year
Annual Failures Beyond 19,417 Planned Replacements
ICNU_DR_113 Attachment H Page 9 of 22
Kris Busko 6/14/12

10

Since large populations of failures are on the horizon, preparations must be made to manage the
replacements necessary outside of any levelized program; they are unavoidable. Replacing more ERTs
annually will not yield greater return--the effect of the additional failures is already a factor in the ROI
analysis noted in this study. The analysis reveals that a more aggressive annual refresh rate begins to
offer diminishing returns since the effect will be to pull units while the still have significant useful life
remaining. Figure 7 indicates that significant unplanned field failures will occur even under the “ideal”
14 years replacement scenario. Each of these options should be compared to Figure 8, the run-to fail
model, which is untenable.
Figure 7. ERT failures predicted to occur outside a 14 year, ideal “birthday” replacement program. These
failures are beyond the planned program.

Figure 8. The run-to-failure option is not viable and does not achieve the goals of this analysis. Managing
20,000-plus unplanned replacements annually would also result in other operations-critical problems.

Ultimately, this Asset Management analysis for ERTs should be performed regularly, especially as new
information is gathered. Actual expenses for contractor labor may not be as predicted; an ongoing
supply of annual work may lend itself to better pricing than a one-time-only project such as the 2009
0
1,000
2,000
3,000
4,000
5,000
ER
T

F
a
i
l
u
r
e
s

Failures Outside 14-year Replacement
0
5,000
10,000
15,000
20,000
25,000
ER
T

F
a
i
l
u
r
e
s

Failures in a Run-to-Failure Model
ICNU_DR_113 Attachment H Page 10 of 22
Kris Busko 6/14/12

11

effort. Better pricing may be obtained on ERTs, or Itron may publish updated lifecycle data on their
products as battery technology improves. Certainly, as improved failure tracking is implemented during
the replacement of Avista’s Work Management System there will likely be opportunities to identify
specific environments that lend themselves to longer battery life. In the meantime, preparations must
be made to manage the increasing rate of predicted unplanned replacements.
Forward–Looking Budget Requirements
Initial budget projections are included as part of the ROI analysis output and are as follows for the first 8
years of the program, years 2015 to 2022, which includes the peak population years. All figures include
escalations for inflation. These values are based on the single-year contactor bid from 2009, plus
inflation, and therefore must be refreshed as better information becomes available. It is possible that
future contractor bid prices may be reduced since a levelized, recurring program will offer multiple years
of work for bidders, hopefully driving costs down.
Year Capital Budget Requirement

ICNU_DR_113 Attachment H Page 11 of 22
Kris Busko 6/14/12

12

Geographic Efficiencies
As noted previously, part of this analysis is to review the spatial layout of existing ERTs to see if there are
opportunities to benefit from geographic efficiencies during replacement. The question must be asked
to determine if it is possible to do replacements in a logical, “A-to-B” way to either preserve any existing
structure and order or to inject some future spatial logic into future rounds of replacements. To
understand this, Avista’s GIS system consulted and a detailed distribution of ERTs by zip code was
captured. Figure 9 are GIS maps of certain representative ERT year populations, which are very similar
to the rest of the system’s historical distribution:
Figure 9. Snapshots of various ERT population years, showing a lack of clustered populations by year.

Year 2000 Year 2005 Year 2010

Unfortunately, there is no clear and obvious clustering of ERTs, since it is appears that during each year
ERTs have been placed fairly randomly across Avista’s 3-state service territory. Each major construction
area includes ERTs from every historical year’s population. The extent of the scattering is even more
apparent when an Excel pivot table is created from the known population data. Attachment 2 includes
this pivot table of ERTs by zip code, including those installed to date in 2012. (Note some small
variations of ERT count by year from the Figure 2 age profile graphic since it includes a more recent
snapshot of data, as well as ERTs installed to date in 2012.) Though not unexpected, it was important to
review this information as part of this analysis.
In a similar vein, details regarding the specific location of any given ERT may become more important—
Avista may choose to first remove those ERTs sited on meters with southern exposures ahead of those
on the cooler, north side of buildings. There are already hints of battery life being longer in cooler
environments this back to the 2006 Report, and there may be a time when Avista can be far more
selective in which populations are upgraded, in an effort to achieve even greater useful life from ERTs
without suffering negative consequences. As Avista’s new work management system is deployed this
type of data could prove to be very valuable for such a purpose.
ICNU_DR_113 Attachment H Page 12 of 22
Kris Busko 6/14/12

13

Summary
Currently, with the advent of Smart Grid technology for electric meters, the full build-out of ERTs for
Washington State has slowed considerably on both the electric and gas sides of Avista’s business. For
customers receiving both gas and electric service, if the electric meter on site still must be read manually
there is little incentive to place an ERT on site for the gas meter; we are already visiting the property for
meter reads. This philosophy may change over time as the impacts of Smart Grid are fully understood.
In any case, the populations of ERTs should be monitored to update this analysis. Given that there will
be more ERTs installed over time and the cost of labor and equipment will likely change into the future;
it is critical to commit to periodically updating this analysis to assure that any new units find their way
into the levelized cycle of replacements. With the improved accounting methods, identifying ERT
replacements as a capital improvement rather than O&M expense, there will be opportunities to
segregate the true spending for vehicles and labor more effectively. As this information is gathered
there may be further adjustments needed to this levelized removal and opportunities to further craft
this program of facility management.
Given that the 2009 project replaced pre-millennial ERTs, there is no urgency to begin a broad
replacement program for some time. The proposed starting point for a levelized program to being in
the year 2015 combines the best balance of useful life and field-failure avoidance. At that time, a rate of
unit removal of approximately 19,417 units annually will offer the best return on investment while
offering the long-term benefit of reintroducing levelized populations into service. During any planned
replacement program, it must be recognized that large populations of failures on the horizon will yield
greater numbers of unplanned replacements even outside this levelized approach and therefore
advanced preparations must be made to secure resources to manage this eventuality.

ICNU_DR_113 Attachment H Page 13 of 22

Attachment 1
2006 Engineering Report

ICNU_DR_113 Attachment H Page 14 of 22

Attachment 2
Pivot Table of ERTs by Zip Code

ICNU_DR_113 Attachment H Page 15 of 22

Zip Code Year
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Grand Total
83501 8624 326 1033 603 352 381 408 1 11728
83801 6 8 1 2 35 385 36 49 36 19 20 24 3 624
83803 25 40 17 4 2 8 96
83805 3 1 2 1015 270 151 147 70 100 62 69 1890
83806 1 91 3 4 3 4 106
83810 36 1 1 38
83814 5384 522 466 588 230 210 210 37 7647
83815 1 8869 480 473 765 342 274 229 46 11479
83823 1 2 227 11 7 3 4 255
83825 68 29 56 17 20 8 10 208
83832 298 7 5 11 12 333
83835 1 5 3 5779 348 365 588 187 201 177 24 7678
83837 1 1 1240 84 76 40 62 1504
83839 321 8 7 9 9 354
83840 13 1 1 1 2 18
83843 6 1 4873 380 280 164 215 9 5928
83844 21 20 15 3 3 62
83845 1 174 25 13 20 8 13 5 10 1 270
83846 1 325 17 17 13 7 380
83847 1 114 25 10 15 10 19 3 4 201
83849 1 713 25 17 24 26 806
83850 1 632 42 26 14 27 742
83852 8 225 50 73 52 24 23 12 467
83854 1 1 9105 648 530 839 361 290 301 54 12130
83858 1 2938 209 209 227 95 96 93 15 3883
83860 3 22 192 75 7 15 1 315
83864 26 12 2 33 88 2627 910 696 340 519 124 241 1 5619
83867 207 11 7 4 6 235
83868 273 17 19 11 3 1 324
83869 9 95 50 45 16 12 18 1 246
83871 1 300 9 13 8 18 349
83873 1 559 50 33 22 15 680
97417 10 78 229 19 18 23 41 33 17 12 6 486
ICNU_DR_113 Attachment H Page 16 of 22

Zip Code Year
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Grand Total
97432 3 4 22 2 4 5 6 26 7 9 2 90
97442 1 4 167 7 1 3 3 186
97457 4 113 661 107 66 63 108 107 368 63 64 16 1740
97462 31 1 3 179 17 9 9 10 21 26 10 10 3 329
97469 13 223 8 20 19 25 22 7 13 1 351
97470 10 265 20 778 3972 456 540 428 573 1327 290 254 115 9028
97471 7 47 132 326 58 44 60 133 200 53 33 18 1111
97479 4 59 52 587 114 55 73 55 136 537 39 43 11 1765
97495 16 129 20 38 30 28 31 164 9 12 5 482
97496 1 4 56 714 94 37 71 73 116 32 47 17 1262
97497 1 1 2
97501 181 203 34 291 6218 234 348 482 442 1670 326 545 10 10984
97502 211 399 146 446 2134 206 197 272 229 1982 182 257 4 6665
97503 37 122 54 94 264 56 126 142 101 555 61 76 1 1689
97504 266 286 92 475 6291 342 580 687 487 2435 408 558 9 12916
97520 140 317 58 251 3124 200 255 380 301 2034 258 395 1 7714
97524 135 761 71 199 339 97 78 112 100 470 53 62 2 2479
97525 16 17 3 32 129 13 24 58 35 274 24 29 3 657
97526 439 337 73 389 2677 348 317 419 293 1499 355 238 15 7399
97527 95 784 100 388 1742 305 244 410 272 888 270 132 8 5638
97528 1 1
97530 29 41 15 61 400 36 47 43 42 398 42 36 1 1191
97535 1 18 5 22 877 24 38 50 33 166 32 39 1 1306
97537 5 6 9 16 402 23 19 33 28 58 18 14 631
97539 8 4 54 50 27 13 13 169
97540 4 13 3 22 1021 63 70 100 78 148 58 95 1 1676
97601 160 685 55 315 1916 393 414 500 321 1855 181 439 17 7251
97603 171 574 92 330 2700 503 476 544 450 2573 226 578 41 9258
97623 4 1 2 7
97627 13 3 8 4 3 8 5 4 124 2 11 185
97632 1 6 3 8 2 6 11 5 80 3 11 136
97824 49 29 9 6 27 15 13 17 20 70 12 14 1 282
97827 32 20 10 14 15 10 15 32 45 407 19 13 632
ICNU_DR_113 Attachment H Page 17 of 22

Zip Code Year
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Grand Total
97841 7 1 3 1 7 2 2 10 6 89 10 2 140
97850 1033 198 165 138 297 199 212 275 289 2463 252 105 44 5670
97867 10 6 2 10 10 3 2 6 12 118 4 4 4 191
97876 3 2 4 1 41 3 4 58
97883 33 26 15 28 31 23 27 50 55 502 33 24 8 855
98620 51 451 15 15 42 188 6 89 3 74 10 10 954
98648 12 130 22 5 17 121 1 43 2 38 6 11 408
98857 9 10 5 3 1 7 4 39
99001 13 17 10 51 208 164 138 71 141 25 26 864
99003 2 1 1 1 2 19 11 10 4 9 6 8 1 75
99004 52 142 17 109 168 327 208 134 77 722 47 64 2 2069
99005 27 46 3 22 28 151 98 118 34 351 21 25 6 930
99006 17 17 5 13 18 135 90 111 41 84 14 19 4 568
99011 29 14 66 16 6 7 138
99014 1 1 2
99016 24 58 6 53 84 473 203 255 37 211 41 61 3 1509
99019 5 4 8 11 169 123 116 27 38 20 38 13 572
99021 16 17 6 12 30 91 70 62 32 203 29 26 9 603
99022 9 13 2 3 25 149 128 98 15 109 6 31 588
99023 2 2 1 4 4 13 1 15 1 64 2 109
99025 14 20 2 21 13 72 21 32 15 247 5 14 476
99026 39 74 12 38 61 142 64 77 42 726 17 36 1328
99027 14 16 2 15 20 102 49 59 22 244 14 31 1 589
99029 4 15 37 7 3 1 4 71
99030 2 2 1 5
99031 1 1 4 12 8 4 2 2 1 35
99032 20 3 4 4 1 32
99036 5 2 2 3 1 5 3 5 1 21 2 2 52
99037 92 190 37 123 118 238 135 196 101 1735 66 115 4 3150
99101 1 1 2 4
99109 1 1 1 2 39 68 33 23 2 3 173
99110 1 1 2
99111 1 1 43 49 41 14 9 3 4 165
ICNU_DR_113 Attachment H Page 18 of 22

Zip Code Year
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Grand Total
99113 8 3 10 2 1 1 25
99114 2 1 5 8 61 89 51 37 6 6 14 280
99122 4 17 35 64 14 7 9 25 1 176
99125 1 5 2 2 1 2 13
99134 1 7 2 4 5 1 20
99141 1 2 2 12 38 15 21 3 1 3 98
99143 13 6 9 1 29
99148 8 7 2 7 7 36 17 23 13 68 7 6 2 203
99159 1 17 6 8 5 2 2 5 46
99161 1 2 20 8 37 3 4 1 6 82
99163 9 15 7 5 3 3 42
99164 4 2 7 1 14
99169 2 85 15 19 31 9 2 6 169
99170 12 13 15 3 4 5 52
99171 12 9 13 3 1 1 1 40
99179 10 10 3 3 1 27
99181 1 2 1 1 5
99201 5 4 11 15 260 228 331 67 82 49 95 8 1155
99202 6 1 10 26 375 238 574 71 76 48 134 16 1575
99203 6 1 2 16 281 278 858 91 61 43 49 4 1690
99204 2 1 1 4 63 87 197 18 22 5 16 2 418
99205 7 17 3 8 58 652 362 931 155 205 129 229 20 2776
99206 111 237 494 239 241 676 454 926 276 2837 234 388 7 7120
99207 5 13 2 10 24 381 351 611 124 139 79 128 20 1887
99208 15 20 8 16 20 791 628 841 130 180 74 190 19 2932
99212 4 6 2 12 24 301 252 494 89 88 69 122 10 1473
99216 70 114 22 83 97 413 222 461 148 1648 126 302 12 3718
99217 13 19 6 17 24 305 198 254 82 224 32 48 6 1228
99218 5 3 1 6 10 175 162 335 52 40 44 89 7 929
99219 3 1 4
99220 1 1
99223 14 26 5 20 31 386 272 549 81 189 52 91 5 1721
99224 15 34 9 32 46 395 270 356 170 134 34 60 5 1560
ICNU_DR_113 Attachment H Page 19 of 22

Zip Code Year
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Grand Total
99260 1 1
99326 3 2 3 4 36 36 10 11 12 3 2 122
99341 29 2 8 5 1 45
99402 309 54 16 7 3 21 10 420
99403 1 1 1 3891 1836 362 211 158 186 168 6815
Grand
Total 3821 7127 1792 7146 39224 61077 15976 30159 12464 37897 7020 9179 746 233628

ICNU_DR_113 Attachment H Page 20 of 22

ICNU_DR_113 Attachment H Page 21 of 22

Attachment 3
ERT Handling and Disposal

ICNU_DR_113 Attachment H Page 22 of 22
1

AL1000TC Gas Meter Asset
Management Plan

Rodney Pickett and Amber Gifford
12-09-2010

ICNU_DR_113 Attachment I Page 1 of 19
2

Table of Contents
Introduction .................................................................................................................................... 3
Business Case .................................................................................................................................. 3
Asset Profile .................................................................................................................................... 3
Model Assumptions ........................................................................................................................ 7
Alternatives Examined .................................................................................................................... 8
Model Results ............................................................................................................................... 12
Recommended Action .................................................................................................................. 19
Conclusion ..................................................................................................................................... 19

ICNU_DR_113 Attachment I Page 2 of 19
3

Introduction
The Gas Engineering department wanted to examine when they should rebuild a meter and
when they should just replace it for the larger commercial bellows type gas meters. Work done
previously on residential meters suggested that the meters should be replaced when they reach
35 years of age. Other work on 425 gas meters indicated they should be replaced when they
reached 40 years of age. In this case, we examine what to do for the AL1000TC gas meter.
A team was formed with Gas Engineering and Asset Management to develop an asset
management model for bellows type gas meters for sizes 425, 1000, 1400, 2300, and 5000. The
team included David Howell, Jeff Webb, Steve Williams, Amber Gifford, and Rodney Pickett.

We analyzed the base case and alternatives using our Availability Workbench (AWB) software’s
RCMCost module which uses a modified Reliability Centered Maintenance approach combined
with probability functions, Weibull distribution functions, and a Monte Carlo Simulation
process. The full details for each of the models discussed below are captured in the software
model. The following discussion is a summary of the information used in the model and the
model’s analysis and results.
Business Case
The business question that the team analyzed was to determine the best approach to
maintaining gas meters. The objective was to save the company and our customer’s money by
optimizing the best approach to maintaining and replacing the gas meters. The inspections of
the meters have already been established by the different states’ utility commissions, but they
could be revised if we identified a compelling case. The measure of success for the winning
alternative is the one that provides the best internal rate of return to the customers using the
Revenue Resource Recovery method developed by Dave DeFelice.
Asset Profile
The AL1000 family of meters represents a small portion of all gas meters with only 3,349
installed throughout Oregon, Washington, and Idaho (see Table 1). The population of these
meters is very young with 80% being 16 years old or younger. Only 4.4% of all these meters are
more than 20 years old. While the overall population is relatively young, 43.6% are between
the ages of 11 years and 16 years old. Figure 1 shows the age profile by year for all of the
meters and how the population is young but concentrated around 15 years old.
The inspection requirement for these gas meters is a random inspection of a portion of the
population by year of manufacture which is typically referred to as a meter family. Based on
the number purchased each year, a small portion of the meters are tested starting when they
reach the ten year old point. Each year subsequent to the ten year point another sample of
each meter family is tested until two times in five years the annual sample failure rate is 10% or
more. When two years out of five years a family has had a failure rate equaling or exceeding
10%, the following year all of the meters in the family will be replaced with new meters. Based
on the failure curves in Figure 2 and Figure 3, these families will enter the 10% failure rate
around year 13 but due to the two in five and the small sampling size, it will take a few more
ICNU_DR_113 Attachment I Page 3 of 19
4

years beyond 13 years before the family is actually replaced. We can anticipate most of these
meters will require replacement over the next five to ten years.

Table 1, AL1000/AL1000TC Gas Meter Inventory
Gas Meter Type Number of Meters
AL1000 745
AL1000TC 2604
Grand Total 3349

Figure 1, Age Profile for AL1000/AL1000TC Gas Meters

0%
2%
4%
6%
8%
10%
12%
0
50
100
150
200
250
300
350
400
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35
10
0
0

M
e
t
e
r
s

Age
Age Profile of AL1000/AL1000TC Meters
ICNU_DR_113 Attachment I Page 4 of 19
5

Figure 2, AL1000/AL1000TC Failure Curve
1000 Combined Cumulative Probability
8760 2.865E+04 9.373E+04 3.066E+05
Time
0.1
0.2
0.3
0.5
1
2
3
5
10
20
30
50
70
90
99
99.9
Un
r
e
l
i
a
b
i
l
i
t
y

(
%
)
Eta estimator
P0: 0%
B50: 2.819E+05
B20: 1.927E+05
B10: 1.424E+05
Median rank
Bi-Weibull
Failure Curve Reaches the 10% Failure point in
the 13 – 17 year range.
ICNU_DR_113 Attachment I Page 5 of 19
6

Figure 3, AL1000/AL1000TC Modified Failure Curve to represent families are replaced when 10% of sampled meter fail twice in five years
1000 Combined Fam Mod Cumulative Probability
8760 2.865E+04 9.373E+04 3.066E+05
Time
0.1
0.2
0.3
0.5
1
2
3
5
10
20
30
50
70
90
99
99.9
Un
r
e
l
i
a
b
i
l
i
t
y

(
%
)
Eta estimator
P175200: 100%
B50: 1.348E+05
B20: 1.366E+05
B10: 1.336E+05
Median rank
Tri-Weibull
This is an example of stacking of hidden
failures revealed when the meters are
initially inspected at the 10 year point. The mis-match in this
region is due to the fact
the meters are not
randomly inspected until
the 10 year point, so all
of the failures show up
as points stacked on top
of each other instead of
spread throughout this
region.

This portion of the curve represents
replacing of the whole family once it
reaches a 10% annual failure rate
10% Annual Failure
Rate at the 15 year
point

ICNU_DR_113 Attachment I Page 6 of 19
7

Model Assumptions
The following are the key assumptions used in the development of the model. Changes in
these assumptions may or may not significantly change the outcome.
Future failures will follow the same trend as past failures
The average inspection cost in the field is $50 per meter
The equivalent of a student is used to paint meters when required
Inflation rate for future years will average 2.3% except for labor which will escalate at
3.5%
The discount rate will remain 7.08%
The average impact to a customer for a fast meter is valued at $144.75 (5 years at
$0.0033/hr)
The average impact to the company for a slow meter is valued at $144.75 (5 years at
$0.0033/hr)
The customers system wide can tolerate no more than 20 meters per year that run slow
and result in higher future bills (non-financial impact) (Note: this is twice the current
rate for this meter type)
The customers system wide cannot tolerate more than 350 failed meters per year (non-
financial impact)
To rebuild or repair a meter requires the following:
o 0.5 hrs of a Gas Meter Tech
o 10 minutes of a Gas Student Tech (to paint meter)
The material identified in
o Table 2
Replacing a meter is done in the field as part of the inspection so the cost is only the
material (See
Table 2 for the material used to replace the meter with the same type of meter)
Installing a filter on the meters and de-rating the meters so they don’t work as hard will
increase the 10% failure point from 15 years to 30 years because the components will
not wear out as fast
The cost to install a new filter on the gas meters will cost $75 in parts and labor per
meter
The additional cost to replace a 1000 meter with a 1400 will add an additional $80 to
the meter costs
A rebuilt gas meter has its equivalent age reduced by 45% (i.e. a 20 year old meter when
rebuilt will act as if it is only 11 years old)
30 Years sufficiently represents 1 lifecycle of a AL1000/AL1000TC gas meter
For each meter failure, a flat $56 charge is incurred to handle the meter and get it back
to the shop for maintenance, i.e. travel time costs.
For each meter that fails outside of the normal meter inspections, an additional 1.7
hours of Gas Meter Technician time is charged to go and check the meter (This
ICNU_DR_113 Attachment I Page 7 of 19
8

addresses meters identified by customers, utility commission, and other means
requiring action outside of the normal inspection cycle)
Table 2, Parts for Replacing and Rebuilding a AL1000 Gas Meter
Meter
Type
Part
Description
Revised
Description
Total
Price Replace Rebuild Capacity
Logistic
Delay time
AL1000
TC
Short Flag
Arm
Short Flag Arm -
AL1000TC $14.00 2 8
5 wks -
840hrs

TC Tangent
Kit
TC Tangent Kit -
AL1000TC $100.00 1 35
5 wks -
840hrs
Gaskets
Gaskets -
AL1000TC $0.75 2 250
5 wks -
840hrs
Index Cover
Index Cover -
AL1000TC $4.00 1 400
5 wks -
840hrs

Security
Seals
Security Seals -
AL1000TC $0.08 8 10,000
6wks -
1008hrs
Paint Paint - AL1000TC 1 120
1 wk -
168hrs
Index Index - AL1000TC $60.00 1 40
5wks -
840hrs

ERT, 100G
Module
com.
ERT, 100G Module
com. - AL1000TC $65.00 1 1 80
5 wks -
840hrs
1000 Meter
1000 Meter -
AL1000TC $717.55 1 25
4.3 wks -
720hrs

Alternatives Examined
Two different base case alternatives were examined against three improved performance
alternatives. The first base case is the current case with one exception. The exception is that
the failed family is not replaced but rebuilt. This base case was found in earlier work to
represent best value to customers. The second base case is the current case were meters
families are replaced with new meters. In the final analysis, the differences to the overall
savings were less than $50,000 and immaterial to the overall results. So the first base case will
be referred to as the base case for the remaining of the report.

The first alternative replaces the existing meters when they reach 15 years of age with a 1400
meter and install the filter. This alternative front loads the capital costs over the next 15 years
and realizes most of the savings in years 16-30. This program requires a significant capital input
early and realizes the savings late in life where the discount rate significantly reduces the NPV
of the savings. Figure 4 shows the failure curve used in this alternative. This alternative will be
called the Replace Case Improved.

The second alternative explores only replacing the existing meters with a new meter and filter
when it fails or fails its inspection. This alternative spreads the capital costs and the savings
over the whole 30 year period examined. The O&M savings in this case would be realized by
ICNU_DR_113 Attachment I Page 8 of 19
9

avoiding the initial repair costs and replacing them with capital costs. This alternative also
allows the discount rate to impact future capital costs and O&M savings in relatively the same
way. This alternative also uses Figure 4 as its failure curve. This case is referred to as the
Replace as Fail case.

The third alternative examined builds on the second alternative. This alternative changes the
second alternative by changing the inspection cycle from a random sampling approach used on
small meters to a 10 year periodic inspection cycle like the larger meters. While the meters
would initially be replaced if needed by a larger sized meter, when they failed in the future,
they would be rebuilt. This would require a change to the current standards established with
all of the utility commissions, so it is not immediately accepted as the plan but as a
consideration for the future. Figure 5 shows the failure curve used in this alternative. This is
called the Rebuild/Maint Case Improved. However, this case was modeled using the Redesign
feature so the costs do not accurately reflect the NPV of the costs.
ICNU_DR_113 Attachment I Page 9 of 19
10

Figure 4, Modified Failure Curve with a filter installed and replaced with a AL14000 Gas Meter
1000 Combined Fam Mod Cumulative Probability
8760 2.865E+04 9.373E+04 3.066E+05
Time
0.1
0.2
0.3
0.5
1
2
3
5
10
20
30
50
70
90
99
99.9
Un
r
e
l
i
a
b
i
l
i
t
y

(
%
)
Eta estimator
P175200: 4.707%
B50: 2.574E+05
B20: 2.635E+05
B10: 2.59E+05
Median rank
Tri-Weibull
10% Failure Point
at 30 Years
This portion of the curve represents
replacing of the whole family once it
reaches a 10% annual failure rate
ICNU_DR_113 Attachment I Page 10 of 19
11

Figure 5 Modified Failure Curve with a filter installed; replaced with a AL14000 Gas Meter; and maintenance changed to a 10 year periodic inspection
1000 Combined Fam Mod Cumulative Probability
8760 2.865E+04 9.373E+04 3.066E+05
Time
0.1
0.2
0.3
0.5
1
2
3
5
10
20
30
50
70
90
99
99.9
Un
r
e
l
i
a
b
i
l
i
t
y

(
%
)
Eta estimator
P175200: 4.849%
B50: 3.8E+05
B20: 3.054E+05
B10: 2.444E+05
Median rank
Tri-Weibull
10% Failure Point at 30
Years but meters repaired
and not replaced
ICNU_DR_113 Attachment I Page 11 of 19
12

Model Results
For all of the cases this report examines, we will discuss the overall lifecycle cost, labor
requirements, spares requirements, number of gas meter failures, effect costs, Customer
Satisfaction performance, annual Failure Performance, and financial performance.
The detailed model results from AWB are provided in the corresponding appendices discussed
below. The lifecycle costs discussed represent the sum of each year’s costs including inflation,
but not the net present value.

Some common impacts of the method used to model the results should be explained to help
understand some of the numbers. The cost of the Gas Meter Technician will appear out of line
with the number of man-hours projected. A flat rate charge for travel time was included in the
model to deal with getting failed meters and transporting them back to the shop. This flat
charge per event is responsible for the largest portion of the labor costs shown below.
Most values shown in the table below represent the sum of the values over a 30 year period
unless stated otherwise. Dividing these numbers by 30 years will yield an average value but
should only be done to help compare models. The actual annual model results show varying
annual results and trends that may make the average value too high or too low when compared
to current annual values. In order to compare the model results to today’s number, you must
look at the early annual numbers from the model.

The cost for performing inspections is captured as an operational cost and not included in the
labor costs.

For the base case model, shows the general results. Table 4 shows how many spare parts are
anticipated over the next 30 years. The financial results are shown in Table 11 for all cases
examined. Figure 6 shows the accumulation of costs over time for each of the cases examined
and provide a graphical representation of the information used to create Table 11. The
Cumulated Cost curves show the sum of the costs for the current and all previous years. The
base case is unique in that its values are determined when it was compared to a theoretical
case after the system has had new filters and meters changed.

ICNU_DR_113 Attachment I Page 12 of 19
13

Table 3, Base Case General Performance Values
Model Results Value Notes
Overall Lifecycle Costs $11,740,000
Labor Requirements – Gas
Meter Technician
$1,001,000 Note: Most costs from flat
charges per event, Man-hours
estimate is 7,000 man-hours
over 30 years
Labor Requirement – Gas
Student Technician
$25,500 2,300 man-hours over 30 years
Number of Gas Meter
Failures
13,900 Over 30 years, Number high due
to repairing with an age
reduction factor of 45% causing
meter to require repair 45%
sooner than the initial repair
Customer Satisfaction
Performance
23.24 Goal: <= 1
Meter Failure Performance 1.3 Goal: <= 1

Table 4, Base Case Spare Parts Performance Values
Meter
Type
Part
Description
Revised
Description
Total
Price Replace Rebuild
Number
Used
AL1000
TC
Short Flag
Arm
Short Flag Arm -
AL1000TC $14.00 2 27,700

TC Tangent
Kit
TC Tangent Kit -
AL1000TC $100.00 1 13,900
Gaskets
Gaskets -
AL1000TC $0.75 2 27,700
Index Cover
Index Cover -
AL1000TC $4.00 1 13,900

Security
Seals
Security Seals -
AL1000TC $0.08 8 110,900
Paint Paint - AL1000TC 1 13,900
Index Index - AL1000TC $60.00 1 13,900

ERT, 100G
Module
com.
ERT, 100G Module
com. - AL1000TC $65.00 1 1 13,900
1000 Meter
1000 Meter -
AL1000TC $717.55 1 0

ICNU_DR_113 Attachment I Page 13 of 19
14

The first alternative or Replace Case Improved results are shown in Table 5 and Table 6.

Table 5, Replace Case Improved General Performance Values
Model Results Value Notes
Overall Lifecycle Costs $5,280,000
Labor Requirements – Gas
Meter Technician
$26,600 Note: Man-hours estimate is 184
man-hours over 30 years
Labor Requirement – Gas
Student Technician
$675 61 man-hours over 30 years
Number of Gas Meter
Failures
370
Customer Satisfaction
Performance
0.6 Goal: <= 1
Meter Failure Performance 0.03 Goal: <= 1

Table 6, Replace Case Improved Spare Parts Performance Values
Meter
Type
Part
Description
Revised
Description
Total
Price Replace Rebuild
Number
Used
AL1000
TC
Short Flag
Arm
Short Flag Arm -
AL1000TC $14.00 2 735

TC Tangent
Kit
TC Tangent Kit -
AL1000TC $100.00 1 370
Gaskets
Gaskets -
AL1000TC $0.75 2 735
Index Cover
Index Cover -
AL1000TC $4.00 1 370

Security
Seals
Security Seals -
AL1000TC $0.08 8 2,900
Paint Paint - AL1000TC 1 370
Index Index - AL1000TC $60.00 1 370

ERT, 100G
Module
com.
ERT, 100G Module
com. - AL1000TC $65.00 1 1 3,350
1000 Meter
1000 Meter -
AL1000TC $717.55 1 3,350

ICNU_DR_113 Attachment I Page 14 of 19
15

The second alternative called the Replace as Fail Case is shown in Table 7 and Table 8.

Table 7, Replace as Fail Case General Performance Values
Model Results Value Notes
Overall Lifecycle Costs $6,500,000
Labor Requirements – Gas
Meter Technician
$26,600 Note: Man-hours estimate is 184
man-hours over 30 years
Labor Requirement – Gas
Student Technician
Note: only labor is associated
with the inspection
Number of Gas Meter
Failures
560
Customer Satisfaction
Performance
0.9 Goal: <= 1
Meter Failure Performance 0.05 Goal: <= 1

Table 8, Replace as Fail Case Spare Parts Performance Values
Meter
Type
Part
Description
Revised
Description
Total
Price Replace Rebuild
Number
Used
AL1000
TC
Short Flag
Arm
Short Flag Arm -
AL1000TC $14.00 2 0

TC Tangent
Kit
TC Tangent Kit -
AL1000TC $100.00 1 0
Gaskets
Gaskets -
AL1000TC $0.75 2 0
Index Cover
Index Cover -
AL1000TC $4.00 1 0

Security
Seals
Security Seals -
AL1000TC $0.08 8 0
Paint Paint - AL1000TC 1 0
Index Index - AL1000TC $60.00 1 0

ERT, 100G
Module
com.
ERT, 100G Module
com. - AL1000TC $65.00 1 1 3,500
1000 Meter
1000 Meter -
AL1000TC $717.55 1 3,500

ICNU_DR_113 Attachment I Page 15 of 19
16

The last alternative examined is the Rebuild/Maint Case Improved. The results from this model
are shown in Table 9 and Table 10.

Table 9, Rebuild/Maint Case Improved General Performance Values
Model Results Value Notes
Overall Lifecycle Costs $2,770,000
Labor Requirements – Gas
Meter Technician
$105,000 Note: Man-hours estimate is 725
man-hours over 30 years
Labor Requirement – Gas
Student Technician
$2,700 Note: Man-hours estimate is 245
man-hours over 30 years
Number of Gas Meter
Failures
1,450 Note: only labor is associated
with the inspection
Customer Satisfaction
Performance
2.4 Goal: <= 1
Meter Failure Performance 0.4 Goal: <= 1

Table 10, Rebuild/Maint Case Improved Spare Parts Performance Values
Meter
Type
Part
Description
Revised
Description
Total
Price Replace Rebuild
Number
Used
AL1000
TC
Short Flag
Arm
Short Flag Arm -
AL1000TC $14.00 2 2,900

TC Tangent
Kit
TC Tangent Kit -
AL1000TC $100.00 1 1,450
Gaskets
Gaskets -
AL1000TC $0.75 2 2,900
Index Cover
Index Cover -
AL1000TC $4.00 1 1,450

Security
Seals
Security Seals -
AL1000TC $0.08 8 11,600
Paint Paint - AL1000TC 1 1,450
Index Index - AL1000TC $60.00 1 1,450

ERT, 100G
Module
com.
ERT, 100G Module
com. - AL1000TC $65.00 1 1 4,950*
1000 Meter
1000 Meter -
AL1000TC $717.55 1 3,500*

*Model did not directly estimate this number since the incremental change was modeled using
the Redesign feature.
ICNU_DR_113 Attachment I Page 16 of 19
17

Table 11, Financial Comparison of Alternatives
Title
Status of
Effect
Costs
IRR
PV of
Savings to
Customers
PV of Savings to Company
Capital O&M Combine
d
Rebuild 1000 Meters - Current
Case No Effects 3.20% -$1,676,289 $331,855 -$2,108,953 -$1,777,097
Replace 1000 Meters - Front
Loaded No Effects 4.60% -$1,192,415 -$2,638,375 $2,700,303 $61,927
Replace 1000 Meters - as fail or
fail inspection No Effects 8.30% $415,504 -$1,423,873 $2,580,045 $1,156,172
Replace/Rebuild 1000 Meters as
fail and change inspection No Effects 23.42% $2,236,246 -$331,855 $2,644,672 $2,312,816
Rebuild 1000 Meters - Current
Case With Effects 2.63% -$2,487,613
Replace 1000 Meters - Front
Loaded With Effects 6.87% -$108,930
Replace 1000 Meters - as fail or
fail inspection With Effects 11.19% $1,480,642
Replace/Rebuild 1000 Meters as
fail and change inspection With Effects 29.73% $3,256,613

ICNU_DR_113 Attachment I Page 17 of 19
18

Figure 6, Cumulative Cost Curves for Base Case and the three Alternatives
$0
$2
$4
$6
$8
$10
$12
$14
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
20
3
0
20
3
2
20
3
4
20
3
6
20
3
8
Cu
m
u
l
a
t
i
v
e

C
o
s
t

P
r
o
j
e
c
t
i
o
n
s
Mi
l
l
i
o
n
s
Year
Rebuild 1000 Meters -Current Case Replace 1000 Meters -Front Loaded
Replace 1000 Meters -as fail or fail inspection Replace 1000 Meters as fail and change inspection
ICNU_DR_113 Attachment I Page 18 of 19
19

Recommended Action
The recommended approach to the AL1000/AL1000TC gas meters is the Replace as Fail Case. In
this case, we will replace the existing meters as they fail in service or fail during the inspections
with a AL1400 meter if appropriate for the current demand and a new filter. The current
inspection requirements will remain in effect.

While the Rebuild/Maint Case Improved did provide a better financial result, it does not meet
the current inspection requirements and the model would need further modification before it
could be relied upon.
Conclusion
In conclusion, the best plan for managing the current AL1000/AL1000TC gas meters is to
replace them as they fail with a more appropriately sized meter and adding a filter upstream of
the meter to extend their life to 30 or more years and reduce the impact to rates.
ICNU_DR_113 Attachment I Page 19 of 19
1

Wood Pole Management – Alternative Pole Material Comparison
Background
Historically, wood poles have been used within Avista’s electric distribution system due to their low cost and
availability. Despite the legacy of wood poles, some other utilities are beginning to convert their distribution
systems to poles made from alternative materials that have the added benefit of longer service lives. Of the
available materials, Cor-Ten steel, galvanized steel, ductile iron and concrete are the most logical direct
replacements for most utility’s distribution poles since each is engineered to have life-spans and strength that
are comparable to wood.
Avista has already taken steps to begin to experiment with other pole types in its distribution system by
installing some very limited quantities of galvanized and Cor-Ten steel poles. The advantage of installing test
lines of these materials is to see how installation procedures may vary from the standard wood pole installation
practice and get a better understanding of the life expectancy.
In order to more fully investigate the economic impacts of making comprehensive use of these different types of
poles, Avista’s Asset Management department conducted a thorough analysis of each alternative by giving
consideration to all economic aspects of maintaining the wood poles the electric distribution system. The
specific goal of this analysis was to determine if any of these materials would prove to be more cost effective
over a long period of time. This report discusses the results of a comparison between the costs of maintaining
the existing predominately wood distribution pole system (Base Case) and the costs of gradually converting the
system to each of the four other most likely options by replacing failed wood poles with either the steel, ductile
iron or concrete poles (Alternative Cases).

ICNU_DR_113 Attachment J Page 1 of 21
2

Alternative Materials Evaluated
In order to fully evaluate the financial impacts of using each of these types of poles, Avista analyzed five
different scenarios as follows:
Base Case – Wood Poles
An electric distribution system consisting of 246,000 wood distribution poles, where poles that
fail or do not meet code requirements are either reinforced with a steel stub or replaced with
another equivalent cedar wood pole
Alternative 1 – Ductile Iron Poles
An electric distribution system consisting of 246,000 wood distribution poles, where poles that
fail or do not meet code requirements are either reinforced with a steel stub or replaced with an
equivalent ductile iron pole
Alternative 2 – Cor Ten Steel Poles
An electric distribution system consisting of 246,000 wood distribution poles, where poles that
fail or do not meet code requirements are either reinforced with a steel stub or replaced with an
equivalent Cor-Ten steel pole
Alternative 3 – Galvanized Steel Poles
An electric distribution system consisting of 246,000 wood distribution poles, where poles that
fail or do not meet code requirements are either reinforced with a steel stub or replaced with an
equivalent galvanized steel pole
Alternative 4 – Concrete Poles
An electric distribution system consisting of 246,000 wood distribution poles, where poles that
fail or do not meet code requirements are either reinforced with a steel stub or replaced with an
equivalent concrete pole
ICNU_DR_113 Attachment J Page 2 of 21
3

Description and Characteristics of Potential Alternatives
1. Cedar Wood Pole
Cedar wood poles are the most common pole in Avista’s electric distribution system and substantial
failure data has been collected over many years. Based on existing data, the Mean Time to Failure
(MTTF) of a cedar pole is 76 years.
Cost - $607
Current Inspection Interval - 20 years
Current Inspection Cost - $32/pole
Mean Time to Failure – 76 yrs
2. Ductile Iron
Ductile iron is a less fragile variation of cast iron and has been commonly used as direct bury sewer
pipe for hundreds of years. Because of its high carbon content, it has good corrosion resistance that
can be further improved with the application of additional coatings below the ground line.
Cost - $701 (Below ground line coatings extra)
Estimated Inspection Interval - 20 years
Estimated Inspection Cost - $150
Estimated Life Time Increase Beyond Wood – 30 years
3. Cor-Ten Steel
Cor-Ten steel has similar mechanical properties to carbon steel but has the additional advantage of
forming its own layer of protective corrosion (patina). It has very good performance when the
material is only subject to atmospheric corrosion but it was not intended to be used in applications
where it would have continuous contact with moisture. In the case of direct bury utility poles,
additional coatings are generally used to further protect the pole below the ground line.
Cost - $2,059 (Below ground line coatings extra)
Estimated Inspection Interval - 20 years
Estimated Inspection Cost - $150
Estimated Life Time Increase Beyond Wood – 30 years
4. Galvanized Steel
Galvanized steel poles are constructed from carbon steel that is plated with a protective zinc coating
that acts as a sacrificial barrier to the steel. It is commonly used in direct buried applications such as
street light poles and culverts. Additional coatings can also be used to further protect the pole
below the ground line.
Cost - $2,244 (Below ground line coatings extra)
Estimated Inspection Interval - 20 years
Estimated Inspection Cost - $150
Estimated Life Time Increase Beyond Wood – 30 years
5. Concrete
Pre-stressed, hollow, spun cast concrete poles tolerate direct bury applications very well and they
do not rot. However, they are prone to damage due to freeze/thaw cycles and are significantly
heavier than a comparable wood pole and are expected to take more time to install.
Cost - $1,223
Estimated Inspection Interval - 20 years
Estimated Inspection Cost - $32
Estimated Life Time Increase Beyond Wood – 30 years
ICNU_DR_113 Attachment J Page 3 of 21
4

Alternative Material Pole Assumptions
Avista has a large body of failure data on the wood poles in its distribution system, which permits very accurate
predictions regarding how long a cedar distribution pole is statistically expected to last in its service region.
However, neither Avista nor the industry as a whole has a great deal of information regarding how long steel,
ductile iron and concrete poles are expected to last. In the absence of accurate data, Asset Management
consulted with representatives of the Line Crew, Distribution Engineering and Wood Pole Management who all
helped to construct experience based estimates on the life of the alternative poles. A table of the relevant
assumptions can be found in Figure 1.
In addition to the information gathered from internal sources, multiple external sources also provided helpful
information:
Craig Stegmeier - Arizona Power Service (Electric Utility located in Arizona)
Zack Heim - Salt River Project (Electric Utility located in Arizona)
Dean McQuillen, Kevin Niles - Osmose (steel and wood pole inspection contractor)
Jarrod Goodwin - Pacific Steel Structures (Manufacturer of Galvanized and Cor-Ten Distribution Poles)
Ed Antar - T&B/Meyer (Manufacturer of Galvanized and Cor-Ten Distribution Poles)
Rick Simpson – McWane Poles (Manufacturer of Ductile Iron Poles)
Assumptions Wood Ductile Iron Cor-Ten Galvanized Concrete
MTTF 78 +30 yrs +30 yrs +30 yrs +30 yrs
Inspection
Interval 20 yrs 20 yrs 20 yrs 20 yrs 20 yrs
Inspection Cost $32 $150 $150 $150 $32
Inspection
Equipment Contractor Contractor Contractor Contractor Contractor
Pole Cost $607 $701 $2,059 $2,249 $1,223
Corrective
Replacement
Labor
3 Lineman (3hrs) 3 Lineman (3hrs) 3 Lineman (3hrs) 3 Lineman (3hrs) 3 Lineman (3hrs)
1 Groundman (3hrs) 1 Groundman (3hrs) 1 Groundman (3hrs) 1 Groundman (3hrs) 1 Groundman (3hrs)
GIS Editor (0.1hrs) GIS Editor (0.1hrs) GIS Editor (0.1hrs) GIS Editor (0.1hrs) GIS Editor (0.1hrs)
Planned
Replacement
Labor
3 Lineman (3hrs) 3 Lineman (3hrs) 3 Lineman (3hrs) 3 Lineman (3hrs) 3 Lineman (3hrs)
1 Groundman (3hrs) 1 Groundman (3hrs) 1 Groundman (3hrs) 1 Groundman (3hrs) 1 Groundman (3hrs)
GIS Editor (0.1hrs) GIS Editor (0.1hrs) GIS Editor (0.1hrs) GIS Editor (0.1hrs) GIS Editor (0.1hrs)
Corrective
Replacement
Equipment

Class 56 (Dual Wheel) Class 56 (Dual Wheel) Class 56 (Dual Wheel) Class 56 (Dual Wheel) Class 56 (Dual Wheel)
Class 57 (Dump Flatbed) Class 57 (Dump Flatbed) Class 57 (Dump Flatbed) Class 57 (Dump Flatbed) Class 57 (Dump Flatbed)
Class 66 (Tandem Digger) Class 66 (Tandem Digger) Class 66 (Tandem Digger) Class 66 (Tandem Digger) Class 66 (Tandem Digger)
Class 68 (DBL Bucket) Class 68 (DBL Bucket) Class 68 (DBL Bucket) Class 68 (DBL Bucket) Class 68 (DBL Bucket)
Class 76 (Trencher/Plow) Class 76 (Trencher/Plow) Class 76 (Trencher/Plow) Class 76 (Trencher/Plow) Class 76 (Trencher/Plow)
Class 87 (Trailer) Class 87 (Trailer) Class 87 (Trailer) Class 87 (Trailer) Class 87 (Trailer)
Planned
Replacement
Equipment

Class 56 (Dual Wheel) Class 56 (Dual Wheel) Class 56 (Dual Wheel) Class 56 (Dual Wheel) Class 56 (Dual Wheel)
Class 57 (Dump Flatbed) Class 57 (Dump Flatbed) Class 57 (Dump Flatbed) Class 57 (Dump Flatbed) Class 57 (Dump Flatbed)
Class 66 (Tandem Digger) Class 66 (Tandem Digger) Class 66 (Tandem Digger) Class 66 (Tandem Digger) Class 66 (Tandem Digger)
Class 68 (DBL Bucket) Class 68 (DBL Bucket) Class 68 (DBL Bucket) Class 68 (DBL Bucket) Class 68 (DBL Bucket)
Class 76 (Trencher/Plow) Class 76 (Trencher/Plow) Class 76 (Trencher/Plow) Class 76 (Trencher/Plow) Class 76 (Trencher/Plow)
Class 87 (Trailer) Class 87 (Trailer) Class 87 (Trailer) Class 87 (Trailer) Class 87 (Trailer)
Figure 1
Table of Assumptions
ICNU_DR_113 Attachment J Page 4 of 21
5

Failure Mechanism – Galvanized, Cor-Ten and Ductile Iron Poles
The primary failure mechanism of the metallic poles is corrosion, which is generally expected to occur to a
greater extent at or below the ground line due to the increased duration of contact with moisture. These
engineered poles are designed and constructed with specific wall thicknesses that are expected to slowly thin
and weaken as corrosion takes place. Below ground line coatings and treatments (Figure 2, Figure 3) will
decrease the rate of corrosion, but will never eliminate it entirely. Since the rate of corrosion for each of these
materials varies depending on the soil conditions there is no absolute value that describes how long each of
these pole types would be expected to last. Further complicating the issue is that none of these materials has
been used within the industry for a long enough to have an accurate estimate of their life expectancy. In the
absence of detailed failure data, failure curve estimates were used for these alternatives.
In order to construct the estimated failure distribution curve for the steel and iron poles, the existing data points
were used to fit a curve that was similar in shape to the failure curve of wood poles (Figure 5) but with the Mean
Time to Failure (MTTF) increased by 30 years (Figure 6).
If the organization needs more accurate life cycle cost predictions in the future, it will be necessary to have
detailed failure estimates with which to make decisions. With Cor-Ten and galvanized poles already in our
distribution system, it will eventually be possible for Avista to have much more accurate lifetime estimates by
conducting inspections to measure the wall thickness and calculate the rate of corrosion with respect to time.
Failure Mechanism – Concrete Poles
The primary failure mechanism of concrete poles is cracking due to the repeated freeze-thaw cycles that they
are subjected to in Avista’s service region. Minor cracks wick in trace amounts of moisture and when this
moisture freezes and expands, the small crack becomes slightly larger. After many of these cycles, the cracking
will become significant enough to affect the structural integrity of the poles (Figure 2).

Figure 2
Cracked Concrete Pole
ICNU_DR_113 Attachment J Page 5 of 21
6

Figure 4
Galvanized Pole w/below ground line coating

Figure 3
Cor-Ten Pole w/below ground line coating
ICNU_DR_113 Attachment J Page 6 of 21
7

Figure 5
Cedar Pole Failure Curve

Figure 6
Estimated Cor-Ten, Galvanized, Ductile Iron and Concrete Failure Curve

Weibull curve extended beyond
existing failure data to represent the
estimated life characteristics of
concrete, steel and ductile iron poles
Weibull Curve closely
approximates actual failure data
B50 Value indicates that
the MTTF for wood and
concrete poles is
approximately 76 yrs
B50 Value indicates that the
MTTF for steel and iron
poles is 30 yrs greater than
for a comparable wood pole
ICNU_DR_113 Attachment J Page 7 of 21
8

Analysis Results
The results of the analysis show that the initial cost of the replacement poles has the greatest affect on the near
term economic results and that the estimated lifetime differences of the poles affect the results of the analysis
very little. The reason for this is that each new pole (wood or an alternative) is expected to last for a very long
time, so in either case a second replacement in a given location is going to be many decades in the future and as
a result, the economic benefits will be deferred until that time. Since the steel, ductile iron and concrete
distribution poles all have higher purchase prices there would necessarily be an initial budget increase
requirement in the first few years after beginning to install any of the options. Based on the assumption that
these poles will last longer than a standard wood pole, the increased lifetimes of the alternatives will eventually
begin to offset the higher initial purchase price but this advantage would be not recognized until two complete
inspection cycles have occurred.

The ductile iron pole is the most promising alternative but the cost of these poles ($701) would need to be
reduced down to the point of a comparable cedar pole before it would be economically justifiable in the short
term to begin installing them in. (Figure 8). The results of the analysis also indicate that the costs of the other
three options are also too high to justify making the transition at this time. Currently, the cost for a single wood
pole is $607 and the costs of concrete, Cor-Ten and galvanized poles are much higher at $1,223, $2,059 and
$2,249 respectively, so the investment into these types of poles would never be recovered. Considering the
volatility of metals prices, there is a possibility that the cost of Cor-Ten and galvanized poles could drop to levels
that would make them realistic alternatives.

The following items can be found in the appendix at the end of this report:
Annual Cost Prediction Table
Labor Requirement Prediction Table
Equipment Requirement Prediction Table
Spares Requirement Prediction Table
Effects Prediction Table
Predicted Pole Replacements Table

ICNU_DR_113 Attachment J Page 8 of 21
9

Figure 7
Annual Cost Comparison Chart

Figure 8
Cumulative Comparison Chart

No Crossover
ICNU_DR_113 Attachment J Page 9 of 21
10

Figure 9
Financial Results Comparison Table

Figure 10
Cumulative Cost Comparison Chart

ICNU_DR_113 Attachment J Page 10 of 21
11

Recommendations
Based on the results of the analysis, Asset Management makes the
following recommendations.
1. Make contact with other utilities that have installed ductile
iron poles and get further feedback on the material and
determine if the material is suitable for our needs.
2. Begin to replace failed wood poles with ductile iron poles
on a limited basis to get a better understanding of their
installation and failure properties.
3. Begin to conduct wall thickness measurements on these
ductile iron poles at five year intervals so that additional
data can be gathered on life expectancy, which will give us
more accurate information to work with in the future.
4. Evaluate the installation procedure required for ductile iron
poles and determine if any additional training needs to be
implemented.
5. Begin to conduct wall thickness measurements on Avista’s
existing direct buried Cor-Ten and galvanized
distribution/transmission poles and establish the rate of
corrosion for these materials.
6. Continue to monitor the prices of Ductile Iron, Concrete,
Cor-Ten steel and galvanized steel poles so that if their
respective prices decrease in the future, additional
consideration could be given to them at that time.
Resource/Budget Effects – Alternative Material
Pole Installation/Inspection
Since the current cost of a ductile iron pole is 15% higher than a
comparable wood pole, an initial increase in the annual budget will
be required if the decision is made to begin installing this type of
pole. The annual effects on the budget are outlined in (Figure 12).
No additional installation resource requirements are anticipated. In
order to establish more accurate failure estimates on galvanized,
Cor-Ten and ductile iron poles, it is recommended that Avista begin
to inspect ten galvanized and ten Cor-Ten poles per year, at a cost
of $150 per pole, for a total cost of $3,000 per year. This acquisition
of data should be expected to last 20 or more years into the future.
At a minimum, the inspections should include recording the pole ID,
location, pole material, additional pole coatings, below ground line
wall thickness. The data from these inspections should be
communicated to the distribution engineering department and
archived so that a historical wall thickness record for each pole can
be constructed. The record will be used to calculate the rate of
corrosion and the estimated lifespan.
Figure 11
Ductile Iron Pole
ICNU_DR_113 Attachment J Page 11 of 21
12

Annual Cost Prediction Table

Figure 12
Annual Budget Effects
Appendix Items:
The following tables can be used to further compare the Base Case to Alternative #1, they are included in the
appendix located at the end of this report:
1. Labor Requirement Prediction Table - Figure 21
2. Equipment Requirement Prediction Table - Figure 22
3. Spares Requirement Prediction Table - Figure 23
4. Effects Prediction Table - Figure 24
5. Predicted Pole Replacements Table - Figure 25

ICNU_DR_113 Attachment J Page 12 of 21
13

Alternate Evaluation #1 – The Effect of Reduced Life Red Cedar Poles on the System
There is a perception within the industry that the poles that have been installed in the last 20 years are not
lasting as long as the poles that had been installed 40, 60 and 80 years ago. There are a couple of prevailing
theories about why this could be actually happening. The first is that the new poles are constructed from trees
that have grown faster and the rings in these trees are much less dense than their predecessors. The second
theory is that the process used to choose a pole from a selection of Western Red Cedar logs is less selective than
it was in the past. This theory would seem to have some merit, since some sizes of poles are becoming harder to
source and more expensive. To see what affect the reduced life of recently installed poles would have on the
system, this scenario was modeled and compared to the best alternative material pole case (Ductile Iron) to
investigate whether or not there would be economic advantages to alternative poles if one of the above
theories eventually proves to be true.

In order to model this scenario, a new Weibull curve was created that defined a more aggressive rate of failure
and this curve was applied to all poles that are 20 years old and newer. This modified wood pole model was then
compared to the Ductile Iron pole model from the data set discussed above. The curve shown in Figure 13 was
applied to all of the poles in the system that are 20 years old and newer. The curve shown in Figure 14 was
applied to all poles that are 21 years old and older.

Figure 13
Modified Cedar Pole Weibull Curve

ICNU_DR_113 Attachment J Page 13 of 21
14

Figure 14
Actual Cedar Pole Weibull Curve
Alternate Evaluation #1 – Results
The results of the evaluation indicate that if the recently installed wood poles are failing at a greater rate, then
there would be a greater advantage to converting the distribution system to poles made from a more durable
material such as ductile iron. With these assumptions the Internal Rate of Return shows an advantage to ductile
iron poles (Figure 15). The cumulative cost comparison chart shown in Figure 17 shows that if recently installed
wood poles are failing at a younger age then replacing failed wood poles with ductile iron ones would have
economic advantages eight years after beginning the program.

Figure 15
Financial Results Comparison Table, Alternate Evaluation #1
ICNU_DR_113 Attachment J Page 14 of 21
15

Figure 16
Annual Cost Comparison Alternate Evaluation #1

Figure 17
Cumulative Cost Comparison Alternate Evaluation #1
Crossover
at year 8
ICNU_DR_113 Attachment J Page 15 of 21
16

Alternate Evaluation #2 – Ductile Iron Poles and Cedar Poles are comparable in price
In the future, it is very likely that wood poles of certain sizes become scarce enough that the cost increases or
that the cost of ductile iron poles is reduced. Asset Management conducted another alternative analysis that
evaluated the potential future case. To model this scenario, the cost of the ductile iron pole was reduced to
$607 so that the ratio of wood pole cost to ductile iron pole cost was normalized at $607/$607 (1).
Alternate Evaluation #2 – Results
As expected, the results of this analysis indicate that the cost of each alternative is equivalent for the first few
years until the increased life-time of the ductile iron pole begins to become an advantage and then after
approximately 40 years the additional lifespan of the ductile iron poles begins to become an advantage (Figure
18). It is apparent in Figure 19 that the long term cumulative cost advantages are very small. Further economic
comparisons are shown in Figure 20.

Figure 18
Annual Cost Comparison Alternate Evaluation #2
ICNU_DR_113 Attachment J Page 16 of 21
17

Figure 19
Cumulative Cost Comparison Alternate Evaluation #2

Figure 20
Financial Results Comparison Table, Alternate Evaluation #2

ICNU_DR_113 Attachment J Page 17 of 21
18

Appendix - Labor Requirement Prediction Table

Figure 21
Labor Prediction Comparison

ICNU_DR_113 Attachment J Page 18 of 21
19

Appendix - Equipment Requirement Prediction Table

Figure 22
Equipment Prediction Comparison

ICNU_DR_113 Attachment J Page 19 of 21
20

Appendix - Spares Requirement Prediction Table

Figure 23
Spares Prediction Comparison

ICNU_DR_113 Attachment J Page 20 of 21
21

Appendix - Effects Prediction Table

Figure 24
Effects Prediction Comparison
Appendix - Predicted Pole Replacements Table

Figure 25
Predicted Pole Replacement Quantities
ICNU_DR_113 Attachment J Page 21 of 21
Kris Busko 1/17/12

1

Service Regulators Discussion
Introduction
The goal of this discussion is to identify a system of facility management for residential and small
commercial service regulators. The scope includes an analysis of small diaphragm regulators used at
metering sites consuming less than 1,000 cubic feet per hour (CFH). Currently, Avista has no formal plan
or system for replacing these regulators in advance of their end of life, but recognizes that large
quantities may eventually begin to fail which could have a negative impact on several fronts, from
customer safety to O&M budget planning.
It is important to recognize that the use of the phrase “failure” regarding service regulators is a
misnomer in many cases. When service regulators weep through their relief ports, causing a trouble call
visit from gas service personnel, the regulators are actually responding in a fail-safe mode. The number
one cause of relief venting is from debris becoming lodged in the regulator orifice, which, when there is
no downstream demand for gas, prevents the regulator from “locking up” to stop gas flow. Venting
through a relief port prevents gas from continuing to be fed downstream to customer-owned piping and
appliances that are not designed to handle such pressures. It is far less common that a true failure of
some internal component of a regulator occurs, but for convenience in language, and since a trouble call
is required to clear the problem that has caused the regulator to be in fail-safe mode, this phrase is used
throughout this discussion. Since the cost of these regulators is relatively small and many are not easily
field serviceable, they are generally replaced with new units at the time of the trouble call so frequently
no distinction is made between a true breakdown of the regulator and a blockage of the orifice.
Complicating this study is that Avista has not historically collected failure mode data for regulators.
Additionally, installation date details are largely unknown, so the precise location of any particular brand
or vintage of these small regulators is not available for study. Despite these disadvantages, there is still
valuable information that can be gathered and used as a starting point to tackle this important issue.
Figure 1 illustrates a typical small regulator of the type included in this study, and Figure 2 illustrates the
types of regulators used historically in Avista’s system with the overlap that occurs for any given era.
Figure 1. Typical residential and small commercial natural gas regulator, with a ¾” IPS connection. Such
regulators are typically used in intermediate and low pressure applications and represent the vast
majority of regulators used in Avista’s service territory today.

ICNU_DR_113 Attachment K Page 1 of 11
Kris Busko 1/17/12

2

Figure 2. Brands of regulators used in Avista’s history, by era. There are overlapping eras of regulator
brands, with 4-5 types installed during several time periods. In the background is a profile of the number
of services installed over time which indicates the vast quantities of particular brands used for those
services. The identification of specific failures and regulator brand locations is currently not tracked.

Era Type
1950’s to early 1960’s

0
5000
10000
15000
20000
25000
19
5
6
19
6
0
19
6
2
19
6
6
19
7
0
19
7
4
19
7
6
19
8
0
19
8
4
19
8
8
19
9
0
19
9
4
19
9
8
20
0
2
20
0
4
20
0
8
Se
r
v
i
c
e
s

I
n
s
t
a
l
l
e
d
Regulator installation histories
Fisher 733-C Fisher S102 Fisher S252
Rockwell/Sensus 043 Rockwell/Sensus 143 Elster/American 1213-B
Itron/Actaris B42 Elster/American 1213-B2 Elster/American 1813-C
ICNU_DR_113 Attachment K Page 2 of 11
Kris Busko 1/17/12

3

Historical Risks and Recommendations
Over time, Avista has developed standards around regulators, especially regarding their capacity for
relieving gas. As Avista has moved toward a standardized, 60 psig maximum allowable operating
pressure (MAOP) for all service territories, some regulators require replacement due to their inability to
relieve overpressure conditions. In response to the identification of several regulators that fell into this
under-capacity category, the Gas Meter Shop issued a memo in 2004, directed at field personnel,
instructing them to take the following steps for these particular regulators when encountered:
 Fisher S-252 with 3/16” orifice: remove from service
 Rockwell 043 with 3/16” orifice: remove from service
 Fisher 733-C, any orifice: remove from service
 Rockwell 143: 3/16” orifice required for loads up to 1.5MM
BTUs, and 1/4” orifice combined with a Fisher 289L relief for
loads over 1.5MM BTUs
 Rockwell 243-12 (1/2” orifice): remove, or add Fisher 289L or
289H relief valve separately depending on delivery pressure

As stated previously, the exact location of any particular brand or orifice size is unknown, so this memo
is as pertinent today as it was those years ago. These brands still exist in service and the recommended
actions are just as necessary as they were when the memo was issued. A field-worn copy of this memo
(Attachment 1) was recently obtained from a serviceman and not only were the recommendations
above included, but the serviceman also made several other hand-written notes about other
requirements that had been developed over time as well as minimum requirements for certain
applications. Of major concern is that none of this information is included in the Gas Standards Manual
and there is no guarantee that other service personnel have retained the knowledge or put the
recommendations into action, or that new gas personnel have a method to become familiar with its
contents.
Safety Risks and Inconvenience to the Public
Avista’s Distribution Integrity Management Program (DIMP) has identified that service regulator failure
is a relatively high-frequency, low-consequence event, with rare exception. Those regulators noted in
the 2004 memo that have inadequate relief capacity present a risk of over-pressurizing downstream
equipment, though the likely occurrence is small since few are believed to remain in service. However,
some safety risk is noted within this Asset Management analysis for such concerns. For most failures of
properly sized and vented regulators, since they are installed above ground, any relieving gas can vent
freely to the atmosphere and is unlikely to be trapped within structures. Sites where meters are
enclosed within buildings must have their relief ports piped to atmosphere, and as part of Avista’s
continuing surveillance, all meter sites are patrolled at least once every 3 years to assure that customers
have not over-built their meters with structures that could entrap gas.
ICNU_DR_113 Attachment K Page 3 of 11
Kris Busko 1/17/12

4

When gas vents, customers respond by calling the utility to report problems for the vast number of
instances. Indeed, of the failure events used in this Asset Management study, 95% were reported by the
public as area odors. The distinct smell of venting gas, combined with the presence of gas equipment
visible in the environment, is a clear indication to the public that something is out of order. In contrast,
underground piping leaks of Aldyl A were reported only 45% of the time by the public during that same
time period, and underground facilities can permit gas to migrate through the soils and possibly become
trapped within structures nearby. Though the frequency of venting regulators is far higher than the
frequency of underground piping leaks, the likelihood that hazardous conditions will result from freely
venting is far less than for the underground piping.
Obviously, safety elements cannot be dismissed, but often the greatest risk is found when high
occupancy structures are evacuated after the odor of gas is detected from a weeping regulator. Fairly
often it occurs that buildings are evacuated when gas drifts in through doors and windows, and in
situations where large groups of difficult-to-egress people are affected (such as schools), the impact is
very negative. Therefore, the effects of this potential public inconvenience are also included in the
Asset Management analysis.
Opportunities for Replacement
Other than the inconsistent application of the actions recommended in the 2004 memo, Avista does not
have a program for regulator replacements; this is precisely why this analysis is needed. There is
currently no formal process by which service regulators are replaced at regular intervals, either through
a dedicated site visit or simultaneously with other types of meter maintenance. Lacking mean-time-to-
failure (MTTF) knowledge about any particular brand of regulator, and even more challenging, lacking
knowledge of precisely where any certain regulator brands are installed in the system, no organized
replacement program is viable at the current state. Fortunately, there has not been a trend of failures
that would lead Avista to replace large quantities of specific types at this time. An analysis of a
dedicated regulator replacement plans (those not linked to any type of meter visit for other
maintenance) is included as part of this study to measure the expense associated with that program and
confirm any advantages or disadvantages that exist for a dedicated approach.
A more likely outcome is the identification of what opportunities already exist for meter site visits and in
which of those visits it makes the best sense to replace the regulator. Such opportunities include visits
for planned meter changes (PMC) where certain quantities of random meters are tested for accuracy
each year, the annual removal of those meter families that have failed prior accuracy testing, (“failed
families”), atmospheric corrosion and continuing surveillance patrols, and other service call and trouble
call visits. If more information is gathered in the future about failures of particular regulator brands and
their locations there could be dedicated replacement programs that make sense, but at this time that is
not feasible. Ultimately, any regulator replacement work recommended at this time will be performed
at the same time as other necessary work at the meters.

ICNU_DR_113 Attachment K Page 4 of 11
Kris Busko 1/17/12

5

Available Failure Data
Through the development of the Distribution Integrity Management Program (DIMP) in 2011, over
17,000 leaks were analyzed, covering every type of hazard from dig-ins to material failures occurring
between 2006 through 2010. One standardized category of leaks is “equipment failure,” of which more
than 2,000 leaks were included. Of these 2,000 equipment failures, 925 small regulator failure events
qualified for analysis within this study since they were on 1,000 CFH- and smaller metering applications.
Most, (84%), of those events were on the smallest domestic meters up to 250 CFH and the balance were
on 425 CFH through 1,000 CFH applications.
Unfortunately, (though typically), only 43 of the 925 events included any detailed regulator brand
information. The following information was included in the failure reports:
Type noted in leak report Quantity

Though certain brands have an apparently larger representation in the table above, it shouldn’t be
assumed that those regulator types fail more often than others. The Rockwell 143, for example, is the
most common regulator used in Avista’s history (see again Figure 2), and was installed over a period of
50 years, so the likelihood that it will appear more often in failure counts is not unexpected.
Unfortunately, Avista is unable to identify the populations and ages of any particular regulator family
since this information has not been tracked formally at either the installation point or retirement point
for these devices. When regulators are updated over time for any reason the information about what
was removed and what was installed is not captured. This makes analysis of any particular brand’s
failure trends impossible at this time. As Avista develops a new Work Management System over the
next few years this information could be gathered and a more complete analysis can then be performed.
Analysis of Failure Data
There was an unexpected revelation found immediately upon analyzing the 925 failures gathered by
DIMP, in that 34% of the 925 events occurred by the 11th year of service, far earlier than any end of life
expectancy for these durable items. In studying the comments on each trouble order, this “infant
ICNU_DR_113 Attachment K Page 5 of 11
Kris Busko 1/17/12

6

mortality” trend is clearly linked to debris in the orifice. The resolution to the events was most often
identified as a replacement of the regulator, while some were cleaned in the field and reset. The cost
per regulator is just $14.25 so if the replacement is simple it is often the preferred and logical choice by
field personnel. By the same token, regulators of this size are generally not rehabilitated for future
service since the expense to disassemble and refit them is greater than the cost of a new item. Figure 3
shows a simple Excel chart of failures, indicating that infant mortality is a significant occurrence.
Figure 3. An Excel chart of small service regulator failures from 2006-2010, with a trend line included.
Infant mortality is a strong component, in that 34% of the total failures occurred by the 11th year of use.

Availability Workbench Modeling
Availability Workbench software has the capacity to chart failures and make predictions about the
lifecycle and future behavior of failures for components through Weibull curve generation; this is not
just a charting of previous failures as shown in Excel, but it is a curve that represents what can be
expected in the future for these devices. As noted previously, the specific age of the failed regulators is
unknown, so the only option that could be used to identify installation age was to use the service piping
age. While it is possible that some regulators have been replaced since the service pipe was installed,
given that Avista has no formal program of regulator upgrades it is most likely that the instance of
replacement is very small. Using the best age data available, the 925 failure events were modeled, and
a clearer profile of the expected lifecycle for regulators became apparent. Figure 4 shows the Weibull
profile for service regulators, with each region identified. Further discussion in this report includes what
actions may be taken to address the regulator lifecycle behaviors represented by the time frames noted
within the curves.
y = 34.858e-0.033x
0
5
10
15
20
25
30
35
40
45
0 5 10 15 20 25 30 35 40 45 50
Co
u
n
t

o
f

F
a
i
l
u
r
e
s
Years Since Installation
Service Regulator Failures
ICNU_DR_113 Attachment K Page 6 of 11
Kris Busko 1/17/12

7

Figure 4. Weibull failure profile of service regulators, indicating three regions of lifecycle behaviors.
Infant mortality is a very strong component. If the regulator survives this period it is subject to random
failures until about year 30 where the failure curve takes on a classic, wear-out beta shape.

Infant Failures, 0-10 Years of Age
Since there is such a strong component of infant mortality, this seems to be a first-order-of-business
failure mode that could be addressed. Unlike many manufactured components that can suffer failures
during initial use (“burn-in failures”), regulators are known to be functioning when they are set. Each
regulator is given a flow-and-lock up test when it is installed, and is known to be operating free of debris
at the time of its original commissioning. Representing the most difficult failure mode to resolve, this
mode of failure is also not something that can be managed through other ‘opportunity work’ such as a
PMC--there are no accuracy tests for new meters until they at least 10 years old, beyond when the data
indicates an infant failure would most likely have occurred. Additionally, the failure mode is not a
problem with the regulator; it is due to debris in the service piping itself. In this modern era of federally-
required excess flow valve (EFV) installations, it has become increasingly more difficult to purge the
newly installed service line due to the limitations of the velocity of air or gas can be blown through the
pipe for clean-out purposes without tripping the EFV. Finally, it is possible that doing a bypass to change
the regulator at the time of a PMC could result in a disturbing of any sediment in the riser as the meter
site is re-commissioned and purged of air, possibly resulting in a new cycle of infant mortality for those
services which may already be prone to releasing debris into the riser.
Early in this study process Asset Management suggested that a filter could be included in the riser,
upstream of the regulator, to catch any small particles that could clog the orifice. Gas Engineering
looked into this and found that while a few filters have been developed for industry, they have been
Infant
Mortality
Random Failures Wear Out
5 Yrs 16 Yrs 32 Yrs 43 Yrs
ICNU_DR_113 Attachment K Page 7 of 11
Kris Busko 1/17/12

8

found to be more trouble than they have proven to be worth. They have become a source of leaks in
the riser and create a weak spot on the riser at their threaded connection points, resulting in a point
that can break relatively easily and cause blowing gas. The conclusion from Gas Engineering was that a
filter would add more harm than good and other alternatives should be sought.
The remaining solution is to develop an effective purge system for new services despite the presence of
an EFV. In response to this recommendation, Gas Engineering is collaborating with Operations in the
2012 construction season to test a method of regulated flow that may prove beneficial.
Random Failures, 10-25 Years of Age
If regulators survive their first 10 years of service, the likelihood that debris will cause a failure drops
dramatically. From year 10 to 25 of regulator life, there is a near-flat (only a minor increase) profile of
failures. For random failures, which can’t be predicted or linked to age, the only viable approach is to
repair as they are found. Since they are random, they are unpredictable and not preventable for these
devices.
Wear Out Failures, 25+ Years of Age
Per Gas Engineering and Meter Shop historical data, meters begin to lose accuracy at approximately 25-
30 years of age. Their failure is a function of a lack of accuracy in metering natural gas and does not
result in leaking or venting gas. The discovery of their inaccuracy is via the PMC program, in that when a
certain percentage of meters of a specific brand, install year, and state location (“families”), are found to
be inaccurate, they are scheduled for replacement in a following season. When families are discovered
as failing, plans are made to remove all meters within that family in a relatively short time frame.
Coincidentally, the final phase of service regulator failure modes, the wear out period, happens to
correspond with the typical accuracy failure of meters. Therefore is makes logical sense to replace
service regulators any time a failed meter family is removed, considering that the regulator is likely to be
at least as old as the meter it serves. As better location data is collected over time, this may not be the
appropriate response, but given that currently we do not have detailed information on regulator age
and location, this is a viable approach.
Limitations of Suggested Replacement Plans
Failed meter families net 3,000-5,000 meters per year pulled from service. If new regulators are
installed with each of these, it will take 60-100 years to replace every regulator on a planned basis.
However, there are few alternatives given the current state of knowledge of our system.
If Avista were to additionally replace regulators during the random PMC visits, there would be another
6,000 updates available. Unfortunately, this plan would mean that many relatively “young” regulators
are removed while there is still life available, and even at this rate it would still take 27-33 years to
replace regulators, and no guarantee that the “right” ones are being replaced. Said another way, Avista
could undertake a plan to replace regulators at all PMC and failed meter family upgrade visits, but still
there would be random failures outside of that planned replacement program. And off course, neither
ICNU_DR_113 Attachment K Page 8 of 11
Kris Busko 1/17/12

9

PMC nor failed family visits will solve the infant mortality problem since those meters are not eligible for
either opportunity visit.
Return on Investment Analysis for Dedicated Replacement Program
A comparison was made to determine the various return-on-investment (ROI) advantages of any
particular approach compared to others. The results are compiled below.
Case Studied Internal Rate of Return Levelized Gross Margin Reqmnt

When it comes to a dedicated program not associated with other maintenance, allowing regulators to
fail is by far the best return (essentially, the current state of facility management). In allowing the model
to optimize, the program indicates that the next ideal time to replace regulators under a planned basis
would be when they are 57 years old. Unfortunately, since several regulator types were installed for
many, many years, it can be difficult to identify the difference between a 1975 regulator of a certain
brand vs. a 1995 regulator of the same brand, so finding exactly which regulators are 57 years old is not
feasible. There are relatively few regulators from 1959 simply because there were far fewer services in
the system at that time. To seek out just the regulators in a dedicated program simply is not viable.
Therefore, it is exceedingly difficult to set up any planned replacement based on age alone.
A “do nothing” approach seems counterintuitive, and indeed, there is an operational criticality that is
not effectively included in the model. In other words, if large quantities (many thousands) of service
regulators begin to fail during any given year, there is a tipping point in which the resource burden
overcomes the desire to achieve maximum useful regulator life. The model does not consider that
Avista has a limited number of personnel dedicated to these types of service calls, or that these service
calls must be dispatched and responded to on an urgent (no more than 2 hours from notification)
timeframe. Therefore, the idea of “do nothing” has a higher risk than what is reflected here. Essentially
the conclusion that should be drawn is that it is not necessarily harmful to replace the oldest regulators
when other opportunities align with increasing regulator age, but any specialized, dedicated effort to
pull regulators before they achieve significant service life has a negative impact. If the “do nothing” and
57 year approaches can be reasonably set aside, it is appropriate to replace regulators when they have
provided 25 years of service life.
Summary and Recommendations
Ultimately, this analysis has yielded that given the current state of knowledge for service regulators, it is
not feasible to attempt to replace certain types or ages in a dedicated program that is not associated
ICNU_DR_113 Attachment K Page 9 of 11
Kris Busko 1/17/12

10

with other types of meter maintenance. Frankly, we simply do not know where they are. However, it
makes logical sense to replace regulators at the same time a failed meter family replacement is
occurring; these regulators are the most likely to be at least 25 years old, and the effort to replace them
is negligible since the meter assemblies are being significantly dismantled at the time of the visit. This is
a viable method to upgrade facilities over time at the least expense possible, at the point that they will
have likely offered extended service lifetimes.
To make the most impact in reducing failures overall, the development of an effective service line purge
procedure is critical. This effort alone has the potential to reduce the number of service regulator
failures by 30% from current levels. As noted, there is active effort to develop and test a purge
procedure in a collaborative effort between Gas Engineering and Operations. By decreasing these infant
failures, there will be a continued greater availability of resources to manage the increasing pool of
aging regulators. In the future that valuable service personnel time will become more and more
important to recapture and redirect toward servicing the aging regulator population.
Additionally, it is recommended that the “2004 memo” (Attachment 1) content should be reviewed and
its information and any updates should be included in the Gas Standards manual for wide distribution to
all personnel engaged in meter site management activities.
Finally, and as a recurring theme of this report, the lack of knowledge of regulator location, brand, and
age is currently a significant obstacle to implementing efficient regulator management strategies over
the long term. Asset Management therefore recommends that during other opportunity work visits,
such as planned meter change outs, atmospheric corrosion patrols, trouble or service calls, and possibly
even leak survey visits, a meter site inventory should be taken. The technology to capture meter and
regulator data during a visit is becoming far more commonplace (such as hand-held data capture units)
and it does seem that it is feasible to add this activity to at least one of the other opportunity visits. The
most promising visit is possibly the atmospheric corrosion patrol activity—Avista currently visits every
meter site, every three years, for each state. Therefore it is feasible that within three short years Avista
will have been able to acquire data for every single service regulator in its natural gas territory. With the
increased use of bar coding, these sites could possibly be tagged for rapid future confirmation of site
data to keep this information fresh and readily available, at a reduced ongoing cost. Finally, as Avista
develops a replacement work management system it is vital that this kind of site inventory detail is
included within that program, and this has been recommended to that project team.

ICNU_DR_113 Attachment K Page 10 of 11

Attachment 1
2004 Meter Shop Memo

ICNU_DR_113 Attachment K Page 11 of 11

Avista
Study of Aldyl-A Mainline Pipe and Bending
Stress Point Leaks

ISSUE DATE: July 2013
DOCUMENT NO: 356-006 Revision 1

Report Prepared By:
Scott Gloyna

Report Approved for Issue By:
Jason Ballentine

ICNU_DR_113 Attachment L Page 1 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
2 Document No: 356-006 Issue Date: July 2013

Executive Summary
The scope of this study was to develop a failure distribution to describe the likelihood of leaks
occurring on the Aldyl-A pipe installed by Avista for natural gas distribution and to evaluate a
number of replacement scenarios. This study and the models developed were used to evaluate if
a replacement program is appropriate what the timeframe of replacement should be.
The study reviewed and utilized the available historical data on Aldyl-A pipe collected by Avista,
including leak history, installation year, replacement history, location and length to develop
predictive models for the failure rates over the next 75 years. To accurately model the failure
mechanisms and match the scope for current replacement programs, the pipe locations were split
between mainline pipe and locations where the Aldyl-A pipe is tied into steel mains.
During this review the soil type that Aldyl-A mainline pipe was installed in was identified and
confirmed to be a strong contributing factor to the frequency of leaks. Specifically rocky soil was
identified as the soil type most likely to have Aldyl-A mainline pipe leaks. Utilizing soil type
specific Weibull distributions, the number of leaks predicted when no proactive replacements are
conducted over the next 75 years on Aldyl-A mainline pipe is 26,888.69 and the cumulative
replacement costs is $7 billion.
Scenarios where all of the Aldyl-A mainline pipe is proactively replaced in 15, 20 and 25 years
were also analyzed. Of the replacement scenarios the 25 year replacement program was
determined to be the most cost effective as can be seen in the table below. According to Table 1
the baseline scenario is more cost effective, but it should be considered that current cost
forecasts are based on cost of replacement and effects per leak. The study did not incorporated
safety thresholds which should be considered before the replacement scenario is selected.
Results of Aldyl-A Mainline Pipe Leak and Replacement Study
Scenario Leaks
over 75
years
IRR Levelized Gr.
Mar.
Requirement*
Lev
ROE*
NPV
equity*
Payback
levelized
Payback
forecasted
flows
EPS
Baseline with
effects 26,888.69 9.21% $16,417 $0 $0 10.15 13.92 $0.000
20 Year
Replacement
with effects
228.55 6.04% $23,229 $6,513 $93,490 20.31 32.59 $1.675
15 Year
Replacement
with effects
355.65 5.85% $25,120 $7,174 $102,980 21.97 33.41 $1.845
25 Year
Replacement
with effects
519.94 6.21% $21,664 $5,933 $85,175 18.94 31.84 $1.526
ICNU_DR_113 Attachment L Page 2 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
3 Document No: 356-006 Issue Date: July 2013

*In Thousands
The Bending Stress point failures were also modeled and it was determined that without proactive
replacement, 4,980.43 leaks at a cost of $535 million would occur over the next 75 years. A 5
year replacement scenario that was compared to the baseline and was found that replacing the
bending stress locations would greatly reduce the number of leaks and the lifetime costs
according to the Revenue Requirement calculator as can be seen in below.

Results of Aldyl-A Bending Stress Point Leak and Replacement Study
Scenario Leaks
over 75
years
IRR* Levelized Gr.
Mar.
Requirement*
Lev
ROE*
NPV
equity*
Baseline with
effects 4,980.43 4.22% $2,034 $0 $0
5 Year
Replacement
with effects
18.23 8.16% $1,430 $411 $5,909
*In Thousands
ICNU_DR_113 Attachment L Page 3 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
4 Document No: 356-006 Issue Date: July 2013

Contents
1 INTRODUCTION .................................................................................................. 6
2 METHOD ............................................................................................................. 6
2.1 Mainline Pipe ........................................................................................................ 6
2.2 Bending Stress Points .......................................................................................... 7
3 ASSUMPTIONS ................................................................................................... 8
4 MAINLINE ALDYL-A PIPE .................................................................................. 9
4.1 Analysis ................................................................................................................ 9
4.1.1 Maintenance Cost Forecast .............................................................................................. 11
4.1.2 Impact of Soil Type ............................................................................................................ 13
4.2 Replacement Scenarios ..................................................................................... 15
4.2.1 Scenario A - 20 Year Replacement Program .................................................................... 15
4.2.2 Scenario B – 15 Year Replacement Program ................................................................... 16
4.2.3 Scenario C – 25 Year Replacement Program ................................................................... 18
4.2.4 Scenario Comparison ........................................................................................................ 18
5 ALDYL-A BENDING STRESS POINTS ............................................................. 22
5.1.1 Model Validation ................................................................................................................ 22
5.1.2 Maintenance Cost Forecast .............................................................................................. 26
5.1 Replacement Scenarios ..................................................................................... 28
5.1.1 Scenario A – 5 Year Replacement Program ..................................................................... 28
6 CONCLUSION ................................................................................................... 30
7 FUTURE DATA COLLECTION .......................................................................... 31
APPENDIX A – MAINLINE ALDYL-A PIPE ANNUAL EXPENSES PER YEAR BASED ON
AVISTA REVENUE REPLACEMENT CALCULATOR ...................................... 32
APPENDIX B – BENDING STRESS POINTS ANNUAL EXPENSES PER YEAR BASED ON
AVISTA REVENUE REQUIREMENT CALCULATOR ....................................... 35
APPENDIX C – Aldyl-A Mainline Risk Based Replacement Schedule………...…Attached

ICNU_DR_113 Attachment L Page 4 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
5 Document No: 356-006 Issue Date: July 2013

Disclaimer

© 2013 ARMS Reliability LLC
THIS PUBLICATION IS PROTECTED BY COPYRIGHT LAW AND UNLESS OTHERWISE SPECIFIED IS FOR
YOUR INTERNAL BUSINESS USE ONLY. NO PART OF THIS PUBLICATION MAY BE REPRODUCED OR
DISTRIBUTED OUTSIDE BY ANY PROCESS, ELECTRONIC OR OTHERWISE, WITHOUT THE SPECIFIC
WRITTEN PERMISSION OF ARMS RELIABILITY

Although every effort has been made by ARMS Reliability Engineers LLC to ensure the
accuracy and completeness of this document and reported results, no warranty, express
or implied is made by ARMS Reliability Engineers LLC as to the accuracy or completeness
of the documentation or reported results. Any decisions made as a result of the
information in this report are at the sole discretion of the reader

ICNU_DR_113 Attachment L Page 5 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
6 Document No: 356-006 Issue Date: July 2013

1 INTRODUCTION
This report has been developed to provide the results of an analysis carried out on the Aldyl-A
pipe installed by Avista for natural gas distribution. The scope of the study was to develop a
failure distribution to describe the likelihood of leaks occurring based on the installation year of
the pipe, the soil type the pipe was installed in, and the replacement/leak history. To accurately
model the failure mechanisms and match the scope for current replacement programs, the pipe
locations were split between mainline pipe and locations where the Aldyl-A pipe is tied into steel
mains (Bending Stress Points). Based on the failure distributions, a number of replacement
scenarios were evaluated.
2 METHOD
During the first phase of this study all available historical data on the Aldyl-A pipe was collected.
This included GIS segment, installation year, soil type, leak history, replacement history, location,
and length. The various sources of this data were combined in Excel and used to calculate the
following:
 The age of the pipe when each of the leaks occurred
 The age of the pipe at capital replacement
 The length of pipe replaced
 The age of the pipe not yet replaced
 The length of the pipe not yet replaced
2.1 Mainline Pipe
For the mainline Aldyl-A pipe the data was separated by GIS locations and imported into the
Availability Workbench software where Weibull distributions could be developed. Each location
had an associated age, soil type, and length. The Weibull distribution was selected, as it is able
to provide risk predictions with small samples and can describe infant mortality, chance failure,
and wear-out failure behaviors. For two soil types, Control Density Fill (CDF) and
Concrete/Grout, a Weibayes distribution had to be used because the numbers of failure events
was insufficient for a standard Weibull analysis. For these two soil types the shape factor was set
to four to reflect a wear-out failure behavior.
Four models were run for the Mainline Aldyl-A replacement, a baseline scenario with no proactive
pipe replacement followed by models where all of the Aldyl-A pipe is replaced over 15, 20 and 25
ICNU_DR_113 Attachment L Page 6 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
7 Document No: 356-006 Issue Date: July 2013

year timeframes. In the latter three scenarios the replacements were evenly distributed and
prioritized per the risk rankings provided in Appendix C
2.2 Bending Stress Points
Each location where Aldyl-A Pipe is tied into steel mains has been identified as points where
bending stresses are a concern. These points have a history of leaks associated with the stresses
induced due to the relative movement of the steel mains and the connected plastic pipe.
For the Bending Stress models the locations were grouped by year installed and imported into the
Availability Workbench software where Weibull distributions could be developed and assigned.
Two models were run for the Bending Stress Aldyl-A Replacement, a baseline scenario where the
pipe was not proactively replaced and a model where all at risk connections are replaced over a
five year span with 20% of the bending stress points being replaced in each year.

ICNU_DR_113 Attachment L Page 7 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
8 Document No: 356-006 Issue Date: July 2013

3 ASSUMPTIONS
The assumptions made during the study were as follows:
1. All models are simulated over a 75 year lifetime
2. A three foot section of pipe is replaced when a leak occurs.
3. Only 1.25” OD and greater pipe was considered
4. Soil Types of 0, unknown, or blank was assumed of rocky type
5. All Aldyl-A pipe installed between 1984 and 1987 was manufactured before 1984
6. Pipe of unknown install year was installed in 1970
7. All replacements that were done in 2011 and 2012 were in rocky soil
8. Call out time for corrective replacements includes 1.75 hours of travel time
9. All maintenance costs are entered as included as equipment
10. The PF interval for leak inspections is zero
11. The shape factor, Beta of 4 was used for Concrete/Grout and CDF Soil types
12. The characteristic life, Eta of 100 years (876,000) was used for the bending stress failures
13. Each Exposed Pipe Report for the Davenport and Talent replacement projects reports on
an equal length of pipe.
14. Baseline models do not consider any planned capital replacement.
15. Planned replacement of Aldyl-A Mainline pipe costs $243.42 per three feet in Washington
and Idaho and $183.15 per three feet in Oregon.
16. Unplanned replacement of Aldyl-A Mainline pipe costs $3,346.26 per three foot section.
17. Planned replacement of Aldyl-A Bending Stress Points costs $1,709.84 per location.
18. Unplanned replacement of Aldyl-A Bending Stress Points costs $2,160.00 per location.
19. Consequences for a Catastrophic Event, Injury with lost time and injury without lost time
are applied per Avista standard practice.
20. A different type of pipe is used to replace failed Aldyl-A pipe and as such a second failure
of the same length cannot occur in the lifetime.
21. Cost escalations are 2.3% per year.
22. Effects escalation is 10% per year.
23. Safety thresholds not incorporated into study.

ICNU_DR_113 Attachment L Page 8 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
9 Document No: 356-006 Issue Date: July 2013

4 MAINLINE ALDYL-A PIPE
4.1 Analysis
As an example, the failure rate curve based on the Weibull distribution developed for Aldyl-A
Mainline pipe installed in rocky soil is shown in Figure 1. This curve has the following
parameters:
η = 1,944,000 hours or 221 years (63.2% of the installed pipe will generate a leak
prior to reaching this age)
β = 4.364 (indicating a predictable end of life)

Figure 1 –Failure rate curve for Aldyl-A Mainline pipe installed in rocky soil.

Using the distribution shown in Figure 1, along with the distributions generated for the other soil
types identified in the study and knowing the length of Aldyl-A pipe installed in each soil type that
Rocky Failure Rate
0 37668 75336 1.13E+05 1.5067E+05 1.8834E+05 2.2601E+05 2.6368E+05 3.0134E+05 3.3901E+05 3.7668E+05
Time
0
8.9864E-10
1.7973E-09
2.6959E-09
3.5946E-09
4.4932E-09
5.3918E-09
6.2905E-09
7.1891E-09
8.0878E-09
8.9864E-09
Fa
i
l
u
r
e

R
a
t
e
Regionalised rate
Distribution rate
P0: 0%
B20: 1378483.86
B15: 1281905.53
B10: 1160724.65
e: 3.65521766E-05
r: 0.994087485
g: 0
b: 4.364
h: 1944000
Median rank
2-parameterWeibull
ICNU_DR_113 Attachment L Page 9 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
10 Document No: 356-006 Issue Date: July 2013

is yet to be replaced, the expected number of leaks in Aldyl-A was calculated over a ten year
period. The predicted number of leaks on Aldyl-A pipe for the next 10 years is shown in Figure 2.

Figure 2 – Predicted number of leaks per year in Aldyl-A mainline pipe for next 10 years.
Note: The prediction shown above in Figure 2 and the following Figures 3 through 7 assume that
repairs are only carried out when a leak occurs. The effect of capital replacement on this profile
is not considered as part of the baseline.
The frequency of leaks for the next 10 years ranges from 16 to 66 and the average number of
leaks per year is 36. The uneven increase in leak frequency is most likely due to both pipe of
different ages failing and the actual pipe lengths considered.
As the pipe continues to age the number of leaks is predicted to continue to increase in the
baseline scenario. This can be seen in the 75 year leak prediction for Aldyl-A mainline pipe in
Figure 3. The model predicts that the leaks will increase from an average of 36.07 leaks per year
over the next 10 years to an average of 358.52 leaks per year over a 75 year time period.
0
10
20
30
40
50
60
70
1 2 3 4 5 6 7 8 9 10
Le
a
k
s

p
e
r

Y
e
a
r

Baseline Aldyl-A Main Line pipe leaks for next 10 years
ICNU_DR_113 Attachment L Page 10 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
11 Document No: 356-006 Issue Date: July 2013

Figure 3 – Predicted number of leaks per year in Aldyl-A mainline pipe for the next 75 years.
4.1.1 Maintenance Cost Forecast
By considering all of the Aldyl-A mainline pipe installed which has not been replaced, a financial
forecast can be made based on the number of leaks expected. If an unplanned replacement
costs $3,346 is applied to repair each leak, the maintenance budget dedicated to leak repairs can
also be determined. The baseline maintenance cost forecast is provided in more detail in the
following sections of this report.
The total costs, which includes the maintenance costs and effects, is shown in Figure 4 and
Appendix A
0
200
400
600
800
1000
1200
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 73 75
Le
a
k
s

p
e
r

Y
e
a
r

Year
Baseline Aldyl-A Main Line pipe leaks for next 75 years
ICNU_DR_113 Attachment L Page 11 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
12 Document No: 356-006 Issue Date: July 2013

Figure 4 –Forecasted unplanned total costs of leaks on Aldyl-A mainline pipe for next 75 years.

$
$50
$100
$150
$200
$250
$300
$350
$400
$450
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 73 75
Co
s
t

(
M
i
l
l
i
o
n
s
)

Year
Aldyl-A Mainline Unplanned Total Cost
75 Year Forecast
ICNU_DR_113 Attachment L Page 12 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
13 Document No: 356-006 Issue Date: July 2013

4.1.2 Impact of Soil Type
To best determine which soil types have the greatest impact on likelihood of leaks, the leak
contribution of each soil type towards the total needs to be examined. This contribution is based
on the number of leaks that have occurred, the soil type in which the leaks occurred, and the
length of pipe that has not been replaced in each soil type. Figure 6 shows the contribution of
leaks in the four most common soil types adjusted to show leaks over the next 20 years per 100
miles of pipe installed.

Figure 5 – Contribution of Aldyl-A mainline leaks occurring in four most common soil types per 100
miles of pipe for the next 20 years

1
Rocky 286.12
Sand 106.57
Clay/Bentonite 64.04
Loam 117.26
0.00
50.00
100.00
150.00
200.00
250.00
300.00
350.00
Le
a
k
s

p
e
r

1
0
0

m
i
l
e
s

Leaks per 100 miles of Aldyl-A pipe
20 Year Forecast
ICNU_DR_113 Attachment L Page 13 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
14 Document No: 356-006 Issue Date: July 2013

Based upon the findings shown in Figures 5 focusing on replacement of pipe installed in rocky
soil, would provide the largest reduction on the total number of leaks. The leak profile for each soil
type over the next 20 years is provided in Figure 6.

Figure 6 – Baseline Aldyl-A Mainline leak profile per soil type for the next 20 years
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
Other 0 0 0 1 1 0 1 0 0 0 1 1 1 1 1 1 0 1 1 1
Control Density Fill (CDF)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Concrete/Grout 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Clay/Bentonite 0 1 1 2 3 1 3 1 1 2 6 4 3 4 4 4 2 3 6 4
Loam 1 1 4 6 8 8 10 8 6 8 15 20 12 14 11 13 13 18 15 20
Sand 1 1 4 6 9 7 11 8 6 8 18 22 13 16 12 15 14 22 18 23
Rocky 6 4 13 14 13 26 22 26 18 26 34 33 35 41 30 32 35 41 42 47
0
10
20
30
40
50
60
70
80
90
100
Le
a
k
s

Leak Profile by Soil Type
20 Year Forecast
ICNU_DR_113 Attachment L Page 14 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
15 Document No: 356-006 Issue Date: July 2013

4.2 Replacement Scenarios
Scenarios are compared to one another by looking at the reduction in leaks per year from
Availability Workbench combined with the financial predictions from Avista’s Revenue
Requirement calculator.
For all scenarios, capital replacements are assumed to cost $243.42 per three feet in Washington
and Idaho and $183.15 per three feet in Oregon. Unplanned replacements of leaks are assumed
to cost $3346.26 per three feet. Further assumptions are made for the consequence costs, the
LCC model and the Revenue Requirement calculator which are standard Avista assumptions and
processes and will not be covered in this discussion.
Leaks and capital replacements are not returned to service after repair/replacement to reflect
replacing the failed Aldyl-A pipe with a different type of pipe.
4.2.1 Scenario A - 20 Year Replacement Program
This scenario has been modeled to evaluate the potential effectiveness of a capital replacement
program targeting replacing all mainline Aldyl-A pipe within 20 years. The total length of
replacements were evenly distributed across each year and prioritized per the risk scores
provided by Avista.
Leaks or failures identified through inspection are handled as unplanned replacements with
associated costs and consequences. This is reflective of the inspection method which provides
no indication of a deteriorating condition, only an indication of a failure or a leak.
Scenario A showed a reduction in leaks of 26,533 over 75 years and 1,339 leaks over 25 years
when compared to the baseline
The leak profile comparison can be seen in Figure 7.
ICNU_DR_113 Attachment L Page 15 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
16 Document No: 356-006 Issue Date: July 2013

Figure 7 – Comparison between Aldyl-A mainline baseline scenario and scenario A over 25 years.

4.2.2 Scenario B – 15 Year Replacement Program
Scenario B evaluates the potential effectiveness of compressing the capital replacement program
to 15 years. As in scenario A the total footage of replacements was evenly distributed across
each year and prioritized per the risk scores provided by Avista.
Scenario B shows a reduction in total number of leaks over the baseline and scenario A. Over the
75 year simulation scenario B shows 127 fewer leaks than scenario A and 26,660 fewer leaks
than the baseline model. Over the first 25 years scenario B shows 127 fewer leaks than scenario
A and 1,466 fewer leaks than the baseline model.
0
20
40
60
80
100
120
140
160
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25
Le
a
k
s

Year
Baseline Vs 20 Year Mainline Replacement Program
Baseline Leaks 20 Year Replacement Leaks
ICNU_DR_113 Attachment L Page 16 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
17 Document No: 356-006 Issue Date: July 2013

Figure 8 – Comparison between Aldyl-A mainline baseline scenario and scenario B over 25 years.
0
20
40
60
80
100
120
140
160
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25
Le
a
k
s

Year
Baseline Vs 15 Year Mainline Replacement Program
Baseline Leaks 15 Year Replacement Leaks
ICNU_DR_113 Attachment L Page 17 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
18 Document No: 356-006 Issue Date: July 2013

4.2.3 Scenario C – 25 Year Replacement Program
This scenario evaluates the potential effectiveness of extending the capital replacement program
5 years to 25 total years. As in scenario A the total length of replacements were evenly distributed
across each year and prioritized per the risk scores provided by Avista.
Scenario C does not show the same reduction in total number of leaks over the baseline as
scenarios A or B, but it does still have significant improvement when compared to the baseline.
Over the 75 year simulation scenario C shows 164 more leaks than scenario A and 26,368 fewer
leaks than the baseline model.

Figure 9 – Comparison between Aldyl-A mainline baseline scenario and scenario C over 25 years.
4.2.4 Scenario Comparison
To compare the three capital replacement scenarios to the total number of leaks over a 75 year
lifetime was compared to the baseline and to the 20 year replacement program. As can be seen
in Table 1, all of the scenarios show a significant reduction in leaks over the baseline however
0
20
40
60
80
100
120
140
160
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25
Le
a
k
s

Year
Baseline Vs 25 Year Mainline Replacement Program
Baseline Leaks 25 Year Replacement Leaks
ICNU_DR_113 Attachment L Page 18 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
19 Document No: 356-006 Issue Date: July 2013

when comparing to the 20 year replacement scenario the 15 year scenario has fewer leaks while
the 25 year scenario has more.

Scenario Total Compared to baseline Compared to 20 year
Baseline 26888.69 0.00 26533.04
15 Year Replacement
Program
228.55 -26660.14 -127.10
20 Year Replacement
Program
355.65 -26533.04 0.00
25 Year Replacement
Program
519.94 -26368.75 164.29
Table 1 - Leaks results and scenario comparison for 75 years Aldyl-A mainline pipe simulations
To be able to effectively compare the scenarios the results from the RCM and LCC studies were
compiled and analyzed in Avista’s Replacement Revenue Requirement model. The annual
expenditures from this analysis are recorded in Appendix A.
Figure 10 shows the cumulative cost comparisons of the four Aldyl-A mainline pipe replacement
scenarios. All of the replacement scenarios have significant early life costs when compared to the
baseline as is expected. After the replacement projects are completed the cost associated with
the Aldyl-A pipe is negligible while the baseline maintenance expenditures continue to increase
with the increasing number of leaks. Total lifetime expenditures for the baseline surpass the 15
year replacement program in 35 years (2048), the 20 year replacement program in 36 years
(2049) and the 25 year replacement program in 37 years (2050).
ICNU_DR_113 Attachment L Page 19 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
20 Document No: 356-006 Issue Date: July 2013

Figure 10 – Cumulative Cost Comparison of Aldyl-A mainline Replacement Scenarios

$
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
0 3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60 63 66 69 72
Cu
m
u
l
a
t
i
v
e

C
o
s
t

P
r
o
j
e
c
t
i
o
n
s

Mi
l
l
i
o
n
s

Year
Mainline Aldyl-A Pipe Cumulative Cost Projections
Base Case weff 20 yr program weff 15 yr program weff 25 yr program weff
ICNU_DR_113 Attachment L Page 20 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
21 Document No: 356-006 Issue Date: July 2013

Title IRR Levelized Gr.
Mar.
Requirement*
Lev
ROE*
NPV
equity*
Baseline 29.90% $2,641 $0 $0
20 Year
Replacement 2.72% $22,044 $6,513 $93,490
15 Year
Replacement 2.55% $24,232 $7,174 $102,980
25Year
Replacement 2.88% $20,139 $5,933 $85,175
Baseline with
effects 9.21% $16,417 $0 $0
20 Year
Replacement
with effects
6.04% $23,229 $6,513 $93,490
15 Year
Replacement
with effects
5.85% $25,120 $7,174 $102,980
25 Year
Replacement
with effects
6.21% $21,664 $5,933 $85,175
* In thousands
Table 2 – Mainline Aldyl-A Replacement Revenue Requirement Analysis Summary
The Aldyl-A Mainline Replacement Revenue Requirement Analysis summary in Table 2 shows
that over a 75 year time frame that the 25 year replacement program is the most cost effective of
all of the replacement programs. The Levelized Gross Margin Requirements is approximately $2
million less than the 20 year replacement program which is approximately $2 million less than the
15 year replacement program. The option of not replacing the pipe is more cost effective in the
75 year timeframe of the study given the assumptions of the Revenue Requirement model, but it
should be noted that as the pipe continues to age the cost and associated risk of leaks increases
significantly.

ICNU_DR_113 Attachment L Page 21 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
22 Document No: 356-006 Issue Date: July 2013

5 ALDYL-A BENDING STRESS POINTS
5.1.1 Model Validation
As an example, the failure rate curve based on the Weibull distribution developed for Aldyl-A
Bending Stress Points is shown in Figure 11. This curve has the following parameters:
η = 1,312,000 hours or 150 years (63.2% of the installed Bending Stress Points will
cause a leak prior to reaching this age)
β = 4.125 (indicating a predictable end of life)

Figure 11 – The failure rate distribution for Aldyl-A Bending Stress Points.
Using this distribution and knowing the number of Aldyl-A Bending Stress Points that are yet to
be replaced the expected number of leaks can be calculated at any point in time. The predicted
number of leaks in Aldyl-A Bending Stress Points is shown in Figure 12.

APE BEND STRESS SVCS - Pre 87 Failure Rate
0 35305 70609 1.0591E+05 1.4122E+05 1.7652E+05 2.1183E+05 2.4713E+05 2.8244E+05 3.1774E+05 3.5305E+05
Time
0
5.199E-09
1.0398E-08
1.5597E-08
2.0796E-08
2.5995E-08
3.1194E-08
3.6393E-08
4.1592E-08
4.6791E-08
5.199E-08
Fa
i
l
u
r
e

R
a
t
e
Regionalised rate
Distribution rate
P569400:3.15103%
B50:1.20003E+06
B25: 969613
B10: 760035
e: 0.000126309
r: 0.981459
g: 0
b: 4.125
h: 1.312E+06
Median rank
2-parameterWeibull
ICNU_DR_113 Attachment L Page 22 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
23 Document No: 356-006 Issue Date: July 2013

Figure 12 – Initial predicted number of leaks per year in Aldyl-A Bending Stress Points for next 20
years.
Note: The prediction shown above in Figure 12 assumes that repairs are only carried out when a
leak occurs. The effect of capital replacement on this profile is considered in the various
scenarios which follow.
To validate the model the recent leak history was reviewed and compared to the predicted
number. It was found that from 2006 to the end of 2012 the number of leaks has varied between
0 and 12 and averaged 6.14 per year. The Bending Stress Point model predicted that over the
next ten years the frequency of leaks would increase steadily from 1.69 to 3.44 per year. This
does not correlate to the actual frequency or distribution evident from 2006 to 20012. The
recorded leaks each year between 2006 and 2012 are shown in Figure 13.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
Leaks per year 1.69 1.88 1.96 2.11 2.37 2.6 2.81 3.05 3.13 3.44 3.74 4.13 4.42 4.65 4.93 5.34 5.5 5.94 6.39 6.69
0
1
2
3
4
5
6
7
8
Le
a
k
s

Bending Stress Point Leaks
Initial 20 Year Forecast
ICNU_DR_113 Attachment L Page 23 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
24 Document No: 356-006 Issue Date: July 2013

Figure 13 – The recorded leaks between 2006 and 2012 on Aldyl-A Bending Stress points.
The differences between the leak prediction and the actual variation in the number of leaks can
be explained by both previous leaks that have not been recoded and various inspection activities
that have been identifying leaks that may have existed for a significant amount of time. Since it is
known that historical leaks of this manner were not recorded so that they could be identified as
this failure type, it was determined the calculated eta (η), characteristic life was too long. To
correct this η was adjusted down to increase the number of failures without changing the shape
parameter beta (β). After review η = 8760,000 hours was determined to represent an acceptable
fit with current data. The predicted number of leaks in Aldyl-A bending stress points with η =
8760,000 hours is shown in Figure 14.
2006 2007 2008 2009 2010 2011 2012
Bending Stress Leaks 4 8 12 0 5 3 11
0
2
4
6
8
10
12
14
Le
a
k
s

Bending Stress Point Leaks per year
2006 through 2012
ICNU_DR_113 Attachment L Page 24 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
25 Document No: 356-006 Issue Date: July 2013

Figure 14- Predicted number of leaks per year in Aldyl-A Bending Stress Points for next 10 years
with η set to 876,000 hours.
Note - All subsequent Bending Stress models and discussion use η = 876,000 hours.
As the pipe continues to age the number of leaks is predicted to increase. This can be seen in the
75 year leak prediction for Bending Stress Points in Figure 15. The model predicts that the leaks
will increase steadily until a sufficient percentage of the points have failed and been replaced
such that the leak rate begins to decrease.
0
2
4
6
8
10
12
14
16
18
20
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Le
a
k
s

Year
Bending Stress Leaks
10 Year Forecast
η=876,000
ICNU_DR_113 Attachment L Page 25 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
26 Document No: 356-006 Issue Date: July 2013

Figure 15 – Predicted number of leaks per year in Aldyl-A Bending Stress Points for the next 75
years.
5.1.2 Maintenance Cost Forecast
By considering all 17,593 Aldyl-A bending stress points which have not been replaced a forecast
can be made which represents the number of leaks expected. If an unplanned replacement cost
of $2,160 is applied to repair each leak the maintenance budget dedicated to leak repairs can
also be determined.
The total costs, which includes the maintenance costs and effects, is shown in Figure 16 and
Appendix B

0
20
40
60
80
100
120
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 73 75
Le
a
k
s

Year
Bending Stress Leaks
ICNU_DR_113 Attachment L Page 26 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
27 Document No: 356-006 Issue Date: July 2013

Figure 16 –Forecasted unplanned total costs of leaks on Aldyl-A Bending Stress points pipe for
next 75 years.

$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$18.00
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 73 75
Co
s
t

(
M
i
l
l
i
o
n
s
)

Year
Aldyl-A Bending Stress Unplanned Total Costs
ICNU_DR_113 Attachment L Page 27 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
28 Document No: 356-006 Issue Date: July 2013

5.1 Replacement Scenarios
Scenarios are compared to one another by looking at the reduction in leaks per year from AWB
and results from Avista’s Revenue Requirement calculator.
For all scenarios, planned capital replacements are assumed to cost $1,709.84 per location and
unplanned replacements of leaks are assumed to cost $2,160.00 per location. Further
assumptions are made in the effect costs, the LCC model and the Revenue Requirement
calculator but those are standard Avista assumptions and processes and will not be covered in
this discussion.
Leaks and capital replacements are not returned to service after repair/replacement to reflect
replacing the failed Aldyl-A pipe with a different type of pipe which is outside the scope of this
study.
5.1.1 Scenario A – 5 Year Replacement Program
This scenario has been modeled to evaluate the potential effectiveness of a capital replacement
program targeting replacing all Aldyl-A bending stress points within 5 years. An equal number of
points were scheduled to be replaced in each of the 5 years.
Leaks or failures identified through inspection are handled as unplanned replacements with the
associated cost and effects.

Figure 17 – The comparison between the Bending Stress baseline and scenario A

Figure 17 and Table 3 show that a 5 year replacement program rapidly decreases the number of
leaks per year and over the 5 year scope of the replacements. The total number of leaks is
0
20
40
60
80
100
120
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 73 75
Le
a
k
s

P
e
r

Y
e
a
r

Year
Baseline Vs 5 Yr Replacement plan Leaks Per Year
75 Year Forecast
Leaks per year 5 Yr Replacement Program
ICNU_DR_113 Attachment L Page 28 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
29 Document No: 356-006 Issue Date: July 2013

reduced from 40.75 in the baseline model to 18.23 leaks in the 5 year replacement model. Over
the 75 year simulation the total number of leaks in the baseline model is 4,980.43 with only 18.23
leaks predicted based on a 5 year replacement program.

Scenario Total Compared to Baseline
Baseline 4980.43 0.00
5 Year Replacement
Program
18.23 -4962.19
Table 3 - Leaks results and scenario comparison for 75 years Aldyl-A Bending Stress Point
simulations

Figure 18 – Cumulative Cost Comparison for Bending Stress baseline vs 5 Year Replacement
Program
Figure 18 shows that with a 5 year replacement program the cost are front loaded and greater
than the baseline for the first 18 years. In year 18 the cumulative lifetime costs of not proactively
replacing the bending stress points surpass the cost of the 5 year replacement program and will
continue to grow until all points have failed and been replaced through corrective work.

$
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 72 74
Cu
m
u
l
a
t
i
v
e

C
o
s
t

P
r
o
j
e
c
t
i
o
n
s

(
M
i
l
l
i
o
n
s
)

Year
Baseline 5 Yr Replacement
ICNU_DR_113 Attachment L Page 29 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
30 Document No: 356-006 Issue Date: July 2013

The Bending Stress Replacement Revenue Requirement Analysis summary in Table 4 shows the
levelized gross margin requirement with effects considered over 75 years is $1,430,219 for a 5
year replacement program and $2,034,796 with just addressing the failures.
Title IRR* Levelized Gr.
Mar.
Requirement
*
Lev
ROE*
NPV
equity
*
Baseline 69.71% $137 $0 $0
5Yr
Replacement 1.22% $1,389 $411 $5,909
Baseline with
effects 4.22% $2,034 $0 $0
5Yr
Replacement
with effects
8.16% $1,430 $411 $5,909
* In thousands
Table 4 – Bending Stress Replacement Revenue Requirement Analysis Summary
6 CONCLUSION
This study based on the available historical records of Aldyl-A pipe installed, leaks and capital
pipe replacements identifies the soil type in which the pipe was installed is a strong contributing
factor to leaks in Aldyl-A mainline pipe. Referring to Figure 5 the pipe installed in rocky soil is the
highest contributor to the number of leaks occurring in Aldyl-A mainline pipe and is predicted to
have 538 of the 1,055 total leaks over the next 20 years.
A total of 26,888.69 leaks on Aldyl-A mainline pipe and 4,980.43 leaks on Bending Stress points
are predicted to occur over the next 75 years without any form of a proactive replacement
program.
The Avista Revenue Requirement Calculator shows that it is less costly to maintain the current
system rather than proactively replacing all Aldyl-A mainline pipe, but it should be considered that
current cost forecasts are based on cost of replacement and effects per leak. The study did not
incorporated safety thresholds which should be considered before the replacement scenario is
selected. Of the replacement scenarios, the 25 year replacement program is the most cost
effective, but carries with it an increased risk of leaks when compared to the 15 year replacement
program.
For the Aldyl-A Bending Stress Points the models predicts that without proactive replacement
there will be 4,980.43 over the next 75 years. With a 5 year replacement program the number of
Aldyl-A Bending Stress Point leaks are predicted to be reduced to 18.23. Table 4 shows that
ICNU_DR_113 Attachment L Page 30 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
31 Document No: 356-006 Issue Date: July 2013

along with having fewer leaks, the 5 Year Replacement Program is also more cost effective due
to the very high maintenance costs that are avoided by replacing the locations before failure.
This study has evaluated if a replacement program is appropriate and identified what the
timeframe of replacement should be.
7 FUTURE DATA COLLECTION
Future data collection focused on better documentation of failures to easily attribute these to
Aldyl-A pipe would make it possible to refine the Weibull sets and improve accuracy of model
predictions. A better understanding of how soil type affect failures will allow for targeted
replacement based upon likelihood of failure. Also further refinement of per occurrence cost for
both planned and unplanned replacements and the associated effects will produce improvement
in cost forecasting.

The below Availability Workbench models and excel files have been included in the attachment:
Appendix C – Aldyl-A Mainline Risk Based Replacement Schedule.xlsx
Aldyl-A_Mainline_Baseline.awb
Aldyl-A_Mainline_15YrReplacement.awb
Aldyl-A_Mainline_20YrReplacement.awb
Aldyl-A_Mainline_25YrReplacement.awb
Aldyl-A_Mainline_Revenue_Requirement.xlsm
Aldyl-A_Bending_Stress_5Yr_Replacement.awb
Aldyl-A_Bending_Stress_Baseline.awb
Aldyl-A_BendingStress_Revenue_Requirement.xlsm

For any further information regarding this report please contact:
Scott Gloyna
ARMS Reliability Engineers
Phone: [phone] Email: [e-mail]
ICNU_DR_113 Attachment L Page 31 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
32 Document No: 356-006 Issue Date: July 2013

APPENDIX A – MAINLINE ALDYL-A PIPE ANNUAL EXPENSES PER
YEAR BASED ON AVISTA REVENUE REPLACEMENT CALCULATOR
Year Baseline Model 15 year Replacement 20 year Replacement 25 year Replacement
2014 $1,053,098 $20,630,396 $15,523,692 $12,600,398
2015 $1,366,085 $21,502,344 $16,732,890 $13,670,362
2016 $1,578,819 $22,154,899 $16,693,408 $13,625,781
2017 $2,392,676 $21,984,874 $17,800,548 $14,688,886
2018 $2,768,005 $23,246,955 $17,358,435 $14,543,083
2019 $1,660,312 $23,208,866 $18,218,004 $14,802,814
2020 $1,730,966 $23,602,701 $17,973,699 $14,861,131
2021 $3,499,201 $24,718,573 $18,985,577 $16,139,340
2022 $4,925,618 $24,763,492 $19,501,977 $16,021,402
2023 $4,880,447 $25,117,222 $19,365,478 $16,405,554
2024 $4,747,529 $26,046,042 $19,606,495 $17,065,648
2025 $5,123,168 $27,173,746 $21,534,237 $17,134,260
2026 $4,519,919 $25,533,874 $21,076,111 $17,860,877
2027 $6,249,062 $26,177,636 $20,547,201 $16,673,768
2028 $5,886,914 $28,336,876 $21,629,593 $19,320,214
2029 $8,341,754 $62 $24,204,686 $18,714,383
2030 $8,130,556 $58 $21,657,261 $19,526,333
2031 $7,091,184 $68 $21,951,619 $19,456,422
2032 $8,308,972 $79 $22,528,242 $20,680,853
2033 $11,558,254 $78 $23,920,821 $20,110,171
2034 $8,624,054 $54 $54 $20,017,521
2035 $14,231,303 $148 $148 $19,040,579
2036 $9,286,458 $92 $92 $19,864,204
2037 $10,436,924 $66 $66 $21,045,013
2038 $14,639,935 $127 $127 $21,556,039
2039 $14,902,569 $112 $112 $112
ICNU_DR_113 Attachment L Page 32 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
33 Document No: 356-006 Issue Date: July 2013

2040 $18,513,248 $99 $99 $99
2041 $16,612,017 $109 $109 $109
2042 $24,180,445 $197 $197 $197
2043 $21,360,174 $194 $194 $194
2044 $21,464,664 $186 $186 $186
2045 $28,159,708 $175 $175 $175
2046 $28,103,552 $192 $192 $192
2047 $34,714,096 $253 $253 $253
2048 $32,353,197 $246 $246 $246
2049 $32,105,620 $201 $201 $201
2050 $39,925,133 $289 $289 $289
2051 $40,815,099 $331 $331 $331
2052 $45,896,431 $408 $408 $408
2053 $45,768,912 $326 $326 $326
2054 $50,456,902 $349 $349 $349
2055 $51,042,099 $369 $369 $369
2056 $57,321,609 $340 $340 $340
2057 $62,998,111 $399 $399 $399
2058 $66,025,281 $397 $397 $397
2059 $69,912,764 $369 $369 $369
2060 $72,925,486 $445 $445 $445
2061 $82,840,530 $558 $558 $558
2062 $79,252,603 $425 $425 $425
2063 $97,983,309 $619 $619 $619
2064 $97,760,020 $613 $613 $613
2065 $106,183,812 $613 $613 $613
2066 $109,769,824 $666 $666 $666
2067 $126,136,597 $762 $762 $762
ICNU_DR_113 Attachment L Page 33 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
34 Document No: 356-006 Issue Date: July 2013

2068 $133,596,627 $802 $802 $802
2069 $133,736,191 $853 $853 $853
2070 $141,958,882 $762 $762 $762
2071 $155,150,583 $976 $976 $976
2072 $133,517,706 $772 $772 $772
2073 $170,774,975 $1,063 $1,063 $1,063
2074 $189,628,157 $1,051 $1,051 $1,051
2075 $210,917,084 $1,322 $1,322 $1,322
2076 $208,313,915 $1,054 $1,054 $1,054
2077 $223,209,649 $1,244 $1,244 $1,244
2078 $246,975,709 $1,449 $1,449 $1,449
2079 $240,213,479 $1,516 $1,516 $1,516
2080 $245,517,144 $1,516 $1,516 $1,516
2081 $277,541,496 $1,748 $1,748 $1,748
2082 $303,475,254 $1,780 $1,780 $1,780
2083 $309,803,301 $1,978 $1,978 $1,978
2084 $349,869,383 $2,326 $2,326 $2,326
2085 $389,165,746 $2,388 $2,388 $2,388
2086 $386,439,169 $2,187 $2,187 $2,187
2087 $381,916,092 $2,237 $2,237 $2,237
2088 $439,216,355 $2,535 $2,535 $2,535

ICNU_DR_113 Attachment L Page 34 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
35 Document No: 356-006 Issue Date: July 2013

APPENDIX B – BENDING STRESS POINTS ANNUAL EXPENSES PER
YEAR BASED ON AVISTA REVENUE REQUIREMENT CALCULATOR
Year Baseline Model 15 year Replacement
2014 $317,649 $3,183,913
2015 $304,085 $2,819,456
2016 $351,226 $3,029,240
2017 $418,833 $3,027,854
2018 $455,343 $2,942,853
2019 $455,891 $
2020 $577,162 $
2021 $609,543 $
2022 $651,385 $
2023 $711,827 $
2024 $768,983 $
2025 $855,607 $
2026 $962,361 $
2027 $1,076,513 $
2028 $1,159,275 $
2029 $1,279,780 $
2030 $1,333,203 $
2031 $1,409,130 $
2032 $1,582,067 $
2033 $1,724,496 $
2034 $1,846,103 $
2035 $2,040,629 $
2036 $2,138,427 $
2037 $2,269,137 $
2038 $2,468,549 $
2039 $2,630,429 $
ICNU_DR_113 Attachment L Page 35 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
36 Document No: 356-006 Issue Date: July 2013

2040 $2,965,074 $
2041 $3,070,587 $
2042 $3,182,011 $
2043 $3,430,967 $
2044 $3,778,150 $
2045 $3,995,484 $
2046 $4,209,379 $
2047 $4,422,393 $
2048 $4,701,923 $
2049 $4,893,690 $
2050 $5,173,259 $
2051 $5,415,284 $
2052 $5,892,520 $
2053 $6,274,770 $
2054 $6,624,868 $
2055 $6,946,215 $
2056 $7,151,475 $
2057 $7,561,836 $
2058 $7,882,020 $
2059 $8,179,922 $
2060 $8,705,696 $
2061 $8,872,728 $
2062 $9,312,980 $
2063 $9,945,979 $
2064 $9,963,486 $
2065 $10,362,652 $
2066 $10,815,663 $
2067 $11,262,009 $
ICNU_DR_113 Attachment L Page 36 of 37
AVISTA
ALDYL-A REPLACEMENT STUDY
37 Document No: 356-006 Issue Date: July 2013

2068 $11,609,775 $
2069 $12,343,611 $
2070 $12,397,001 $
2071 $12,693,905 $
2072 $13,048,328 $
2073 $13,484,249 $
2074 $13,830,755 $
2075 $14,205,038 $
2076 $14,366,121 $
2077 $14,786,553 $
2078 $15,129,889 $
2079 $15,467,402 $
2080 $15,735,893 $
2081 $15,404,001 $
2082 $15,754,908 $
2083 $16,271,565 $
2084 $16,507,732 $
2085 $16,448,616 $
2086 $16,561,863 $
2087 $16,760,211 $
2088 $16,763,466 $

ICNU_DR_113 Attachment L Page 37 of 37
MAC 206 – Vegetation Management
Background
The Avista Vegetation Management program maintains the distribution and transmission
systems and strives to maintain a clearance between power lines and trees and other vegetation.
The Vegetation Management program provides safety clearances for the public and also reduces
customer outages caused by power lines coming into contact with trees. The Avista Electric
Distribution System runs for 7,777 overhead circuit miles in Washington, Idaho, and Montana.
The Transmission System includes 1,675 circuit miles of 115 kV Transmission Lines and 984
circuit miles of 230 kV Transmission Lines in Washington, Idaho, and Montana. The Gas
System High Pressure Lines includes 291 miles. This report discusses strategic plans for
Vegetation Management of the Electrical Distribution system, since vegetation management of
the Gas High Pressure Lines and Transmission System are driven by federal requirements.
Avista analyzed four cases to help determine an optimal approach for managing vegetation in the
electric distribution system.
1. The first case is called the No Action Case. In this case, Avista would only respond to
outages and events (events are defined as a report of a tree or vegetation problem that
does not always result in an outage) as they occur. The No Action Case represents the
base case against which all other alternatives are compared. Avista compared this base
case against current practices and also examined two other alternatives.
2. The next case represents our current vegetation management practices (as of 2009) of
trimming many feeders on either a 7 or 8 year cycle. This case is called the Current Case.
3. The first alternative represents trimming all Distribution Feeders on a straight five year
cycle and identifies it as the Five Year Case.
4. The second alternative came from optimizing the trim interval using our Asset
Management software. This method optimized an interval for each individual feeder
using the failure curves and is called the Optimized Case.
Based on risks associated with “risk trees” not previously identified for separate analysis, we
have added new scope for Vegetation Management to address codominant (split top) trees.
These codominant trees present a unique hazard because these split tree tops tend to fail at a
significantly higher rate than normal tree tops.
Vegetation Management Program Trends and Analysis
Figure 1, Figure 2, and Figure 3 show the pattern of tree-related events tracked by Avista’s
Outage Management Tool (OMT) for the last several years. Figure 4 shows how the current
trends indicate tree-related events might occur through 2016. Figure 1 shows the past six years
trends in the Outage Management Tool for Tree Fell, Tree Growth, and Tree Weather Events and
Figure 2 shows just the number of these events that actually cause an outage or partial outage.
Figure 3 expands Figure 1 to show the number of events by quarter and year. Figure 4 shows an
extrapolation of the current trends into the year 2016 for tree related OMT Events and the
extrapolation of the outages and partial outages. Comparing the curves on Figure 4, we see that
the number of OMT Events due to vegetation issues continues to grow but the impact from these
events has reduced. The number of OMT Events due to tree growth shows a rising trend but the
ICNU_DR_113 Attachment M Page 1 of 24
outages from these events are actually trending down. Tree Fell events are also increasing at a
faster pace than the outages caused by tree falls. The trends in the average increment added to
SAIFI for Tree Fell, Tree Growth, and Tree Weather shown in Figure 5 supports the desired goal
that impacts from these types of outages has been improving.
The customer impacts based on the past three years are shown in Table 1 and Figure 6. The
average outage duration information used in Figure 6 does not go back any further than 2008, so
confidence to identify trends is questionable. The average number of affected customers has
remained relatively flat or declining for the past few years despite an increase in the number of
events.
In 2010, we trimmed 1,257 miles out of 7,800 circuit miles for a clearing cycle time of 6.2 years.
The approved amount for Washington state of $4.025 million provides sufficient funding to
support a 5.3 year clearing cycle time.
Overall, the data indicates the number of vegetation related events continue to increase.
However, the impact of vegetation related problems has improved based on the past reductions
of the cycle times, so the severity of each event has diminished.
Vegetation Management Model Results
Sustained action is required to firmly establish a downward trend in the number of vegetation
related events. Based on our current analysis, the Optimized Case represents the best approach
to managing the system. The Optimized Case calls for tailoring the risks and program to each
feeder. The analysis indicates an average cycle time for each feeder of 4 years based on the
results shown in Table 2. Previous modeling indicated a cycle time of 5 years across the board
for all feeders, but the updated model indicates better performance of the system in the
Optimized Case and, therefore, we believe this justifies a shorter cycle time. Table 3 and Table 4
show the difference in system performance where the Optimized Cycle times will further reduce
vegetation events by an additional 380 events on average per year.
The data behind the failure rates used in the models comes from information gathered during
past years’ work and failures. Failures are defined as a component or system did not properly
perform a function and becomes a functional failure or simply a failure. Failure rate is defined as
the number of failures over a period of time and total population. The number of trees removed,
trees trimmed, and brush removed along with the tree-related failures documented in the OMT
were used to create the failure curves represented in by a combined curve in Figure 7.
Examining the failure rate curve shown in Figure 7, we see that the failure rates due to weather,
snow and ice, wind, tree growing into lines and trees falling into lines increases at a steady rate
in region 1. Region 1 of Figure 7 represents the current practices and its associated failures and
indicates that our system will reach a 53% failure percentage at about 10 years. The
corresponding five year trim cycle failure percentage is 22% and the four year trim cycle is at a
16% failure percentage. Region 2 of Figure 7 was caused by a lack of data and falsely implies
the failure rate in this region is unchanged. Region 2 is an absence of information and is not
used. Region 3 of Figure 7 represents the failure rates associated with our old method of
trimming at 4 year intervals for predominantly deciduous or urban feeders and an 8 year interval
for predominantly conifer or rural feeders which are higher.
One effect not addressed by our analysis above come from the increased amount of work
required to clear the distribution lines after delaying clearing for many years. Figure 8 shows
ICNU_DR_113 Attachment M Page 2 of 24
how the amount of work grows over time. The first five years after clearing the line, the amount
of work remains relatively flat, but after 5 years, the work load grows exponentially. Figure 8 is
based on actual data collected that documented the number of trees trimmed, trees removed, and
amount of brush cleared by feeder and plotted against how many years have passed since the last
time the line was cleared. Even after a line is cleared, some vegetation will quickly encroach on
the line because the removed vegetation held it back in the past.
Table 6 and Table 7 show the financial analysis between Base Case, our current practices, Five
Year Cycle Case, and the Optimized Case. Table 6 shows the impacts to our customers if we
ignore all possible consequence costs and customer outage costs. Table 7 shows the impacts to
our customers when we consider all potential costs to the company and the customer outage
costs. To best determine the value of the program to our customers, we selected Table 7 to use
and maximize the value. The Optimized Case provides our customers the best value over time
by avoiding outage costs and other failure costs.
Our analysis clearly shows that a pro-active maintenance program is necessary to provide the
best value to our customers. The Optimized Case (see Table 2) shows an optimized trimming
time of 4 years for most feeders with many feeders trimmed on a 3 or 5 year cycle. The
Optimized Case also provides the lowest predicted number of vegetation related events and
outages (see Table 4). The force behind the analysis that drives the Optimized Case to an
average trim cycle of four years is the risk associated with fires and property damage.
The required budgets for 2011 through 2015 are shown in Table 8 for Washington and Table 9
for Idaho (combined numbers for both states are shown in Table 10). These estimates are based
on model predictions and on the feeders scheduled for work over the next 5 years. Based on the
proposed budget, Avista will need an additional $4.4 million over the test year of 2010
($3,144,720 for Washington and $1,178,410 for Idaho as shown in Table 12). Figure 9 plots the
cumulative costs for each alternative over time and demonstrates how the value will be realized.
Future savings estimates will be realized only after the work is completed and generally will not
be seen until the year following the actual work. This means that the actual savings for work
performed in 2011 will not be realized until 2012. The estimates for savings in the future are
based on Table 11. The assumption is that all of the events over 5 years in will be avoided on a 5
year trim cycle and save ~ $1,000 per event. This assumption is very optimistic and the actual
number will be less because some events will still occur within a 5 year trim cycle as we have
seen for all of the feeders discussed above. Next, the total savings cannot be realized until all of
the feeders have been trimmed on a 5 year cycle, so the savings for 2012 is 1/5 of the overall
savings and is shown in Table 11 as $80,000 for Idaho and $154,800 for Washington in 2012.
The four year cycle will save an additional $342,000 after the first year of change (assumed to be
2013) as shown in Table 5.
Managing Vegetation Risk
All trees have the potential to fail, and any tree failure has the potential to contact electric power
lines. Trees or their branches may fall into power lines or they can be carried into contact from a
distance beyond the reach of gravity’s pull in high wind situations. Currently, field reviews have
shown that the majority of tree related outages are due to tree failures and most of these trees are
outside of the right of way. It has also been found that tree failures increase rapidly at wind
ICNU_DR_113 Attachment M Page 3 of 24
speeds over 60 mph. Avista seeks to drive down outages due to tree failures through an
enhanced risk tree removal program.
A risk tree is defined as dead, diseased or dying tree, however, many trees that fail have no
visible fault indicators which make it difficult to justify as removals. Risk assessment does not
mean just finding dead trees and branches, as any defects such as internal decay are hidden and
require a higher level of inspection to identify.
Studies show common annual tree mortality to be 1% to 3% and there is an ongoing residual
population of risk trees. Tree mortality rates will depend on tree species and conditions.
Based on increased risk, Avista is modifying our current risk tree program. Codominant
stemmed trees will be removed, or structurally pruned in a fashion where a dominant leader is
developed, which is usually the largest stem. Addressing the codominant stemmed trees is new
to our current program and is discussed in more detail in Appendix A. Avista will also revise the
current risk tree inspection process to inspect and remove trees more frequently to insure right of
ways are reviewed every two years. We will also focus on problem tree species. The additional
codominant stemmed tree scope and revised risk tree inspections drives some of the increased
costs planned for 2012.
Summary
In summary, Avista plans to change the Vegetation Management Program to an optimized cycle
based on the individual feeders for an average cycle time of four years. We will also go to a two
year cycle on inspecting and removing risk trees on all circuits. The Optimized Case provides
the best return to the customers by avoiding significantly more outages than the other alternatives
and avoiding an increasing risk associated with vegetation caused fires. In order to get the
Vegetation Management Program into the correct cycle, Avista will need an additional $4.4
million above the spending in 2010 in order to keep future rates lower.

ICNU_DR_113 Attachment M Page 4 of 24

Figure 1, Vegetation Related OMT Events by Year

0
100
200
300
400
500
600
700
800
900
1000
2005 2006 2007 2008 2009 2010
Nu
m
b
e
r

o
f

O
M
T

E
v
e
n
t
s

Year
Tree Fell Tree Growth Weather
ICNU_DR_113 Attachment M Page 5 of 24
Figure 2, Vegetation Management Related Outages and Partial Outages by Year

0
100
200
300
400
500
600
700
2005 2006 2007 2008 2009 2010
Nu
m
b
e
r

o
f

O
M
T

O
u
t
a
g
e
s

a
n
d

P
a
r
t
i
a
l

Ou
t
a
g
e
s

Year
Tree Fell Tree Growth Weather
ICNU_DR_113 Attachment M Page 6 of 24
Figure 3, Vegetation Management OMT Events for Tree Fell and Tree Growth by Quarter

0
10
20
30
40
50
60
70
80
90
100
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4
2005 2006 2007 2008 2009 2010
Nu
m
b
e
r

o
f

O
M
T

E
v
e
n
t
s
Year and Quarter
Tree Fell Tree Growth
ICNU_DR_113 Attachment M Page 7 of 24
Figure 4, Vegetation Management OMT Events and Outages

0
200
400
600
800
1000
1200
1400
1600
0
200
400
600
800
1000
1200
1400
1600
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Nu
m
b
e
r

o
f

O
u
t
a
g
e
s

a
n
d

P
a
r
t
i
a
l

O
u
t
a
g
e
s
Nu
m
b
e
r

o
f

O
M
T

E
v
e
n
t
s
Year
Tree Fell Events Tree Growth Events Tree Weather Events
Tree Fell Outages Tree Growth Outages Tree Weather Outages
ICNU_DR_113 Attachment M Page 8 of 24
Figure 5, Average Incremental Impact to SAIFI by Tree Fell, Tree Growth, and Tree Weather Outages

0
0.0005
0.001
0.0015
0.002
0.0025
2005 2006 2007 2008 2009 2010
Av
e
r
a
g
e

I
m
p
a
c
t

t
o

S
A
I
F
I

p
e
r

O
u
t
a
g
e
Year
Tree Fell Tree Growth Weather
ICNU_DR_113 Attachment M Page 9 of 24
Figure 6, Trends in Average Number of Affected Customers and Average Outage Durations

Table 1, 3 Year Average of Customer Impacts from Vegetation Related Outages
Subreason Average Outage
Duration (hrs)
Average Number of Affected
Customers
Tree Fell 2.294 104.030
Tree
Growth 2.757 23.110
Tree
Weather 3.208 124.438

0
0.5
1
1.5
2
2.5
3
3.5
4
0
50
100
150
200
250
2004 2005 2006 2007 2008 2009 2010 2011
Av
e
r
a
g
e

O
u
t
a
g
e

D
u
r
a
t
i
o
n

(
h
r
s
)
Av
e
r
a
g
e

N
u
m
b
e
r

o
f

A
f
f
e
c
t
e
d

C
u
s
t
o
m
e
r
s
Year
Tree Fell -Average Number of Impacted Customers Tree Growth -Average Number of Impacted Customers
Tree Weather -Average Number of Impacted Customers Tree Fell -Average Outage Duration
Tree Growth -Average Outage Duration Tree Weather -Average Outage Duration
ICNU_DR_113 Attachment M Page 10 of 24
Table 2, Optimized Vegetation Management Cycle Times
Optimized Interval (Years) Number of Feeders
1 1
2 1
3 24
4 271
5 21

Table 3, OMT Data and Projection Comparisons for Current Case and 5 Year Cycle Case
OMT Events Tree
Fell
Tree
Growth
Tree
Weather
Combined
OMT Totals
6 Year Average
OMT Events 420 309 440 1,169
Projected 10 Year
Average - Current
Case
330 789 774 1,893
Projected 10 Year
Average - 5 Year
Trim Cycle Case
212 344 164 720
Difference between
Current Case and 5
Year Trim Cycle
Case
118 445 610 1,173

ICNU_DR_113 Attachment M Page 11 of 24
Table 4, OMT Data and Projection Comparisons for Current Case and Optimized Case
OMT Events Tree
Fell
Tree
Growth
Tree
Weather
Combined
OMT Totals
6 Year Average
OMT Events 420 309 440 1,169
Projected 10 Year
Average - Current
Case
330 789 774 1,893
Projected 10 Year
Average -
Optimized Case
53 225 62 340
Difference between
Current Case and
Optimized Case
277 564 712 1,553

Table 5, Projected O&M Offsets for changing from a 5 Year to 4 year Clearing Cycle
Year
Tree Fell
Outage Cost
per Event
Tree Growth
Outage Cost
per Event
Tree
Weather
Outage Cost
per Event
Projected
Value if
changed
from 5 year
to 4 year
cycle
2012 $502.65 $2,489.23 $163.91 $0
2013 $517.73 $2,563.91 $168.83 $342,000
2014 $533.27 $2,640.83 $173.89 $704,000
2015 $549.26 $2,720.05 $179.11 $1,088,000
2016 $565.74 $2,801.65 $184.48 $1,495,000

Table 6, Financial Analysis excluding Effects and Consequence Costs
Title Customer Internal
Rate of Return
Levelized Gr. Mar.
Requirement
No Action
Case 18.16% $4,823,333
Current Case 4.03% $5,813,678
5 Year Case 0.70% $7,225,887
Optimized
Case -2.79% $9,207,982
ICNU_DR_113 Attachment M Page 12 of 24

Table 7, Financial Analysis including Effects and Consequence Costs
Title Customer Internal
Rate of Return
Levelized Gr. Mar.
Requirement
No Action Case -22.91% $157,778,097
Current Case 38.59% $38,076,500
5 Year 63.39% $19,207,108
Optimized Case 75.96% $14,790,077

ICNU_DR_113 Attachment M Page 13 of 24
Table 8, Washington’s Distribution Vegetation Management Projected Budget
WASHINGTON
2011 2012 2013 2014 2015
Circuit Trimming $3,917,679 $5,154,805 $5,273,366 $5,394,653 $5,518,730
Unplanned Trimming $200,000 $175,000 $150,000 $125,000 $125,000
Sub Total $4,117,679 $5,329,805 $5,423,366 $5,519,653 $5,643,730
HPGPL Reclearing $50,000 $100,000 $50,000 $50,000 $50,000
Avista FTE (1 - Tim) $70,000 $72,100 $75,000 $77,000 $80,000
Enhanced Risk Tree / CoDom N/A $313,816 $201,568 $315,315 $108,674
Contract Administration $334,000 $354,040 $375,000 $398,000 $422,000
Grand total WASHINGTON $4,571,679 $6,169,761 $6,124,934 $6,359,968 $6,304,404

Table 9, Idaho’s Distribution Vegetation Management Projected Budget
IDAHO
2011 2012 2013 2014 2015
Circuit Trimming $1,533,350 $2,780,532 $2,844,484 $2,909,907 $2,976,835
Unplanned Trimming $100,000 $100,000 $100,000 $100,000 $100,000
Sub Total $1,633,350 $2,880,532 $2,944,484 $3,009,907 $3,076,835
HPGPL Reclearing $100,000 $150,000 $50,000 $50,000 $50,000
Avista FTE (1 - Ernie) $70,000 $72,100 $75,000 $77,000 $80,000
Enhanced Risk Tree / CoDom N/A $104,845 $171,299 $149,849 $171,123
Contract Administration $170,000 $180,000 $191,000 $202,000 $215,000
Grand total IDAHO $1,973,350 $3,387,477 $3,431,783 $3,488,756 $3,592,958

Table 10, Combined Washington and Idaho Vegetation Management Projected Budget
GRAND TOTAL D51
2011 2012 2013 2014 2015
Circuit Trimming $5,451,029 $7,935,337 $8,117,850 $8,304,560 $8,495,565
Unplanned Trimming $300,000 $275,000 $250,000 $225,000 $225,000
Sub Total $5,751,029 $8,210,337 $8,367,850 $8,529,560 $8,720,565
HPGPL Reclearing $150,000 $250,000 $100,000 $100,000 $100,000
Avista FTE (2) $140,000 $144,200 $150,000 $154,000 $160,000
Enhanced Risk Tree / CoDom N/A $418,661 $372,867 $465,164 $279,797
Contract Administration $504,000 $534,040 $566,000 $600,000 $637,000
Grand total $6,545,029 $9,557,238 $9,556,717 $9,848,724 $9,897,362
ICNU_DR_113 Attachment M Page 14 of 24
Figure 7, Unreliability due to Snow/Ice/Wind/Weather/Tree Growth/Tree Fell Combined based on Time since last Trimmed

Veg Man Combined Cumulative Probability
24.33 441.4 8008 1.453E+05
Time
0.1
0.2
0.3
0.5
1
2
3
5
10
20
30
50
70
90
99
99.9
Un
r
e
l
i
a
b
i
l
i
t
y

(
%
)
Eta estimator
P0: 0%
B20: 4.065E+04
B15: 3.334E+04
B10: 2.543E+04
Median rank
Phased tri-Weibull
Time (Hours)
Un
r
e
l
i
a
b
i
l
i
t
y

(
%
)

ICNU_DR_113 Attachment M Page 15 of 24
Figure 8, Probability a 150’ Feeder Segment will require Vegetation Management based on Time since Last Trimmed

0.00%
20.00%
40.00%
60.00%
80.00%
100.00%
120.00%
0 2 4 6 8 10 12 14 16
Pr
o
b
a
b
i
l
i
t
y

a

L
i
n
e

S
e
g
m
e
n
t

w
i
l
l

R
e
q
u
i
r
e

W
o
r
k
Years since Last Vegetation Management
Probability a Feeder Segment will require Vegetation Management
Work
ICNU_DR_113 Attachment M Page 16 of 24

Table 11, Savings Offset Estimate
State Sum of Vegetation
Management
Related OMT
Events
Maximum
Number of
Potentially
Avoided
Events
Sum of Projected
Total Savings
after 10 Years
2012 Savings
Offset
Idaho 644 244 $400,000 $80,000
Washington 1249 475 $774,000 $154,800
Grand Total 1893 720 $1,174,000 $234,800

Table 12, Distribution Pro Forma Increment
Year WA Elec ID Elec
2010 Actual $3,144,720 $1,178,410
2011 Planned $4,521,679 $1,873,350
2012 Planned $6,069,761 $3,237,477
2012 Offset -$154,800 -$80,000
Pro Forma
Increment $2,770,241 $1,979,067
ICNU_DR_113 Attachment M Page 17 of 24

ICNU_DR_113 Attachment M Page 18 of 24

0
200
400
600
800
1000
1200
1400
1600
20
1
0

20
1
1

20
1
2

20
1
3

20
1
4

20
1
5

20
1
6

20
1
7

20
1
8

20
1
9

Cu
m
u
l
a
t
i
v
e

C
o
s
t

P
r
o
j
e
c
t
i
o
n
s
Mi
l
l
i
o
n
s

Year
No Action Case Current Case 5 Year Case Optimized Case
ICNU_DR_113 Attachment M Page 19 of 24

Figure 9, Cumulative Cost Comparison Curve
0
200
400
600
800
1000
1200
1400
1600
20
1
0

20
1
1

20
1
2

20
1
3

20
1
4

20
1
5

20
1
6

20
1
7

20
1
8

20
1
9

Cu
m
u
l
a
t
i
v
e

C
o
s
t

P
r
o
j
e
c
t
i
o
n
s
Mi
l
l
i
o
n
s

Year
No Action Case Current Case 5 Year Case Optimized Case
ICNU_DR_113 Attachment M Page 20 of 24
Appendix A - Enhanced risk tree and development of co-dominant stem removal programs

ICNU_DR_113 Attachment M Page 21 of 24
2011 Rate Case information
Enhanced risk tree and development of co-dominant stem removal programs

BACKGROUND – Codominant Stemmed Trees

Coniferous trees with good structure are characterized by a single dominant leader, strong branch unions without bark inclusion,
whereas, trees with compromised structure, such as ones with a co-dominant stem, have more potential to fail in severe weather
events. Many studies have found that trees fail due to structural issues like codominant stems and bark inclusions.

Codominant stems originate from the same point on the tree. Included bark is bark pinched between two stems creating a weak
union, and stems with a tight ‘V’ shaped union are often accompanied by included bark. This union is weak because the bark
inclusion prevents any physical connection between the two stems. A co-dominant stem will split from a tree because of a weak
branch connection and included bark.

Most codominant stemmed trees are healthy, intact trees which can be negatively impacted by extreme wind, snow and ice loading.
Codominant stems that fail can make a bridge between phases resulting in sparking and arching, which could result in a devastating
fire and/or an overall outage of the line.

There will be a need to employ additional qualified/certified tree assessors and software developed to address the codominant stem
population throughout Avista’s service territory.

BACKGROUND – Enhancement of Risk Tree Identification and Removal Program

All trees have the potential to fail, and any tree failure has the potential to cause property damage, injury or death. Currently, field
reviews have shown that the majority of tree-related outages are due to tree failures and most of these trees are outside of the right
of way. Avista seeks to drive down outages due to tree failures through an enhanced risk tree removal program.

A risk tree is defined as dead, diseased or dying tree, however, a many of trees that fail have no visible fault indicators which make it
difficult to justify as removals. Risk assessment does not mean just finding dead trees and branches, as any defects such as internal
decay are hidden and require a higher level of inspection to identify.

ICNU_DR_113 Attachment M Page 22 of 24
Studies show common annual tree mortality to be 1% to 3% and there is an ongoing residual population of risk trees. Tree mortality
rates will depend on tree species and conditions. It has been found that tree failures increase rapidly at wind speeds over 60 mph.

Risk is directly related to the number of trees within striking distance of the line. All trees are susceptible to failure and all trees
capable of striking the line represent liability. The risk can be mitigated by decreasing the number of trees capable of striking the
line.

A risk assessment program allows for prudent use of ratepayer dollars because it clearly delineates action thresholds based on risk
tolerance, and ensures that money is being spent in areas that provide the biggest reliability return and lowers liability, both for the
least cost.

Avista plans to follow up with risk tree evaluation 2 years after the cycle trim is completed on specific circuits which dictate needing
the work performed.

There will be a need to employee additional qualified/certified tree risk assessors and software developed to address this
enhancement and to identify the risk tree population throughout Avista’s service territory.

IN CONCLUSION –

Tree related outages are an expression of the tree liability, therefore resulting in the utility’s overall liability associated with tree
failures.

DEVELOPMENT OF CODOMINANT STEM REMOVAL PROGRAM - Codominant stemmed trees should either be removed, or
structurally pruned in a fashion where a dominant leader is developed, which is usually the largest stem.

ENHANCEMENT OF RISK TREE REMOVAL PROGRAM - Avista would like to revise the current risk tree inspection process to a cycle
being performed on a more frequent basis to insure right of ways are reviewed two years after normal cyclic trimming has been
completed. We will also focus on problem tree species.

DEVELOPMENT OF AN ELECTRONIC TREE INVENTORY SYSTEM – Avista needs to review, inventory and assess its tree population.
We are proposing the development of an electronic data gathering system to capture that information. This data will be our base in
ICNU_DR_113 Attachment M Page 23 of 24
the development, prioritization and scheduling associated with the annual integrated vegetation management work plan(s). The
data will also be utilized for reporting purposes.

We will utilize GIS/AFM to review past tree related OMT events as an additional tool to help develop and prioritize the work plan(s).

ADDITIONAL FTE REQUIREMENTS (Per our conversation 3/3/11) –

1 Program Manager
2 pre-auditors / work planners
1 technician (focus on AFM/GIS/Electronic data gathering information and other duties)
At least 2 each 3-man tree crews

ICNU_DR_113 Attachment M Page 24 of 24
1

2012 Wood Pole Management – Complete System Analysis
Background
Avista’s Wood Pole Management Department is tasked with overseeing the maintenance and repair of the wood poles
in Avista’s electric transmission and distribution systems. Part of the wood pole management program involves
inspecting all of the poles in the distribution system on a twenty year cycle and conducting maintenance as needed to
avoid future failures, which have the potential to cause an outages. Avista’s Asset Management Department has
conducted some analysis that looks very closely at the current twenty year inspection interval. The intent of this report
is to communicate the details of that analysis.
Model Assumptions
The following assumptions were made in the construction of the distribution system model
Poles
The electric distribution system consists of 246,000 wood distribution poles
Poles that fail will be replaced with another equivalent (45’) cedar wood pole
Poles that do not meet code requirements are either reinforced with a steel stub or replaced with
another equivalent (45’) cedar wood pole
The age of the poles is based on the age distribution of a representative sample
The poles are inspected on a 20 year interval
Cross arms
Each of the 246,000 poles has one cross arm
The age of the cross arm is initially assumed to be the same as the age of the pole
Pin
Each of the 246,000 poles has three pins
The age of the pins is initially assumed to be the same as the age of the pole
Insulators
Each of the 246,000 pole locations has three insulators
The age of the pins is initially assumed to be the same as the age of the pole
Transformers
There are approximately 118,000 transformers in the distribution system
The age of the transformers is based on the age distribution of a representative sample
Lightning Arrestors
Each transformer has one lightning arrestor
The age of the lightning arrestor is initially based on the age of the transformer at each location
Wildlife Guards
Each transformer has one wildlife guard
The age of the wildlife guard is initially based on the age of the transformer at each location
Cutout
Each transformer has one cutout
The age of the cutout is initially based on the age of the transformer at each location
Ground Rod
Each pole with a transformer has one ground rod
The age of the ground rod is initially based on the age of the transformer at each location

ICNU_DR_113 Attachment N Page 1 of 11
2

Model Assumptions (cont.)
Since the actual age of the distribution components is not exactly the same as the pole or transformer, the model’s
initial predictions don’t match the 2011 actual replacement quantities. The initial values and the errors can be seen in
Figure 1.

Figure 1
Error in initial calculations due to unknown age of components

It can be seen from the chart above that the model fairly closely predicts the number of replaced failed poles, stubbed
poles stubbed and transformers that are replaced (all highlighted green). The other components which have age profiles
based on either the poles or the transformers are not as accurate so the failure curves of each component were shifted
so that the predictions would more closely match the 2011 replacements. Figure 2 below, shows the actual failure data
points and the adjusted failure curve that is used by the software to calculate failures.

Figure 2
Offsetting Weibull Curve

ICNU_DR_113 Attachment N Page 2 of 11
3

Analysis Results - 20 yr Inspection vs. No Inspection

The system was modeled to closely match the current scenario where each pole and its additional components are
inspected on a twenty year cycle. This case was compared to a hypothetical case where no inspection was completed.
Results from this comparison show that a twenty year inspection cycle has financial benefits to the customer. The results
can be seen tabulated in Figure 3 and graphically in Figure 4.

Figure 3
Comparison of Financial Data Between 20 yr inspection and no inspection
Figure 4
Cumulative Cost Comparison

Figure 5
20 yr Inspection vs. No Inspection - Labor Prediction Comparison
ICNU_DR_113 Attachment N Page 3 of 11
4

Figure 6
20 yr Inspection vs. No Inspection – Effects Prediction Comparison
ICNU_DR_113 Attachment N Page 4 of 11
5

Figure 7
20 yr Inspection vs. No Inspection - Equipment Prediction Comparison

Figure 8
20 yr vs. No Inspection - Spares Prediction Comparison

ICNU_DR_113 Attachment N Page 5 of 11
6

Analysis Results - Inspection Interval Optimization

In addition to comparing our current inspection scenario to a case where no inspection is done, analysis was conducted
to see if a shorter or longer maintenance interval would be more cost effective. Five, ten, fifteen and twenty year
inspection intervals were compared. The results of this comparison show that increasing the frequency of the inspection
to approximately 10 yrs would yield financial advantages. A separate calculation was also done within Availability
Workbench to optimize the inspection interval. This calculation shows that there is a slight advantage to increasing the
inspection interval to approximately eight years. The results of this calculation can be seen in Figure 12. The charts and
figures below show the comparison between the current base case 20yr inspection interval with a 10yr inspection
interval as well as a comparison between the 10 year inspection interval and the no inspection case.

Figure 9

Figure 10

Figure 11
ICNU_DR_113 Attachment N Page 6 of 11
7

Figure 12
Optimization of Inspection Interval

Figure 13
20 yr vs. 10 yr Inspection - Labor Prediction Comparison
ICNU_DR_113 Attachment N Page 7 of 11
8

Figure 14
20 yr vs. 10 yr Inspection - Effects Prediction Comparison
ICNU_DR_113 Attachment N Page 8 of 11
9

Figure 15
20 yr vs. 10 yr Inspection - Equipment Prediction Comparison
ICNU_DR_113 Attachment N Page 9 of 11
10

Figure 16
20 yr vs. 10 yr Inspection - Spares Prediction Comparison

ICNU_DR_113 Attachment N Page 10 of 11
11

Recommendations –

While the advantage is slight, all of the analysis indicates that increasing the frequency of inspection would yield
financial benefits to the customers. It may not be practical to immediately increase the inspection frequency to 10 years
but the goal should be to increase the inspection interval on a regular basis until such time as the number of yearly pole
replacements per year begins to stabilize. Although the budgetary requirements for increasing the inspection frequency
are considerably more than the current 20 year inspection frequency (See Figure 17Figure 17) the increased costs will
ultimately yield financial advantages as few poles are replaced each year. (See Error! Reference source not found.).

Figure 17

ICNU_DR_113 Attachment N Page 11 of 11

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 113 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 10:5. Can the Company provide any additional explanation about the level of investment Avista needs “to further optimize our facilities,” including any Company relevant policies or studies?
RESPONSE:

Avista’s facilities are assessed individually as to the potential for improved efficiency, replacement cycle, available technology, maintenance and repair history, operating performance, and other factors to
determine levels of investment. These criteria are part of an asset management process that the Company
uses to determine optimal maintenance and replacement practices.

Please see examples of the asset management reviews conducted in Attachments A – N. Due to the voluminous nature of these attachments they are being provided in electronic format only.

Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 113C. Please note that
Avista’s response to ICNU – 113C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/03/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 114 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 11, Illustration No. 1. Please reconcile the planned capital expenditures in Mr. Thies’s exhibit with forecasted net plant investment in Exhibit No.__(SLM-1T) at 11, Illustration No. 7.
RESPONSE:
Page 11, Illustration No.1 in Mr. Thies’s testimony, represents gross capital spend. Illustration No. 7 in
Mr. Morris’s testimony represents net plant investment. The net plant investment is comprised of capital transfers to plant net of accumulated depreciation. The difference between these two charts is therefore,
the construction work in progress balances, as well as the current and accumulated depreciation.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 115 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 11:13-15. Does the Company have any data which can be provided in support of Mr.
Thies’s testimony? If yes, please provide a table or chart, with supporting data, showing an annual comparison of funded v. unfunded departmental requests for new capital investments, from 2005 to the
present.
RESPONSE:

Prior to 2009, the various departments only submitted the highest priority projects that fully utilized their allocated portion of the capital budget.

Year Total Requests Funded Requests Unfunded Requests
2009 $261 $202 $59
2010 $259 $210 $49 2011 $291 $230 $61
2012 $269 $250 $19
2013 $320 $266 $54
2014 $386 $331 $55

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/02/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 116 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 16:5-8. Is the Company’s “planning process” referenced by Mr. Thies conducted by Avista’s Capital Planning Group? If no, please explain this planning process in more detail, including the
groups and individuals involved.
RESPONSE:

No, the planning process is referring to the Company’s financial planning process which forecasts the expected financial position, results of operations and cash flows based on expected conditions and
forward-looking assumptions. The Financial Planning and Analysis group has the primary responsibility
for the financial forecast with inputs from various other departments. These other departments are
primarily accounting, treasury, tax, rates, energy resources, energy delivery and information technology.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 3/2/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark T. Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 117 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 21:1-2. Regarding the Company’s most recent debt issuance (in 2014) at a rate of 4.11%,
did Mr. Thies assume a 5.5% cost for this same issuance in Avista’s last rate case? If no, please explain.
RESPONSE: When the previous rate case was initially prepared in January of 2014, a 5.5% cost was assumed for the
2014 debt issuance based on the most recent interest rate forecast. Subsequently, this cost was updated to
5.125% and then further updated to 4.5%. As footnoted in Exhibit MTT-2 page 3, coupon rates may change depending on market conditions.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 3/2/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark T. Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 118 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 28:20. Please provide a narrative response explaining the Company’s policy and/or
position on evaluating “challenging credit markets,” including an assessment of whether Avista is presently in a “challenging” credit market.
RESPONSE:
The Company continuously monitors the credit markets through various avenues. Daily, weekly,
monthly, and quarterly reports, commentary, and market updates are obtained from a variety of sources including different banks, capital market groups, and rating agencies.

Avista currently has access to credit under reasonable terms. However, the dynamics of the credit market
are in constant change. In every market environment, Avista must compete with alternate choices
available to potential investors. A stronger credit rating will attract more investors on terms more favorable to the Company, and a weaker credit rating could reduce or eliminate the number of potential
investors which may result in higher costs of capital and more difficulty accessing the capital markets on
reasonable terms.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 3/2/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark T. Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 119 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 29:3-14. What is the median credit rating for utilities in Illustration No. 7? RESPONSE:

The median credit rating for utilities in Illustration No. 7 is BBB.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 120 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 6:19-21, and 9:20-22. Please provide any Company studies relied upon by Mr. McKenzie in support of his testimony that an increased return on equity (“ROE”) is justified by the Company’s
reliance on hydroelectric generation and dependence upon natural gas fueled capacity.
RESPONSE:
Mr. McKenzie did not rely on any company studies to support his testimony that investors consider the
exposures associated with Avista’s reliance on hydroelectric generation in their appraisal of the Company’s overall risks and their required rate of return.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 121 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 9:23. Please provide support for Mr. McKenzie’s testimony that Avista has been
chronically unable to earn its allowed ROE. RESPONSE:
See Avista’s response to ICNU_DR_029 for consolidated Washington electric and natural gas operations
ROE on an actual basis, for the period 2001 through 2014. See also Avista response to ICNU_DR_004 for Avista’s consolidated Washington electric and natural gas operations return on equity ROE on a
normalized basis for the period 2009-2013.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: A. McKenzie/M. Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 122 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 6:26. Please reconcile Mr. McKenzie’s testimony concerning “[w]idespread expectations for higher interest rates” with the Company’s “ability to take advantage of historically low rates” and
Avista’s “plan to continue issuing long-term debt with various maturities for the foreseeable future,” as
testified by Mr. Thies in Exhibit No.__(MTT-1T) at 21:13-22.

RESPONSE:

There is no contradiction between the testimony of Mr. Thies and Mr. McKenzie concerning interest
rates. While both witnesses, Mr. Thies and Mr. McKenzie, refer to interest rates, the particular cited
comments from Mr. Thies are related to how the Company uses debt financing while Mr. McKenzie is describing considerations related to the return on equity. Both witnesses emphasize uncertainty about
interest rates.
In Mr. Thies’ testimony in Exhibit No.__(MTT-1T) at 21:13-22, he describes the Company’s approach in
achieving a balanced debt portfolio with regards to the weighted average maturity of the debt. Issuing
debt at varying maturities allows the Company to manage future debt maturities and diversify among interest rates at both ends of the yield curves. Additionally, Mr. Thies states that we are in a historically
low interest rate environment at both the short and long end of the yield curve. Mr. Thies also explains in
his testimony that the Company hedges the interest rate risk on forecasted debt issuances, which mitigates
the risk of uncertain future interest rates for those debt issuances. This is compatible with Mr. McKenzie’s
testimony, where he refers to considerations relevant to an evaluation of investors’ expectations and a fair and reasonable return on equity. Mr. McKenzie points out that the WUTC should consider the investment
community’s expectation that the historically low interest rate environment will not persist indefinitely, as
well as the implications of current capital market conditions and expectations in evaluating the results of
quantitative methods. Mr. McKenzie describes the importance of considering widely-held expectations
that interest rates will rise materially from current levels estimating investors’ required rate of return.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 123 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 6:32-33. Please provide any studies considered by Mr. McKenzie in support of his testimony that “[s]ensitivity to financial market and regulatory uncertainties has increased dramatically.”
RESPONSE: Concerns over the ability to recover costs on a timely basis have become increasingly pronounced in the
utility industry, as evidenced by the widespread adoption of regulatory mechanisms to address these
uncertainties, which was discussed at pages 45-51 of Mr. McKenzie’s testimony. Meanwhile, the impact of recent dislocations in capital markets on investors’ expectations was discussed at pages 16-23 of Mr.
McKenzie. Copies of all source documents referenced in Mr. McKenzie’s testimony were included in his
workpapers, which have been previously provided.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 124 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 9:17-20. Please explain the “[r]ecent challenges” of “interest rate risk,” including the testimony of Mr. Thies concerning “historically low rates,” in Exhibit No.__(MTT-1T) at 21:14.
RESPONSE:
Please refer to the response to ICNU-122.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 125 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 9:23-25. As in this case, did Mr. McKenzie testify in Avista’s last rate case: “Due to broad-based expectations for higher bond yields, current cost of capital estimates are likely to understate
investors’ requirements at the time the outcome of this proceeding becomes effective and beyond”? If
yes, does the Company agree that the average utility bond yield in 2014 was lower than in 2013, as stated
in Exhibit No.__(AMM-9), page 3?
RESPONSE: In estimating the cost of equity, the focus is on investors’ expectations. As in Case Nos. UE- 140188/UG-
140189, Mr. McKenzie’s conclusions regarding expectations for higher interest rates in the near-term are
based on independent, third-party forecasts that provide an objective basis to evaluate the opinions of
investors. Mr. McKenzie agrees that the average yield on utility bonds for 2014 proved to be slightly lower than 2013, but the fact that the actual trend in interest rates will invariably depart from forecasts
does not alter the fact that capital costs are expected to rise in the near-term. As the Federal Energy
Regulatory Commission has observed, for example, “the cost of common equity to a regulated enterprise
depends upon what the market expects, not upon what ultimately happens.” 147 FERC ¶ 61,234 at P 88
(2014) The very same is true of investors’ expectations for higher interest rates, and the fact that past forecasts have not materialized does not undermine reference to this evidence.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 3/2/2015
CASE NO: UE-150204 & UG-150205 WITNESS: A. McKenzie/M. Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 126 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 13:6-7. Has Avista considered decreasing capital expenditures, to address Moody’s “primary credit concern for Avista” caused by increasing capital expenditures?
RESPONSE:

A range of factors influences the level of capital expenditures made each year, including, among other things,: 1) the level of investment needed to meet safety, service and reliability objectives and to further
optimize our facilities; 2) the degree of overall rate pressure faced by our customers; 3) the variability of
investments required for major projects; 4) unanticipated capital requirements, such as an unplanned
outage on a large generating unit; 5) the cost of debt and 6) the opportunity to issue equity on reasonable
terms.
Capital expenditures involve multi-year planning horizons and are subject to continuing review and
adjustment based on the influences of the factors described above, among others, which partly rely on our
credit ratings. In Moody’s report, their statements about capital expenditures acknowledge that the
Company has increased its cap-ex levels compared to a few years ago and further note that recovery of costs through the regulatory process is a key ratings driver.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 127 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 13:17-18. Does Mr. McKenzie consider Avista a typical smaller firm that is “more risky” than larger counterparts due to “relative lack of diversification,” given the testimony of Mr. Morris
concerning the Company’s historical “preservation of a diversified portfolio of low cost resources,” in
Exhibit No.__(SLM-1T) at 15:1-3?

RESPONSE: Mr. Morris’s testimony concerning the benefits associated with Avista’s generating resources does not
contradict Mr. McKenzie’s position that Avista’s size relative to other publicly traded electric utilities
imparts a degree of uncertainty that is not faced by larger entities with greater diversification and
resources. While Mr. McKenzie has made no adjustment to his recommended ROE to account for the
size disparity between Avista and the average firm in the electric utility industry, this factor provides additional support for his conclusion that Avista’s requested ROE of 9.9 percent is conservative.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/06/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 128 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to 35:17-39:6. Has Mr. McKenzie based his flotation cost adjustment on known and measurable Avista costs?
RESPONSE:
As discussed in Mr. McKenzie’s testimony at pages 36-37, there are no established conventions to
account for the known and measurable flotation costs associated with the sale of common stock. As a result, the most common method to account for flotation costs in regulatory proceedings is to apply an
average flotation cost percentage to the utility’s dividend yield. The flotation cost adjustment discussed
by Mr. McKenzie is directly comparable to that approved by the WUTC in Docket No. UE-991696.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 129 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 14:3-5. Is Mr. McKenzie’s testimony a legal opinion, that “the legal tests embodied in the Hope and Bluefield cases cannot be met,” unless certain compensation is provided in the rate of return? If
no, please provide all studies relied upon by Mr. McKenzie in support of his testimony.

RESPONSE:
Mr. McKenzie is not an attorney and his testimony does not render any legal opinions; rather, his
testimony addresses the implications of Hope and Bluefield for a just and reasonable ROE from the
standpoint of his position as a financial expert.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 130 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 14:17-18. Does the Company agree that the Commission uses a “modified” historic test year approach to ratemaking, rather than an unqualified “historical test year” approach, as referenced by
Mr. McKenzie?

RESPONSE:
Mr. McKenzie’s statement at 14:17-18 does not reference an “unqualified” historical test year. Rather, he
notes that investors are concerned with the actual returns achieved by the utility. Adjustments to
historical test year data or use of a future test year are consistent with the goal of allowing the utility a
reasonable opportunity to earn its allowed ROE.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 131 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 16, n.14. Regarding Mr. McKenzie’s testimony concerning the connection between “[e]conomic logic and common sense” and what “investors expect,” please provide a narrative response
explaining Mr. McKenzie’s policy and/or position on the application of the efficient-market hypothesis to
his testimony.

RESPONSE:
The efficient market hypothesis theorizes that investors are rational and that the market prices of financial
assets, such as utility common stocks, fully reflect investors’ assessment of all information relevant to an
evaluation of risk and expected returns. The efficient market hypothesis underlies the market-based
approaches relied on in Mr. McKenzie’s testimony to develop estimates of investors’ required rate of return.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 132 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 17:29-31. Does Mr. McKenzie agree with the recent observation of Federal Reserve President Charles Plosser “that U.S. interest rates are unprecedentedly low”?
RESPONSE:

Yes.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 133 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 17, Figure 1. Please confirm that the December 2014 average utility bond yield of 4.70%, as represented in Figure 1, is 55 basis points lower than the December 2013 average bond yield
represented by Mr. McKenzie, in the comparable “Figure 1” included in his testimony filed in Avista’s
2014 GRC.

RESPONSE:
Yes.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 134 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 18:1-37. Please confirm that, in February 2014, Mr. McKenzie testified to the following in Avista’s 2014 GRC, just as in the current proceeding: a) investors do not anticipate that very low
interests rates will continue into the future; and b) “highly regarded and widely referenced” forecasting
services evince “a clear consensus expectation in the investment community that the cost of long-term
capital will be significantly higher over” the next five years than it is currently.
RESPONSE:
a) The evidence provided in Mr. McKenzie’s testimony in Avista’s 2014 GRC indicated that investors
did not anticipate that very low interest rates would continue into the future, and that continues to be
the case presently, as evidenced by Figure 2 to Mr. McKenzie’s testimony in this case. b) The evidence provided in Mr. McKenzie’s testimony in Avista’s 2014 GRC indicated that the
projections of highly regarded and widely referenced forecasting services evidenced prevailing view
that the cost of capital was expected to increase, and this continues to be the case presently, as
evidenced by Figure 2 to Mr. McKenzie’s testimony in this case.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 135 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 18:5-37. Please confirm that: a) Mr. McKenzie used the same forecasting service sources to present future “interest rate trends” in Figure 2, as Mr. McKenzie used in the comparable “Figure 2,”
included in his testimony filed in February 2014 in Avista’s 2014 GRC; and b) the 10- and 30-Year
Government interest rate trend estimates for December 2014, figured by Mr. McKenzie in his February
2014 testimony (i.e., Figure 2), were each higher than the actual interest rates depicted in current
testimony, as starting points in Figure 2.
RESPONSE:
a) Mr. McKenzie consistently referenced the same sources of interest rate projections in his testimony
in Avista’s 2014 GRC and in this case. b) Please also refer to the response to question 134 (b).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 136 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 18:9-34. Please confirm that Mr. McKenzie used the same sources for both Figure 2 and for exhibits supporting his “Capital Market Estimates” in Section III of his testimony.
RESPONSE:

The projected interest rates used in Section III of Mr. McKenzie’s testimony were drawn from the same sources used to develop Figure 2 to his testimony.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 137 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 19:5-11 and 19, n.18. In both the referenced testimony and his February 2014 testimony in Avista’s 2014 GRC, did Mr. McKenzie rely on the same 2013 article and quotation from The Wall Street
Journal to support testimony that reductions in the Federal Reserve’s bond buying program should ease
downward pressure on long-term interest rates?

RESPONSE:
The article cited at n. 18 to Mr. McKenzie’s testimony in this case was one source relied on by Mr.
McKenzie to support the observation in his testimony in Avista’s 2014 GRC and in his testimony in this
case that reductions in the Federal Reserve’s stimulus program are widely expected to result in higher
interest rates going forward.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 138 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 22:12-13. As in the referenced testimony, did Mr. McKenzie also testify in February 2014 in Avista’s 2014 GRC that “current capital costs are not representative of what is likely to prevail over the
near-term future”? (Emphasis added). If yes, please indicate whether Mr. McKenzie’s assessment of
what was “likely” proved accurate, over the twelve-month period between the filing of his 2014 GRC
testimony and his current testimony.
RESPONSE:
As indicated in response to ICNU’s question nos. 133 and 134, the evidence continues to indicate
expectations for higher capital costs over the near-term future. While interest rates have fluctuated over
the intervening period since his testimony in Avista’s 2014 GRC was prepared, they are currently lower than they were at that time, as evidenced by the response to INCU’s question no. 133.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 139 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 23:19-24:3. For each of the following factors identified by Mr. McKenzie as having implications for the financial standing of utilities, please indicate whether Mr. McKenzie agrees that these
factors potentially affect all electric utilities, constantly: a) “the possibility of volatile fuel or purchased
power costs”; b) “uncertain environmental mandates and associated costs”; and c) “implications of
declining demand associated with economic weakness or structural changes in usage patterns.” If no,
please explain and provide support (e.g., identifying and demonstrating certain periods in which utilities did not face any possibility of volatile fuel or purchased power costs).
RESPONSE:

While Mr. McKenzie agrees that the factors enumerated in his testimony at 23:19-24:3 are relevant to investors’ evaluation of the risks inherent in the utility industry generally, the extent to which individual utilities are exposed to these risks may vary considerably.

ICNU_DR_140 Attachment A Page 1 of 2
ICNU_DR_140 Attachment A Page 2 of 2

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 140 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 34:4-9. Please provide any studies or academic support for use of an adjusted beta in an ECAPM analysis.
RESPONSE:

The need to adjust for the observed tendency of beta values to regress towards the market mean of 1.00 is well supported in the financial research. This adjustment is separate and apart from the refinement
reflected in the ECAPM, which is designed to correct the results of the traditional CAPM approach to
reflect the observed tendency of beta values to underestimate investors’ required return for low beta
stocks and overestimate the return for high beta stocks. Please refer to INCU_DR_140 Attachment A an
excerpt from New Regulatory Finance.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 141 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 35:4-9. Please provide a narrative explanation of the consideration of investment risk differentials in Mr. McKenzie’s implementation of the risk premium method.
RESPONSE:

Please refer to Exhibit No.___(AMM-3), pages 26 through 30 and Exhibit No.___(AMM-9). As indicated there, Mr. McKenzie accommodated risk differences by applying the electric utility industry
equity risk premium determined using average utility bond yields over the study period to the average Baa
utility bond yield corresponding to Avista’s current credit ratings.

ICNU_DR_142 Attachment A Page 1 of 5
ICNU_DR_142 Attachment A Page 2 of 5
ICNU_DR_142 Attachment A Page 3 of 5
ICNU_DR_142 Attachment A Page 4 of 5
ICNU_DR_142 Attachment A Page 5 of 5

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 142 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 35:6-9. Please provide any studies or academic support relied upon for testimony concerning the inverse relationship between equity risk premiums and interest rates.
RESPONSE:

Please refer to WP-39 and WP-40 contained in Mr. McKenzie’s workpapers, which were previously provided. Please also refer to ICNU_DR_142 Attachment A an excerpt from New Regulatory Finance.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 143 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 36:17-20. Given that Mr. McKenzie testifies that “there is no accounting convention to accumulate the flotation costs associated with equity issues,” please provide a narrative response
explaining how the Company will demonstrate actual and verifiable flotation expenses in support of
Avista’s proposed flotation cost adjustment.

RESPONSE:
The absence of an established convention to account for flotation costs associated with past issuances of
common stock means that it is not possible to compile “actual and verifiable” flotation costs, as is
normally the case with other reasonable and necessary expenses that the utility incurs in order to provide
service. Nevertheless, as Mr. McKenzie indicates in his testimony flotation costs are a legitimate cost that is necessary to raise the equity capital supporting the utility’s investment required to provide service to
customers, and failing to recognize these reasonable and necessary expenses will undermine the utility’s
ability to earn investors’ required rate of return.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 144 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 37:9-10. Is Mr. McKenzie aware of any Commission orders approving a flotation cost adjustment which included retained earnings? If yes, please indicate any such orders.
RESPONSE:

No, and Mr. McKenzie is not proposing such an adjustment in this proceeding.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 145 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 38:16-39:6. In the order quoted by Mr. McKenzie, please confirm that the Commission did not consider retained earnings as part of a flotation cost adjustment. If Mr. McKenzie cannot confirm,
please provide a pinpoint citation in that order which demonstrates that the Commission considered
retained earnings as part of a flotation cost adjustment.

RESPONSE:
As indicated in the quotation on page 38-39 of Mr. McKenzie’s testimony, the flotation cost adjustment
approved by the WUTC in Docket No. UE-991606, which is directly analogous to Mr. McKenzie’s
recommendation in this case, was to compensate Avista “for costs incurred from past issues of common
stock.”

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 03/24/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Adrien McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 146 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 39:2-4. Please provide all factual evidence that Avista has not been compensated for all costs incurred from past issuances of common stock.
RESPONSE:

As discussed in Mr. McKenzie’s testimony at pages 35-36, flotation costs are not recorded on the books of the utility and recognized in the cost of service. Because there is has been no consistently approved
mechanism for Avista to recover flotation costs, there is no basis to conclude that Avista has been
compensated for these costs.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Adrien McKenzie
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 147 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide copies of all publications and credit reports referenced in the direct testimony and exhibits of Mr. McKenzie.

RESPONSE:
All publications and credit reports referenced in Mr. McKenzie's testimony and exhibits, with the
exception of regulatory and court orders which are publicly available from the respective agencies, are
contained in his workpapers, which were previously provided.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 148 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all of Mr. McKenzie’s and Mr. Thies’s exhibits and workpapers in an electronic spreadsheet with all formulas and links intact.

RESPONSE:
All available exhibits and workpapers, in electronic format, were provided with the original filing.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 149 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide copies of all credit reports published by Standard & Poor’s (“S&P”), Moody’s and Fitch Ratings for Avista and all affiliate companies issued over the last two years.

RESPONSE:
ICNU_DR_149 Attachment A through Y are copies of each Moody’s1 (Attachments A - K) and Standard
& Poor's (Attachments L - O) credit rating reports related to the Company issued over the last two years.
Due to the voluminous nature of the reports they are being provided in electronic format only.

1 As of May 20, 2011, Fitch Ratings affirmed and simultaneously withdrew its ratings for Avista Corp. This withdrawal was
based on a business decision by Avista Corp. to discontinue its annual subscription with Fitch.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/25/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 150 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide complete copies of all credit reports issued by S&P, Moody’s and Fitch Ratings that discuss the current electric and natural gas utility industries.

RESPONSE:
Please see the Company’s response to ICNU_DR_149 for credit reports related to the Company. The
volume of reports related to the utility industry issued by S&P and Moody’s would be voluminous and
burdensome to provide. These reports are available on sight for review through S&P and Moody’s web
portals.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 151 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the most recent senior secured, unsecured and corporate credit ratings of Avista assigned by S&P, Moody’s and Fitch. Also, please provide Avista’s S&P business and financial risk profiles.

RESPONSE:
Please see Thies Exhibit No.___ (MTT-2) page 1 for the current ratings by Standard & Poor's and
Moody's1. Avista’s S&P business risk is “Strong” and the current financial risk is “Significant”.

1 As of May 20, 2011, Fitch Ratings affirmed and simultaneously withdrew its ratings for Avista Corp. This withdrawal was
based on a business decision by Avista Corp. to discontinue its annual subscription with Fitch.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 152 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide copies of all correspondence, presentations and all other materials that Avista provided to credit and equity analysts over the last two years.

RESPONSE:
Date Purpose Company Reps Audience

ICNU_DR_152 Attachment A
February 2013 Business Update Mark Thies Equity analyst and Investors
MWR Kevin Christie Jason Lang

ICNU_DR_152 Attachment B
March 2013 Business Update Mark Thies Equity analyst and Investors
UBS Kevin Christie Jason Lang

ICNU_DR_152 Attachment C
March 2013 Business Update Mark Thies Equity analyst and Investors
Sidoti & Co. Kevin Christie Jason Lang

ICNU_DR_152 Attachment D
March 2013 Business Update Mark Thies Equity analyst and Investors
West Coast Seminar Kevin Christie Jason Lang

ICNU_DR_152 Attachment E
May 2013 Business Update Scott Morris Equity analyst and Investors
American Gas Assoc Mark Thies Kevin Christie
Jason Lang

ICNU_DR_152 Attachment F
November 2013 Business Update Scott Morris Equity analyst and Investors Edison Elec. Inst. Mark Thies
Jason Lang

Page 2 of 2

ICNU_DR_152 Attachment G
December 2013 Business Update Mark Thies Equity analyst and Investors BMO Conference Jason Lang
& KeyBanc Conference

ICNU_DR_152 Attachment H
March 2014 Business Update Mark Thies Equity analyst and Investors West Coast Seminar Jason Lang

ICNU_DR_152 Attachment I
May 2014 Business Update Scott Morris Equity analyst and Investors
American Gas Assoc Mark Thies Jason Lang

ICNU_DR_152 Attachment J
September 2014 Business Update Mark Thies Equity analyst and Investors
UBS Jason Lang
ICNU_DR_152 Attachment K
November 2014 Business Update Scott Morris Equity analyst and Investors
Mark Thies
Rich Stevens Connie Hulbert
Jason Lang

ICNU_DR_152 Attachment L
December 2014 Business Update Mark Thies Equity analyst and Investors BMO Conference Jason Lang
& KeyBanc Conference

ICNU_DR_152 Attachment M
March 2015 Business Update Mark Thies Equity analyst and Investors UBS Conference Jason Lang

ICNU_DR_152 Attachment N
March 2015 Business Update Mark Thies Equity analyst and Investors
West Coast Seminar Jason Lang

Due to the voluminous nature of the reports they are being provided in electronic format only.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 4/20/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 153 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

In an electronic spreadsheet with all formulas intact, please provide the monthly average balances for construction work in progress and short-term debt for the most recent 13-month period.

RESPONSE:
Please see ICNU_DR_153 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/27/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Howard Grimsrud
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: 154 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the amount of capitalized interest paid during the test year related to construction projects for both electric and natural gas utility operations.
RESPONSE:

The capitalized interest for the period October 2013 through September 2014 for Washington electric and gas construction projects was:

Electric - $2,903,685
Gas - $759,780

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/25/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 155 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please state whether Avista has any off-balance sheet debt equivalents such as purchased power agreements and operating leases. If the answer is “yes,” provide the amount of each off-balance sheet
debt item and estimate the related imputed interest and amortization expense associated with these off
balance sheet debt equivalents.

RESPONSE:
Please see the Company’s response to ICNU_DR_028C for the requested information.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/21/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 156 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

In an electronic spreadsheet with all formulas intact, please provide the five-year projected and five-year historical capital structure, capital expenditures and capital funding.

RESPONSE:
Please see the Company’s response to INCU_DR_027C.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 4/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft/Jason Lang
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 157 TELEPHONE: [phone] EMAIL: [e-mail]
[e-mail]

REQUEST:
Please provide a detailed explanation of Avista’s dividend payment and debt financing plans through the
test period.

RESPONSE:
The company’s current dividend policy is to target an industry average payout ratio of 60% to 70%. The
Board of Directors considers the level of dividends on a regular basis, taking into account numerous
factors including, without limitation:

• our results of operations, cash flows and financial condition,
• the success of our business strategies, and
• general economic and competitive conditions.
The Company has a forecasted long-term debt issuance of $120,000,000 in September of 2015. Coupon
rate, tenor, and other details associated with the debt will be determined as the issuance date becomes
closer.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 4/22/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 158 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Do any of Avista’s outstanding long-term debt issues have call provisions? If the answer is “yes,” please provide a list of the callable issues with the following: (a) outstanding balance, (b) issuance date, (c)
maturity date, (d) coupon payment percent, (e) annual interest expense, and (f) call price (as a percent of
par).

RESPONSE:
Yes, see ICNU_DR_158 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 4/20/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 159 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Has Avista performed any debt refinancing feasibility studies on its outstanding debt issues? If the answer is “yes,” please provide the following:
a. A detailed description of the results from the study.
b. A detailed description of the conclusion(s) made by Avista based on the results of the
study.
c. All debt refinancing feasibility studies in an electronic spreadsheet with all formulas intact.
RESPONSE:
While Avista has not performed formal debt refinancing feasibility studies on its outstanding debt
issuances, it continuously monitors market conditions to assess interest rate trends and opportunities.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 160 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

For each month of the test year, please provide monthly peak demand and energy consumption on a total system basis and for each rate class on the Company’s system.

RESPONSE:
Please see ICNU_DR_160 Attachment A which contains data from the load study, summarized by
monthly system peak hour and monthly total energy consumption.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jody Morehouse/Scott Kinney
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 161 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a copy of the Company’s most recent Integrated Resource Plans for electric and gas operations that were approved by the Washington Utilities and Transportation Commission.

RESPONSE:
Please see Morehouse Exhibit JM-2 for the natural gas Integrated Resource Plan and Kinney Exhibit
SJK-2 for the electric Integrated Resource Plan.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 162 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide workpapers detailing the manner in which the demand and energy allocation factors in the Company’s class cost of service study were adjusted for line losses. Please provide these workpapers in
electronic format as a Microsoft Excel spreadsheet with all formulas intact.

RESPONSE:
The Company’s initial filing included the Electric Cost of Service workpapers in formula intact electronic
format files. The development of the loss factors used to adjust energy and demand allocation factors is
in the file named “2013 Losses.xlsx” TLK-E-134. These loss factors were provided to DNV GL as a
component of the load study demand results used for the demand allocation factors. These loss factors are
applied directly in the cost of service model class allocator worksheet TLK-E-123 (ASSIGN row 13, columns BG through BL) to determine the generation level consumption energy allocation factor.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 163 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a complete electronic copy of the Company’s class cost of service study as a Microsoft Excel spreadsheet, with all formulas intact.
RESPONSE:

The Company’s initial filing included the Electric Cost of Service workpapers in formula intact electronic format files. The Company’s class cost of service study is the file named “WAElec COS As Filed.xlsm”.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/23/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 164 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a complete electronic copy of the workpapers supporting the Company’s proposed revenue distribution as a Microsoft Excel spreadsheet with all formulas intact.
RESPONSE:
See the previously provided Excel workpaper file labeled “Ehrbar Electric Workpapers”.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 165 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide workpapers that demonstrate how the Company developed its distribution plant allocators in its class cost of service study to recognize differences in the voltage level of service (transmission, sub-
transmission, primary distribution and secondary distribution). Please provide these workpapers in
electronic format as a Microsoft Excel spreadsheet with all formulas intact. If voltage level distinctions
are not fully recognized in the development of the allocators, please explain in detail why not.
RESPONSE:
The Company’s initial filing included the Electric Cost of Service workpapers in formula intact electronic
format files. Distribution plant classification workpapers are included in the file named “Misc
Assign.xlsx” TLK-E-82 through TLK-E-98, tabs named “Substations”, “Primary-Secondary”, “DA Sch 25”, and “st lights”. All demand allocation factors include voltage level loss assumptions and the primary
purpose of the aforementioned workpapers is to determine voltage level distinctions and direct
assignments for distribution plant.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 166 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a table that shows a breakdown of the Company transmission and distribution plant in service by voltage level of service (transmission, sub-transmission, primary distribution and secondary
distribution). Please provide workpapers supporting the table in electronic format as a Microsoft Excel
spreadsheet, with all formulas intact.

RESPONSE:
Please see ICNU_DR_166 Attachment A. These values were derived from the cost of service study and
the workpapers supporting the voltage level distinctions were discussed in the Company’s response to
ICNU_DR_165.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: James Gall
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 167 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the monthly system peak demands on the Company’s system for each of the most recent five calendar years.
RESPONSE:

The table below is Avista’s native hourly load peak load by month since January 1, 2010.

Month 2010 2011 2012 2013 2014 2015
Jan 1,526 1,669 1,554 1,574 1,463 1,492
Feb 1,383 1,634 1,455 1,408 1,715 1,382
Mar 1,348 1,439 1,377 1,394 1,514 1,374
Apr 1,286 1,295 1,341 1,284 1,201 May 1,245 1,205 1,243 1,304 1,161
Jun 1,344 1,290 1,242 1,406 1,253
Jul 1,552 1,399 1,571 1,577 1,606 Aug 1,556 1,535 1,579 1,473 1,555 Sep 1,210 1,391 1,222 1,385 1,176
Oct 1,301 1,308 1,309 1,271 1,210
Nov 1,704 1,463 1,428 1,415 1,524 Dec 1,597 1,536 1,499 1,669 1,589

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 168 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 12:14-16. Please provide detailed workpapers showing the determination of the peak credit ratio and the resulting classification of generation and transmission fixed costs using the prior
method of comparing the ratio of the replacement cost per kW of the Company’s peaking units to the
replacement cost per kW of the Company’s thermal and hydro plants (separately). Please provide these
workpapers in electronic format as a Microsoft Excel spreadsheet with all formulas intact.
RESPONSE:
The Company’s initial filing included the Electric Cost of Service workpapers in formula intact electronic
format files. The determination of the various peak credit ratios using the prior method was provided in
the file named “Prior Peak Credit Detail.xlsx” TLK-E-181.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 169 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exhibit No.__(TLK-2) at 4:19-5:5. Please provide workpapers supporting the following calculations in electronic format as a Microsoft Excel spreadsheet, with all formulas intact:
a. The direct assignment of distribution demand-related costs to customer classes and the
justification for such direct assignment, including the direct assignment of specific
substations and related primary voltage distribution facilities to Extra Large General
Service customers based on their load ratio share of substation capacity.
b. The development of the allocator for distribution facilities that serve only secondary
voltage customers.

RESPONSE:
a. Please see the Company’s response to ICNU_DR_165.
b. A detailed table provided by DNV GL as part of the load study segregates the demand
results for Schedule 21 by voltage level, making it possible to exclude Schedule 21
customers served at primary voltage from this allocation factor. Schedule 25 is excluded
from this allocation factor entirely.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 170 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exhibit No.__(TLK-2) at 3:11-15. Please provide detailed workpapers showing the determination of the peak credit ratio and the resulting classification of generation and transmission fixed
costs using the electric system load factor. Please provide these workpapers in electronic format as a
Microsoft Excel spreadsheet with all formulas intact.

RESPONSE:
The Company’s initial filing included the Electric Cost of Service workpapers in formula intact electronic
format files. The electric system load factor calculation is provided in the file named “2013 System Load
Factor.xlsx” TLK-E-79.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: James Gall
TYPE: Data Request DEPT: Energy Resources
REQUEST NO.: ICNU – 171 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an extract from the Company’s energy trading information systems that details each and every power and gas transaction, including both physical and financial transactions, settled or delivered in
the period January 2010 through March 2013. Please include each and every field stored in the energy
trading system for each transaction and do not delete any columns or data from the extract.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 171C. Please note that
Avista’s response to ICNU – 171C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.
The requested transactions are included in ICNU_DR_171C Confidential Attachment A. Due to the
voluminous nature of the attachment it is being provided in electronic format only.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 172 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all workpapers necessary to link the AURORA net power cost report, titled “XDB WA 2016 Filing_80 Years_Test_Period_Load_040315_Fix,” into Mr. Johnson’s Exh. Nos. WGJ-2 through
WGJ-5, including any intermediary spreadsheets, with all links intact.

RESPONSE:
There are no workpapers necessary to link the AURORA net power cost report into Mr. Johnson’s Exh.
Nos. WGJ-2 through WGJ-5. The fuel cost and energy for non-hydro plants and the dollars and energy
for market purchases and sales are simply copied and pasted into the AURORA tab in Mr. Johnson’s Exh.
Nos. WGJ-2 through WGJ-5 worksheet.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 173 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide an updated version of Mr. Johnson’s Exh. Nos. WGJ-2 through WGJ-5, incorporating all
known updates and corrections to the Company’s net power supply costs. RESPONSE: Please see the Company’s response to Staff_DR_059 for a revised power supply pro forma exhibit and
Staff_DR_059C Confidential Attachment A the supporting AURORA output worksheets that incorporate
two changes to the power supply expense. These changes include a correction to the mark-to-market calculation of financial electric transactions and the inclusion of the actual expense for a “slice” purchase
from Chelan PUD.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 174 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please explain the purpose of the portfolio contracts entitled “COB Arbitrage Buy” and “COB Arbitrage Sell” in the AURORA model.
RESPONSE:

The Company purchases transmission from John Day to COB (PGE Firm Wheeling). This transmission is used to facilitate sales to California entities as either energy/REC sales or energy only sales. On
average, we assume we can make 50 aMW of sales at COB with a $3/MWh premium over the Mid C
price. The sale to Energy America is an energy/REC sale for 35 aMW at a price of Mid C index plus a
$3/MWh adder plus the REC adder. That leaves 15 aMW additional that can be sold at COB. The
portfolio contracts entitled “COB Arbitrage Buy” and “COB Arbitrage Sell” in the AURORA model and the line item labeled “COB Optimization” in the AURORA output file are the additional 15 aMW of
COB/Mid C arbitrage sales.

The line labeled “SMUD Sale – (Energy America)” in the pro forma year is the revenue from both the
Energy America sale (35 aMW x (AURORA Mid C flat price + $3/MWh) plus the additional 15 aMW times a $3/MWh spread between COB and Mid C. The REC adder for the Energy America sale in
Exhibit No. WGJ-2 is not included since REC revenue is not longer included in base power supply
expense. The AURORA model output line labeled “Energy America” contains the REC adder.

The SMUD sales was for 50 aMW priced at the COB index plus a REC adder. The test-year SMUD revenue included both the energy revenue and the REC revenue. The test-year SMUD revenue is higher
than the pro forma revenue because it was a different pricing point in a different year with different index
prices and includes the REC adder.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 175 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all supporting workpapers and analysis used to support the “Energy Min” and “Energy Max” values for the portfolio contracts entitled “COB Arbitrage Buy” and “COB Arbitrage Sell” in the
AURORA model.

RESPONSE:
Please see the Company’s response to ICNU_DR_174.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 176 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please identify the line in the Company power cost table, Exh No. WGJ-2, where the portfolio contracts entitled “COB Arbitrage Buy” and “COB Arbitrage Sell” are included. If these portfolio contracts are not
included in Exh No. WGJ-2, please provide an explanation of why they are excluded.

RESPONSE:
Please see the Company’s response to ICNU_DR_174.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: Thomas C Dempsey
TYPE: Data Request DEPT: Generation Production Support
REQUEST NO.: ICNU – 177 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all supporting data, analyses, and reports relied upon to forecast $9.3 million in Operations and Maintenance (“O&M”) for Coyote Springs 2 in the 2016 pro-forma period as detailed in Exh. No.
WGJ-2.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 177C. Please note that
Avista’s response to ICNU – 177C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.
The $9.3 million total Operations and Maintenance (“O&M”) for Coyote Springs 2 in the 2016 pro-forma
period is based on planned costs. The net increase above the test period (12ME 09.2014) level of expense
of $5.9 million is mainly due to the Hot Gas Path (HGP) maintenance planned for 2016 of $3.5 million
(system). A HGP major maintenance occurs on an approximate four-year cycle based on required hours
of operation. The prior HGP maintenance occurred in 2012. The Company plans to reach the hours of operations requiring the HGP maintenance in 2016.

See the Confidential attachment ICNU_DR_177C-Confidential Attachment A for a recap of the Hot Gas
Path maintenance cost of $3.5 million.
See also attachment ICNU_DR_177-Attachment C for the GE Energy “Heavy-Duty Gas Turbine
Operating and Maintenance Considerations” manual discussing the HGP maintenance and inspection
intervals.

Included as ICNU_DR_177-Attachment A is the monthly transaction history for the test period (12ME 09.2014) previously provided with Mr. Johnson and Ms. Smith workpapers. Included as ICNU_DR_177-
Attachment B is the monthly transaction detail for the 2016 monthly maintenance previously provided
with Mr. Johnson and Ms. Smith workpapers.
GE Energy
Heavy-Duty Gas Turbine
Operating and Maintenance
Considerations
GER-3620L.1 (10/10)
David Balevic
Steven Hartman
Ross Youmans
GE Energy
Atlanta, GA
ICNU_DR_177 Attachment C Page 1 of 60
ICNU_DR_177 Attachment C Page 2 of 60
Contents:
GE Energy | GER-3620L.1 (10/10)i
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Maintenance Planning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Gas Turbine Design Maintenance Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Borescope Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Major Factors Influencing Maintenance and Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Starts and Hours Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Service Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Firing Temperatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Steam/Water Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Cyclic Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Hot Gas Path Parts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Rotor Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Combustion Parts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Casing Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Exhaust Diffuser Parts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Off-Frequency Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Air Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Lube Oil Cleanliness. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Moisture Intake . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Maintenance Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Standby Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Running Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Load vs. Exhaust Temperature. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Vibration Level. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Fuel Flow and Pressure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Exhaust Temperature and Spread Variation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Startup Time. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Coast-Down Time. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Rapid Cool-Down . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Combustion Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Hot Gas Path Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Major Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Parts Planning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Inspection Intervals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Borescope Inspection Interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Hot Gas Path Inspection Interval. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Rotor Inspection Interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Combustion Inspection Interval. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Manpower Planning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
ICNU_DR_177 Attachment C Page 3 of 60
References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Appendix. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
Revision History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
ii ICNU_DR_177 Attachment C Page 4 of 60
Introduction
Maintenance costs and availability are two of the most important
concerns to a heavy-duty gas turbine equipment owner. Therefore,
a well thought out maintenance program that optimizes the
owner’s costs and maximizes equipment availability should be
instituted. For this maintenance program to be effective, owners
should develop a general understanding of the relationship
between the operating plans and priorities for the plant, the
skill level of operating and maintenance personnel, and all
equipment manufacturer’s recommendations regarding the
number and types of inspections, spare parts planning, and other
major factors affecting component life and proper operation
of the equipment.
In this document, operating and maintenance practices for
heavy-duty gas turbines will be reviewed, with emphasis placed
on types of inspections plus operating factors that influence
maintenance schedules. A well-planned maintenance program
will result in maximum equipment availability and optimization
of maintenance costs.
Note:
• The operation and maintenance practices outlined in this
document are based on full utilization of GE-approved parts,
repairs, and services.
• The operating and maintenance discussions presented are
generally applicable to all GE heavy-duty gas turbines; i.e.,
MS3000, 5000, 6000, 7000 and 9000. For purposes of illustration,
the MS7001EA was chosen for most components except exhaust
systems, which are illustrated using different gas turbine models
as indicated. Consult the GE Operation and Maintenance (O&M)
Manual for specific questions on a given machine, or contact the
local GE Energy representative.
Maintenance Planning
Advanced planning for maintenance is a necessity for utility,
industrial, independent power and cogeneration plant operators
in order to maximize reliability and availability. The correct
implementation of planned maintenance and inspection
provides direct benefits in reduced forced outages and
increased starting reliability, which in turn can reduce
unscheduled repairs and downtime. The primary factors
Heavy-Duty Gas Turbine
Operating and Maintenance Considerations
that affect the maintenance planning process are shown in
Figure 1.The owners’ operating mode and practices will determine
how each factor is weighted. Parts unique to a gas turbine
requiring the most careful attention are those associated with
the combustion process, together with those exposed to the
hot gases discharged from the combustion system. These are
called the combustion section and hot gas path parts, and they
include combustion liners, end caps, fuel nozzle assemblies,
crossfire tubes, transition pieces, turbine nozzles, turbine
stationary shrouds and turbine buckets.
Additional areas for consideration and planning, though longer-
term concerns, are the lives of the compressor rotor, turbine rotor,
casings and exhaust diffuser. The basic design and recommended
maintenance of GE heavy-duty gas turbines are oriented toward:
• Maximum periods of operation between inspections and
overhauls
• In-place, on-site inspection and maintenance
• Use of local trade skills to disassemble, inspect and re-assemble
gas turbine components
In addition to maintenance of the basic gas turbine, the control
devices, fuel-metering equipment, gas turbine auxiliaries, load
package, and other station auxiliaries also require periodic
servicing. The primary maintenance effort involves five basic
systems: controls and accessories, combustion, turbine, generator
and balance-of-plant. Controls and accessories are typically
serviced in outages of short duration, whereas the other four
systems are maintained through less frequent outages of
longer duration.
Gas turbine maintenance starts with a clear understanding
of the plant operation and the environment in which the plant
operates. These two factors should be the basis for developing a
maintenance plan for gas turbines.
The inspection and repair requirements, outlined in the O&M Manual
provided to each owner, lend themselves to establishing a pattern
of inspections. These inspection patterns will vary from site to site
and owner operators should understand how factors such as air and
fuel quality will be used to develop an inspection and maintenance
program. In addition, supplementary information is provided through
a system of Technical Information Letters (TILs) associated with
GE Energy | GER-3620L.1 (10/10)1ICNU_DR_177 Attachment C Page 5 of 60
specific gas turbines after shipment. This updated information, in
addition to the O&M Manual, assures optimum installation, operation
and maintenance of the turbine. (See Figure 2.) Many of the TILs
contain advisory technical recommendations to help resolve issues
(as they become known) and to help improve the operation,
maintenance, safety, reliability or availability of the turbine. The
recommendations contained in TILs should be reviewed and
factored into the overall maintenance planning program.
For a maintenance program to be effective, from both cost and
turbine availability standpoints, owners must develop a general
understanding of the relationship between their operating plans
and priorities for the plant and the manufacturer’s
recommendations regarding the number and types of inspections,
spare parts planning, and other major factors affecting the life and
proper operation of the equipment. Each of these issues will be
discussed in greater detail in the sections that follow.
2
Figure 1. Key factors affecting maintenance planning
Manufacturer’s
Recommended
Maintenance
Program
Diagnostics &
Expert Systems
Reliability Need
On-Site
Maintenance
Capability
Design Features Duty Cycle Cost of
Downtime
Type of Fuel
Replacement
Parts
Availability/
Investment
Reserve
RequirementsEnvironmentUtilization Need
Maintenance
Planning
• O&M Manual
– Turbine-specific manual provided to customer
– Includes outline of recommended Inspection and Repair requirements
– Helps customers to establish a pattern of systematic inspections for their site
• Technical Information Letters (TILs)
– Issued after shipment of turbine
– Provides O&M updates related to turbine installation, maintenance, and operation
– Provides advisory technical recommendations to help resolve potential issues
Figure 2.Key technical reference documents to include in maintenance planning
ICNU_DR_177 Attachment C Page 6 of 60
Gas Turbine Design
Maintenance Features
The GE heavy-duty gas turbine is designed to withstand severe
duty and to be maintained on-site, with off-site repair required
only on certain combustion components, hot gas path parts and
rotor assemblies needing specialized shop service. The following
features are designed into GE heavy-duty gas turbines to facilitate
on-site maintenance:
• All casings, shells and frames are split on machine horizontal
centerline. Upper halves may be lifted individually for access to
internal parts.
• With upper-half compressor casings removed, all stationary
vanes can be slid circumferentially out of the casings for
inspection or replacement without rotor removal.
• With the upper-half of the turbine shell lifted, each half of the
first stage nozzle assembly can be removed for inspection, repair
or replacement without rotor removal. On some units, upper-half,
later-stage nozzle assemblies are lifted with the turbine shell,
also allowing inspection and/or removal of the turbine buckets.
• All turbine buckets are moment-weighed and computer charted
in sets for rotor spool assembly so that they may be replaced
without the need to remove or rebalance the rotor assembly.
• All bearing housings and liners are split on the horizontal
centerline so that they may be inspected and replaced when
necessary. The lower half of the bearing liner can be removed
without removing the rotor.
• All seals and shaft packings are separate from the main bearing
housings and casing structures and may be readily removed
and replaced.
• On most designs, fuel nozzles, combustion liners and flow
sleeves can be removed for inspection, maintenance or
replacement without lifting any casings. All major accessories,
including filters and coolers, are separate assemblies that are
readily accessible for inspection or maintenance. They may also
be individually replaced as necessary.
• Casings can be inspected during any outage or any shutdown
when the unit enclosure is cool enough for safe entry. The
exterior of the inlet, compressor case, compressor discharge
case, turbine case, and exhaust frame can be inspected during
any outage or period when the enclosure is accessible. The
interior surfaces of these cases can be inspected to various
degrees depending on the type of outage performed. All interior
surfaces can be inspected during a major outage when the rotor
has been removed.
• Exhaust diffusers can be inspected during any outage by entering
the diffuser through the stack or Heat Recovery Steam Generator
(HRSG) access doors. The flow path surfaces, flex seals, and other
flow path hardware can be visually inspected with or without the
use of a borescope. Diffusers can be weld-repaired without the
need to remove the exhaust frame upper half.
• Inlets can be inspected during any outage or shutdown.
Inspection aid provisions have been built into GE heavy-duty
gas turbines to facilitate conducting several special inspection
procedures. These special procedures provide for the visual
inspection and clearance measurement of some of the
critical internal components without removal of the casings.
These procedures include gas path borescope inspection (BI),
radial clearance measurements and turbine nozzle axial
clearance measurements.
A GE gas turbine is a fully integrated design consisting of
stationary and rotating mechanical, fluid, thermal, and electrical
systems. The turbine’s performance, as well as the performance
of each component within the turbine, is dependent upon the
operating interrelationship between internal components and the
total operating systems. GE’s engineering process evaluates how
new designs, design changes or repairs impact components and
systems. This design, evaluation, testing, and approval assures the
proper balance and interaction between all components and
systems for safe, reliable, and economical operation.
Failure to evaluate the full system impact of a new, repaired,
or modified part may have negative impacts on the operation
and reliability of the entire system. The use of non-GE approved
parts, repairs, and maintenance practices may represent a
significant risk. Pursuant to the governing terms and conditions,
warranties and performance guarantees are predicated upon
proper storage, installation, operation, and maintenance,
conforming to GE approved operating instruction manuals
and repair/modification procedures.
GE Energy | GER-3620L.1 (10/10)3ICNU_DR_177 Attachment C Page 7 of 60
In general, an annual or semiannual borescope inspection
should use all the available access points to verify the safe and
uncompromised condition of the static and rotating hardware.
This should include, but is not limited to, signs of excessive gas
path fouling, symptoms of surface degradation (such as erosion,
corrosion, or spalling), displaced components, deformation or
impact damage, material loss, nicks, dents, cracking, indications
of contact or rubbing, or other anomalous conditions.
During BIs and similar inspections, the condition of the upstream
components should be verified, including all systems from the filter
house to the compressor inlet.
The application of a borescope monitoring program will assist with
the scheduling of outages and preplanning of parts requirements,
resulting in outage preparedness, lower maintenance costs and
higher availability and reliability of the gas turbine.
Major Factors Influencing
Maintenance and Equipment Life
There are many factors that can influence equipment life and
these must be understood and accounted for in the owner’s
maintenance planning. As indicated in Figure 5, starting cycle
(hours per start), power setting, fuel, level of steam or water
injection, and site environmental conditions are key factors in
determining the maintenance interval requirements as these
factors directly influence the life of replaceable gas turbine parts.
Non-consumable components and systems, such as the compressor
airfoils, may be affected by such variables as site environmental
conditions and plant and accessory system effects. Other factors
affecting maintenance planning are shown in Figure 1. The plant
operator should consider these external factors to prevent the
degradation and shortened life of non-consumable components.
GE provides supplementary documentation to assist the operator
in this regard.
Borescope Inspections
An effective borescope inspection (BI) program can monitor the
condition of internal components without the need for casing
removal. Borescope inspections should be scheduled with
consideration given to the operation and environment of the
gas turbine and information from the O&M manual and TILs.
GE heavy-duty gas turbine designs incorporate provisions in
both compressor casings and turbine shells for gas path visual
inspection of intermediate compressor rotor stages, first, second
and third-stage turbine buckets and turbine nozzle partitions by
means of the optical borescope. These provisions, consisting of
radially aligned holes through the compressor casings, turbine shell
and internal stationary turbine shrouds, are designed to allow the
penetration of an optical borescope into the compressor or turbine
flow path area, as shown in Figure 3. Borescope inspection access
locations for F Class gas turbines can be found in Appendix E.
Figure 4 provides a recommended interval for a planned borescope
inspection program following initial base line inspections. It should
be recognized that these borescope inspection intervals are based
on average unit operating modes. Adjustment of these borescope
intervals may be made based on operating experience and the
individual unit mode of operation, the fuels used and the results
of previous borescope inspections.
4
PRIMARY INSP. ACCESS. (NORMAL INSP.)
SECONDARY INSP. ACCESS. (ADDITIONAL STATORS & NOZZLES)
ACCESS. ALSO FOR EDDY-CURRENT & NOZZLE DEFLECTION INSP.
LEGEND
L/E = Leading Edge
T/E = Trailling Edge
Insp. = Inspection
18º
18º
18º
COMPRESSOR-4th STAGE
COMPRESSOR-12th STAGE
COMPRESSOR-17th STAGE
1st NOZZ T/E
1st BKT L/E
32º
1st BKT T/E
2nd NOZZ L/E
34º
2nd NOZZ T/E
2nd BKT L/E
42º
2nd BKT T/E
3rd NOZZ L/E
34º
3rd NOZZ T/E
3rd BKT L/E
42º
Figure 3. MS7001E gas turbine borescope inspection access locations
Borescope
Heavy Fuel Oil
Gas and Distillate
Fuel Oil
At Combustion Inspection
or Annually, Whichever
Occurs First
At Combustion Inspection
or Semiannually,
Whichever Occurs First
Figure 4. Borescope inspection programming
ICNU_DR_177 Attachment C Page 8 of 60
In the GE approach to maintenance planning, a gas fuel unit
operating under continuous duty, with no water or steam injection,
is established as the baseline condition, which sets the maximum
recommended maintenance intervals. For operation that differs
from the baseline, maintenance factors (MF) are established that
determine the impact to the component lives and increased
frequency of maintenance required. For example, a maintenance
factor of two would indicate a maintenance interval that is half
of the baseline interval.
Starts and Hours Criteria
Gas turbines wear in different ways for different service-duties, as
shown in Figure 6. Thermal mechanical fatigue is the dominant
limiter of life for peaking machines, while creep, oxidation, and
corrosion are the dominant limiters of life for continuous duty
machines. Interactions of these mechanisms are considered in the
GE design criteria, but to a great extent are second-order effects.
For that reason, GE bases gas turbine maintenance requirements
on independent counts of starts and hours. Whichever criteria
limit is first reached determines the maintenance interval. A
graphical display of the GE approach is shown in Figure 7. In
this figure, the inspection interval recommendation is defined
by the rectangle established by the starts and hours criteria.
These recommendations for inspection fall within the design life
expectations and are selected such that components verified to be
acceptable for continued use at the inspection point will have low
risk of failure during the subsequent operating interval.
An alternative to the GE approach, which is sometimes employed
by other manufacturers, converts each start cycle to an equivalent
number of operating hours (EOH) with inspection intervals based
on the equivalent hours count. For the reasons previously stated,
GE does not use this approach. While this logic can create the
impression of longer intervals, it actually may result in more
frequent maintenance inspections, since separate effects are
considered additive. Referring again to Figure 7, the starts and
hours inspection “rectangle” is reduced in half as defined by the
diagonal line from the starts limit at the upper left hand corner
to the hours limit at the lower right hand corner. Midrange duty
applications, with hours-per-start ratios of 30-50, are particularly
penalized by this approach.
This is further illustrated in Figure 8 for the example of an
MS7001EA gas turbine operating on gas fuel, at base load
conditions with no steam or water injection or trips from load.
The unit operates 4000 hours and 300 starts per year. Following
GE’s recommendations, the operator would perform the hot gas
path inspection after four years of operation, with starts being
the limiting condition. Performing maintenance on this same
unit based on an equivalent hours criteria would require a hot
gas path inspection after 2.4 years. Similarly, for a continuous duty
application operating 8000 hours and 160 starts per year, the GE
recommendation would be to perform the hot gas path inspection
after three years of operation with the operating hours being the
limiting condition for this case. The equivalent hours criteria would
set the hot gas path inspection after 2.1 years of operation for
this application.
GE Energy | GER-3620L.1 (10/10)5
• Continuous Duty Application
– Rupture
– Creep Deflection
– High-Cycle Fatigue
– Corrosion
– Oxidation
– Erosion
– Rubs/Wear
– Foreign Object Damage
• Cyclic Duty Application
– Thermal Mechanical Fatigue
– High-Cycle Fatigue
– Rubs/Wear
– Foreign Object Damage
Figure 6. Causes of wear – hot gas path components
– Cyclic effects
– Firing temperature
– Fuel
– Steam/water injection
– Site environmental conditions
Figure 5. Maintenance cost and equipment life are influenced by key service
factors
ICNU_DR_177 Attachment C Page 9 of 60
6
Figure 7. GE bases gas turbine maintenance requirements on independent counts of starts and hours
Figure 8.Hot gas path maintenance interval comparisons. GE method vs. EOH method
GE vs. Equivalent Operating Hours (EOH) Approach
1400
1200
1000
800
600
400
200
0
0 4 8 12 16 20 24 28
Fired Hours ~ KHR
St
a
r
t
s
Case 2
8,000 Hrs/Yr
160 Starts/Yr
GE Every 3 Yr
EOH Every 2.1 Yr
Case 1
4,000 Hrs/Yr
GE Method
300 Starts/Yr
GE Every 4 Yr
EOH Every 2.4 Yr
ICNU_DR_177 Attachment C Page 10 of 60
When these service or maintenance factors are involved in a
unit’s operating profile, the hot gas path maintenance “rectangle”
that describes the specific maintenance criteria for this operation
is reduced from the ideal case, as illustrated in Figure 10. The
following discussion will take a closer look at the key operating
factors and how they can impact maintenance intervals as well as
parts refurbishment/replacement intervals.
Fuel
Fuels burned in gas turbines range from clean natural gas to
residual oils and impact maintenance, as illustrated in Figure 11.
Heavier hydrocarbon fuels have a maintenance factor ranging
from three to four for residual fuel and two to three for crude oil
Service Factors
While GE does not subscribe to the equivalency of starts to hours,
there are equivalencies within a wear mechanism that must be
considered. As shown in Figure 9, influences such as fuel type and
quality, firing temperature setting, and the amount of steam or
water injection are considered with regard to the hours-based
criteria. Startup rate and the number of trips are considered
with regard to the starts-based criteria. In both cases, these
influences may act to reduce the maintenance intervals.
GE Energy | GER-3620L.1 (10/10)7
4
3
2
1
7 8 9 10 11 12 13 14 15 20
Fuel Percent Hydrogen by Weight in Fuel
In
t
e
r
v
a
l

R
e
d
u
c
t
i
o
n

F
a
c
t
o
r
Natural Gas
Distillates
Residual
LightHeavy
Figure 11. Estimated effect of fuel type on maintenance
Hours Factors
Starts Factors
Figure 9. Maintenance factors – hot gas path (buckets and nozzles)
Hours Factors
• Firing Temperature
• Steam/Water Injection
• Fuel Type
• Trips
• Fasts Starts
St
a
r
t
s
Thousands of Fired Hours
Starts Factors
Maintenance Factors Reduce Maintenance Interval
Figure 10.GE maintenance interval for hot gas inspections
ICNU_DR_177 Attachment C Page 11 of 60
fuels (this maintenance factor is to be adjusted based on the water
to fuel ratio in cases when water injection for NOx abatement is
used). These fuels generally release a higher amount of radiant
thermal energy, which results in a subsequent reduction in
combustion hardware life, and frequently contain corrosive
elements such as sodium, potassium, vanadium and lead that can
cause accelerated hot corrosion of turbine nozzles and buckets. In
addition, some elements in these fuels can cause deposits either
directly or through compounds formed with inhibitors that are
used to prevent corrosion. These deposits impact performance and
can lead to a need for more frequent maintenance.
Distillates, as refined, do not generally contain high levels of these
corrosive elements, but harmful contaminants can be present in
these fuels when delivered to the site. Two common ways of
contaminating number two distillate fuel oil are: salt-water ballast
mixing with the cargo during sea transport, and contamination of
the distillate fuel when transported to site in tankers, tank trucks
or pipelines that were previously used to transport contaminated
fuel, chemicals or leaded gasoline. From Figure 11, it can be
seen that GE’s experience with distillate fuels indicates that the
hot gas path maintenance factor can range from as low as one
(equivalent to natural gas) to as high as three. Unless operating
experience suggests otherwise, it is recommended that a hot gas
path maintenance factor of 1.5 be used for operation on distillate
oil. Note also that contaminants in liquid fuels can affect the
life of gas turbine auxiliary components such as fuel pumps
and flow dividers.
As shown in Figure 11, gas fuels that meet GE specifications are
considered the optimum fuel with regard to turbine maintenance
and are assigned no negative impact. The importance of proper
fuel quality has been amplified with Dry Low NOx (DLN) combustion
systems. Proper adherence to GE fuel specifications in GEI-41040
and GEI-41047 is required to allow proper combustion system
operation, and to maintain applicable warranties. Liquid
hydrocarbon carryover can expose the hot gas path hardware to
severe overtemperature conditions and can result in significant
reductions in hot gas path parts lives or repair intervals. Liquid
hydrocarbon carryover is also responsible for upstream
displacement of flame in combustion chambers, which can lead to
severe combustion hardware damage. Owners can control this
potential issue by using effective gas scrubber systems and by
superheating the gaseous fuel prior to use to approximately 50°F
(28°C) above the hydrocarbon dew point temperature at the
turbine gas control valve connection. For exact superheat
requirement calculations please review GEI 41040. Integral to the
system, coalescing filters installed upstream of the performance
gas heaters is a best practice and ensures the most efficient
removal of liquids and vapor phase constituents.
The prevention of hot corrosion of the turbine buckets and nozzles
is mainly under the control of the owner. Undetected and
untreated, a single shipment of contaminated fuel can cause
substantial damage to the gas turbine hot gas path components.
Potentially high maintenance costs and loss of availability can be
minimized or eliminated by:
• Placing a proper fuel specification on the fuel supplier. For liquid
fuels, each shipment should include a report that identifies
specific gravity, flash point, viscosity, sulfur content, pour point
and ash content of the fuel.
• Providing a regular fuel quality sampling and analysis program.
As part of this program, an online water in fuel oil monitor is
recommended, as is a portable fuel analyzer that, as a minimum,
reads vanadium, lead, sodium, potassium, calcium and
magnesium.
• Providing proper maintenance of the fuel treatment system
when burning heavier fuel oils and by providing cleanup
equipment for distillate fuels when there is a potential for
contamination.
In addition to their presence in the fuel, contaminants can also enter
the turbine via the inlet air and from the steam or water injected for
NOx emission control or power augmentation. Carryover from
evaporative coolers is another source of contaminants. In some
cases, these sources of contaminants have been found to cause hot
gas path degradation equal to that seen with fuel-related
contaminants. GE specifications define limits for maximum
concentrations of contaminants for fuel, air and steam/water.
In addition to fuel quality, fuel system operation is also a factor in
equipment maintenance. Liquid fuel may remain unpurged and in
contact with hot combustion components after shutdown, as well
as stagnate in the fuel system when strictly gas fuel is run for an
extended time. To minimize varnish and coke accumulation, dual
fuel units (gas and liquid capable) should be shutdown running gas
8 ICNU_DR_177 Attachment C Page 12 of 60
fuel whenever possible. Likewise, during extended operation on
gas, regular transfers from gas to liquid are recommended to
exercise the system components and minimize coking.
Contamination and build-up may prevent the system from
removing fuel oil and other liquids from the combustion, compressor
discharge, turbine, and exhaust sections when the unit is shut down
or during startup. Liquid fuel oil trapped in the system piping also
creates a safety risk. Correct functioning of the false start drain
system (FSDS) should be ensured through proper maintenance
and inspection per GE procedures.
Firing Temperatures
Significant operation at peak load, because of the higher operating
temperatures, will require more frequent maintenance and
replacement of hot gas path components. Figure 12 defines the
parts life effect corresponding to changes in firing temperature.
It should be noted that this is not a linear relationship.
Higher firing temperature reduces hot gas path parts lives while
lower firing temperature increases parts lives.
It is important to recognize that a reduction in load does not
always mean a reduction in firing temperature. In heat recovery
applications, where steam generation drives overall plant
efficiency, load is first reduced by closing variable inlet guide vanes
to reduce inlet airflow while maintaining maximum exhaust
temperature. For these combined cycle applications, firing
temperature does not decrease until load is reduced below
approximately 80% of rated output. Conversely, a turbine
running in simple cycle mode maintains full open inlet guide
vanes during a load reduction to 80% and will experience over a
200°F/111°C reduction in firing temperature at this output level.
The hot gas path parts life effects for these different modes of
operation are obviously quite different. This turbine control effect
is illustrated in Figure 13. Similarly, turbines with DLN combustion
systems utilize inlet guide vane turndown as well as inlet bleed
heat to extend operation of low NOx premix operation to part
load conditions.
Firing temperature effects on hot gas path maintenance, as
described above, relate to clean burning fuels, such as natural
gas and light distillates, where creep rupture of hot gas path
components is the primary life limiter and is the mechanism that
determines the hot gas path maintenance interval impact. With
ash-bearing heavy fuels, corrosion and deposits are the primary
influence and a different relationship with firing temperature exists.
Figure 14 illustrates the sensitivity of hot gas path maintenance
GE Energy | GER-3620L.1 (10/10)9
Figure 13.Firing temperature and load relationship – heat recovery vs. simple
cycle operation
E-Class: Ap = e (0.018*ΔTf)
F-Class: Ap = e (0.023*ΔTf)
Ap = Peak fire severity factor
ΔTf = Peak firing temperature adder (in °F)
Figure 12.Bucket life firing temperature effect
Figure 14. Heavy fuel maintenance factors
ICNU_DR_177 Attachment C Page 13 of 60
factor to firing temperature for a heavy fuel operation. It can be
seen that while the sensitivity to firing temperature is less, the
maintenance factor itself is higher due to issues relating to the
corrosive elements contained in these fuels.
Steam/Water Injection
Water or steam injection for emissions control or power
augmentation can impact parts lives and maintenance intervals
even when the water or steam meets GE specifications. This
relates to the effect of the added water on the hot gas transport
properties. Higher gas conductivity, in particular, increases
the heat transfer to the buckets and nozzles and can lead
to higher metal temperature and reduced parts life as shown
in Figure 15.
Parts life impact from steam or water injection is directly impacted
by the way the turbine is controlled. The control system on most
base load applications reduces firing temperature as water or
steam is injected. This is known as dry control curve operation,
which counters the effect of the higher heat transfer on the
gas side, and results in no net impact on bucket life. This is
the standard configuration for all gas turbines, both with and
without water or steam injection. On some installations, however,
the control system is designed to maintain firing temperature
constant with water or steam injection level. This is known
as wet control curve operation, which results in additional
unit output, but decreases parts life as previously described.
Units controlled in this way are generally in peaking applications
where annual operating hours are low or where operators have
determined that reduced parts lives are justified by the power
advantage. Figure 16 illustrates the wet and dry control curve
and the performance differences that result from these two
different modes of control.
An additional factor associated with water or steam injection
relates to the higher aerodynamic loading on the turbine
components that results from the injected water increasing
the cycle pressure ratio. This additional loading can increase
the downstream deflection rate of the second- and third-stage
nozzles, which would reduce the repair interval for these
components. However, the introduction of GTD-222™ and
GTD-241™, high creep strength stage two and three nozzle
alloys, has minimized this factor.
Water injection for NOx abatement should be performed
according to the control schedule implemented in the controls
system. Forcing operation of the water injection system at high
loads can lead to combustion and HGP hardware damage due
to thermal shock.
Cyclic Effects
In the previous discussion, operating factors that impact the
hours-based maintenance criteria were described. For the
starts-based maintenance criteria, operating factors associated
with the cyclic effects produced during startup, operation and
shutdown of the turbine must be considered. Operating conditions
other than the standard startup and shutdown sequence can
potentially reduce the cyclic life of the hot gas path components
and rotors, and, if present, will require more frequent maintenance
and parts refurbishment and/or replacement.
10
Figure 15.Steam/water injection and bucket/nozzle life
Figure 16. Exhaust temperature control curve – dry vs. wet control MS7001EA
ICNU_DR_177 Attachment C Page 14 of 60
Hot Gas Path Parts
Figure 17 illustrates the firing temperature changes occurring over
a normal startup and shutdown cycle. Light-off, acceleration,
loading, unloading and shutdown all produce gas temperature
changes that produce corresponding metal temperature changes.
For rapid changes in gas temperature, the edges of the bucket or
nozzle respond more quickly than the thicker bulk section, as
pictured in Figure 18. These gradients, in turn, produce thermal
stresses that, when cycled, can eventually lead to cracking.
Figure 19 describes the temperature/strain history of an MS7001EA
stage 1 bucket during a normal startup and shutdown cycle.
Light-off and acceleration produce transient compressive strains
in the bucket as the fast responding leading edge heats up more
quickly than the thicker bulk section of the airfoil. At full load
conditions, the bucket reaches its maximum metal temperature
and a compressive strain is produced from the normal steady state
temperature gradients that exist in the cooled part. At shutdown,
the conditions reverse and the faster responding edges cool more
quickly than the bulk section, which results in a tensile strain at
the leading edge.
Thermal mechanical fatigue testing has found that the number
of cycles that a part can withstand before cracking occurs is
strongly influenced by the total strain range and the maximum
metal temperature experienced. Any operating condition that
significantly increases the strain range and/or the maximum metal
temperature over the normal cycle conditions will act to reduce the
fatigue life and increase the starts-based maintenance factor. For
example, Figure 20 compares a normal operating cycle with one
that includes a trip from full load. The significant increase in the
strain range for a trip cycle results in a life effect that equates to
eight normal start/stop cycles, as shown. Trips from part load will
have a reduced impact because of the lower metal temperatures
at the initiation of the trip event. Figure 21 illustrates that while a
trip from between 80% and 100% load has an 8:1 maintenance
factor, a trip from full speed no load has a maintenance factor of
2:1. Similarly, overfiring of the unit during peak load operation
leads to increased component metal temperatures.
As a result, a trip from peak load has a maintenance factor
of 10:1. Trips are to be assessed in addition to the regular
startup/shutdown cycles (as starts adders). As such, in the
factored starts equation of Figure 46, one is subtracted from
the severity factor so that the net result of the formula (Figure 46)
is the same as that dictated by the increased strain range.
For example, a startup and trip from base load would count
as eight total cycles (one cycle for startup to base load plus
8-1=7 cycles for trip from base load), just as indicated by the
8:1 maintenance factor.
Similarly to trips from load, emergency starts and fast loading will
impact the starts-based maintenance interval. This again relates to
the increased strain range that is associated with these events.
Emergency starts, in which units are brought from standstill to
full load in less than five minutes, will have a parts life effect equal
to 20 additional cycles and a normal start with fast loading will
have a parts life effect equal to 2 additional cycles. Like trips,
the effects of a fast start or fast loading on the machine are
considered separate from a normal cycle and their effects must
be tabulated in addition to the normal start/stop cycle. However,
there is no -1 applied to these factors, so an emergency start to
base load would have a total impact of 21 cycles. Refer to
Appendix A for factored starts examples.
GE Energy | GER-3620L.1 (10/10)11
Figure 17. Turbine start/stop cycle – firing temperature changes
Figure 18.First stage bucket transient temperature distribution
ICNU_DR_177 Attachment C Page 15 of 60
While the factors described above will decrease the starts-based
maintenance interval, part load operating cycles would allow
for an extension of the maintenance interval. Figure 22 is a
guideline that could be used in considering this type of operation.
For example, two operating cycles to maximum load levels of
less than 60% would equate to one start to a load greater than
60% or, stated another way, would have a maintenance factor
of 0.5. Factored starts calculations are based upon the maximum
load achieved during operation. Therefore, if a unit is operated
at part load for three weeks, and then ramped up to base load
for the last ten minutes, then the unit’s total operation would be
described as a base load start/stop cycle.
12
0
Key Parameters
Fired
Shutdown
• Max Strain Range
• Max Metal Temperature
FSNL
Δε
Light Off
& Warm-up
Acceleration
Base Load
Metal
Temperature
Tm
%
S
t
r
a
i
n
Figure 19. Bucket low cycle fatigue (LCF)
+
-
Normal Startup/Shutdown
Temperature
ΔεMAX
Strain
~ %
+
-
Strain
~ %
Leading Edge Temperature/Strain
TMAX
Normal Start & Trip
1 Trip Cycle = 8 Normal Shutdown Cycles
Temperature
ΔεMAX
TMAX
Figure 20. Low cycle fatigue life sensitivities – first stage bucket
ICNU_DR_177 Attachment C Page 16 of 60
Rotor Parts
In addition to the hot gas path components, the rotor structure
maintenance and refurbishment requirements are impacted by the
cyclic effects associated with startup, operation and shutdown, as
well as loading and off-load characteristics. Maintenance factors
specific to an application’s operating profile and rotor design must
be determined and incorporated into the operators maintenance
planning. Disassembly and inspection of all rotor components is
required when the accumulated rotor starts or hours reach the
inspection limit. (See Figure 47 and Figure 48 in the Inspection
Intervals Section.)
For the rotor, the thermal condition when the startup sequence is
initiated is a major factor in determining the rotor maintenance
interval and individual rotor component life. Rotors that are cold
when the startup commences develop transient thermal stresses
as the turbine is brought on line. Large rotors with their longer
thermal time constants develop higher thermal stresses than
smaller rotors undergoing the same startup time sequence.
High thermal stresses will reduce thermal mechanical fatigue life
and the age for inspection.
The steam turbine industry recognized the need to adjust startup
times in the 1950 to 1970 time period when power generation
market growth led to larger and larger steam turbines operating
at higher temperatures. Similar to the steam turbine rotor size
increases of the 1950s and 1960s, gas turbine rotors have seen
a growth trend in the 1980s and 1990s as the technology has
advanced to meet the demand for combined cycle power plants
with high power density and thermal efficiency.
With these larger rotors, lessons learned from both the steam
turbine experience and the more recent gas turbine experience
should be factored into the startup control for the gas turbine
and/or maintenance factors should be determined for an
application’s duty cycle to quantify the rotor life reductions
associated with different severity levels. The maintenance factors
so determined are used to adjust the rotor component inspection,
repair and replacement intervals that are appropriate to that
particular duty cycle.
Though the concept of rotor maintenance factors is applicable
to all gas turbine rotors, only F Class rotors will be discussed in
detail. The rotor maintenance factor for a startup is a function
of the downtime following a previous period of operation. As
downtime increases, the rotor metal temperature approaches
ambient conditions and thermal fatigue impact during a
subsequent startup increases. As such, cold starts are assigned
a rotor maintenance factor of two, and hot starts a rotor
maintenance factor of less than one due to the lower thermal
stress under hot conditions. This impact varies from one location
in the rotor structure to another. Since the most limiting location
determines the overall rotor impact, the rotor maintenance factor
indicates the highest rotor maintenance factors at these locations.
Rotor starting thermal condition is not the only operating factor
that influences rotor maintenance intervals and component life.
Fast starts and fast loading, where the turbine is ramped quickly
to load, increase thermal gradients and are more severe duty
for the rotor. Trips from load and particularly trips followed by
immediate restarts reduce the rotor maintenance interval, as
GE Energy | GER-3620L.1 (10/10)13
Figure 22. Maintenance factor – effect of start cycle maximum load level
aT –

T
r
i
p

S
e
v
e
r
i
t
y

F
a
c
t
o
r
Note:
0 20 40 60 80 100
0
2
4
6
8
10
% Load
FSNL
Base
• For Trips During Startup Accel Assume aT=2
• For Trips from Peak Load Assume aT=10
F Class and E Class
units with Inlet
Bleed Heat
Units Without
Inlet Bleed Heat
Figure 21. Maintenance factor – trips from load
ICNU_DR_177 Attachment C Page 17 of 60
do hot restarts within the first hour of a hot shutdown. Figure 23
lists recommended operating factors that should be used to
determine the rotor’s overall maintenance factor for FA and FB
design rotors. The factors to be used for other models are
determined by applicable Technical Information Letters.
The significance of each of these factors to the maintenance
requirements of the rotor is dependent on the type of operation
that the unit sees. There are three general categories of operation
that are typical of most gas turbine applications. These are
peaking, cyclic and continuous duty as described below:
• Peaking units have a relatively high starting frequency and a
low number of hours per start. Operation follows a seasonal
demand. Peaking units will generally see a high percentage of
warm and cold starts.
• Cyclic duty units start daily with weekend shutdowns.
Twelve to sixteen hours per start is typical which results
in a warm rotor condition for a large percentage of the starts.
Cold starts are generally seen only after a maintenance outage
or following a two-day weekend outage.
• Continuous duty applications see a high number of hours per
start and most starts are cold because outages are generally
maintenance driven. While the percentage of cold starts is high,
the total number of starts is low. The rotor maintenance interval
on continuous duty units will be determined by service hours
rather than starts.
Figure 24 lists operating profiles on the high end of each of these
three general categories of gas turbine applications.
As can be seen in Figure 24, these duty cycles have different
combinations of hot, warm and cold starts with each starting
condition having a different impact on rotor maintenance
interval as previously discussed. As a result, the starts-based
rotor maintenance interval will depend on an application’s specific
duty cycle. In a later section, a method will be described that
allows the turbine operator to determine a maintenance factor
that is specific to the operation’s duty cycle. The application’s
integrated maintenance factor uses the rotor maintenance factors
described above in combination with the actual duty cycle of a
specific application and can be used to determine rotor inspection
intervals. In this calculation, the reference duty cycle that yields a
starts-based maintenance factor equal to one is defined in Figure
14
FA/FB* Designs
Hot Start Factor
(1–4 Hrs. Down)
Hot Start Factor
(0–1 Hr. Down)
Warm 1 Start Factor
(4–20 Hrs. Down)
Warm 2 Start Factor
(20–40 Hrs. Down)
Cold Start Factor
(>40 Hrs. Down)
Trip from Load Factor
*Other factors may apply to early 9351 units
• Factors Are a Function of Machine Thermal Condition
at Startup
• Trips from Load, Fast Starts and >20-hour Restarts
Reduce Maintenance Intervals
Rotor Maintenance Factors
Fast Start
(FA Only)
Normal
Start
1.0
4.0
4.0
2.0
4.0
4.0 2.0
1.8
2.8
0.5
0.9
1.4
Figure 23.Operation-related maintenance factors
Hot Start (Down <4 Hr.) 3% 1% 10%
Warm 1 Start (Down 4-20 hr.) 10% 82% 5%
Warm 2 Start (Down 20-40 Hr.) 37% 13% 5%
Cold Start (Down >40 Hr.) 50% 4% 80%
Hours/Start 4 16 400
Hours/Year 600 4800 8200
Starts per Year 150 300 21
Percent Trips 3% 1% 20%
Number of Trips per Year 5 3 4
Typical Maintenance Factor 1.7 1.0 NA
(Starts Based)
Peaking – Cyclic – Continuous
Peaking Cyclic Continuous
• Operational Profile is Application Specific
• Inspection Interval is Application Specific
Figure 24.FA gas turbine typical operational profile
ICNU_DR_177 Attachment C Page 18 of 60
presence of bow is detected. Vibration data taken while at
crank speed can be used to confirm that rotor bow is at
acceptable levels and the start sequence can be initiated.
Users should reference the Operation and Maintenance Manual
and appropriate TILs for specific instructions and information
for their units.
Combustion Parts
A typical combustion system contains transition pieces,
combustion liners, flow sleeves, head-end assemblies containing
fuel nozzles and cartridges, end caps and end covers, and assorted
other hardware including cross-fire tubes, spark plugs and flame
detectors. In addition, there can be various fuel and air delivery
components such as purge or check valves and flex hoses. GE
provides several types of combustion systems including standard
combustors, Multi-Nozzle Quiet Combustors (MNQC), Integrated
Gasification Combined Cycle (IGCC) combustors and Dry Low NOx
(DLN) combustors. Each of these combustion systems has unique
operating characteristics and modes of operation with differing
responses to operational variables affecting maintenance and
refurbishment requirements.
Dry Low NOx (DLN) combustion systems produce lowest NOx
emissions during operation in premixed steady-state combustion
mode (PMSS). Continuous and extended operation in lower
combustion modes (lean-lean and/or extended lean-lean
modes for DLN-1, DLN-1+, DLN 2.0 and sub-piloted premix
and/or extended sub-piloted premix, piloted premixed and/or
extended piloted premix modes for DLN 2+) is not encouraged
due to their impact on combustion hardware life.
Extension of a combustion mode—for example, extended piloted
premix—is often attained through manually forcing controls
logic in order to maintain the same combustion mode beyond
the load where transfer into the next combustion mode would
normally occur.
The maintenance and refurbishment requirements of
combustion parts are impacted by many of the same factors
as hot gas path parts including start cycle, trips, fuel type and
quality, firing temperature and use of steam or water injection
for either emissions control or power augmentation. However,
there are other factors specific to combustion systems. As
mentioned above, one of these factors is operating mode,
25.Duty cycles different from the Figure 25 definition, in particular
duty cycles with more cold starts, or a high number of trips, will
have a maintenance factor greater than one.
Turning gear or ratchet operation after shutdown, and before
starting/restarting is a crucial part of normal operating procedure.
Figure F-1 describes turning gear/ratchet scenarios and operation
guidelines (See Appendix). Relevant operating instructions and TILs
should be adhered to where applicable. After a shutdown, turning
of the warm rotor is essential to avoid bow, which could lead to
high vibrations and excessive rubs if a start is initiated with the
rotor in a bowed condition. As a best practice, units should remain
on turning gear or ratchet following a planned shutdown until
wheelspace temperatures have stabilized at near ambient
temperature. If the unit is to see no further activity for 48 hours
after cool-down is completed, then it may be taken off of
turning gear.
Further guidelines exist for hot restarts and cold starts. It is
recommended that the rotor be placed on turning gear for one
hour prior to restart following a trip from load, trip from full speed
no load, or normal shutdown. This will allow transient thermal
stresses to subside before superimposing a startup transient.
If the machine must be restarted in less than one hour, a start
factor of 2 will apply. Longer periods of turning gear operation
may be necessary prior to a cold start or hot restart if the
GE Energy | GER-3620L.1 (10/10)15
Baseline Unit
Cyclic Duty
6 Starts/Week
16 Hours/Start
4 Outage/Year Maintenance
50 Weeks/Year
4800 Hours/Year
300 Starts/Year
0 Trips/Year
1 Maintenance Factor

12 Cold Starts/Year (down >40 Hr.) 4%
39 Warm 2 Starts/Year (Down 20-40 Hr.) 13%
246 Warm Starts/Year (Down 4-20 Hr.) 82%
3 Hot Starts per Year 1%
Baseline Unit Achieves Maintenance Factor = 1
Figure 25. Baseline for starts-based maintenance factor definition
ICNU_DR_177 Attachment C Page 19 of 60
which describes the applied fueling pattern. The use of
low combustion modes (as described above) for continuous
operation at high turbine loads reduces the maintenance interval
significantly, by subsequent increase of the maintenance factor.
Examples:
• DLN-1 / DLN-1+ and DLN 2.0 extended lean-lean mode at
high loads, which results in a maintenance factor of 10.
• Operation of DLN 2+ combustion systems in extended
sub-piloted and extended piloted premixed mode result in
a maintenance factor of 10.
• Continuous operation of DLN 2+ in sub-piloted premixed
and piloted premixed mode is not recommended as it will
drive increased maintenance cost.
• In addition, cyclic operation between piloted premix and
premix modes lead to thermal loads on the combustion liner
and transition piece similar to the loads encountered during
startup/shutdown cycle.
Another factor that can impact combustion system maintenance
is acoustic dynamics. Acoustic dynamics are pressure oscillations
generated by the combustion system, which, if high enough
in magnitude, can lead to significant wear and cracking. GE
practice is to tune the combustion system to levels of acoustic
dynamics low enough to ensure that the maintenance practices
described here are not compromised. In addition, GE encourages
monitoring of combustion dynamics during turbine operation
throughout the full range of ambient temperatures and loads.
Combustion maintenance is performed, if required, following
each combustion inspection (or repair) interval. Inspection
interval guidelines are included in Figure 44. It is expected,
and recommended, that intervals be modified based on
specific experience. Replacement intervals are usually
defined by a recommended number of combustion (or repair)
intervals and are usually combustion component specific.
In general, the replacement interval as a function of the
number of combustion inspection intervals is reduced if the
combustion inspection interval is extended. For example, a
component having an 8,000-hour combustion inspection
interval (CI), and a six (CI) replacement interval, would have
a replacement interval of four (CI) intervals if the inspection
interval were increased to 12,000 hours (to maintain a 48,000-hour
replacement interval).
For combustion parts, the base line operating conditions that
result in a maintenance factor of one are normal fired startup
and shutdown to base load on natural gas fuel without steam
or water injection. Factors that increase the hours-based
maintenance factor include peaking duty, distillate or heavy
fuels, and steam or water injection with dry or wet control
curves. Factors that increase starts-based maintenance factor
include peaking duty, fuel type, steam or water injection, trips,
emergency starts and fast loading.
Casing Parts
Most GE gas turbines have inlet, compressor, compressor
discharge, and turbine cases in addition to exhaust frames.
Inner barrels are typically attached to the compressor discharge
case. These cases provide the primary support for the bearings,
rotor, and gas path hardware.
The exterior of all casings should be visually inspected for
cracking and loose hardware at each combustion, hot gas path,
and major outage. The interior of all casings should be inspected
whenever possible. The level of the outage determines which
casing interiors are accessible for visual inspection. Borescope
inspections are recommended for the inlet cases, compressor
cases, and compressor discharge cases during gas path borescope
inspections. All interior case surfaces should be visibly inspected
during a major outage.
Key inspection areas for casings are listed below.
• Bolt holes
• Shroud pin and borescope holes in the turbine shell (case)
• Compressor stator hooks
• Turbine shell shroud hooks
• Compressor discharge case struts
• Inner barrel and inner barrel bolts
• Inlet case bearing surfaces and hooks
• Inlet case and exhaust frame gibs and trunions
• Extraction manifolds (for foreign objects)
16 ICNU_DR_177 Attachment C Page 20 of 60
Exhaust Diffuser Parts
GE exhaust diffusers come in either axial or radial configurations
as shown in Figures 26 and 27 below. Both types of diffusers are
composed of a forward and aft section. Forward diffusers are
normally axial diffusers, while aft diffusers can be either axial
or radial. Axial diffusers are used in the F-class gas turbines, while
radial diffusers are used in B-class and E-class gas turbines.
Exhaust diffusers are subject to high gas path temperatures and
vibration due to normal gas turbine operation. Because of the
extreme operating environment and cyclic operating nature of
gas turbines, exhaust diffusers may develop cracks in the sheet
metal surfaces and weld joints used for diffuser construction.
Additionally, erosion may occur due to extended operation at high
temperatures. Exhaust diffusers should be inspected for cracking
and erosion at every combustion, hot gas path and major outage.
In addition to the previously discussed inspections, flex seals,
L-seals, and horizontal joint gaskets should be visually inspected
for signs of wear or damage at every combustion, hot gas path,
and major outage. GE recommends that seals with signs of wear
or damage be replaced.
Key areas that should be inspected are listed below. Any damage
should be reported to GE for recommended repairs.
• Forward diffuser carrier flange (6FA)
• Airfoil leading and trailing edges
• Turning vanes in radial diffusers (6B, E-class)
• Insulation packs on interior or exterior surfaces
• Clamp ring attachment points to exhaust frame (major
outage only)
• Flex seals
• Horizontal joint gaskets
Off-Frequency Operation
GE heavy-duty single shaft gas turbines are designed to operate
over a 95% to 105% speed range. Operation at other than rated
speed has the potential to impact maintenance requirements.
Depending on the industry code requirements, the specifics
of the turbine design, and the turbine control philosophy
employed, operating conditions can result that will accelerate
life consumption of gas turbine components, particularly rotating
flowpath hardware. Where this is true, the maintenance factor
associated with this operation must be understood and these
speed events analyzed and recorded in order to include them
in the maintenance plan for the gas turbine.
Generator drive turbines operating in a power system grid are
sometimes required to meet operational requirements that are
aimed at maintaining grid stability under conditions of sudden
load or capacity changes. Most codes require turbines to remain on
line in the event of a frequency disturbance. For under-frequency
operation, the turbine output decrease that will normally occur
with a speed decrease is allowed and the net impact on the turbine
as measured by a maintenance factor is minimal. In some grid
systems, there are more stringent codes that require remaining on
line while maintaining load on a defined schedule of load versus
grid frequency. One example of a more stringent requirement is
defined by the National Grid Company (NGC). In the NGC code,
conditions under which frequency excursions must be tolerated
and/or controlled are defined as shown in Figure 28.
GE Energy | GER-3620L.1 (10/10)17
Figure 26. F-Class Axial Diffuser
Figure 27.E-Class Radial Diffuser
ICNU_DR_177 Attachment C Page 21 of 60
With this specification, load must be maintained constant over
a frequency range of +/- 1% (+/- 0.5Hz in a 50 Hz grid system)
with a one percent load reduction allowed for every additional
one percent frequency drop down to a minimum 94% speed.
Requirements stipulate that operation between 95% to 104%
speed can be continuous but operation between 94% and 95% is
limited to 20 seconds for each event. These conditions must be
met up to a maximum ambient temperature of 25°C (77°F).
Under-frequency operation impacts maintenance to the degree
that nominally controlled turbine output must be exceeded in order
to meet the specification defined output requirement. As speed
decreases, the compressor airflow decreases, reducing turbine
output. If this normal output fall-off with speed results in loads less
than the defined minimum, power augmentation must be applied.
Turbine overfiring is the most obvious augmentation option but
other means, such as gas turbine, water-wash, inlet fogging or
evaporative cooling also provide potential means for augmentation.
Ambient temperature can be a significant factor in the level
of power augmentation required. This relates to compressor
operating margin that may require inlet guide vane closure if
compressor corrected speed reaches limiting conditions. For
an FA class turbine, operation at 0°C (32°F) would require no
power augmentation to meet NGC requirements while operation
at 25°C (77°F) would fall below NGC requirements without a
substantial amount of power augmentation. As an example,
Figure 29 illustrates the output trend at 25°C (77°F) for an FA
class gas turbine as grid system frequency changes and where
no power augmentation is applied.
In Figure 29,the gas turbine output shortfall at the low frequency
end (47.5 Hz) of the NGC continuous operation compliance range
would require a 160°F increase over base load firing temperature
to be in compliance. At this level of over-fire, a maintenance
factor exceeding 100x would be applied to all time spent at
these conditions. Overfiring at this level would have implications
on combustion operability and emissions compliance as well as
have major impact on hot gas path parts life. An alternative power
augmentation approach that has been utilized in FA gas turbines
for NGC code compliance utilizes water wash in combination
with increased firing temperature. As shown in Figure 30, with
water wash on, 50°F overfiring is required to meet NGC code for
operating conditions of 25°C (77°F) ambient temperature and grid
frequency at 47.5 Hz. Under these conditions, the hours-based
maintenance factor would be 3x as determined by Figure 12.
It is important to understand that operation at overfrequency
conditions will not trade one-for-one for periods at under-
frequency conditions. As was discussed in the firing temperature
section, above, operation at peak firing conditions has a nonlinear,
logarithmic relationship with maintenance factor.
As described above, the NGC code limits operation to 20 seconds
per event at an under-frequency condition between 94% to 95%
speed. Grid events that expose the gas turbine to frequencies
below the minimum continuous speed of 95% introduce additional
maintenance and parts replacement considerations. Operation
at speeds less than 95% requires increased over-fire to achieve
compliance, but also introduces an additional concern that relates
to the potential exposure of the blading to excitations that could
18
47 49.5Frequency ~ Hz 50.5
100% of Active
Power Output
95% of Active
Power Output
Figure 28. The NGC requirement for output versus frequency capability over all
ambients less than 25°C (77°F)
Output versus Grid Frequency
Tamb = 25°C (77°F)
No
r
m
a
l
i
z
e
d

O
u
t
p
u
t
Frequency
46 47 48 49 50 51 52
1.100
1.000
0.900
0.800
0.700
NGC Requirement
Constant Tf
Output Trend
Output
Shortfall
Without
Overfiring
Figure 29.Turbine output at under-frequency conditions
ICNU_DR_177 Attachment C Page 22 of 60
result in blade resonant response and reduced fatigue life.
Considering this potential, a starts-based maintenance factor
of 60x is assigned to every 20 seconds of excursion for grid
frequencies less than 95% speed.
Over-frequency or high speed operation can also introduce
conditions that impact turbine maintenance and part replacement
intervals. If speed is increased above the nominal rated speed,
the rotating components see an increase in mechanical stress
proportional to the square of the speed increase. If firing
temperature is held constant at the overspeed condition, the
life consumption rate of hot gas path rotating components will
increase as illustrated in Figure 31 where one hour of operation
at 105% speed is equivalent to two hours at rated speed.
If overspeed operation represents a small fraction of a turbine’s
operating profile, this effect on parts life can sometimes be
ignored. However, if significant operation at overspeed is expected
and rated firing temperature is maintained, the accumulated hours
must be recorded and included in the calculation of the turbine’s
overall maintenance factor and the maintenance schedule
adjusted to reflect the overspeed operation. An option that
mitigates this effect is to under fire to a level that balances the
overspeed parts life effect. Some mechanical drive applications
have employed that strategy to avoid a maintenance factor
increase.
The frequency-sensitive discussion above describes code
requirements related to turbine output capability versus grid
frequency, where maintenance factors within the continuous
operating speed range are hours-based. There are other
considerations related to turbines operating in grid frequency
regulation mode. In frequency regulation mode, turbines are
dispatched to operate at less than full load and stand ready to
respond to a frequency disturbance by rapidly picking up load.
NGC requirements for units in frequency regulation mode include
being equipped with a fast-acting proportional speed governor
operating with an overall speed droop of 3-5%. With this control, a
gas turbine will provide a load increase that is proportional to the
size of the grid frequency change. For example, a turbine operating
with five percent droop would pick up 20% load in response to a
.5 Hz (1%) grid frequency drop.
The rate at which the turbine picks up load in response to an
under-frequency condition is determined by the gas turbine design
and the response of the fuel and compressor airflow control
systems, but would typically yield a less than ten-second turbine
response to a step change in grid frequency. Any maintenance
factor associated with this operation depends on the magnitude
of the load change that occurs. A turbine dispatched at 50% load
that responded to a 2% frequency drop would have parts life and
maintenance impact on the hot gas path as well as the rotor
structure. More typically, however, turbines are dispatched at
closer to rated load where maintenance factor effects may be
less severe. The NGC requires 10% plant output in 10 seconds in
response to a .5 Hz (1%) under frequency condition. In a combined
cycle installation where the gas turbine alone must pick up the
transient loading, a load change of 15% in 10 seconds would be
GE Energy | GER-3620L.1 (10/10)19
Figure 30.NGC code compliance TF required – FA class
Figure 31.Maintenance factor for overspeed operation ~constant TF
ICNU_DR_177 Attachment C Page 23 of 60
required to meet that requirement. Maintenance factor effects
related to this would be minimal for the hot gas path but would
impact the rotor maintenance factor. For an FA class rotor, each
frequency excursion would be counted as an additional factored
start in the numerator of the maintenance factor calculation
described in Figure 47.A further requirement for the rotor is that
it must be in hot running condition prior to being dispatched in
frequency regulation mode.
Air Quality
Maintenance and operating costs are also influenced by the quality
of the air that the turbine consumes. In addition to the deleterious
effects of airborne contaminants on hot gas path components,
contaminants such as dust, salt and oil can also cause compressor
blade erosion, corrosion and fouling. Twenty-micron particles
entering the compressor can cause significant blade erosion.
Fouling can be caused by submicron dirt particles entering the
compressor as well as from ingestion of oil vapor, smoke, sea salt
and industrial vapors. Corrosion of compressor blading causes
pitting of the blade surface, which, in addition to increasing the
surface roughness, also serves as potential sites for fatigue crack
initiation. These surface roughness and blade contour changes
will decrease compressor airflow and efficiency, which in turn
reduces the gas turbine output and overall thermal efficiency.
Generally, axial flow compressor deterioration is the major cause
of loss in gas turbine output and efficiency. Recoverable losses,
attributable to compressor blade fouling, typically account for
70 to 85 percent of the performance losses seen. As Figure 32
illustrates, compressor fouling to the extent that airflow is reduced
by 5%, will reduce output by 13% and increase heat rate by 5.5%.
Fortunately, much can be done through proper operation and
maintenance procedures to both minimize fouling type losses
and to limit the deposit of corrosive elements. On-line compressor
wash systems are available that are used to maintain compressor
efficiency by washing the compressor while at load, before
significant fouling has occurred. Off-line systems are used to clean
heavily fouled compressors. Other procedures include maintaining
the inlet filtration system and inlet evaporative coolers as well as
periodic inspection and prompt repair of compressor blading.
There are also non-recoverable losses. In the compressor, these are
typically caused by nondeposit-related blade surface roughness,
erosion and blade tip rubs. In the turbine, nozzle throat area
changes, bucket tip clearance increases and leakages are potential
causes. Some degree of unrecoverable performance degradation
should be expected, even on a well-maintained gas turbine. The
owner, by regularly monitoring and recording unit performance
parameters, has a very valuable tool for diagnosing possible
compressor deterioration.
Lube Oil Cleanliness
Contaminated or deteriorated lube oil can cause wear and
damage on bearing liners. This can lead to extended outages and
costly repairs. Routine sampling of the turbine lube oil for proper
viscosity, chemical composition and contamination is an essential
part of a complete maintenance plan.
Lube oil should be sampled and tested per GEK-32568,
“Lubricating Oil Recommendations for Gas Turbines with Bearing
Ambients Above 500°F (260°C).” Additionally, lube oil should be
checked periodically for particulate and water contamination as
outlined in GEK-110483, “Cleanliness Requirements for Power Plant
Installation, Commissioning and Maintenance.” At a minimum, the
lube oil should be sampled on a quarterly basis; however, monthly
sampling is recommended.
20
Figure 32. Deterioration of gas turbine performance due to compressor blade
fouling
ICNU_DR_177 Attachment C Page 24 of 60
Moisture Intake
One of the ways some users increase turbine output is through the
use of inlet foggers. Foggers inject a large amount of moisture in
the inlet ducting, exposing the forward stages of the compressor to
potential water carry-over. Operation of a compressor in such an
environment may lead to long-term degradation of the compressor
due to corrosion and erosion, fouling, and material property
degradation. Experience has shown that depending on the quality
of water used, the inlet silencer and ducting material, and the
condition of the inlet silencer, fouling of the compressor can be
severe with inlet foggers. Similarly, carry-over from evaporative
coolers and excessive water washing can degrade the compressor.
Figure 33 shows the long-term material property degradation
resulting from operating the compressor in a wet environment.
The water quality standard that should be adhered to is found
in GEK-101944B, “Requirements for Water/Steam Purity in
Gas Turbines.”
For turbines with AISI 403 stainless steel compressor blades, the
presence of water carry-over will reduce blade fatigue strength by
as much as 30% and increases the crack propagation rate in a
blade if a flaw is present. The carry-over also subjects the blades
to corrosion. Such corrosion might be accelerated by a saline
environment (see GER-3419). Further reductions in fatigue strength
will result if the environment is acidic and if pitting is present on
the blade. Pitting is corrosion-induced and blades with pitting can
see material strength reduced to 40% of its original value. This
condition is exacerbated by downtime in humid environments,
which promotes wet corrosion.
Uncoated GTD-450™ material is relatively resistant to corrosion
while uncoated AISI 403 is quite susceptible. Relative susceptibility
of various compressor blade materials and coatings is shown in
Figure 34. As noted in GER-3569F, Al coatings are susceptible to
erosion damage leading to unprotected sections of the blade.
Because of this, the GECC-1™ coating was created to combine
the effects of an aluminum-based (Al) coating to prevent corrosion
and a ceramic topcoat to prevent erosion. Water droplets will
cause leading edge erosion on the first few stages of the
compressor. This erosion, if sufficiently developed, may lead to
blade failure. Additionally, the roughened leading edge surface
lowers the compressor efficiency and unit performance.
Utilization of inlet fogging or evaporative cooling may also
introduce water carry-over or water ingestion into the compressor,
resulting in R0 erosion. Although the design intent of evaporative
coolers and inlet foggers should be to fully vaporize all cooling
water prior to its ingestion into the compressor, evidence suggests
that, on systems that were not properly commissioned, the water
may not be fully vaporized (e.g., streaking discoloration on the inlet
duct or bell mouth). If this is the case, then the unit should be
inspected and maintained per instruction, as presented in
applicable Technical Information Letters (TILs).
GE Energy | GER-3620L.1 (10/10)21
Corrosion Due to Environment Aggravates Problem
• Reduces Vane Material Endurance Strength
• Pitting Provides Localized Stress Risers
Fatigue Sensitivity to Environment
Al
t
e
r
n
a
t
i
n
g

S
t
r
e
s
s

R
a
t
i
o
Estimated Fatigue Strength (107 Cycles)
for AISI 403 Blades
ISO
200°F
Acid H2O 180°F
Wet Steam
ISO
Pitted in Air
1.0
0.9
0.7
0.8
0.6
0.5
0.4
0.3
0.2
0.1
0.0
Figure 33. Long-term material property degradation in a wet environment
Bare
Al Slurry Coatings
NiCd+ Topcoats
Ceramic
NiCd
Bare
0 2 4 6 8 10
Worst Best
GTD-450
AISI 403
Relative Corrosion Resistance
Figure 34.Susceptibility of compressor blade materials and coatings
ICNU_DR_177 Attachment C Page 25 of 60
Maintenance Inspections
Maintenance inspection types may be broadly classified as
standby, running and disassembly inspections. The standby
inspection is performed during off-peak periods when the unit is
not operating and includes routine servicing of accessory systems
and device calibration. The running inspection is performed by
observing key operating parameters while the turbine is running.
The disassembly inspection requires opening the turbine for
inspection of internal components and is performed in varying
degrees. Disassembly inspections progress from the combustion
inspection to the hot gas path inspection to the major inspection
as shown in Figure 35.Details of each of these inspections are
described below.
Standby Inspections
Standby inspections are performed on all gas turbines but pertain
particularly to gas turbines used in peaking and intermittent-duty
service where starting reliability is of primary concern. This
inspection includes routinely servicing the battery system, changing
filters, checking oil and water levels, cleaning relays and checking
device calibrations. Servicing can be performed in off-peak periods
without interrupting the availability of the turbine. A periodic startup
test run is an essential part of the standby inspection.
The O&M Manual, as well as the Service Manual Instruction Books,
contain information and drawings necessary to perform these
periodic checks. Among the most useful drawings in the Service
Manual Instruction Books for standby maintenance are the control
specifications, piping schematic and electrical elementaries.
These drawings provide the calibrations, operating limits,
operating characteristics and sequencing of all control devices.
This information should be used regularly by operating and
maintenance personnel. Careful adherence to minor standby
inspection maintenance can have a significant effect on reducing
overall maintenance costs and maintaining high turbine reliability.
It is essential that a good record be kept of all inspections made
and of the maintenance work performed in order to ensure
establishing a sound maintenance program.
Running Inspections
Running inspections consist of the general and continued
observations made while a unit is operating. This starts by
establishing baseline operating data during initial startup of a new
unit and after any major disassembly work. This baseline then
serves as a reference from which subsequent unit deterioration
can be measured.
22
Shutdown Inspections
• Combustion
• Hot Gas Path
• Major
Major Inspection
Hot Gas Path
Inspection
Combustion
Inspection
Figure 35.MS7001EA heavy-duty gas turbine – shutdown inspections
ICNU_DR_177 Attachment C Page 26 of 60
Data should be taken to establish normal equipment startup
parameters as well as key steady state operating parameters.
Steady state is defined as conditions at which no more than a
5°F/3°C change in wheelspace temperature occurs over a
15-minute time period. Data must be taken at regular intervals
and should be recorded to permit an evaluation of the turbine
performance and maintenance requirements as a function of
operating time. This operating inspection data, summarized in
Figure 36,includes: load versus exhaust temperature, vibration, fuel
flow and pressure, bearing metal temperature, lube oil pressure,
exhaust gas temperatures, exhaust temperature spread variation
and startup time. This list is only a minimum and other parameters
should be used as necessary. A graph of these parameters will
help provide a basis for judging the conditions of the system.
Deviations from the norm help pinpoint impending trouble,
changes in calibration or damaged components.
Load vs. Exhaust Temperature
The general relationship between load and exhaust temperature
should be observed and compared to previous data. Ambient
temperature and barometric pressure will have some effect upon
the absolute temperature level. High exhaust temperature can be
an indicator of deterioration of internal parts, excessive leaks or a
fouled air compressor. For mechanical drive applications, it may
also be an indication of increased power required by the driven
equipment.
Vibration Level
The vibration signature of the unit should be observed and
recorded. Minor changes will occur with changes in operating
conditions. However, large changes or a continuously increasing
trend give indications of the need to apply corrective action.
Fuel Flow and Pressure
The fuel system should be observed for the general fuel flow
versus load relationship. Fuel pressures through the system should
be observed. Changes in fuel pressure can indicate the fuel nozzle
passages are plugged, or that fuel-metering elements are
damaged or out of calibration.
Exhaust Temperature and Spread Variation
The most important control function to be observed is the
exhaust temperature fuel override system and the back-up over
temperature trip system. Routine verification of the operation and
calibration of these functions will minimize wear on the hot gas
path parts.
Startup Time
Startup time is an excellent reference against which subsequent
operating parameters can be compared and evaluated. A curve of
the starting parameters of speed, fuel signal, exhaust temperature
and critical sequence bench marks versus time from the initial
start signal will provide a good indication of the condition of the
GE Energy | GER-3620L.1 (10/10)23
• Speed
• Load
• Fired Starts
• Fired Hours
• Site Barometric Reading
• Temperatures
– Inlet Ambient
– Compressor Discharge
– Turbine Exhaust
– Turbine Wheelspace
– Lube Oil Header
– Lube Oil Tank
– Bearing Metal
– Bearing Drains
– Exhaust Spread
• Pressures
– Compressor Discharge
– Lube Pump(s)
– Bearing Header
– Cooling Water
– Fuel
– Filters (Fuel, Lube, Inlet Air)
• Vibration Data for Power Train
• Generator
– Output Voltage – Field Voltage
– Phase Current – Field Current
– VARS – Stator Temp.
– Load – Vibration
• Startup Time
• Coast-Down Time
Figure 36. Operating inspection data parameters
ICNU_DR_177 Attachment C Page 27 of 60
control system. Deviations from normal conditions help pinpoint
impending trouble, changes in calibration or damaged
components.
Coast-Down Time
Coast-down time is an excellent indicator of bearing alignment and
bearing condition. The time period from when the fuel is shut off on
a normal shutdown until the rotor comes to turning gear speed
can be compared and evaluated.
Close observation and monitoring of these operating parameters
will serve as the basis for effectively planning maintenance work
and material requirements needed for subsequent shutdown
periods.
Rapid Cool-Down
Prior to an inspection, it may be necessary to force cool the unit
to speed the cool-down process and shorten outage time. Force
cooling involves turning the unit at crank speed for an extended
period of time to continue flowing ambient air through the
machine. This is permitted, although a natural cool-down cycle
on turning gear or ratchet is preferred for normal shutdowns
when no outage is pending.
Forced cooling should be limited since it imposes additional thermal
stresses on the unit that may result in a reduction of parts life.
Opening the compartment doors during any cool-down operation
is prohibited unless an emergency situation requires immediate
compartment inspection—which requires that the doors be opened.
Cool-down times should not be accelerated by opening the
compartment doors or lagging panels, since uneven cooling of the
outer casings may result in excessive case distortion and blade rubs
that could potentially lead to tip distress if the rubs are significant.
Combustion Inspection
The combustion inspection is a relatively short disassembly
shutdown inspection of fuel nozzles, liners, transition pieces,
crossfire tubes and retainers, spark plug assemblies, flame
detectors and combustor flow sleeves. This inspection
concentrates on the combustion liners, transition pieces, fuel
nozzles and end caps which are recognized as being the first to
require replacement and repair in a good maintenance program.
Proper inspection, maintenance and repair (Figure 37)of these
items will contribute to a longer life of the downstream parts, such
as turbine nozzles and buckets.
Figure 35 illustrates the section of an MS7001EA unit that is
disassembled for a combustion inspection. The combustion liners,
transition pieces and fuel nozzle assemblies should be removed
and replaced with new or repaired components to minimize
downtime. The removed liners, transition pieces and fuel nozzles
can then be cleaned and repaired after the unit is returned to
operation and be available for the next combustion inspection
interval. Typical combustion inspection requirements for
MS6001B/7001EA/9001E machines are:
• Inspect and identify combustion chamber components.
• Inspect and identify each crossfire tube, retainer and
combustion liner.
• Inspect combustion liner for TBC spalling, wear and cracks.
Inspect combustion system and discharge casing for debris and
foreign objects.
• Inspect flow sleeve welds for cracking.
• Inspect transition piece for wear and cracks.
• Inspect fuel nozzles for plugging at tips, erosion of tip holes and
safety lock of tips.
• Inspect all fluid, air, and gas passages in nozzle assembly for
plugging, erosion, burning, etc.
• Inspect spark plug assembly for freedom from binding; check
condition of electrodes and insulators.
• Replace all consumables and normal wear-and-tear items such
as seals, lockplates, nuts, bolts, gaskets, etc.
• Perform visual inspection of first-stage turbine nozzle partitions
and borescope inspect (Figure 3) turbine buckets to mark the
progress of wear and deterioration of these parts. This inspection
will help establish the schedule for the hot gas path inspection.
• Perform borescope inspection of compressor.
• Enter the combustion wrapper and observe the condition of
blading in the aft end of axial-flow compressor with a borescope.
• Visually inspect the compressor inlet, checking the condition of
the IGVs, IGV bushings, and first stage rotating blades.
24 ICNU_DR_177 Attachment C Page 28 of 60
• Check the condition of IGV actuators and rack-and-pinion
gearing.
• Visually inspect compressor discharge case struts for signs of
cracking.
• Visually inspect compressor discharge case inner barrel if
accessible.
• Visually inspect the last-stage buckets and shrouds.
• Visually inspect the exhaust diffuser for any cracks in
flow path surfaces. Inspect insulated surfaces for loose
or missing insulation and/or attachment hardware in internal
and external locations. In E-class machines, inspect the
insulation on the radial diffuser and inside the exhaust
plenum as well.
• Inspect exhaust frame flex seals, L-seals, and horizontal joint
gaskets for any signs of wear or damage.
• Verify proper operation of purge and check valves. Confirm
proper setting and calibration of the combustion controls.
After the combustion inspection is complete and the unit is
returned to service, the removed combustion hardware can be
inspected by a qualified GE field service representative and, if
necessary, sent to a qualified GE Service Center for repairs. The
removed fuel nozzles can be cleaned on-site and flow tested
on-site, if suitable test facilities are available. For F Class gas
turbines it is recommended that repairs and fuel nozzle flow
testing be performed at qualified GE Service Centers.
See the O&M manual for additional recommendations and unit
specific guidance.
GE Energy | GER-3620L.1 (10/10)25
Figure 37.Combustion inspection – key elements
Combustion Inspection
Key Hardware Inspect For Potential Action
Combustion liners Foreign objects
Combustion end covers Abnormal wear
Fuel nozzles Cracking
End caps Liner cooling hole plugging
Transition pieces TBC coating condition
Cross fire tubes Oxidation/corrosion/erosion
Flow sleeves Hot spots/burning
Purge valves Missing hardware
Check valves Clearance limits
Spark plugs Borescope compressor and turbine
Flame detectors
Flex hoses
Exhaust diffuser Cracks Weld repair
Exhaust diffuser Insulation Loose/missing parts Replace/tighten parts
Forward diffuser flex seal Wear/cracked parts Replace seals
Compressor discharge case Cracks Repair or monitoring
Cases – exterior Cracks Repair or monitoring
Criteria
• Op. & Instr. Manual • TILs
• GE Field Engineer
Inspection Methods
• Visual • Liquid Penetrant
• Borescope
Availability of On-Site Spares
is Key to Minimizing Downtime
• Transition Piece
– Strip and recoat
– Weld repair
– Creep repair
• Liners
– Strip and recoat
– Weld repair
– Hula seal
replacement
– Repair out-of-
roundness
• Fuel nozzles
– Weld repair
– Flow test
– Leak test
Repair/refurbish/replace
ICNU_DR_177 Attachment C Page 29 of 60
Hot Gas Path Inspection
The purpose of a hot gas path inspection is to examine those parts
exposed to high temperatures from the hot gases discharged from
the combustion process. The hot gas path inspection outlined
in Figure 38 includes the full scope of the combustion inspection
and, in addition, a detailed inspection of the turbine nozzles,
stator shrouds and turbine buckets. To perform this inspection,
the top half of the turbine shell must be removed. Prior to shell
removal, proper machine centerline support using mechanical
jacks is necessary to assure proper alignment of rotor to stator,
obtain accurate half-shell clearances and prevent twisting of the
stator casings. The MS7001EA jacking procedure is illustrated in
Figure 39.
Special inspection procedures may apply to specific components
in order to ensure that parts meet their intended life. These
inspections may include, but are not limited to, dimensional
inspections, Fluorescent Penetrant Inspection (FPI), Eddy Current
Inspection (ECI) and other forms of non-destructive testing (NDT).
The type of inspection required for specific hardware is determined
on a part number and operational history basis, and can be
obtained from a GE service representative.
Similarly, repair action is taken on the basis of part number, unit
operational history, and part condition. Repairs including (but not
limited to) strip, chemical clean, HIP (Hot Isostatic Processing), heat
treat, and recoat may also be necessary to ensure full parts life.
Weld repair will be recommended when necessary, typically as
determined by visual inspection and NDT. Failure to perform the
required repairs may lead to retirement of the part before its
life potential is fulfilled. In contrast, unnecessary repairs are
an unneeded expenditure of time and resources. To verify the
26
Hot Gas Path Inspection
Key Hardware Inspect For Potential Action
Nozzles (1, 2, 3)Foreign object damage Repair/refurbishment/replace
• Nozzles • Buckets
– Weld repair – Strip & recoat
– Reposition – Weld repair
– Recoat – Blend
– Creep life limit
– Top shroud
deflection
Buckets (1, 2, 3) Oxidation/corrosion/erosion
Stator shrouds Cracking
IGVs and bushings Cooling hole plugging
Compressor blading (borescope)Remaining coating life
Nozzle deflection/distortion
Abnormal deflection/distortion
Abnormal wear
Missing hardware
Clearance limits
Exhaust diffuser Cracks Weld repair
Exhaust diffuser Insulation Loose/missing parts Replace/tighten parts
Forward diffuser flex seal Wear/cracked parts Replace seals
Compressor discharge case Cracks Repair or monitoring
Turbine shell Cracks Repair or monitoring
Cases – exterior Cracks Repair or monitoring
Criteria
• Op. & Instr. Manual • TILs
• GE Field Engineer
Inspection Methods
• Visual • Liquid Penetrant
• Borescope
Availability of On-Site Spares
is Key to Minimizing Downtime
Figure 38. Hot gas path inspection – key elements
ICNU_DR_177 Attachment C Page 30 of 60
types of inspection and repair required, contact your service
representative prior to an outage.
For inspection of the hot gas path (Figure 35), all combustion
transition pieces and the first-stage turbine nozzle assemblies
must be removed. Removal of the second- and third-stage
turbine nozzle segment assemblies is optional, depending upon
the results of visual observations, clearance measurements, and
other required inspections. The buckets can usually be inspected
in place. Fluorescent penetrant inspection (FPI) of the bucket vane
sections may be required to detect any cracks. In addition, a
complete set of internal turbine radial and axial clearances
(opening and closing) must be taken during any hot gas path
inspection. Re-assembly must meet clearance diagram
requirements to ensure against rubs and to maintain unit
performance. Typical hot gas path inspection requirements for
all machines are:
• Inspect and record condition of first, second and third-stage
buckets. If it is determined that the turbine buckets should be
removed, follow bucket removal and condition recording
instructions. Buckets with protective coating should be
evaluated for remaining coating life.
• Inspect and record condition of first-, second- and third-stage
nozzles.
• Inspect and record condition of later-stage nozzle diaphragm
packings.
• Check seals for rubs and deterioration of clearance.
• Record the bucket tip clearances.
• Inspect bucket shank seals for clearance, rubs and deterioration.
• Perform inspections on cutter teeth of tip-shrouded buckets.
Consider refurbishment of buckets with worn cutter teeth,
particularly if concurrently refurbishing the honeycomb of the
corresponding stationary shrouds. Consult your GE Energy
representative to confirm that the bucket under consideration
is repairable.
• Check the turbine stationary shrouds for clearance, cracking,
erosion, oxidation, rubbing and build-up.
• Check and replace any faulty wheelspace thermocouples.
• Enter compressor inlet plenum and observe the condition of the
forward section of the compressor.
• Visually inspect the compressor inlet, checking the condition of
the IGVs, IGV bushings, and first stage rotating blades.
• Check the condition of IGV actuators and rack-and-pinion
gearing.
• Enter the combustion wrapper and, with a borescope, observe
the condition of the blading in the aft end of the axial flow
compressor.
• Visually inspect compressor discharge case struts for signs of
cracking.
• Visually inspect compressor discharge case inner barrel if
accessible.
• Visually inspect the turbine shell shroud hooks for sign of
cracking.
GE Energy | GER-3620L.1 (10/10)27
Figure 39.Stator tube jacking procedure – MS7001EA
ICNU_DR_177 Attachment C Page 31 of 60
• Visually inspect the exhaust diffuser for any cracks in flow path
surfaces. Inspect insulated surfaces for loose or missing
insulation and/or attachment hardware in internal and external
locations. In E-class machines, inspect the insulation on the
radial diffuser and inside the exhaust plenum as well.
• Inspect exhaust frame flex seals, L-seals, and horizontal joint
gaskets for any signs of wear or damage.
The first-stage turbine nozzle assembly is exposed to the direct hot
gas discharge from the combustion process and is subjected to the
highest gas temperatures in the turbine section. Such conditions
frequently cause nozzle cracking and oxidation and, in fact, this
is expected. The second- and third-stage nozzles are exposed to
high gas bending loads, which in combination with the operating
temperatures, can lead to downstream deflection and closure
of critical axial clearances. To a degree, nozzle distress can be
tolerated and criteria have been established for determining when
repair is required. These limits are contained in the Operations
and Maintenance Manuals previously described. However, as
a general rule, first stage nozzles will require repair at the hot
gas path inspection. The second- and third-stage nozzles may
require refurbishment to re-establish the proper axial clearances.
Normally, turbine nozzles can be repaired several times and it is
generally repair cost versus replacement cost that dictates the
replacement decision.
Coatings play a critical role in protecting the buckets operating
at high metal temperatures to ensure that the full capability of
the high strength superalloy is maintained and that the bucket
rupture life meets design expectations. This is particularly true
of cooled bucket designs that operate above 1985°F (1085°C)
firing temperature. Significant exposure of the base metal to
the environment will accelerate the creep rate and can lead
to premature replacement through a combination of increased
temperature and stress and a reduction in material strength,
as described in Figure 40. This degradation process is driven
by oxidation of the unprotected base alloy. In the past, on early
generation uncooled designs, surface degradation due to corrosion
or oxidation was considered to be a performance issue and not a
factor in bucket life. This is no longer the case at the higher firing
temperatures of current generation designs.
Given the importance of coatings, it must be recognized that even
the best coatings available will have a finite life and the condition
of the coating will play a major role in determining bucket life.
Refurbishment through stripping and recoating is an option for
achieving bucket’s expected/design life, but if recoating is selected,
it should be done before the coating is breached to expose base
metal. Normally, for turbines in the MS7001EA class, this means
that recoating will be required at the hot gas path inspection. If
recoating is not performed at the hot gas path inspection, the life
28
Oxidation & Bucket Life
Base Metal Oxidation
Pressure Side Surface
Reduces Bucket Creep Life
Cooling Hole
Surface Oxidation
Depleted Coating
Airfoil Surface
OxidationTE Cooling Hole
Increases Stress
• Reduced Load Carrying Cross Section
Increases Metal Temperature
• Surface Roughness Effects
Decreases Alloy Creep Strength
• Environmental Effects
Figure 40. Stage 1 bucket oxidation and bucket life
ICNU_DR_177 Attachment C Page 32 of 60
of the buckets would generally extend to the major inspection,
at which point the buckets would be replaced. For F class gas
turbines, recoating of the first stage buckets is recommended at
each hot gas path inspection. Visual and borescope examination
of the hot gas path parts during the combustion inspections as
well as nozzle-deflection measurements will allow the operator
to monitor distress patterns and progression. This makes part-life
predictions more accurate and allows adequate time to plan for
replacement or refurbishment at the time of the hot gas path
inspection. It is important to recognize that to avoid extending
the hot gas path inspection, the necessary spare parts should
be on site prior to taking the unit out of service.
See the O&M manual for additional recommendations and unit
specific guidance.
Major Inspection
The purpose of the major inspection is to examine all of the
internal rotating and stationary components from the inlet
of the machine through the exhaust. A major inspection should
be scheduled in accordance with the recommendations in the
owner’s Operations and Maintenance Manual or as modified by
the results of previous borescope and hot gas path inspection.
The work scope shown in Figure 41 involves inspection of all of
the major flange-to-flange components of the gas turbine, which
are subject to deterioration during normal turbine operation.
This inspection includes previous elements of the combustion
and hot gas path inspections, in addition to laying open the
complete flange-to-flange gas turbine to the horizontal joints,
as shown in Figure 42.
Removal of all of the upper casings allows access to the
compressor rotor and stationary compressor blading, as well as
to the bearing assemblies. Prior to removing casings, shells and
frames, the unit must be properly supported. Proper centerline
support using mechanical jacks and jacking sequence procedures
are necessary to assure proper alignment of rotor to stator, obtain
accurate half shell clearances and to prevent twisting of the
casings while on the half shell. Typical major inspection
requirements for all machines are:
• All radial and axial clearances are checked against their original
values (opening and closing).
• Casings, shells and frames/diffusers are inspected for cracks
and erosion.
• Compressor inlet and compressor flow-path are inspected for
fouling, erosion, corrosion and leakage.
• Visually inspect the compressor inlet, checking the condition of
the IGVs, IGV bushings, and first stage rotating blades.
• Check the condition of IGV actuators and rack-and-pinion
gearing.
• Rotor and stator compressor blades are checked for tip
clearance, rubs, impact damage, corrosion pitting, bowing and
cracking.
• Turbine stationary shrouds are checked for clearance, erosion,
rubbing, cracking, and build-up.
• Seals and hook fits of turbine nozzles and diaphragms are
inspected for rubs, erosion, fretting or thermal deterioration.
• Turbine buckets are removed and a nondestructive check of
buckets and wheel dovetails is performed (first stage bucket
protective coating should be evaluated for remaining coating
life). Buckets that were not recoated at the hot gas path
inspection should be replaced. Wheel dovetail fillets, pressure
faces, edges, and intersecting features must be closely examined
for conditions of wear, galling, cracking or fretting.
• Rotor inspections recommended in the maintenance and
inspection manual or by Technical Information Letters should be
performed.
• Bearing liners and seals are inspected for clearance and wear.
• Inlet systems are inspected for corrosion, cracked silencers and
loose parts.
• Visually inspect compressor and compressor discharge case
hooks for signs of wear.
• Visually inspect compressor discharge case struts for signs of
cracking.
• Visually inspect compressor discharge case inner barrel if
accessible.
• Visually inspect the turbine shell shroud hooks for sign of
cracking.
GE Energy | GER-3620L.1 (10/10)29ICNU_DR_177 Attachment C Page 33 of 60
30
Major Inspection
Hot Gas Path Inspection Scope—Plus:
Key Hardware Inspect For Potential Action
Compressor blading Foreign object damage Repair/refurbishment/replace
Compressor and turbine rotor dovetails Oxidation/corrosion/erosion Stator shrouds
• Cracking/oxidation/erosionJournals and seal surfaces Cracking
Bearing seals Leaks Buckets
• Coating deterioration
• FOD/rubs/cracking
• Tip shroud deflection
• Creep life limit
Exhaust system Abnormal wear
Missing hardware
Clearance limits
Nozzles
• Severe deterioration
IGV bushings
• Wear
Bearings/seals
• Scoring/wear
Compressor blades
• Corrosion/erosion
• Rubs/FOD
Rotor inspection
Compressor discharge case Cracks Repair or monitoring
Turbine shell Cracks Repair or monitoring
Compressor and compressor
discharge case hooks
Wear Repair
Cases – exterior and interior Cracks Repair or monitoring
Exhaust diffuser Cracks Weld repair
Exhaust diffuser insulation Loose/missing parts Replace/tighton parts
Forward diffuser flex seal Wear/cracked parts Replace seals
Figure 41. Gas turbine major inspection – key elements
Criteria
• Op. & Instr. Manual • TILs
• GE Field Engineer
Inspection Methods
• Visual • Liquid Penetrant
• Borescope • Ultrasonics
Figure 41. Gas turbine major inspection – key elements
ICNU_DR_177 Attachment C Page 34 of 60
• Visually inspect the exhaust diffuser for any cracks in flow path
surfaces. Inspect insulated surfaces for loose or missing
insulation and/or attachment hardware in internal and external
locations. In E-class machines, inspect the insulation on the
radial diffuser and inside the exhaust plenum as well.
• Inspect exhaust frame flex seals, L-seals, and horizontal joint
gaskets for any signs of wear or damage. Inspect steam gland
seals for wear and oxidation.
• Check torque values for steam gland bolts and re-torque to
full values.
• Check alignment – gas turbine to generator/gas turbine to
accessory gear.
Comprehensive inspection and maintenance guidelines have been
developed by GE and are provided in the O&M Manual to assist
users in performing each of the inspections previously described.
Parts Planning
Lack of adequate on-site spares can have a major effect on plant
availability; therefore, prior to a scheduled disassembly type of
inspection, adequate spares should be on-site. A planned outage
such as a combustion inspection, which should only take two to
five days, could take weeks. GE will provide recommendations
regarding the types and quantities of spare parts needed; however,
it is up to the owner to purchase these spare parts on a planned
basis allowing adequate lead times.
Early identification of spare parts requirements ensures their
availability at the time the planned inspections are performed.
Refer to the Reference Drawing Manual provided as part of the
comprehensive set of O&M Manuals to aid in identification and
ordering of gas turbine parts.
Additional benefits available from the renewal parts catalog data
system are the capability to prepare recommended spare parts
lists for the combustion, hot gas path and major inspections as
well as capital and operational spares.
Typical expectations for estimated repair cycles for some of the
major components are shown in Appendix D. These tables assume
that operation of the unit has been in accordance with all of the
manufacturer’s specifications and instructions.
Maintenance inspections and repairs are also assumed to be
done in accordance with the manufacturer’s specifications and
instructions. The actual repair and replacement cycles for any
particular gas turbine should be based on the user’s operating
GE Energy | GER-3620L.1 (10/10)31
Major Inspection
Hot Gas Path
Inspection
Combustion
Inspection
Figure 42.Major inspection work scope
ICNU_DR_177 Attachment C Page 35 of 60
procedures, experience, maintenance practices and repair
practices. The maintenance factors previously described can have
a major impact on both the component repair interval and service
life. For this reason, the intervals given in Appendix D should only
be used as guidelines and not certainties for long range parts
planning. Owners may want to include contingencies in their
parts planning.
The expected repair and replacement cycle values reflect current
production hardware.
To achieve these lives, current production parts with design
improvements and newer coatings are required. With earlier
production hardware, some of these lives may not be achieved.
Operating factors and experience gained during the course of
recommended inspection and maintenance procedures will be a
more accurate predictor of the actual intervals.
Appendix D shows expected repair and replacement intervals
based on the recommended inspection intervals shown in
Figure 44.The application of inspection (or repair) intervals other
than those shown in Figure 44 can result in different replacement
intervals (as a function of the number of repair intervals) than
those shown in Appendix D. See your GE representative for
details on a specific system. It should be recognized that, in some
cases, the service life of a component is reached when it is no
longer economical to repair any deterioration as opposed to
replacing at a fixed interval. This is illustrated in Figure 43 for a
first stage nozzle, where repairs continue until either the nozzle
cannot be restored to minimum acceptance standards or the
repair cost exceeds or approaches the replacement cost. In other
cases, such as first-stage buckets, repair options are limited by
factors such as irreversible material damage. In both cases, users
should follow GE recommendations regarding replacement or
repair of these components.
While the parts lives shown in Appendix D are guidelines, the
life consumption of individual parts within a parts set can have
variations. The repair versus replacement economics shown in
Figure 43 may lead to a certain percentage of “fallout,” or scrap,
of parts being repaired. Those parts that fallout during the
repair process will need to be replaced by new parts. Parts
fallout will vary based on the unit operating environment history,
the specific part design, and the current state-of-the-art for
repair technology.
32
Operating Hours
No
z
z
l
e

C
o
n
s
t
r
u
c
t
i
o
n
Severe Deterioration
10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000
New Nozzle
Acceptance Standards
Repaired Nozzle
Min. Acceptance
Standard
1st
Repair
2nd
Repair
3rd
Repair
Re
p
a
i
r

C
o
s
t

E
x
c
e
e
d
s
Re
p
l
a
c
e
m
e
n
t

C
o
s
t
Without Repair
Figure 43. First-stage nozzle wear-preventive maintenance: gas fired – continuous dry – base load
ICNU_DR_177 Attachment C Page 36 of 60
Inspection Intervals
In the absence of operating experience and resulting part conditions,
Figure 44 lists the recommended combustion, hot gas path and
major inspection intervals for current production GE turbines
operating under typical conditions of gas fuel, base load, and no
water or steam injection. These recommended intervals represent
factored hours or starts calculated using maintenance factors to
account for application specific operating conditions. Initially,
recommended intervals are based on the expected operation of
a turbine at installation, but this should be reviewed and adjusted
as actual operating and maintenance data are accumulated.
While reductions in the recommended intervals will result from the
factors described previously or unfavorable operating experience,
increases in the recommended intervals may also be considered
where operating experience has been favorable. The condition
of the combustion and hot gas path parts provides a good basis
for customizing a program of inspection and maintenance. The
condition of the compressor and bearing assemblies is the key
driver in planning a Major Inspection. Historical operation and
machine conditions can be used to tailor custom maintenance
programs such as optimized repair and inspection criteria to specific
sites/machines. GE leverages these principles and accumulated site
and fleet experience in a “Condition Based Maintenance” program
as the basis for maintenance of units under Contractual Service
Agreements. This experience was accumulated on units that
operate with GE approved repairs, field services, monitoring
and full compliance to GE’s technical recommendations.
GE can assist operators in determining the appropriate
maintenance intervals for their particular application. Equations
have been developed that account for the factors described
earlier and can be used to determine application specific hot
gas path and major inspection intervals.
GE Energy | GER-3620L.1 (10/10)33
Factors that can reduce maintenance intervals:
• Fuel
• Load setting
• Steam/water injection
• Peak load firing
operation
• Trips
• Start cycle
• Hardware design
Type of Inspection Combustion System
Factored Hours/Factored Starts
MS3002K MS5001PA/MS5002C, D MS6B MS7E/EA MS9E
Combustion Non-DLN 24000/400 12000/800 (1) (3)12000/1200(2) (3)8000/900 (3)8000/900(3)
DLN 8000/400 12000/450 12000/450 12000/450
Hot Gas Path 24000/1200 Eliminated/1200 24000/1200 24000/1200 24000/900
Major 48000/2400 48000/2400 48000/2400 48000/2400 48000/2400
Type of
Inspection
Combustion
System
Factored Hours/Factored Starts
MS6FA MS6FA+e MS7F/FA/FA+MS7FA+e MS9F/FA/FA+MS9FA+e MS7FB MS9FB
Combustion Non-DLN 8000/450 8000/450
DLN 8000/450 12000/450 8000/450 12000/450 8000/450 8000/450 12000/450 12000/450
Hot Gas Path 24000/900 24000/900 24000/900 24000/900 24000/900 24000/900 24000/900 24000/900
Major 48000/2400 48000/2400 48000/2400 48000/2400 48000/2400 48000/2400 48000/2400 48000/2400
1. Units with Lean Head End liners have
a 400-starts combustion inspection interval.
2. Machines with 6581 and 6BeV combustion
hardware have a 12000/600 combustion
inspection interval.
3. Multiple Non-DLN configurations exist
(Standard, MNQC, IGCC). The typical case
is shown; however, different quoting limits
may exist on a machine and hardware basis.
Contact a GE Energy representative for
further information.
Note: Factored Hours/Starts intervals include an
allowance for nominal trip maintenance
factor effects.
Hours/Starts intervals for Major Inspection
are quoted in Actual Hours and Actual Starts.
Repair/replace cycles reflect current
production hardware, unless otherwise
noted, and operation in accordance with
manufacturer specifications. They represent
initial recommended intervals in the absence
of operating and condition experience.
Figure 44.Base line recommended inspection intervals: base load – gas fuel – dry
ICNU_DR_177 Attachment C Page 37 of 60
Borescope Inspection Interval
In addition to the planned maintenance intervals, which undertake
scheduled inspections or component repairs or replacements,
borescope inspections (BIs) should be conducted to identify any
additional actions, as discussed in the sections “Gas Turbine Design
Maintenance Features.” Such inspections may identify additional
areas to be addressed at a future scheduled maintenance outage,
assist with parts or resource planning, or indicate the need to
change the timing of a future outage to minimize potential effects.
The BI should use all the available access points to verify the safe
and uncompromised condition of the static and rotating hardware.
As much of the Major Inspection workscope as possible should
be done using this visual inspection without dissassembly. Refer
to Figure 4 for standard recommended BI frequency. Specific
concerns may warrant subsequent BIs in order to operate
the unit to the next scheduled outage without teardown.
Hot Gas Path Inspection Interval
The hours-based hot gas path criterion is determined from the
equation given in Figure 45. With this equation, a maintenance
factor is determined that is the ratio of factored operating hours
and actual operating hours. The factored hours consider the
specifics of the duty cycle relating to fuel type, load setting and
steam or water injection. Maintenance factors greater than one
reduce the hot gas path inspection interval from the 24,000 hour
ideal case for continuous base load, gas fuel and no steam or
water injection. To determine the application specific maintenance
interval, the maintenance factor is divided into 24,000, as shown
in Figure 45.
The starts-based hot gas path criterion is determined from the
equation given in Figure 46. As with the hours-based criteria, an
application specific starts-based hot gas path inspection interval is
calculated from a maintenance factor that is determined from the
number of trips typically being experienced, the load level and
loading rate.
As previously described, the hours and starts operating spectrum
for the application is evaluated against the recommended hot gas
path intervals for starts and for hours. The limiting criterion (hours or
starts) determines the maintenance interval. An example of the use
of these equations for the hot gas path is contained in Appendix A.
34
Hours-Based HGP Inspection
Where:
Factored Hours = (K + M x I) x (G + 1.5D + AfH + ApP)
Actual Hours = (G + D + H + P)
G = Annual Base Load Operating hours on Gas Fuel
D = Annual Base Load Operating hours on
Distillate Fuel
H = Annual Operating Hours on Heavy Fuel
Af = Heavy Fuel Severity Factor
(Residual Af = 3 to 4, Crude Af = 2 to 3)
Ap = Peak Load Factor (See Figure 12)
P = Annual Peak Load Operating Hours on gas or distillate
I = Percent Water/Steam Injection Referenced to
Compressor Inlet Air Flow
M&K = Water/Steam Injection Constants
Maintenance Interval =(Hours)
24000
Maintenance Factor
Factored Hours
Actual HoursMaintenance Factor =
M K Control Steam Injection N2/N3 Material
0 1 Dry <2.2% GTD-222/FSX-414
0 1 Dry >2.2% GTD-222
.18 .6 Dry >2.2% FSX-414
.18 1 Wet >0% GTD-222
.55 1 Wet >0% FSX-414
Figure 45. Hot gas path maintenance interval: hours-based criterion
Actual Starts = (NA + NB + NP)
η
Factored Starts = 0.5NA + NB + 1.3NP + 20E + 2F + Σ (aTi – 1) Tii=1
Starts-Based HGP Inspection
Maintenance Interval
(Starts)
S
Maintenance Factor=
Where:
Maintenance Factor Factored Starts
Actual Starts=
S Maximum Starts-Based Maintenance Interval
(Model Size Dependent)
=
NA Annual Number of Part Load Start/Stop Cycles (<60% Load)=
NB Annual Number of Base Load Start/Stop Cycles=
NP Annual Number of Peak Load Start/Stop Cycles (>100% Load)=
E Annual Number of Emergency Starts=
F Annual Number of Fast Load Starts=
T Annual Number of Trips=
a T Trip Severity Factor = f(Load) (See Figure 21)=
Number of Trip Categories (i.e.Full Load, Part Load, etc.)=η
Model Series S Model Series S
MS6B/MS7EA 1,200 MS9E 900
MS6FA 900 MS7F/MS9F 900
Figure 46. Hot gas path maintenance interval: starts-based criterion
ICNU_DR_177 Attachment C Page 38 of 60
Rotor Inspection Interval
Like HGP components, the unit rotor has a maintenance interval
involving removal, disassembly and thorough inspection. This
interval indicates the serviceable life of the rotor and is generally
considered to be the teardown inspection and repair/replacement
interval for the rotor. These intervals are traditionally concurrent
with hot gas path and major inspections, however, it should be
noted that the maintenance factors for rotor maintenance intervals
are distinct and different from those of combustion and hot gas
path components. As such, the calculation of consumed life on
the rotor may vary from that of combustion and hot gas path
components. Customers should contact GE when their rotor has
reached the end of its serviceable life for technical advisement.
The starts-based rotor maintenance interval is determined from the
equation given in Figure 47. Adjustments to the rotor maintenance
interval are determined from rotor-based operating factors as were
described previously. In the calculation for the starts-based rotor
maintenance interval, equivalent starts are determined for cold,
warm, and hot starts over a defined time period by multiplying
the appropriate cold, warm and hot start operating factors by the
number of cold, warm and hot starts respectively. In this calculation,
start classification is key. Additionally, equivalent starts for trips
from load are added. The total equivalent starts are divided by
the actual number of starts to yield the maintenance factor. The
rotor starts-based maintenance interval for a specific application
is determined by dividing the baseline rotor maintenance interval
of 5000 starts by the calculated maintenance factor. As indicated
in Figure 47, the baseline rotor maintenance interval is also the
maximum interval, since calculated maintenance factors less
than one are not considered.
Figure 48 describes the procedure to determine the hours-based
maintenance criterion. Peak load operation is the primary
maintenance factor for the F class rotor and will act to increase
the hours-based maintenance factor and to reduce the rotor
maintenance interval.
When the rotor reaches the limiting inspection interval determined
from the equations described in Figures 47 and 48, a refurbishment
of the rotor is required so that a complete inspection of the rotor
components in both the compressor and turbine can be performed.
It should be expected that some rotor components will either have
reached the end of their serviceable life or will have a minimal
GE Energy | GER-3620L.1 (10/10)35
cwwh
ttccwwwwhh
NNNN
NFNFNFNFNF
+++
·+·+·+·+·
21
2211Maintenance Factor =
Rotor Maintenance Interval = (Not to exceed 5000 starts)
MF>=1
= Number of hot starts
= Number of Warm1 starts
= Number of Warm2 starts
= Number of cold starts
= Number of trips
Number of Starts
Nh
Nw1
Nw2
Nc
Nt
Start Factors
Fh
Fw1
Fw2Fc
Ft
= Warm1 start factor (Down 4-20 hr)
= Warm2 start factor (Down 20-40 hr)
= Cold start factor (Down >40 hr)
= Trip from load factor
5000
Maintenance Factor
(1)
Starts-Based Rotor Inspection
(1) F class
Note: Start factors for 7/9 FA+e machines are tabulated in Figure 23.
For other F Class machines, refer to applicable TILs.
= Hot start factor (Down 1-4 hr)*
Figure 47. Rotor maintenance interval: starts-based criterion
ICNU_DR_177 Attachment C Page 39 of 60
amount of residual life remaining and will require replacement at
this inspection point. Depending on the extent of refurbishment
and part replacement, subsequent inspections may be required
at a reduced interval.
As with major inspections, the rotor repair interval should include
thorough dovetail inspections for wear and cracking. The baseline
rotor life is predicated upon sound inspection results at the majors.
The baseline intervals of 144,000 hours and 5000 starts in Figures
47 and 48 pertain to F class rotors. For rotors other than F class,
rotor maintenance should be performed at intervals recommended
by GE through issued Technical Information Letters (TILs). Where
no recommendations have been made, rotor inspection should be
performed at 5,000 factored starts or 200,000 factored hours.
Combustion Inspection Interval
Equations have been developed that account for the earlier
mentioned factors affecting combustion maintenance intervals.
These equations represent a generic set of maintenance factors
that provide general guidance on maintenance planning. As such,
these equations do not represent the specific capability of any given
combustion system. They do provide, however, a generalization of
combustion system experience. For combustion parts, the base line
operating conditions that result in a maintenance factor of one
are normal fired startup and shutdown (no trip) to base load
on natural gas fuel without steam or water injection.
An hours-based combustion maintenance factor can be
determined from the equations given in Figure 49 as the ratio
of factored-hours to actual operating hours. Factored-hours
considers the effects of fuel type, load setting and steam or
water injection. Maintenance factors greater than one reduce
recommended combustion inspection intervals from those shown
in Figure 44 representing baseline operating conditions. To obtain
a recommended inspection interval for a specific application, the
maintenance factor is divided into the recommended base line
inspection interval.
36
Maintenance Factor = (Factored Hours)/(Actual Hours)
Factored Hours = ∑ (Ki x Afi x Api x ti), i = 1 to n Operating Modes
Actual Hours = ∑ (ti), i = 1 to n Operating Modes
Where:
i = Discrete Operating mode (or Operating Practice of Time Interval)
ti = Operating hours at Load in a Given Operating mode
Api = Load Severity factor
Ap = 1.0 up to Base Load
Ap = For Peak Load Factor See Figure 12
Afi = Fuel Severity Factor (dry)
Af = 1.0 for Gas Fuel (1)
Af = 1.5 for Distillate Fuel, Non-DLN (2.5 for DLN)
Af = 2.5 for Crude (Non-DLN)
Af = 3.5 for Residual (Non-DLN)
Ki = Water/Steam Injection Severity Factor
(% Steam Referenced to Compressor Inlet Air Flow, w/f = Water to Fuel Ratio)
K = Max(1.0, exp(0.34(%Steam – 2.00%))) for Steam, Dry Control Curve
K = Max(1.0, exp(0.34(%Steam – 1.00%))) for Steam, Wet Control Curve
K = Max(1.0, exp(1.80(w/f – 0.80))) for Water, Dry Control Curve
K = Max(1.0, exp(1.80(w/f – 0.40))) for Water, Wet Control Curve
(1) Af = 10 for DLN 1 extended lean-lean, DLN 2.0 lean-lean and DLN 2+ in extended sub-piloted
and extended piloted premixed operating modes.
Figure 49.Combustion inspection hours-based maintenance factors

Maintenance Factor =
Where:
H ~ Base load hours
P ~ Peak load hours
(1) F class
(2) For E-class, MF = (H + 2*P + 2*TG) / (H + P), where TG is
hours on turning gear.
To diminish potential turning gear impact, Major
Inspections must include a thorough visual and
dimensional examination of the hot gas path turbine
rotor dovetails for signs of wearing, galling, fretting or
cracking. If inspections and repairs are performed to
the dovetails, time on turning gear may be omitted
from the hours based maintenance factor.
144000(1)
Maintenance Factor
H + 2*P (2)
H + P
Hours-Based Rotor Inspection
Note:
Rotor Maintenance Interval =
Figure 48.Rotor maintenance interval: hours-based criterion
ICNU_DR_177 Attachment C Page 40 of 60
A starts-based combustion maintenance factor can be determined
from the equations given in Figure 50 and considers the effect
of fuel type, load setting, emergency starts, fast loading rates,
trips and steam or water injection. An application specific
recommended inspection interval can be determined from the
baseline inspection interval in Figure 44 and the maintenance
factor from Figure 50. Appendix B shows six example maintenance
factor calculations using the above hours and starts maintenance
factors equations.
Manpower Planning
It is essential that advanced manpower planning be conducted
prior to an outage. It should be understood that a wide range of
experience, productivity and working conditions exist around the
world. However, based upon maintenance inspection man-hour
assumptions, such as the use of an average crew of workers in the
United States with trade skill (but not necessarily direct gas turbine
experience), with all needed tools and replacement parts (no repair
time) available, an estimate can be made. These estimated craft
labor man-hours should include controls and accessories and the
generator. In addition to the craft labor, additional resources are
needed for technical direction of the craft labor force, specialized
tooling, engineering reports, and site mobilization/demobilization.
Inspection frequencies and the amount of downtime varies
within the gas turbine fleet due to different duty cycles and
the economic need for a unit to be in a state of operational
readiness. It can be demonstrated that an 8000-hour interval
for a combustion inspection with minimum downtime can be
achievable based on the above factors. Contact your local GE
Energy representative for the specific man-hours and
recommended crew size for your specific unit.
Depending upon the extent of work to be done during each
maintenance task, a cooldown period of 4 to 24 hours may
be required before service may be performed. This time can be
utilized productively for job move-in, correct tagging and locking
equipment out-of-service and general work preparations. At the
conclusion of the maintenance work and systems check out,
a turning gear time of two to eight hours is normally allocated
prior to starting the unit. This time can be used for job clean-up
and preparing for start.
Local GE field service representatives are available to help plan
your maintenance work to reduce downtime and labor costs.
This planned approach will outline the renewal parts that may
be needed and the projected work scope, showing which tasks
can be accomplished in parallel and which tasks must be sequential.
GE Energy | GER-3620L.1 (10/10)37
Maintenance Factor = (Factored starts)/(Actual Starts)
Factored Starts = ∑ (Ki x Afi x Ati x Api x Asi x Ni), i = 1 to n Start/Stop Cycles
Actual Starts = ∑ (Ni), i = 1 to n Start/Stop Cycles
Where:
i = Discrete Start/Stop Cycle (or Operating Practice)
Ni = Start/Stop Cycles in a Given Operating Mode
Asi = Start Type Severity Factor
As = 1.0 for Normal Start
As = 1.2 for Start with Fast Load
As = 3.0 for Emergency Start
Api = Load Severity Factor
Ap = 1.0 up to Base Load
Ap = exp(0.009 x Peak Firing Temp Adder in deg F) for Peak Load
Ati = Trip Severity Factor
At = 0.5 + exp(0.0125*%Load) for Trip
Afi = Fuel Severity Factor (Dry, at Load)
Af = 1.0 for Gas Fuel
Af = 1.25 for Non-DLN (or 1.5 for DLN) for Distillate Fuel
Af = 2.0 for Crude (Non-DLN)
Af = 3.0 for Residual (Non-DLN)
Ki = Water/Steam Injection Severity Factor
(% Steam Referenced to Compressor Inlet Air Flow, w/f = Water to Fuel Ratio)
K = Max(1.0, exp(0.34(%Steam – 1.00%))) for Steam, Dry Control Curve
K = Max(1.0, exp(0.34(%Steam – 0.50%))) for Steam, Wet Control Curve
K = Max(1.0, exp(1.80(w/f – 0.40))) for Water, Dry Control Curve
K = Max(1.0, exp(1.80(w/f – 0.20))) for Water, Wet Control Curve
Figure 50. Combustion inspection starts-based maintenance factors
ICNU_DR_177 Attachment C Page 41 of 60
Planning techniques can be used to reduce maintenance cost by
optimizing lifting equipment schedules and manpower requirements.
Precise estimates of the outage duration, resource requirements,
critical-path scheduling, recommended replacement parts, and
costs associated with the inspection of a specific installation may
be sourced from the local GE field services office.
Conclusion
GE heavy-duty gas turbines are designed to have an inherently
high availability. To achieve maximum gas turbine availability,
an owner must understand not only the equipment, but the
factors affecting it. This includes the training of operating
and maintenance personnel, following the manufacturer’s
recommendations, regular periodic inspections and the stocking
of spare parts for immediate replacement. The recording and
analysis of operating data, is essential to preventative and
planned maintenance. A key factor in achieving this goal
is a commitment by the owner to provide effective outage
management and full utilization of published instructions
and the available service support facilities.
It should be recognized that, while the manufacturer provides
general maintenance recommendations, it is the equipment
user who has the major impact upon the proper maintenance
and operation of equipment. Inspection intervals for optimum
turbine service are not fixed for every installation, but rather
are developed through an interactive process by each user,
based on past experience and trends indicated by key turbine
factors. In addition, through application of a Contractual Service
Agreement to a particular turbine, GE can work with a user to
establish a maintenance program that may differ from general
recommendations but will be consistent with contractual
responsibilities.
The level and quality of a rigorous maintenance program have a
direct impact on equipment reliability and availability. Therefore, a
rigorous maintenance program which optimizes both maintenance
cost and availability is vital to the user. A rigorous maintenance
program will minimize overall costs, keep outage downtimes to
a minimum, improve starting and running reliability and provide
increased availability and revenue earning ability for GE gas
turbine users.
References
Jarvis, G., “Maintenance of Industrial Gas Turbines,” GE Gas Turbine
State of the Art Engineering Seminar, paper SOA-24-72, June 1972.
Patterson, J. R., “Heavy-Duty Gas Turbine Maintenance Practices,”
GE Gas Turbine Reference Library, GER-2498, June 1977.
Moore, W. J., Patterson, J.R, and Reeves, E.F., “Heavy-Duty Gas
Turbine Maintenance Planning and Scheduling,” GE Gas Turbine
Reference Library, GER-2498; June 1977, GER 2498A, June 1979.
Carlstrom, L. A., et al., “The Operation and Maintenance of General
Electric Gas Turbines,” numerous maintenance articles/authors
reprinted from Power Engineering magazine, General Electric
Publication, GER-3148; December 1978.
Knorr, R. H., and Reeves, E. F., “Heavy-Duty Gas Turbine
Maintenance Practices,” GE Gas Turbine Reference Library, GER-
3412; October 1983; GER- 3412A, September 1984; and GER-
3412B, December 1985.
Freeman, Alan, “Gas Turbine Advance Maintenance Planning,”
paper presented at Frontiers of Power, conference, Oklahoma State
University, October 1987.
Hopkins, J. P, and Osswald, R. F., “Evolution of the Design,
Maintenance and Availability of a Large Heavy-Duty Gas Turbine,”
GE Gas Turbine Reference Library, GER-3544, February 1988 (never
printed).
Freeman, M. A., and Walsh, E. J., “Heavy-Duty Gas Turbine
Operating and Maintenance Considerations,” GE Gas Turbine
Reference Library, GER-3620A.
GEI-41040, “Fuel Gases for Combustion in Heavy-Duty Gas
Turbines.”
GEI-41047, “Gas Turbine Liquid Fuel Specifications.”
GEK-101944, “Requirements for Water/Steam Purity in Gas Turbines.”
GER-3419A, “Gas Turbine Inlet Air Treatment.”
GER-3569F, “Advanced Gas Turbine Materials and Coatings.”
GEK-32568, “Lubricating Oil Recommendations for Gas Turbines
with Bearing Ambients Above 500°F (260°C).”
GEK-110483, “Cleanliness Requirements for Power Plant
Installation, Commissioning and Maintenance.”
38 ICNU_DR_177 Attachment C Page 42 of 60
GE Energy | GER-3620L.1 (10/10)39
Appendix
A.1) Example 1 – Hot Gas Path Maintenance
Interval Calculation
An MS7001EA user has accumulated operating data since the last
hot gas path inspection and would like to estimate when the next
one should be scheduled. The user is aware from GE publications
that the normal HGP interval is 24,000 hours if operating on
natural gas, with no water or steam injection, and at base load.
It is also understood that the nominal starts interval is 1200,
based on normal startups, no trips, no emergency starts. The
actual operation of the unit since the last hot gas path inspection
is much different from the GE “baseline case.”
Annual hours on natural gas, base load
= G = 3200 hr/yr
Annual hours on light distillate
= D = 350 hr/yr
Annual hours on peak load
= P = 120 hr/yr
Steam injection rate
= I = 2.4%
Also, since the last hot gas path inspection,
140 Normal start-stop cycles:
40 Part load
100 Base load
0 Peak load
In addition,
E = 2 Emergency Starts w / ramp to
base load
F = 5 Fast loads ending in a normal shutdown
from base load
T = 20 Starts with trips from base load

(a Ti = 8)
From Figure 45, at a steam injection rate of 2.4%, the
value of “M” is .18, and “K” is .6.
From the hours-based criteria, the maintenance factor is
determined from Figure 45.
For this particular unit, the second and third-stage nozzles are
FSX-414 material. The unit operates on “dry control curve.”
MF =[K + M(I)] x [G + 1.5(D) + Af(H) + AP x P]
(G + D + H + P)
MF =[.6 + .18(2.4)] x [3200 + 1.5(350) + 0 + 6(120)]
(3200 + 350 + 0 + 120)
MF = 1.25
The hours-based adjusted inspection interval is therefore,
H = 24,000/1.25
H = 19,200 hours
[Note, since total annual operating hours is 3670,
the estimated time to reach 19,200 hours is
5.24 years (19,200/3670).]
From the starts-based criteria, the maintenance factor
is determined from Figure 46.
The total number of part load starts is
NA = 40/yr
The total number of base load starts is
NB = 100 + 2 + 5 + 20 = 127/yr
The total number of peak load starts is
NP = 0/yr
MF =[0.5 (NA)+(NB )+1.3(NP )+20(E)+2(F) +
NA + N B + N P
MF =0.5(40)+(127)+1.3(0)+20(2)+2(5)+(8–1)20
40+127+0
MF = 2
Σ
n
i=1
(aTI – 1) Ti
Annual hours on peak load at +100 deg F firing temperature
P = 120 hr/yr
AP = 6
ICNU_DR_177 Attachment C Page 43 of 60
40
The adjusted inspection interval based on starts is
S = 1200/2.0
S = 600 starts [Note, since the total annual number of starts is
167, the estimated time to reach 600 starts is
600/167 = 3.6 years.]
In this case, the starts-based maintenance factor is greater than
the hours maintenance factor and therefore the inspection interval
is set by starts. The hot gas path inspection interval is 600 starts
(or 3.6 years).
A.2) Example 2 – Hot Gas Path Factored
Starts Calculation
An MS7001EA user has accumulated operating data for the past
year of operation. This data shows number of trips from part, base,
and peak load, as well as emergency starting and fast loading. The
user would like to calculate the total number of factored starts in
order to plan the next HGP outage. Figure 46 is used to
calculate the total number of factored starts as shown below.
Operational history:
150 Start-stop cycles per year:
40 Part load
60 Base load
50 Peak load
50 ending in trips:
10 from 105% load
5 from 50% load (part load)
35 from 65% load (base load)
In addition,
3 Emergency Starts w/ramp to base load:
2 ended in a trip from full load
1 ended in a normal shutdown
4 Fast loads:
1 tripped during loading at 50% load
3 achieved base load and ended in
a normal shutdown
Total Starts
Part Load, NA = 40 + 1 = 41
Base Load, NB = 60 + 3 + 3 = 66
Peak Load, NP = 50
Total Trips
1. 50% load (aT1=6.5), T1 = 5 + 1 = 6
2. Full load (aT 2 =8), T2 = 35 + 2 = 37
3. Peak load (aT3 =10), T3 = 10
Additional Cycles
Emergency starting, E = 3
Fast loading, F = 4
From the starts-based criteria, the total number of
factored starts is determined from Figure 46.
FS = 0.5(NA)+(NB)+1.3(NP)+20(E)+2(F)+
FS = 0.5(41)+(66)+1.3(50)+20(3)+2(4)+[(6.5–1)6+
(8–1)37+(10–1)10]=601.50
AS = 41 + 66 + 50 = 157
MF = = 3.8601.5
157
Σ
n
i=1
(aTI – 1) Ti
ICNU_DR_177 Attachment C Page 44 of 60
B) Examples – Combustion Maintenance Interval
Calculations (reference Figures 49 and 50)
GE Energy | GER-3620L.1 (10/10)41
DLN 1 Peaking Duty with Power Augmentation
+50F Tfire Increase
Factored Hours = Ki * Afi * Api * ti = 34.5 Hours
Hours Maintenance Factor =(34.5/6)5.8
Where Ki =2.34 Max(1.0, exp(0.34(3.50-1.00))) Wet
Afi =1.00 Gas Fuel
Api =2.46 exp(0.018(50)) Peaking
ti =6.0 Hours/Start
Factored Starts = Ki * Afi * Ati * Api * Asi * Ni =5.2 Starts
Starts Maintenance Factor =(5.2/1)5.2
Where Ki =2.77 Max(1.0, exp(0.34(3.50-0.50))) Wet
Afi =1.00 Gas Fuel
Ati =1.00 No Trip at Load
Api =1.57 exp(0.009(50)) Peaking
Asi =1.20 Start with Fast Load
Ni = 1.0 Considering Each Start
3.5% Steam Augmentation
Start with Fast Load
Gas Fuel
6 Hours/Start
Wet Control Curve
Normal Shutdown (No Trip)
Standard Combustor Baseload on Crude Oil
No Tfire Increase
Factored Hours = Ki * Afi * Api * ti = 788.3 Hours
Hours Maintenance Factor =(788.3/220)3.6
Where Ki =1.43 Max(1.0, exp(1.80(1.00-0.80))) Dry
Afi =2.50 Crude Oil, Std (Non-DLN)
Api =1.00 Baseload
ti =220.0 Hours/Start
Factored Starts = Ki * Afi * Ati * Api * Asi * Ni =5.9 Starts
Starts Maintenance Factor =(5.9/1)5.9
Where Ki =2.94 Max(1.0, exp(1.80(1.00-0.40))) Dry
Afi =2.00 Crude Oil, Std (Non-DLN)
Ati =1.00 No Trip at Load
Api =1.00 Baseload
Asi =1.00 Normal Start
Ni = 1.0 Considering Each Start
1.0 Water/Fuel Ratio
Normal Start and Load
Crude Oil Fuel
220 Hours/Start
Dry Control Curve
Normal Shutdown (No Trip)
DLN 2.6 Baseload on Gas with Trip @ Load
No Tfire Increase
Factored Hours = Ki * Afi * Api * ti = 168.0 Hours
Hours Maintenance Factor =(168.0/168)1.0
Where Ki =1.00 No Injection
Afi =1.00 Gas Fuel
Api =1.00 Baseload
ti =168.0 Hours/Start
Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 2.6 Starts
Starts Maintenance Factor =(2.6/1)2.6
Where Ki =1.00 No Injection
Afi =1.00 Gas Fuel
Ati =2.62 0.5+exp(0.0125*60) for Trip
Api =1.00 Baseload
Asi =1.00 Normal Start
Ni = 1.0 Considering Each Start
No Steam/Water Injection
Normal Start and Load
Gas Fuel
168 Hours/Start
Dry Control Curve
Trip @ 60% Load
DLN 2.6 Baseload on Distillate
No Tfire Increase
Factored Hours = Ki * Afi * Api * ti = 943.8 Hours
Hours Maintenance Factor =(943.8/220)4.3
Where Ki =1.72 Max(1.0, exp(1.80(1.10-0.80))) Dry
Afi =2.50 Distillate Fuel, DLN
Api =1.00 Baseload
ti =220.0 Hours/Start
Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 5.3 Starts
Starts Maintenance Factor =(5.3/1)5.3
Where Ki =3.53 Max(1.0, exp(1.80(1.10-0.40))) Dry
Afi =1.50 Distillate Fuel, DLN
Ati =1.00 No Trip at Load
Api =1.00 Baseload
Asi =1.00 Normal Start
Ni = 1.0 Considering Each Start
1.1 Water/Fuel Ratio
Normal Start
Distillate Fuel
220 Hours/Start
Dry Control Curve
Normal Shutdown (No Trip)
DLN 2.6 Peak Load on Gas with Emergency Starts
+35F Tfire Increase
Factored Hours = Ki * Afi * Api * ti = 12.5Hours
Hours Maintenance Factor =(12.5/4)3.1
Where Ki =1.67 Max(1.0, exp(0.34(3.50-2.00)))
Afi =1.00 Gas Fuel
Api =1.88 exp(0.018(35)) Peaking
ti =4.0 Hours/Start
Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 9.6 Starts
Starts Maintenance Factor =(9.6/1)9.6
Where Ki =2.34 Max(1.0, exp(0.34(3.50-1.00))) Dry
Afi =1.00 Gas Fuel
Ati =1.00 No Trip at Load
Api =1.37 exp(0.009(35)) Peaking
Asi =3.00 Emergency Start
Ni = 1.0 Considering Each Start
3.5% Steam Augmentation
Emergency Start
Gas Fuel
4 Hours/Start
Dry Control Curve
Normal Shutdown (No Trip)
DLN 1 Combustor Baseload on Distillate
No Tfire Increase
Factored Hours = Ki * Afi * Api * ti = 1496.5 Hours
Hours Maintenance Factor =(1496.5/500)3.0
Where Ki =1.20 Max(1.0, exp(1.80(0.90-0.80))) Dry
Afi =2.50 Distillate Fuel, DLN 1
Api =1.00 Partload
ti =500.0 Hours/Start
Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 3.7 Starts
Starts Maintenance Factor =(3.7/1)3.7
Where Ki =2.46 Max(1.0, exp(1.80(0.90-0.40))) Dry
Afi =1.50 Distillate Fuel, DLN
Ati =1.00 No Trip at Load
Api =1.00 Part Load
Asi =1.00 Normal Start
Ni = 1.0 Considering Each Start
0.9 Water/Fuel Ratio
Normal Start
Distillate Fuel
500 Hours/Start
Dry Control Curve
Normal Shutdown (No Trip)
Figure B-1. Combustion maintenance interval calculations
ICNU_DR_177 Attachment C Page 45 of 60
C) Definitions
Reliability: Probability of not being forced out of
service when the unit is needed — includes forced
outage hours (FOH) while in service, while on
reserve shutdown and while attempting to start
normalized by period hours (PH) — units are %.
Reliability = (1-FOH/PH) (100)
FOH = total forced outage hours
PH = period hours
Availability: Probability of being available,
independent of whether the unit is needed – includes
all unavailable hours (UH) – normalized by period
hours (PH) – units are %:
Availability = (1-UH/PH) (100)
UH = total unavailable hours (forced outage,
failure to start, scheduled maintenance
hours, unscheduled maintenance hours)
PH = period hours
Equivalent Reliability: Probability of a multi-shaft
combined-cycle power plant not being totally forced
out of service when the unit is required includes the
effect of the gas and steam cycle MW output
contribution to plant output – units are %.
Equivalent Reliability =
GT FOH = Gas Turbine Forced Outage Hours
GT PH = Gas Turbine Period Hours
HRSG FOH = HRSG Forced Outage Hours
B PH = HRSG Period Hours
ST FOH = Steam Turbine Forced Outage Hours
ST PH = Steam Turbine Period Hours
B = Steam Cycle MW Output
Contribution (normally 0.30)
Equivalent Availability: Probability of a multi-shaft
combined-cycle power plant being available for power
generation — independent of whether the unit is
needed — includes all unavailable hours — includes
the effect of the gas and steam cycle MW output
contribution to plant output; units are %.
Equivalent Availability =
GT UH = Gas Turbine Unavailable Hours
GT PH = Gas Turbine Period Hours
HRSG UH = HRSG Total Unavailable Hours
ST UH = Steam Turbine Unavailable Hours
ST PH = Steam Turbine Period Hours
B = Steam Cycle MW Output
Contribution (normally 0.30)
Operating Duty Definition:
Duty Service Factor Fired Hours/Start
Stand-by < 1% 1 to 4
Peaking 1% – 17% 3 to 10
Cycling 17% – 50% 10 to 50
Continuous > 90% >> 50
MTBF–Mean Time Between Failure: Measure of
probability of completing the current run. Failure
events are restricted to forced outages (FO) while in
service – units are service hours.
MTBF = SH/FO
SH = Service Hours
FO = Forced Outage Events from a Running
(On-line) Condition
Service Factor: Measure of operational use, usually
expressed on an annual basis – units are %.
SF = SH/PH x 100
SH = Service Hours on an annual basis
PH = Period Hours (8760 hours per year)
ST FOHHRSG FOHGT FOH
ST PHB PHGT PH
+ B +x 1001 –
GT UH ST UHHRSG UH
ST PHGT PH GT PH
+ B +x 100[[]1 –
[]
42 ICNU_DR_177 Attachment C Page 46 of 60
PG6571-81 (6BU) / 6BeV Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners Cl 4 (Cl)4 (Cl) / 5 (Cl)(1)
Caps Cl 4 (Cl)5 (Cl)
Transition Pieces Cl 4 (Cl)4 (Cl) / 5 (Cl)(1)
Fuel Nozzles Cl 2 (Cl)2 (Cl) / 3 (Cl)(5)
Crossfire Tubes Cl 1 (CI)1 (CI)
Crossfire Tube
Retaining Clips
CI 1 (CI) 1 (CI)
Flow Divider
(Distillate)
Cl 3 (Cl)3 (Cl)
Fuel Pump
(Distillate)
Cl 3 (Cl)3 (Cl)
Stage 1 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 2 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 3 (HGPI)4 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)4 (HGPI)
Stage 1 Bucket HGPI 3 (HGPI)(2)/ 2 (HGPI)(3)3 (HGPI)
Stage 2 Bucket HGPI 3 (HGPI)(4)4 (HGPI)
Stage 3 Bucket HGPI 3 (HGPI)4 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
Cl = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
(1) 4 (CI) for non-DLN / 5 (CI) for DLN
(2) 3 (HGPI) for 6BU with strip and recoat at first HGPI
(3) 2 HGPI for 6BeV
(4) 3 (HGPI) for current design only. Consult your GE Energy representative for replace intervals by part number.
(5) 2 (CI) for non-DLN / 3 (CI) for DLN
GE Energy | GER-3620L.1 (10/10)43
D) Repair and Replacement Cycles (Natural Gas Only)
Figure D-1.Estimated repair and replacement cycles
MS3002K Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners CI 2 (CI)4 (CI)
Transition Pieces CI, HGPI 2 (CI)2 (HGPI)
Stage 1 Nozzles HGPI 2 (HGPI)2 (HGPI)
Stage 2 Nozzles MI 2 (MI)2 (MI)
Stage 1 Shrouds MI 2 (MI)2 (MI)
Stage 2 Shrouds MI 2 (MI)2 (MI)
Stage 1 Bucket –1 (MI)(1)3 (HGPI)
Stage 2 Bucket –1 (MI)3 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
CI = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
MI = Major Inspection Interval
(1) GE approved repair at 24,000 hours may extend life to 72,000 hours.
Figure D-2.Estimated repair and replacement cycles
MS5001PA / MS5002C,D Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners CI 4 (CI)3 (CI) / 4 (CI)(1)
Transition Pieces CI, HGPI 4 (CI)(2)3 (CI) / 4 (CI)(1)
Stage 1 Nozzles HGPI, MI 2 (MI)2 (HGPI)
Stage 2 Nozzles HGPI, MI 2 (MI)2 (HGPI) / 2 (MI)(3)
Stage 1 Shrouds MI 2 (MI)2 (MI)
Stage 2 Shrouds –2 (MI)2 (MI)
Stage 1 Bucket –1 (MI)(4)3 (HGPI)
Stage 2 Bucket –1 (MI)3 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
CI = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
MI = Major Inspection Interval
(1) 3 (CI) for non-DLN units, 4 (CI) for DLN units
(2) Repair interval is every 2 (CI)
(3) 2 (HGPI) for MS5001PA, 2 (MI) for MS5002C, D
(4) GE approved repair at 24,000 hours may extend life to 72,000 hours
Figure D-3.Estimated repair and replacement cycles
PG6541-61 (6B)
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Stage 1 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 2 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 3 (HGPI)4 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)4 (HGPI)
Stage 1 Bucket HGPI 2 (HGPI)(1)/ 3 (HGPI)(2)3 (HGPI)
Stage 2 Bucket HGPI 3 (HGPI)(3)4 (HGPI)
Stage 3 Bucket HGPI 3 (HGPI)4 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
HGPI = Hot Gas Path Inspection Interval
(1) 2 (HGPI) with no repairs at 24k hours.
(2) 3 (HGPl) with Strip, HIP Rejuvenation, and Re-coat at 24k hours.
(3) May require meeting tip shroud engagement criteria at prior HGP repair intervals. 3 (HGPI) for current
design only. Consult your GE Energy representative for replace intervals by part number.
Figure D-4.Estimated repair and replacement cycles
ICNU_DR_177 Attachment C Page 47 of 60
44
PG7001(EA) / PG9001(E) Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners Cl 3 (Cl) / 5 (Cl)(1)5 (Cl)
Caps Cl 3 (Cl) 5 (Cl)
Transition Pieces Cl 4 (Cl) / 6 (Cl)(5)6 (Cl)
Fuel Nozzles Cl 2 (Cl) / 3 (Cl)(6)3 (Cl)
Crossfire Tubes Cl 1 (Cl)1 (Cl)
Crossfire Tube
Retaining Clips
CI 1 (CI) 1 (CI)
Flow Divider
(Distillate)
Cl 3 (Cl)3 (Cl)
Fuel Pump
(Distillate)
Cl 3 (Cl)3 (Cl)
Stage 1 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 2 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 3 (HGPI)4 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)4 (HGPI)
Stage 1 Bucket HGPI 3 (HGPI)(2)(3)3 (HGPI)
Stage 2 Bucket HGPI 3 (HGPI)(4)4 (HGPI)
Stage 3 Bucket HGPI 3 (HGPI)4 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
Cl = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
(1) 3 (CI) for DLN / 5 (CI) for non-DLN
(2) Strip and Recoat is required at first HGPI to achieve 3 HGPI replace interval for all E-Class.
(3) Uprated 7EA machines (2055 Tfire) require HIP rejuvenation at first HGPI to achieve 3 HGPI replace interval.
(4) 3 (HGPI) interval requires meeting tip shroud engagement criteria at prior HGP repair intervals.
Consult your GE Energy representative for details.
(5) 4 (CI) for DLN / 6 (CI) for non-DLN
(6) 2 (CI) for DLN / 3 (CI) for non-DLN
Figure D-6. Estimated repair and replacement cycles
PG6101(FA): 6FA.01 Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners Cl 6 (Cl)5 (Cl)
Caps Cl 6 (Cl)5 (Cl)
Transition Pieces Cl 6 (Cl)5 (Cl)
Fuel Nozzles Cl 3 (Cl)3 (Cl)
Crossfire Tubes Cl 1 (Cl)1 (Cl)
Crossfire Tube
Retaining Clips
CI 1 (CI) 1 (CI)
End Covers CI 6 (Cl)3 (Cl)
Stage 1 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 2 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)3 (HGPI)
Stage 1 Bucket HGPI 2 (HGPI)2 (HGPI)(1)
Stage 2 Bucket HGPI 1 (HGPI)(3)3 (HGPI)(2)
Stage 3 Bucket HGPI 3 (HGPI)(2)3 (HGPI)(2)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
Cl = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
(1) GE approved repair operations may be needed to meet expected life. Consult your GE Energy
representative for details.
(2) With welded hardface on shroud, recoating at 1st HGPI is required to achieve replacement life.
(3) Repair may be required on non-scalloped-from-birth parts. Redesigned bucket is capable of 3 (HGPI).
Figure D-7.Estimated repair and replacement cycles
PG6111(FA): 6FA.02 Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners CI 2 (CI)2 (CI)
Caps CI 3 (CI)2 (CI)
Transition Pieces CI 3 (CI)2 (CI)
Fuel Nozzles CI 2 (CI)2 (CI)
Crossfire Tubes CI 1 (CI)1 (CI)
Crossfire Tube
Retaining Clips
CI 1 (CI)1 (CI)
End Covers CI 4 (CI)2 (CI)
Stage 1 Nozzles HGPI 2 (HGPI) 2 (HGPI)
Stage 2 Nozzles HGPI 2 (HGPI) 2 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI)
Stage 1 Buckets HGPI 3 (HGPI) 2 (HGPI)
Stage 2 Buckets HGPI 3 (HGPI) 2 (HGPI)
Stage 3 Buckets HGPI 2 (HGPI) 3 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
CI = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
Figure D-5.Estimated repair and replacement cycles
ICNU_DR_177 Attachment C Page 48 of 60
GE Energy | GER-3620L.1 (10/10)45
Figure D-9. Estimated repair and replacement cycles
PG7221(FA): 7FA.01 / PG9311(FA): 9FA.01 Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners Cl 6 (Cl)5 (Cl)
Caps Cl 6 (Cl)5 (Cl)
Transition Pieces Cl 6 (Cl)5 (Cl)
Fuel Nozzles Cl 3 (Cl)3 (Cl)
Crossfire Tubes Cl 1 (Cl)1 (Cl)
Crossfire Tube
Retaining Clips
CI 1 (CI) 1 (CI)
End Covers CI 6 (Cl)3 (Cl)
Stage 1 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 2 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)3 (HGPI)
Stage 1 Bucket HGPI 2 (HGPI)2 (HGPI)(1)
Stage 2 Bucket HGPI 2 (HGPI)3 (HGPI)
Stage 3 Bucket HGPI 3 (HGPI)(2)3 (HGPI)(2)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
Cl = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
(1) GE approved repair operations may be needed to meet expected life. Consult your GE Energy
representative for details.
(2) With welded hardface on shroud, recoating at 1st HGPI may be required to achieve replacement life.
Figure D-10. Estimated repair and replacement cycles
PG7231(FA): 7FA.02 Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners Cl 6 (Cl)5 (Cl)
Caps Cl 6 (Cl)5 (Cl)
Transition Pieces Cl 6 (Cl)5 (Cl)
Fuel Nozzles Cl 3 (Cl)3 (Cl)
Crossfire Tubes Cl 1 (Cl)1 (Cl)
Crossfire Tube
Retaining Clips
CI 1 (CI) 1 (CI)
End Covers CI 6 (Cl)3 (Cl)
Stage 1 Nozzles HGPI 2 (HGPI)2 (HGPI)
Stage 2 Nozzles HGPI 2 (HGPI)2 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)3 (HGPI)
Stage 1 Bucket HGPI 2 (HGPI)2 (HGPI)(1)
Stage 2 Bucket HGPI 1 (HGPI)(2)3 (HGPI)(3)
Stage 3 Bucket HGPI 3 (HGPI)3 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
Cl = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
(1) Periodic inspections are recommended within each HGPI. GE approved repair operations may be needed
to meet 2 (HGPI) replacement. Consult your GE Energy representative for details on both.
(2) Interval can be increased to 2 (HGPI) by performing a repair operation. Consult your GE Energy
representative for details.
(3) Recoating at 1st HGPI may be required to achieve 3 HGPI replacement life.
Figure D-8.Estimated repair and replacement cycles
PG7211(F): 7F.01 / PG9301(F): 9F.01 Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners Cl 6 (Cl)5 (Cl)
Caps Cl 6 (Cl)5 (Cl)
Transition Pieces Cl 6 (Cl)5 (Cl)
Fuel Nozzles Cl 3 (Cl)3 (Cl)
Crossfire Tubes Cl 1 (Cl)1 (Cl)
Crossfire Tube
Retaining Clips
CI 1 (CI) 1 (CI)
End Covers CI 6 (Cl)3 (Cl)
Stage 1 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 2 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)3 (HGPI)
Stage 1 Bucket HGPI 2 (HGPI)2 (HGPI)
Stage 2 Bucket HGPI 3 (HGPI)(1)3 (HGPI)(1)
Stage 3 Bucket HGPI 3 (HGPI)(1)3 (HGPI)(1)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
Cl = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
(1) With welded hardface on shroud, recoating at 1st HGPI is required to achieve replacement life.
ICNU_DR_177 Attachment C Page 49 of 60
46
Figure D-13.Estimated repair and replacement cycles
Figure D-11.Estimated repair and replacement cycles
PG7241(FA): 7FA.03 Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners*Cl 4 (Cl)5 (Cl)
Caps*Cl 4 (Cl)5 (Cl)
Transition Pieces*Cl 4 (Cl)5 (Cl)
Fuel Nozzles*Cl 4 (Cl)3 (Cl)
Crossfire Tubes*Cl 1 (Cl)1 (Cl)
Crossfire Tube
Retaining Clips
CI 1 (CI) 1 (CI)
End Covers*CI 4 (Cl)3 (Cl)
Stage 1 Nozzles HGPI 2 (HGPI)2 (HGPI)
Stage 2 Nozzles HGPI 2 (HGPI)2 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)3 (HGPI)
Stage 1 Bucket HGPI 3 (HGPI)(2)2 (HGPI)(4)
Stage 2 Bucket HGPI 3 (HGPI)(1)3 (HGPI)(1)
Stage 3 Bucket HGPI 3 (HGPI)(3)3 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
*12K Extended Interval Hardware
Cl = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
(1) 3 (HGPI) for current design. Consult your GE Energy representative for replacement intervals by part
number.
(2) GE approved repair procedure required at first HGPI for designs without platform cooling.
(3) GE approved repair procedure at 2nd HGPI is required to meet 3 (HGPI) replacement life.
(4) 2 (HGPI) for current design with GE approved repair at first HGPI. 3 (HGPI) is possible for redesigned bucket
with platform undercut and cooling modifications.Figure D-12. Estimated repair and replacement cycles
PG9351(FA): 9FA.03 Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners Cl 5 (Cl)5 (Cl)
Caps Cl 5 (Cl)5 (Cl)
Transition Pieces Cl 5 (Cl)5 (Cl)
Fuel Nozzles Cl 3 (Cl)(1)3 (Cl)(1)
Crossfire Tubes Cl 1 (Cl)1 (Cl)
Crossfire Tube
Retaining Clips
CI 1 (CI) 1 (CI)
End Covers CI 6 (Cl)3 (Cl)
Stage 1 Nozzles HGPI 2 (HGPI)2 (HGPI)
Stage 2 Nozzles HGPI 2 (HGPI)2 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)3 (HGPI)
Stage 1 Bucket HGPI 2 (HGPI)(2)2 (HGPI)(4)
Stage 2 Bucket HGPI 3 (HGPI)(5)3 (HGPI)(3)
Stage 3 Bucket HGPI 3 (HGPI)(5)3 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
Cl = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
(1) Blank and liquid fuel cartridges to be replaced at each CI
(2) 2 (HGPI) for current design with GE approved repair at first HGPI. 3 (HGPI) is possible for redesigned bucket
with platform undercut and cooling modifications.
(3) Recoating at 1st HGPI may be required to achieve 3 HGPI replacement life.
(4) GE approved repair procedure at 1 (HGPI) is required to meet 2 (HGPI) replacement life.
(5) GE approved repair procedure is required to meet 3 (HGPI) replacement life.
PG7251(FB): 7FB.01 Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners Cl 3 (Cl)3 (Cl)
Caps Cl 3 (Cl)3 (Cl)
Transition Pieces Cl 3 (Cl)3 (Cl)
Fuel Nozzles Cl 2 (Cl)(1)2 (Cl)(1)
Crossfire Tubes Cl 1 (Cl)1 (Cl)
Crossfire Tube
Retaining Clips
CI 1 (CI) 1 (CI)
End Covers CI 3 (Cl)3 (Cl)
Stage 1 Nozzles HGPI 2 (HGPI)2 (HGPI)
Stage 2 Nozzles HGPI 2 (HGPI)2 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)3 (HGPI)
Stage 1 Bucket HGPI 2 (HGPI)1 (HGPI)
Stage 2 Bucket HGPI 3 (HGPI)3 (HGPI)
Stage 3 Bucket HGPI 3 (HGPI)3 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
Cl = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
(1) Blank and liquid fuel cartridges to be replaced at each CI
ICNU_DR_177 Attachment C Page 50 of 60
GE Energy | GER-3620L.1 (10/10)47
Figure D-14.Estimated repair and replacement cycles
PG9371(FB): 9FB.01 Parts
Repair Interval Replace Interval (Hours)Replace Interval (Starts)
Combustion Liners CI 4 (CI)4 (CI)
Caps CI 4 (CI)4 (CI)
Transition Pieces CI 4 (CI)4 (CI)
Fuel Nozzles CI 2 (Cl)(1)2 (CI)(1)
Crossfire Tubes CI 1 (Cl) 1 (Cl)
Crossfire Tube
Retaining Clips
CI 1 (CI) 1 (CI)
End Covers CI 4 (CI)4 (CI)
Stage 1 Nozzles HGPI 1 (HGPI)(2)1 (HGPI)(2)
Stage 2 Nozzles HGPI 2 (HGPI)2 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI)3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI)2 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI)3 (HGPI)
Stage 1 Buckets HGPI 1 (HGPI)(2)1 (HGPI)(2)
Stage 2 Buckets HGPI 1 (HGPI)(2)1 (HGPI)(2)
Stage 3 Buckets HGPI 1 (HGPI)(2)1 (HGPI)(2)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in
accordance with manufacturer specifications. They represent initial recommended intervals in the absence of
operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 44.
CI = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval
(1) Blank and liquid fuel cartridges to be replaced at each CI
(2) 1 HGPI replacement interval for currently shipping units. Older units may have extended lives.
Consult your GE Energy Services representative for unit specific recommendations.
ICNU_DR_177 Attachment C Page 51 of 60
48
E) Boroscope Inspection Ports
Figure E-1. Borescope inspection access locations for 6F machines
Figure E-2. Borescope inspection access locations for 7/9F machines
ICNU_DR_177 Attachment C Page 52 of 60
GE Energy | GER-3620L.1 (10/10)49
F) Turning Gear/Ratchet Running Guidelines
Scenario Turning Gear (or Ratchet) Duration
Following Shutdown:
Case A.1 – Normal. Restart anticipated for >48 hours
Case A.2 – Normal. Restart anticipated for <48 hours Continuously until restart. Rotor unbowed.
Case B – Immediate rotor stop necessary. (Stop >20 minutes)
Suspected rotating hardware damage or unit malfunction
None. Classified as bowed.
Before Startup:
Case C – Hot rotor, <20 minutes after rotor stop 0–1 hour(3)
Case D – Warm rotor, >20 minutes & <6 hours after rotor stop 4 hours
4 hoursCase E.1 – Cold rotor, unbowed, off TG <48 hours
6 hoursCase E.2 – Cold rotor, unbowed, off TG >48 hours
Case F – Cold rotor, bowed 8 hours(4)
During Extended Outage:
Case G – When idle
(1) Time depends on frame size and ambient environment.
(2) Cooldown cycle may be accelerated using starting device for forced cooldown. Turning gear, however, is recommended method.
(3) 1 hour on turning gear is recommended following a trip, before restarting. For normal shutdowns, use discretion.
(4) Follow bowed rotor startup procedure. See Operation and Maintenance Manual.
(5) Avoids high cycling of lube oil pump during long outages.
Until wheelspace temperatures <150F.(1) Rotor classified as
unbowed. Minimum 24 hours.(2)
1 hour/day
Case H – Alternative No TG; 1 hour/week at full speed (no load).(5)
Figure F-1. Turning Gear Guidelines
ICNU_DR_177 Attachment C Page 53 of 60
50
List of Figures
Figure 1. Key factors affecting maintenance planning
Figure 2. Key technical reference documents to include in maintenance planning
Figure 3. MS7001E gas turbine borescope inspection access locations
Figure 4. Borescope inspection programming
Figure 5. Maintenance cost and equipment life are influenced by key service factors
Figure 6. Causes of wear – hot gas path components
Figure 7. GE bases gas turbine maintenance requirements on independent counts of starts and hours
Figure 8. Hot gas path maintenance interval comparisons. GE method vs. EOH method
Figure 9. Maintenance factors – hot gas path (buckets and nozzles)
Figure 10. GE maintenance interval for hot gas inspections
Figure 11. Estimated effect of fuel type on maintenance
Figure 12. Bucket life firing temperature effect
Figure 13. Firing temperature and load relationship – heat recovery vs. simple cycle operation
Figure 14. Heavy fuel maintenance factors
Figure 15. Steam/water injection and bucket/nozzle life
Figure 16. Exhaust temperature control curve – dry vs. wet control MS7001EA
Figure 17. Turbine start/stop cycle – firing temperature changes
Figure 18. First stage bucket transient temperature distribution
Figure 19. Bucket low cycle fatigue (LCF)
Figure 20. Low cycle fatigue life sensitivities – first stage bucket
Figure 21. Maintenance factor – trips from load
Figure 22. Maintenance factor – effect of start cycle maximum load level
Figure 23. Operation-related maintenance factors
Figure 24. FA gas turbine typical operational profile
Figure 25. Baseline for starts-based maintenance factor definition
Figure 26. F-Class Axial Diffuser
Figure 27. E-Class Radial Diffuser
Figure 28. The NGC requirement for output versus frequency capability over all ambients less than 25°C (77°F)
Figure 29. Turbine output at under-frequency conditions
Figure 30. NGC code compliance TF required – FA class
Figure 31. Maintenance factor for overspeed operation ~constant TF
Figure 32. Deterioration of gas turbine performance due to compressor blade fouling
Figure 33. Long term material property degradation in a wet environment
Figure 34. Susceptibility of compressor blade materials and coatings
Figure 35. MS7001EA heavy-duty gas turbine – shutdown inspections
Figure 36. Operating inspection data parameters
Figure 37. Combustion inspection – key elements
Figure 38. Hot gas path inspection – key elements
Figure 39. Stator tube jacking procedure – MS7001EA
Figure 40. Stage 1 bucket oxidation and bucket life
ICNU_DR_177 Attachment C Page 54 of 60
GE Energy | GER-3620L.1 (10/10)51
Figure 41. Gas turbine major inspection – key elements
Figure 42. Major inspection work scope
Figure 43. First-stage nozzle wear-preventive maintenance: gas fired – continuous dry – base load
Figure 44. Base line recommended inspection intervals: base load – gas fuel – dry
Figure 45. Hot gas path inspection: hours-based criterion
Figure 46. Hot gas path inspection: starts-based criterion
Figure 47. F Class rotor maintenance factor: starts-based criterion
Figure 48. F Class rotor maintenance factor: hours-based criterion
Figure 49. Combustion inspection hours-based maintenance factors
Figure 50. Combustion inspection starts-based maintenance factors
Figure B-1. Combustion maintenance interval calculations
Figure D-1. Estimated repair and replacement cycles
Figure D-2. Estimated repair and replacement cycles
Figure D-3. Estimated repair and replacement cycles
Figure D-4. Estimated repair and replacement cycles
Figure D-5. Estimated repair and replacement cycles
Figure D-6. Estimated repair and replacement cycles
Figure D-7. Estimated repair and replacement cycles
Figure D-8. Estimated repair and replacement cycles
Figure D-9. Estimated repair and replacement cycles
Figure D-10. Estimated repair and replacement cycles
Figure D-11. Estimated repair and replacement cycles
Figure D-12. Estimated repair and replacement cycles
Figure D-13. Estimated repair and replacement cycles
Figure D-14. Estimated repair and replacement cycles
Figure E-1. Borescope inspection access locations for 6F machines
Figure E-2. Borescope inspection access locations for 7/9F machines
Figure F-1. Turning Gear Guidelines
ICNU_DR_177 Attachment C Page 55 of 60
52
Revision History
9/89 Original
8/91 Rev A
9/93 Rev B
3/95 Rev C
• Nozzle Clearances section removed
• Steam/Water Injection section added
• Cyclic Effects section added
5/96 Rev D
• Estimated Repair and Replacement Cycles added for F/FA
11/96 Rev E
11/98 Rev F
• Rotor Parts section added
• Estimated Repair and Replace Cycles added for FA+E
• Starts and hours-based rotor maintenance interval equations
added
9/00 Rev G
11/02 Rev H
• Estimated Repair and Replace Cycles updated and moved to
Appendix D
• Combustion Parts section added
• Inlet Fogging section added
1/03 Rev J
• Off Frequency Operation section added
10/04 Rev K
• GE design intent and predication upon proper components and
use added
• Added recommendation for coalescing filters installation
upstream of gas heaters
• Added recommendations for shutdown on gas fuel, dual fuel
transfers, and FSDS maintenance
• Trip from peak load maintenance factor added
• Lube Oil Cleanliness section added
• Inlet Fogging section updated to Moisture Intake
• Best practices for turning gear operation added
• Rapid Cool-down section added
• Procedural clarifications for HGP inspection added
• Added inspections for galling/fretting in turbine dovetails to major
inspection scope
• HGP factored starts calculation updated for application of trip
factors
• Turning gear maintenance factor removed for F-class hours-
based rotor life
• Removed reference to turning gear impacts on cyclic customers’
rotor lives
• HGP factored starts example added
• F-class borescope inspection access locations added
• Various HGP parts replacement cycles updated and additional
6B table added
• Revision History added
11/09 Rev L
• Updated text throughout
• Casing section added
• Exhaust Diffuser section added
• Added new Fig. 26: F-Class Axial Diffuser
• Added new Fig. 27: E-Class Radial Diffuser
• Revised Fig. 3, 5, 7, 8, 11, 19, 20, 23, 35, 37, 38, 40, 41, 42, 43, 44,
E-1, and E-2
• Appendix D – updated repair and replacement cycles
• Added PG6111 (FA) Estimated repair and replacement cycles
• Added PG9371 (FB) Estimated repair and replacement cycles
10/10 Correction L.1
• Corrected Fig. D-4, D-5, and D-11 combustion hardware repair
and replacement cycles
ICNU_DR_177 Attachment C Page 56 of 60
GE Energy | GER-3620L.1 (10/10)53ICNU_DR_177 Attachment C Page 57 of 60
54 ICNU_DR_177 Attachment C Page 58 of 60
ICNU_DR_177 Attachment C Page 59 of 60
GTD-222, GTD-241, GTD-450, and GECC-1 are trademarks of the General Electric Company.
©2010, General Electric Company. All rights reserved.
GER-3620L.1 (10/10)ICNU_DR_177 Attachment C Page 60 of 60

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: T. Dempsey/L. Andrews
TYPE: Data Request DEPT: Generation Production Support
REQUEST NO.: ICNU – 178 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an explanation for the $3.4 million increase to O&M for Coyote Springs 2 between the test period and 2016 pro-forma period.

RESPONSE:
The $3.4 million system increase in O&M Coyote Springs 2 (CS2) is based on the net change in total
system O&M expense between the test period (12ME 09.2014) of $5.9 million and that planned in the
2016 rate year of $9.3 million. The net increase in maintenance is mainly due to the Hot Gas Path
maintenance planned for 2016 of $3.5 million (system), as explained in Avista’s response to
ICNU_DR_177.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Tara Moses
TYPE: Data Request DEPT: Resource Accounting
REQUEST NO.: ICNU – 179 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Provide the actual Coyote Springs 2 O&M expense by month for the period January 2010 through March 2013 (inclusive).

RESPONSE:
Please see ICNU_DR_179 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: Thomas C Dempsey
TYPE: Data Request DEPT: Generation Production Support
REQUEST NO.: ICNU – 180 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all supporting data, analyses, and reports relied upon to forecast $15.0 million in O&M for Colstrip in the 2016 pro-forma period as detailed in Exh. No. WGJ-2.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 180C. Please note that
Avista’s response to ICNU – 180C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

The $15.0 million (system) total Operations and Maintenance (“O&M”) expense for Avista’s 15% ownership of Colstrip Units 3 and 4 in the 2016 pro-forma period is based on planned costs as provided
by PPL Montana (Colstrip Operator), which provides for a net increase of $2.0 million (system) above the
test period (12ME 09.2014) level of expense of $13.0 million (system). The net increase in expense for
2016 above the historical test year is mainly due to reduced costs during 2014 due to the Colstrip outage
and increases in inflation.
Included as attachment ICNU_DR_180C – Confidential Attachment A is a spreadsheet which provides
detail on development of the 2016 O&M planned expense, based on information from PPL Montana.

Included as ICNU_DR_177-Attachment A is the monthly transaction history for the test period (12ME 09.2014) previously provided with Mr. Johnson and Ms. Smith workpapers. Included as ICNU_DR_180-
Attachment A is the monthly transaction detail for the 2016 monthly maintenance previously provided
with Mr. Johnson and Ms. Smith workpapers.

Page 1 of 2
Expected
2014 2016
(000s)(000s)
Colstrip Actual Expenses (1)99,163$ 104,534$
Avista 15% Ownership Share 14,874$ 15,680$
Less:
Start-up fuel, etc. (2)617$ 675$
Net Costrip actual 2014 expenses 14,257$ 15,005$
Net actual expenses per Avista GL 12,979$
Net difference (3)1,278$
Increase in Expected spend 2016 vs 2014 748$
5.2%
(1) Per 2014 Budget vs Actual Recap Units 3 & 4 Per PPL Montana, see ICNU_DR_180C-Confidential
Attachment B. See ICNU_DR_180C Confidential Attachment A for 2016 information.
(2) 15% PPLM Start Fuel Costs, insurance, rents, misc. not recorded to maintenance
accounts 500-514.
(3) Variance in 2014 between actual Colstrip maintenance expense and expense recorded
in Avista GL, relates to Colstrip Lawsuit refund received in 2014. Refund recorded to
account 506 consistent with recording of original expenses for Washington's share.
COLSTRIP Unit 3 & 4 - Major Maintenance
System
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 08/17/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: Thomas Dempsey/L. Andrews
TYPE: Data Request DEPT: Generation Production Support
REQUEST NO.: ICNU – 180-Revised TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide all supporting data, analyses, and reports relied upon to forecast $15.0 million in O&M for
Colstrip in the 2016 pro-forma period as detailed in Exh. No. WGJ-2. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 180C. Please note that
Avista’s response to ICNU – 180C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205. REVISED 8/17/2015 The $15.0 million (system) total Operations and Maintenance (“O&M”) expense for Avista’s 15%
ownership of Colstrip Units 3 and 4 in the 2016 pro-forma period is based on planned costs as provided
by PPL Montana (Colstrip Operator), which provides for a net increase of $2.0 million (system) above the test period (12ME 09.2014) level of expense of $13.0 million (system) recorded by Avista.

As can be seen from the table above, the $2 million net increase in expense in 2016 ($15.680 million)
versus the historical test year ($12.979 million) is mainly due to a Colstrip Settlement Refund credited to
expense in 2014 of $1.278 million – the actual Colstrip maintenance per PPL Montana was $14.257 million. The remaining difference of $748,000 (or 5%) is due to reduced level of expenses in 2014 related to the Colstrip outage (Q1’2014) and increases in inflation.

Page 2 of 2
Refund Charged ot Account 506 1,275$
WA ID
5/2014 Colstrip Legal Settlement (WA Direct)749$
10/214 PPL MT AEGIS Mediation Settlement (WA/ID)343$ 183$
Total credited to Account 506 1,092$ 183$

Washington’s share of the $1.278 million was approximately $1.09 million as follows:

Included as attachment ICNU_DR_180C – Confidential Attachment A is a spreadsheet which provides
detail on development of the 2016 O&M planned expense, based on information from PPL Montana, the project operator.
Included as attachment ICNU_DR_180C – Confidential Attachment B is a detailed reconciliation of 2014
year-to-date actual $99.163 million ($14.874 million WA share) versus amounts budgeted.

See ICNU_DR_177-Attachment A for the monthly transaction history for the test period (12ME 09.2014) previously provided with Mr. Johnson and Ms. Smith workpapers. Included as ICNU_DR_180-
Attachment A is the monthly transaction detail for the 2016 monthly maintenance previously provided
with Mr. Johnson and Ms. Smith workpapers.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: T. Dempsey/L. Andrews
TYPE: Data Request DEPT: Generation Production Support
REQUEST NO.: ICNU – 181 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an explanation for the $2.0 million increase to O&M for Colstrip between the test period and the 2016 pro-forma period.

RESPONSE:
The $2 million system increase in O&M Colstrip maintenance expense is based on the net change in total
system O&M expense between the test period (12ME 09.2014) of $13.0 million and that planned in the
2016 rate year of $15.0 million. The net increase in expense for 2016 above the historical test year is
mainly due to reduced costs during 2014 due to the Colstrip outage and increases in inflation as explained
in Avista’s response to ICNU_DR_180.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 08/17/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: T. Dempsey/L. Andrews
TYPE: Data Request DEPT: Generation Production Support
REQUEST NO.: ICNU – 181-Revised TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an explanation for the $2.0 million increase to O&M for Colstrip between the test period and the 2016 pro-forma period.

RESPONSE:
REVISED 08/17/2015 Please see Avista’s response to ICNU_DR_180-Revised.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Tara Moses
TYPE: Data Request DEPT: Resource Accounting
REQUEST NO.: ICNU – 182 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Provide the actual Colstrip O&M expense by month for the period January 2010 through March 2015 (inclusive).

RESPONSE:
Please see ICNU_DR_182 Attachment A.

I
II
2.0
III
3.0
3.1
3.2
3.3
3.4
3.5
3.6
IV
4.0
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
V
5.0
5.1
5.2
5.3
5.4
VI
6.0
6.1
6.2
6.3
6.4
VII
7.0
Environmental Narrative
2015 Budget Assumptions
Environmental Inspections -- Graphs
Safety Narrative
NFDL Rates -- Graph
Reportable Incident Rate -- Graph
INCENTIVE FEE
Narrative
2015 A&G Budget Comparison to 2013 Actuals
Capital Budget Cash Flow
2016 - 2019 Capital Budget
2014 AOP Vs. 2015 AOP
Environmental / Safety
Capital Budget Summary
Productivity of Major Equipment
Area C Equipment Hours by Function
Area C Sales vs. Inventory -- Graph
Maps
Capital Budget Recap
OPERATING BUDGET
Narrative
Colstrip 3&4 Pricing Analysis -- 2015
Summary By Function Account -- 2015
Return on Investment Calculation
A&G Budget Comparison
Colstrip 3&4 Pricing Analysis -- 2016 - 2019
Summary By Function Account -- 2016 - 2019
Recap MOC 2015
Recap MOC 2014/2015 vs. 2015
CAPITAL BUDGET
Staffing Plan Summary
MINE PLAN
2015 Expense Budget Narrative
Area C Budget Statistics -- 2015
Area C Budget Statistics -- 2016 - 2019
PERSONNEL
Western Energy Company
Mine Operating Committee
3&4 Contract
TABLE OF CONTENTS
TABLE OF CONTENTS
ICNU_DR_183 Attachment A Page 1 of 54
Western Energy Company
Mine Operating Committee
3&4 Contract
TABLE OF CONTENTS
VIII
8.0
IX
9.0
9.1
9.2
9.3
2016 - 2019 Summary By Function Account
2015 - 2019 Conveyor Royalties
OUTSIDE COAL
Contract Basis
TRANSPORTATION
2015 - 2019 Budget Summary
ICNU_DR_183 Attachment A Page 2 of 54
20
1
4
20
1
5

Q
u
a
r
t
e
r
l
y

E
s
t
i
m
a
t
e
4t
h

Q
t
r
Ma
y
Bu
d
g
e
t
Ac
t
u
a
l
1s
t
2n
d
3r
d
4t
h
20
1
6
20
1
7
20
1
8
20
1
9
Ad
m
i
n
i
s
t
r
a
t
i
o
n
1
1
1
1
1
1
1
1
1
1
Sa
f
e
t
y
3
3
3
3
3
3
3
3
3
3
Mi
n
e

C
o
n
t
r
o
l
l
e
r
11
12
12
12
12
12
12
12
12
12
Hu
m
a
n

R
e
s
o
u
r
c
e
s
15
12
12
12
12
12
12
12
12
12
En
v
i
r
o
n
m
e
n
t
a
l

&

E
n
g
i
n
e
e
r
i
n
g
18
17
18
18
18
18
18
18
18
18
Ma
i
n
t
e
n
a
n
c
e
22
21
22
22
22
22
22
22
22
22
Pr
o
d
u
c
t
i
o
n
17
16
17
17
17
17
17
17
17
17
Sa
l
a
r
i
e
d

S
u
b
-
T
o
t
a
l
87
82
85
85
85
85
85
85
85
85
Ro
s
e
b
u
d

M
i
n
e
31
3
28
6
31
1
32
9
32
9
31
1
32
9
32
9
32
9
32
9
Ho
u
r
l
y

S
u
b
-
T
o
t
a
l
31
3
28
6
31
1
32
9
32
9
31
1
32
9
32
9
32
9
32
9
Pa
r
t
-
T
i
m
e
/
T
e
m
p
o
r
a
r
y

S
u
b
-
T
o
t
a
l
1
1
0
8
8
0
11
11
11
11
To
t
a
l

A
l
l

E
m
p
l
o
y
e
e
s
40
1
36
9
39
6
42
2
42
2
39
6
42
5
42
5
42
5
42
5
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
St
a
f
f
i
n
g

P
l
a
n

S
u
m
m
a
r
y
20
1
5

A
O
P
2015 AOP Final Version
Colstrip 3&4
2.0ICNU_DR_183 Attachment A Page 3 of 54
2015 EXPENSE BUDGET NARRATIVE
AREA C
General
The 2015 Annual Operating Plan (AOP) will provide approximately 7.25 million tons of Area C
coal that will be delivered to Colstrip Units 3&4. Western Energy Company (WECo) will mine in C-South and C-East. The 8200 dragline will be uncovering coal in C-South in 2015 through the end of the contract. The 8050 dragline will begin uncovering coal in C-East from 2015 through
the first half of 2017.
Coal removal typically follows overburden removal for the first two years of the AOP with the gap equaling the pit inventory per period. For years three through five of the AOP, the overburden quantities are calculated utilizing the coal removal polygons. The five-year mining sequence is
presented on the accompanying coal and dragline schedules.
Draglines, Drills and Dozers (Overburden)
During 2015, the Marion 8200 dragline is scheduled to move 13,415,700 cubic yards of
overburden; the Marion 8050 dragline is scheduled to move 9,551,700 cubic yards of
overburden. Annual productivity for the Marion 8200 will be 3,026 CY/hr overall (including
walks) and 3,082 CY/hr excluding walks. Annual productivity for the Marion 8050 will be 2,085 CY/hr overall (including walks) and 2,114 CY/hr excluding walks. Eighteen (18) shifts are scheduled for walking the draglines between pits. Dragline walking accounts for 1.6% of
the total operated hours for both draglines.
Draglines are supported by D-10 dozers on a full time basis. D-11 dozers will pre-bench 2,290,900 cubic yards of overburden. The end-dump fleet will move 3,821,200 cubic yards of auxiliary overburden (above 150 feet and endwall extensions).
Coal Haulage
Coal extraction follows the dragline sequence. The haul cycle times and productivities were
estimated using the TALPAC fleet optimization software. A mixed hauler fleet of Kress 200 and
Kress 240 ton haulers were optimized.
Coal Loading
Coal will be loaded with a Cat 993K wheel loader and Hitachi 1800 backhoe supplemented with
992G loaders. Coal will be hauled from the pit to the Area C crusher, where it will be loaded onto
the overland conveyor. Approximately 7.25 million tons of coal is scheduled from Area C in 2015. TALPAC fleet optimization software was used to simulate the loader productivities with
special consideration given to reduced productivity for inclement weather and multiple loading
operations.
2015 AOP Final Version
Colstrip 3&4
3.0
1 of 2
ICNU_DR_183 Attachment A Page 4 of 54
Coal Quality
Structure models and coal quality estimations include all drilling through 2006. No new core
holes have been added to the model since 2006.
Parting Removal
Parting was included in the southwestern portion of Area C East and C South in 2015.
Pit Inventory
The beginning pit inventory for 2015 has been estimated at 1,200,000 tons of coal exposed,
with the end-of-year pit inventory estimated at 1,058,000 tons of coal exposed.
Articulated Trucks
The articulated truck fleet will perform the following work during 2015:
Regrade (Base Reclamation) 600,000 CY
Topsoil (Base Reclamation) 632,900 CY
Benching /Parting Removal 118,500 CY Miscellaneous 48,000 CY
Reclamation Projects Dozers, articulated trucks, and the end dump fleet will be utilized to perform the regrade work.
The following base reclamation quantities have been scheduled for 2015 in Area C:
Regrade:
•D-11 Dozer – 196.2 Acres
•D-11 Dozer – 2,300,000 BCY
•D-10 Dozer – 1,200,000 BCY
•Articulated Truck Fleet – 600,000 BCY
Topsoil:
•Articulated Truck Fleet – 632,900 BCY
•End-Dump Fleet – 150,000 BCY
Revegetation:
•247 acres
2015 AOP Final Version
Colstrip 3&4
3.0
2 of 2
ICNU_DR_183 Attachment A Page 5 of 54
20
1
5
JA
N
FE
B
MA
R
AP
R
MA
Y
JU
N
JU
L
AU
G
SE
P
OC
T
NO
V
DE
C
TO
T
A
L
CO
A
L

To
n
s

S
o
l
d
Un
i
t
s

3
&
4
64
8
,
2
0
0
58
5
,
8
0
0
64
7
,
2
0
0
55
8
,
2
0
0
55
7
,
6
0
0
44
7
,
2
0
0
62
6
,
8
0
0
64
4
,
1
0
0
62
9
,
8
0
0
64
1
,
8
0
0
62
1
,
9
0
0
64
2
,
3
0
0
7,
2
5
0
,
9
0
0
TO
T
A
L
64
8
,
2
0
0
58
5
,
8
0
0
64
7
,
2
0
0
55
8
,
2
0
0
55
7
,
6
0
0
44
7
,
2
0
0
62
6
,
8
0
0
64
4
,
1
0
0
62
9
,
8
0
0
64
1
,
8
0
0
62
1
,
9
0
0
64
2
,
3
0
0
7,
2
5
0
,
9
0
0
Pi
t

I
n
v
e
n
t
o
r
y
En
d

o
f

P
e
r
i
o
d

T
o
n
s
1,
2
0
0
,
0
0
0
1,
1
6
8
,
0
0
0
1,
1
8
6
,
0
0
0
1,
0
4
3
,
0
0
0
1,
0
9
4
,
0
0
0
1,
2
3
6
,
0
0
0
1,
1
8
4
,
0
0
0
1,
1
2
2
,
0
0
0
1,
1
0
4
,
0
0
0
1,
0
7
8
,
0
0
0
1,
1
0
4
,
0
0
0
1,
0
5
8
,
0
0
0
1,
0
5
8
,
0
0
0
Qu
a
l
i
t
y
BT
U
/
L
B
8,
5
8
3
8,
5
4
7
8,
2
9
5
8,
2
4
7
8,
3
2
1
8,
3
5
9
8,
3
1
8
8,
5
4
2
8,
5
0
9
8,
4
8
6
8,
3
8
2
8,
2
7
5
8,
4
0
8
MO
I
S
T
U
R
E
25
.
8
9
%
26
.
1
0
%
26
.
4
7
%
25
.
7
3
%
25
.
9
5
%
25
.
3
5
%
25
.
0
4
%
26
.
4
1
%
26
.
3
4
%
26
.
1
6
%
25
.
9
9
%
25
.
0
6
%
25
.
8
9
%
AS
H
9.
4
6
%
9.
4
8
%
10
.
8
0
%
11
.
6
8
%
10
.
8
6
%
11
.
3
0
%
12
.
0
3
%
9.
4
4
%
9.
5
1
%
9.
7
7
%
10
.
3
3
%
12
.
3
0
%
10
.
5
5
%
SU
L
F
U
R
0.
7
5
%
0.
7
7
%
0.
7
8
%
0.
7
7
%
0.
7
4
%
0.
7
7
%
0.
6
9
%
0.
7
0
%
0.
7
4
%
0.
7
5
%
0.
8
1
%
0.
7
3
%
0.
7
5
%
SO
D
I
U
M
0.
2
2
%
0.
0
9
%
0.
4
2
%
0.
3
1
%
0.
4
1
%
0.
0
8
%
0.
2
2
%
0.
2
9
%
0.
4
3
%
0.
2
9
%
0.
3
3
%
0.
2
1
%
0.
2
8
%
AV
G
.

H
A
U
L

(
1
-
W
A
Y
)
Mil
e
s
4.
5
0
3.
8
4
3.
5
6
2.
9
5
2.
5
8
2.
1
9
4.
2
4
3.
6
6
4.
2
5
3.
9
1
3.
1
8
4.
2
3
3.
6
4
OV
E
R
B
U
R
D
E
N
Pa
r
t
i
n
g

BC
Y
12
,
6
0
0
15
,
5
0
0
8,
7
0
0
5,
5
0
0
6,
7
0
0
5,
4
0
0
10
,
7
0
0
7,
4
0
0
9,
3
0
0
12
,
4
0
0
12
,
7
0
0
11
,
6
0
0
11
8
,
5
0
0
Sc
r
a
p
e
r

B
C
Y
0
0
0
0
0
0
0
0
0
0
0
0
0
Ab
o
v
e

B
e
n
c
h
Tr
u
c
k
/
L
o
a
d
e
r

B
C
Y
80
,
0
0
0
43
1
,
4
0
0
41
0
,
1
0
0
97
,
1
0
0
57
6
,
6
0
0
31
0
,
6
0
0
52
1
,
2
0
0
10
7
,
4
0
0
30
6
,
8
0
0
32
5
,
9
0
0
24
0
,
6
0
0
41
3
,
5
0
0
3,
8
2
1
,
2
0
0
Ca
s
t

B
C
Y
1,
8
5
2
,
7
0
0
1,
6
5
2
,
0
0
0
1,
8
6
3
,
6
0
0
1,
1
3
8
,
1
0
0
1,
7
1
0
,
0
0
0
1,
6
2
1
,
6
0
0
1,
8
0
1
,
3
0
0
1,
7
5
0
,
7
0
0
1,
8
0
5
,
4
0
0
1,
8
3
3
,
6
0
0
1,
7
8
2
,
1
0
0
1,
8
0
8
,
1
0
0
20
,
6
1
9
,
2
0
0
Do
z
e
r

B
C
Y

f
o
r

8
2
0
0
12
2
,
4
0
0
10
6
,
4
0
0
11
8
,
7
0
0
74
,
0
0
0
11
2
,
7
0
0
97
,
1
0
0
11
7
,
8
0
0
11
9
,
3
0
0
12
1
,
1
0
0
11
7
,
8
0
0
11
4
,
1
0
0
11
8
,
5
0
0
1,
3
3
9
,
9
0
0
Do
z
e
r

B
C
Y

f
o
r

8
0
5
0
83
,
5
0
0
77
,
2
0
0
88
,
3
0
0
52
,
4
0
0
77
,
3
0
0
83
,
1
0
0
82
,
3
0
0
75
,
2
0
0
79
,
5
0
0
85
,
9
0
0
83
,
9
0
0
82
,
4
0
0
95
1
,
0
0
0
82
0
0

B
C
Y
0
0
0
0
0
0
0
0
0
0
0
0
0
80
5
0

B
C
Y
0
0
0
0
0
0
0
0
0
0
0
0
0
To
t
a
l

P
r
e
b
e
n
c
h

w
i
t
h

P
a
r
t
i
n
g

B
C
Y
2,
1
5
1
,
2
0
0
2,
2
8
2
,
5
0
0
2,
4
8
9
,
4
0
0
1,
3
6
7
,
1
0
0
2,
4
8
3
,
3
0
0
2,
1
1
7
,
8
0
0
2,
5
3
3
,
3
0
0
2,
0
6
0
,
0
0
0
2,
3
2
2
,
1
0
0
2,
3
7
5
,
6
0
0
2,
2
3
3
,
4
0
0
2,
4
3
4
,
1
0
0
26
,
8
4
9
,
8
0
0
Be
l
o
w

B
e
n
c
h
82
0
0

B
C
Y
1,
2
2
3
,
5
0
0
1,
0
6
3
,
7
0
0
1,
1
8
7
,
5
0
0
74
0
,
3
0
0
1,
1
2
7
,
2
0
0
97
8
,
8
0
0
1,
1
8
6
,
3
0
0
1,
1
9
3
,
1
0
0
1,
2
1
1
,
0
0
0
1,
1
7
8
,
4
0
0
1,
1
4
1
,
3
0
0
1,
1
8
4
,
6
0
0
13
,
4
1
5
,
7
0
0
80
5
0

B
C
Y
84
3
,
2
0
0
77
1
,
9
0
0
88
3
,
3
0
0
52
4
,
2
0
0
77
2
,
8
0
0
83
1
,
2
0
0
82
3
,
3
0
0
77
6
,
7
0
0
80
3
,
1
0
0
85
8
,
8
0
0
83
8
,
8
0
0
82
4
,
4
0
0
9,
5
5
1
,
7
0
0
To
t
a
l

B
e
l
o
w

B
e
n
c
h

B
C
Y
2,
0
6
6
,
7
0
0
1,
8
3
5
,
6
0
0
2,
0
7
0
,
8
0
0
1,
2
6
4
,
5
0
0
1,
9
0
0
,
0
0
0
1,
8
1
0
,
0
0
0
2,
0
0
9
,
6
0
0
1,
9
6
9
,
8
0
0
2,
0
1
4
,
1
0
0
2,
0
3
7
,
2
0
0
1,
9
8
0
,
1
0
0
2,
0
0
9
,
0
0
0
22
,
9
6
7
,
4
0
0
Re
h
a
n
d
l
e
82
0
0

B
C
Y
55
1
,
3
0
0
52
7
,
6
0
0
58
8
,
5
0
0
36
1
,
6
0
0
52
5
,
1
0
0
46
5
,
0
0
0
59
6
,
7
0
0
58
9
,
6
0
0
55
0
,
4
0
0
59
6
,
4
0
0
57
2
,
3
0
0
59
1
,
4
0
0
6,
5
1
5
,
9
0
0
80
5
0

B
C
Y
40
7
,
3
0
0
35
8
,
9
0
0
38
9
,
9
0
0
24
6
,
9
0
0
38
5
,
9
0
0
38
5
,
1
0
0
41
9
,
1
0
0
36
3
,
6
0
0
40
4
,
6
0
0
39
1
,
2
0
0
36
2
,
4
0
0
41
8
,
0
0
0
4,
5
3
2
,
9
0
0
Do
z
e
r
92
,
6
0
0
82
,
6
0
0
93
,
2
0
0
56
,
9
0
0
85
,
5
0
0
81
,
1
0
0
90
,
1
0
0
87
,
5
0
0
90
,
3
0
0
91
,
7
0
0
89
,
1
0
0
90
,
4
0
0
1,
0
3
1
,
0
0
0
To
t
a
l

R
e
h
a
n
d
l
e
1,
0
5
1
,
2
0
0
96
9
,
1
0
0
1,
0
7
1
,
6
0
0
66
5
,
4
0
0
99
6
,
5
0
0
93
1
,
2
0
0
1,
1
0
5
,
9
0
0
1,
0
4
0
,
7
0
0
1,
0
4
5
,
3
0
0
1,
0
7
9
,
3
0
0
1,
0
2
3
,
8
0
0
1,
0
9
9
,
8
0
0
12
,
0
7
9
,
8
0
0

R
e
h
a
n
d
l
e

%
25
%
24
%
23
%
25
%
23
%
24
%
24
%
26
%
24
%
24
%
24
%
25
%
24
%
To
t
a
l

O
v
e
r
b
u
r
d
e
n

BC
Y
5,
2
6
9
,
1
0
0
5,
0
8
7
,
2
0
0
5,
6
3
1
,
8
0
0
3,
2
9
7
,
0
0
0
5,
3
7
9
,
8
0
0
4,
8
5
9
,
0
0
0
5,
6
4
8
,
8
0
0
5,
0
7
0
,
5
0
0
5,
3
8
1
,
5
0
0
5,
4
9
2
,
1
0
0
5,
2
3
7
,
3
0
0
5,
5
4
2
,
9
0
0
61
,
8
9
7
,
0
0
0
ST
R
I
P

R
A
T
I
O

(b
c
y
/
t
o
n
s

e
x
p
o
s
e
d
)
6.
5
7.
4
6.
9
6.
3
7.
2
6.
7
7.
9
6.
9
7.
1
7.
2
6.
5
7.
5
7.
0
DR
A
G
L
I
N
E

Y
D
S
/
O
P
.

H
R
.
82
0
0

C
Y
/
O
p

H
r
3,
0
7
2
3,
0
7
2
3,
0
7
4
3,
0
7
3
3,
0
7
2
2,
5
5
7
2,
9
5
8
3,
0
8
6
3,
1
5
8
3,
0
7
2
3,
0
7
2
3,
0
7
4
3,
0
2
6
80
5
0

C
Y
/
O
p

H
r
2,
0
8
6
2,
1
3
2
2,
1
5
2
2,
1
0
0
2,
1
0
4
2,
1
2
9
1,
9
4
3
1,
9
6
8
2,
1
0
9
2,
1
1
3
2,
1
0
3
2,
1
0
0
2,
0
8
5
DR
A
G
L
I
N
E

O
P
E
R
A
T
I
N
G

S
H
I
F
T
S
82
0
0

1
2

H
r

S
h
i
f
t
s
48
43
48
30
45
47
50
48
46
48
46
48
54
9
(E
x
c
l
u
d
i
n
g

R
e
c
l
a
m
a
t
i
o
n
)
80
5
0

1
2

H
r

S
h
i
f
t
s
50
44
49
31
46
48
53
48
48
49
48
49
56
3
BA
S
E

R
E
C
L
A
M
A
T
I
O
N

Dr
a
g
l
i
n
e

R
e
g
r
a
d
e
82
0
0

C
Y
0
0
0
0
0
0
0
0
0
0
0
0
0
80
5
0

C
Y
0
0
0
0
0
0
0
0
0
0
0
0
0
Do
z
e
r

R
e
g
r
a
d
e
D1
1

C
Y
20
0
,
0
0
0
20
0
,
0
0
0
30
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
30
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
20
0
,
0
0
0
2,
3
0
0
,
0
0
0
D1
0

C
Y
20
0
,
0
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
10
0
,
0
0
0
1,
2
0
0
,
0
0
0
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
5

S
t
a
t
i
s
t
i
c
s

S
u
m
m
a
r
y
2015 AOP Final Version
Colstrip 3&4
3.1
1 of 2
ICNU_DR_183 Attachment A Page 6 of 54
20
1
5
JA
N
FE
B
MA
R
AP
R
MA
Y
JU
N
JU
L
AU
G
SE
P
OC
T
NO
V
DE
C
TO
T
A
L
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
5

S
t
a
t
i
s
t
i
c
s

S
u
m
m
a
r
y
Re
g
r
a
d
e

f
o
r

P
i
t

A
d
v
a
n
c
e
AC
18
.
6
15
.
7
18
.
4
10
.
8
16
.
4
16
.
0
15
.
6
16
.
1
17
.
7
17
.
3
17
.
6
15
.
9
19
6
.
2
Tr
u
c
k

L
o
a
d
e
r

R
e
g
r
a
d
e
CY
0
0
0
0
0
0
0
0
0
0
0
0
0
Sc
r
a
p
e
r

R
e
g
r
a
d
e
CY
2,
6
0
0
2,
6
0
0
2,
6
0
0
2,
6
0
0
2,
6
0
0
2,
6
0
0
2,
6
0
0
2,
6
0
0
2,
6
0
0
2,
6
0
0
2,
6
0
0
2,
6
0
0
31
,
2
0
0
Ar
t
i
c
u
l
a
t
e
d

T
r
u
c
k

R
e
g
r
a
d
e
CY
50
,
0
0
0
50
,
0
0
0
50
,
0
0
0
50
,
0
0
0
50
,
0
0
0
50
,
0
0
0
50
,
0
0
0
50
,
0
0
0
50
,
0
0
0
50
,
0
0
0
50
,
0
0
0
50
,
0
0
0
60
0
,
0
0
0
To
p
s
o
i
l
CY
60
,
1
0
0
50
,
6
0
0
59
,
5
0
0
34
,
9
0
0
53
,
0
0
0
51
,
5
0
0
50
,
3
0
0
51
,
9
0
0
57
,
1
0
0
55
,
9
0
0
56
,
8
0
0
51
,
3
0
0
63
2
,
9
0
0
Tr
u
c
k

L
o
a
d
e
r

T
o
p
s
o
i
l
CY
50
,
0
0
0
0
0
0
0
50
,
0
0
0
0
0
0
50
,
0
0
0
0
0
15
0
,
0
0
0
Re
v
e
g
a
t
i
o
n
AC
0.
0
0.
0
0.
0
0.
0
11
5
.
5
0.
0
0.
0
0.
0
80
.
8
0.
0
50
.
4
0.
0
24
6
.
7
Se
d
i
m
e
n
t

C
o
n
t
r
o
l
CY
4,
0
0
0
4,
0
0
0
4,
0
0
0
4,
0
0
0
4,
0
0
0
4,
0
0
0
4,
0
0
0
4,
0
0
0
4,
0
0
0
4,
0
0
0
4,
0
0
0
4,
0
0
0
48
,
0
0
0
FI
N
A
L

R
E
C
L
A
M
A
T
I
O
N
Dr
a
g
l
i
n
e

R
e
g
r
a
d
e
82
0
0

C
Y
0
0
0
0
0
0
0
0
0
0
0
0
0
80
5
0

C
Y
0
0
0
0
0
0
0
0
0
0
0
0
0
Do
z
e
r

R
e
g
r
a
d
e
D1
1

C
Y
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
2,
4
0
0
,
0
0
0
D1
0

C
Y
0
0
0
0
0
0
0
0
0
0
0
0
0
Re
g
r
a
d
e

f
o
r

P
i
t

A
d
v
a
n
c
e
(
F
i
n
a
l

P
i
t
)
AC
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
Tr
u
c
k

L
o
a
d
e
r

R
e
g
r
a
d
e
CY
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
20
0
,
0
0
0
2,
4
0
0
,
0
0
0
Sc
r
a
p
e
r

R
e
g
r
a
d
e
CY
0
0
0
0
0
0
0
0
0
0
0
0
0
Ar
t
i
c
u
l
a
t
e
d

T
r
u
c
k

R
e
g
r
a
d
e
CY
To
p
s
o
i
l
CY
0
0
0
0
0
0
0
0
0
0
0
0
0
Tr
u
c
k

L
o
a
d
e
r

T
o
p
s
o
i
l
CY
0
0
0
0
0
0
0
0
0
0
0
0
0
Re
v
e
g
a
t
i
o
n
AC
0.
0
0.
0
15
0
.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
15
0
.
0
Se
d
i
m
e
n
t

C
o
n
t
r
o
l
CY
0
0
5,
0
0
0
5,
0
0
0
5,
0
0
0
5,
0
0
0
0
0
5,
0
0
0
5,
0
0
0
0
0
30
,
0
0
0
2015 AOP Final Version
Colstrip 3&4
3.1
2 of 2
ICNU_DR_183 Attachment A Page 7 of 54
1s
t

Q
t
r

20
1
6
2n
d

Q
t
r

20
1
6
3r
d

Q
t
r

20
1
6
4t
h

Q
t
r

20
1
6
To
t
a
l

2
0
1
6
20
1
7
20
1
8
20
1
9
CO
A
L

To
n
s

S
o
l
d
Un
i
t
s

3
&
4
1,
8
9
7
,
7
0
0
1,
1
7
2
,
6
0
0
1,
8
8
3
,
0
0
0
1,
9
2
4
,
7
0
0
6,
8
7
8
,
0
0
0
6,
8
2
0
,
0
0
0
7,
3
3
2
,
0
0
0
6,
9
0
9
,
0
0
0
TO
T
A
L
1,
8
9
7
,
7
0
0
1,
1
7
2
,
6
0
0
1,
8
8
3
,
0
0
0
1,
9
2
4
,
7
0
0
6,
8
7
8
,
0
0
0
6,
8
2
0
,
0
0
0
7,
3
3
2
,
0
0
0
6,
9
0
9
,
0
0
0
Pi
t

I
n
v
e
n
t
o
r
y
En
d

o
f

P
e
r
i
o
d

T
o
n
s
89
0
,
0
0
0
1,
6
2
4
,
0
0
0
1,
4
6
9
,
0
0
0
1,
4
3
8
,
0
0
0
1,
4
3
8
,
0
0
0
1,
4
4
0
,
0
0
0
1,
4
4
0
,
0
0
0
1,
4
3
9
,
8
0
0
Qu
a
l
i
t
y
BT
U
/
L
B
8,
3
9
9
8,
4
5
2
8,
4
4
9
8,
3
8
4
8,
4
1
7
8,
4
4
7
8,
4
3
1
8,
4
4
2
MO
I
S
T
U
R
E
25
.
7
1
%
26
.
3
2
%
25
.
9
7
%
25
.
7
3
%
25
.
8
9
%
25
.
9
1
%
25
.
6
6
%
25
.
8
0
%
AS
H
10
.
8
4
%
9.
8
0
%
10
.
2
3
%
10
.
8
0
%
10
.
4
8
%
10
.
2
4
%
10
.
4
3
%
10
.
2
8
%
SU
L
F
U
R
0.
7
4
%
0.
7
3
%
0.
7
6
%
0.
7
6
%
0.
7
5
%
0.
7
5
%
0.
7
4
%
0.
7
4
%
SO
D
I
U
M
0.
1
6
%
0.
4
9
%
0.
2
5
%
0.
2
3
%
0.
2
6
%
0.
2
3
%
0.
4
5
%
0.
4
2
%
AV
G
.

H
A
U
L

(
1
-
W
A
Y
)
Mil
e
s
3.
0
9
4.
4
8
3.
8
3
3.
1
6
3.
5
5
3.
9
9
5.
1
5
4.
6
5
OV
E
R
B
U
R
D
E
N
Pa
r
t
i
n
g

BC
Y
22
,
8
0
0
19
,
2
0
0
32
,
5
0
0
27
,
1
0
0
10
1
,
6
0
0
12
3
,
2
0
0
12
7
,
6
0
0
12
4
,
6
0
0
Sc
r
a
p
e
r

B
C
Y
0
0
0
0
0
0
0
Ab
o
v
e

B
e
n
c
h
Tr
u
c
k
/
L
o
a
d
e
r

B
C
Y
1,
7
6
3
,
8
0
0
88
9
,
6
0
0
1,
2
2
6
,
3
0
0
1,
3
7
7
,
8
0
0
5,
2
5
7
,
5
0
0
4,
2
2
9
,
0
0
0
4,
9
1
8
,
8
0
0
6,
3
9
9
,
3
0
0
Ca
s
t

B
C
Y
5,
1
1
9
,
8
0
0
5,
4
0
6
,
1
0
0
5,
1
6
4
,
1
0
0
5,
4
6
4
,
8
0
0
21
,
1
5
4
,
8
0
0
18
,
7
8
0
,
6
0
0
19
,
5
9
5
,
4
0
0
19
,
3
8
0
,
9
0
0
Do
z
e
r

B
C
Y

f
o
r

8
2
0
0
32
9
,
8
0
0
35
2
,
4
0
0
33
1
,
9
0
0
35
7
,
5
0
0
1,
3
7
1
,
6
0
0
1,
2
5
2
,
1
0
0
1,
3
0
6
,
4
0
0
1,
2
9
2
,
1
0
0
Do
z
e
r

B
C
Y

f
o
r

8
0
5
0
23
9
,
0
0
0
24
8
,
3
0
0
24
1
,
9
0
0
24
9
,
7
0
0
97
8
,
9
0
0
83
4
,
7
0
0
87
0
,
9
0
0
86
1
,
4
0
0
82
0
0

B
C
Y
0
0
0
0
0
0
0
0
80
5
0

B
C
Y
0
0
0
0
0
0
0
0
To
t
a
l

P
r
e
b
e
n
c
h

w
i
t
h

P
a
r
t
i
n
g

B
C
Y
7,
4
7
5
,
2
0
0
6,
9
1
5
,
6
0
0
6,
9
9
6
,
7
0
0
7,
4
7
6
,
9
0
0
28
,
8
6
4
,
4
0
0
25
,
2
1
9
,
6
0
0
26
,
8
1
9
,
1
0
0
28
,
0
5
8
,
3
0
0
Be
l
o
w

B
e
n
c
h
82
0
0

B
C
Y
3,
3
1
4
,
9
0
0
3,
5
2
3
,
8
0
0
3,
3
1
9
,
2
0
0
3,
5
9
1
,
5
0
0
13
,
7
4
9
,
4
0
0
12
,
7
1
2
,
4
0
0
13
,
2
7
9
,
6
0
0
13
,
1
3
6
,
6
0
0
80
5
0

B
C
Y
2,
3
9
0
,
1
0
0
2,
4
9
9
,
4
0
0
2,
4
3
5
,
0
0
0
2,
4
9
6
,
8
0
0
9,
8
2
1
,
3
0
0
8,
4
8
0
,
3
0
0
8,
9
0
5
,
1
0
0
8,
8
0
9
,
8
0
0
To
t
a
l

B
e
l
o
w

B
e
n
c
h

B
C
Y
5,
7
0
5
,
0
0
0
6,
0
2
3
,
2
0
0
5,
7
5
4
,
2
0
0
6,
0
8
8
,
3
0
0
23
,
5
7
0
,
7
0
0
21
,
1
9
2
,
7
0
0
22
,
1
8
4
,
7
0
0
21
,
9
4
6
,
4
0
0
Re
h
a
n
d
l
e
82
0
0

B
C
Y
1,
6
2
9
,
5
0
0
1,
7
0
3
,
2
0
0
1,
6
5
6
,
9
0
0
1,
7
2
4
,
0
0
0
6,
7
1
3
,
6
0
0
6,
8
7
0
,
8
0
0
7,
3
8
6
,
4
0
0
6,
4
4
9
,
5
0
0
80
5
0

B
C
Y
1,
1
5
6
,
8
0
0
1,
1
7
0
,
1
0
0
1,
1
6
0
,
6
0
0
1,
1
9
1
,
7
0
0
4,
6
7
9
,
2
0
0
4,
5
8
0
,
5
0
0
4,
9
2
4
,
3
0
0
4,
2
9
9
,
7
0
0
Do
z
e
r
25
6
,
0
0
0
27
0
,
3
0
0
25
8
,
2
0
0
27
3
,
3
0
0
1,
0
5
7
,
8
0
0
93
9
,
1
0
0
97
9
,
8
0
0
96
9
,
0
0
0
To
t
a
l

R
e
h
a
n
d
l
e
3,
0
4
2
,
3
0
0
3,
1
4
3
,
6
0
0
3,
0
7
5
,
7
0
0
3,
1
8
9
,
0
0
0
12
,
4
5
0
,
6
0
0
12
,
3
9
0
,
4
0
0
13
,
2
9
0
,
5
0
0
11
,
7
1
8
,
2
0
0

R
e
h
a
n
d
l
e

%
23
%
24
%
24
%
24
%
24
%
27
%
27
%
23
%
To
t
a
l

O
v
e
r
b
u
r
d
e
n

BC
Y
16
,
2
2
2
,
5
0
0
16
,
0
8
2
,
4
0
0
15
,
8
2
6
,
6
0
0
16
,
7
5
4
,
2
0
0
64
,
8
8
5
,
7
0
0
58
,
8
0
2
,
7
0
0
62
,
2
9
4
,
3
0
0
61
,
7
2
2
,
9
0
0
ST
R
I
P

R
A
T
I
O

(b
c
y
/
t
o
n
s

e
x
p
o
s
e
d
)
7.
6
6.
8
7.
4
7.
2
7.
2
6.
8
6.
7
7.
2
DR
A
G
L
I
N
E

Y
D
S
/
O
P
.

H
R
.
82
0
0

C
Y
/
O
p

H
r
2,
9
0
8
3,
0
8
7
3,
0
7
2
2,
9
3
7
2,
9
9
9
3,
0
3
4
3,
0
3
8
3,
0
3
5
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
6

-

2
0
1
9

S
t
a
t
i
s
t
i
c
s

S
u
m
m
a
r
y
2015 AOP Final Version
Colstrip 3&4
3.2
1 of 2
ICNU_DR_183 Attachment A Page 8 of 54
1s
t

Q
t
r

20
1
6
2n
d

Q
t
r

20
1
6
3r
d

Q
t
r

20
1
6
4t
h

Q
t
r

20
1
6
To
t
a
l

2
0
1
6
20
1
7
20
1
8
20
1
9
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
6

-

2
0
1
9

S
t
a
t
i
s
t
i
c
s

S
u
m
m
a
r
y
80
5
0

C
Y
/
O
p

H
r
2,
1
1
4
2,
0
6
3
2,
0
4
8
2,
1
0
5
2,
0
8
2
2,
1
5
2
2,
1
5
6
2,
1
5
3
DR
A
G
L
I
N
E

O
P
E
R
A
T
I
N
G

S
H
I
F
T
S
82
0
0

1
2

H
r

S
h
i
f
t
s
14
2
14
1
13
5
15
1
56
9
53
8
56
7
53
8
(E
x
c
l
u
d
i
n
g

R
e
c
l
a
m
a
t
i
o
n
)
80
5
0

1
2

H
r

S
h
i
f
t
s
14
0
14
8
14
6
14
6
58
0
50
6
53
5
50
7
BA
S
E

R
E
C
L
A
M
A
T
I
O
N

Dr
a
g
l
i
n
e

R
e
g
r
a
d
e
82
0
0

C
Y
0
0
0
0
0
1
0
0
80
5
0

C
Y
0
0
0
0
0
0
0
0
Do
z
e
r

R
e
g
r
a
d
e
D1
1

C
Y
30
0
,
0
0
0
30
0
,
0
0
0
30
0
,
0
0
0
30
0
,
0
0
0
1,
2
0
0
,
0
0
0
1,
2
0
0
,
0
0
0
50
0
,
0
0
0
50
0
,
0
0
0
D1
0

C
Y
30
0
,
0
0
0
30
0
,
0
0
0
30
0
,
0
0
0
30
0
,
0
0
0
1,
2
0
0
,
0
0
0
80
0
,
0
0
0
0
29
3
,
0
0
0
Re
g
r
a
d
e

f
o
r

P
i
t

A
d
v
a
n
c
e
AC
47
.
3
52
.
4
47
.
4
52
.
5
19
9
.
6
19
1
.
2
20
7
.
4
19
3
.
2
Tr
u
c
k

L
o
a
d
e
r

R
e
g
r
a
d
e
CY
0
0
0
0
0
30
0
,
0
0
0
1,
0
0
0
,
0
0
0
1,
0
0
0
,
0
0
0
Sc
r
a
p
e
r

R
e
g
r
a
d
e
CY
0
0
0
0
0
0
20
,
0
0
0
20
,
0
0
0
Ar
t
i
c
u
l
a
t
e
d

T
r
u
c
k

R
e
g
r
a
d
e
CY
15
0
,
0
0
0
15
0
,
0
0
0
15
0
,
0
0
0
15
0
,
0
0
0
60
0
,
0
0
0
1,
0
0
0
,
0
0
0
1,
0
0
0
,
0
0
0
1,
0
0
0
,
0
0
0
To
p
s
o
i
l
CY
15
2
,
5
0
0
16
9
,
1
0
0
15
3
,
0
0
0
16
9
,
5
0
0
64
4
,
1
0
0
61
6
,
9
0
0
66
9
,
4
0
0
62
3
,
5
0
0
Tr
u
c
k

L
o
a
d
e
r

T
o
p
s
o
i
l
CY
0
22
0
,
0
0
0
17
0
,
0
0
0
50
,
0
0
0
44
0
,
0
0
0
18
0
,
0
0
0
21
0
,
0
0
0
14
0
,
0
0
0
Re
v
e
g
a
t
i
o
n
AC
0.
0
99
.
9
16
8
.
0
48
.
5
31
6
.
4
24
7
.
0
20
7
.
4
19
3
.
2
Se
d
i
m
e
n
t

C
o
n
t
r
o
l
CY
12
,
0
0
0
12
,
0
0
0
12
,
0
0
0
12
,
0
0
0
48
,
0
0
0
48
,
0
0
0
48
,
0
0
0
48
,
0
0
0
FI
N
A
L

R
E
C
L
A
M
A
T
I
O
N
Dr
a
g
l
i
n
e

R
e
g
r
a
d
e
82
0
0

C
Y
0
0
0
0
0
0
0
0
80
5
0

C
Y
0
0
0
0
0
0
0
0
Do
z
e
r

R
e
g
r
a
d
e
D1
1

C
Y
60
0
,
0
0
0
60
0
,
0
0
0
60
0
,
0
0
0
60
0
,
0
0
0
2,
4
0
0
,
0
0
0
3,
0
0
0
,
0
0
0
3,
0
0
0
,
0
0
0
3,
0
0
0
,
0
0
0
D1
0

C
Y
0
0
0
0
0
0
0
0
Re
g
r
a
d
e

f
o
r

P
i
t

A
d
v
a
n
c
e
(
F
i
n
a
l

P
i
t
)
AC
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
Tr
u
c
k

L
o
a
d
e
r

R
e
g
r
a
d
e
CY
20
0
,
0
0
0
0
0
0
20
0
,
0
0
0
0
0
0
Sc
r
a
p
e
r

R
e
g
r
a
d
e
CY
0
0
0
0
0
0
0
0
Ar
t
i
c
u
l
a
t
e
d

T
r
u
c
k

R
e
g
r
a
d
e
CY
To
p
s
o
i
l
CY
0
0
0
0
0
0
0
0
Tr
u
c
k

L
o
a
d
e
r

T
o
p
s
o
i
l
CY
0
0
0
0
0
0
0
0
Re
v
e
g
a
t
i
o
n
AC
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
20
.
0
0.
0
Se
d
i
m
e
n
t

C
o
n
t
r
o
l
CY
5,
0
0
0
15
,
0
0
0
15
,
0
0
0
0
35
,
0
0
0
0
0
0
2015 AOP Final Version
Colstrip 3&4
3.2
2 of 2
ICNU_DR_183 Attachment A Page 9 of 54
20
1
5

B
U
D
G
E
T
20
1
3

A
C
T
U
A
L
S
20
1
2

A
C
T
U
A
L
S
20
1
1

A
C
T
U
A
L
S
20
1
0

A
C
T
U
A
L
S
DR
A
G
L
I
N
E
S
UN
I
T
S

P
E
R
UN
I
T
S

P
E
R
UN
I
T
S

P
E
R
UN
I
T
S

P
E
R
UN
I
T
S

P
E
R
OP
E
R

H
O
U
R
OP
E
R

H
O
U
R
OP
E
R

H
O
U
R
OP
E
R

H
O
U
R
OP
E
R

H
O
U
R
80
5
0

(
1
2
6
)
2,
0
8
5
cy
/
h
r
2,
0
6
0
cy
/
h
r
1,
9
4
6
cy
/
h
r
2,
1
6
2
cy
/
h
r
2,
1
4
0
cy
/
h
r
82
0
0

(
1
2
7
)
3,
0
2
6
cy
/
h
r
2,
9
0
5
cy
/
h
r
2,
7
3
1
cy
/
h
r
2,
9
6
5
cy
/
h
r
3,
0
0
9
cy
/
h
r
DR
I
L
L
S
DK
S
-
7
5

(
1
3
6
)
4,
5
2
6
cy
/
h
r
5,
4
8
7
cy
/
h
r
4,
9
9
1
cy
/
h
r
4,
8
6
5
cy
/
h
r
4,
7
5
9
cy
/
h
r
DK
S
-
7
5

(
1
3
7
)
4,
5
2
6
cy
/
h
r
5,
4
8
7
cy
/
h
r
4,
9
9
1
cy
/
h
r
4,
2
3
0
cy
/
h
r
4,
3
7
7
cy
/
h
r
PV
-
2
7
5

(
1
3
8
)
4,
5
2
6
cy
/
h
r
5,
4
8
7
cy
/
h
r
4,
9
9
1
cy
/
h
r
4,
4
7
6
cy
/
h
r
5,
1
7
6
cy
/
h
r
Lo
a
d
i
n
g
99
3

k
1,
0
8
9
tn
s
/
h
r
81
9
tn
s
/
h
r
84
3
tn
s
/
h
r
1,
0
6
5
tn
s
/
h
r
1,
1
1
0
tn
s
/
h
r
3&
4

C
o
n
t
r
a
c
t
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
20
1
5

A
O
P
Pr
o
d
u
c
t
i
v
i
t
y

o
f

M
a
j
o
r

E
q
u
i
p
m
e
n
t
2015 AOP Final Version
Colstrip 3&4
3.3ICNU_DR_183 Attachment A Page 10 of 54
Co
a
l
Do
z
e
r
Sc
r
a
p
e
r
Lo
a
d
e
r
Dr
a
g
l
i
n
e
De
w
a
t
e
r
i
n
g
Dr
i
l
l

&

Bl
a
s
t
Co
a
l

Cl
e
a
n
i
n
g
Dr
i
l
l

&

Bl
a
s
t
Lo
a
d
i
n
g
Ha
u
l
i
n
g
Lo
a
d
-
o
u
t
Ha
u
l

Ro
a
d
s
Re
g
r
a
d
i
n
g
To
p
s
o
i
l
/

Su
b
s
o
i
l
Re
v
e
g
.
Re
g
r
a
d
i
n
g
To
p
s
o
i
l
/

Su
b
s
o
i
l
Re
v
e
g
.
25
3
1
0
25
3
2
0
25
3
3
0
25
4
0
0
25
7
1
0
25
8
0
0
35
2
0
0
35
3
0
0
35
4
0
0
35
5
0
0
35
6
0
0
40
0
0
0
55
2
0
0
55
2
1
0
55
3
0
0
55
6
5
0
55
6
5
5
55
6
6
0
To
t
a
l
Ma
r
i
o
n

8
2
0
0

-

D
L
1
2
7
-

-

-

6,
5
8
6

-

-

-

-

-

-

-

-

-

-

-

-

-

-

6,
5
8
6

Ma
r
i
o
n

8
0
5
0

-

D
L
1
2
6
-

-

-

6,
7
5
7

-

-

-

-

-

-

-

-

-

-

-

-

-

-

6,
7
5
7

Dr
i
l
l

T
e
c
h

D
7
5
K
S
-

-

-

-

-

4,
6
3
2

-

-

-

-

-

-

-

-

-

-

-

-

4,
6
3
2

Dr
i
l
l

T
e
c
h

D
7
5
K
S
-

-

-

-

-

6,
3
7
5

-

-

-

-

-

-

-

-

-

-

-

-

6,
3
7
5

Ca
t

9
9
3

K

C
o
a
l

L
o
a
d
e
r
-

-

-

-

-

-

-

-

4,
0
8
5

-

-

-

-

-

-

-

-

-

4,
0
8
5

Ca
t

D
1
0
T

D
o
z
e
r
1,
9
0
9

-

4,
7
4
3

-

-

-

-

-

28
8

-

5,
9
2
8

-

3,
4
2
9

13
1

-

-

-

-

16
,
4
2
8

Ca
t

D
1
0
T

D
o
z
e
r
,

L
e
a
s
e
d
-

22
1

-

13
,
3
4
2

20
0

-

60

-

-

-

-

48
0

-

-

-

2,
8
2
4

-

-

17
,
1
2
7

Ca
t

D
1
0
R

D
o
z
e
r
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Ca
t

D
-
1
1

R
/
T

D
o
z
e
r
-

-

-

1,
6
0
1

-

-

-

-

-

-

-

-

-

-

-

4,
3
6
4

-

-

5,
9
6
5

Ca
t

D
-
1
1

D
o
z
e
r
,

L
e
a
s
e
d
3,
4
3
7

-

85
4

-

-

12
0

-

-

-

-

18
7

60
0

10
,
2
6
3

-

-

-

-

-

15
,
4
6
1

Ca
t

D
1
0
T

D
o
z
e
r
,

L
e
a
s
e
d
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Ca
t

D
7

D
o
z
e
r
-

-

-

-

-

-

-

-

-

-

-

-

-

2,
6
8
0

-

-

-

-

2,
6
8
0

Hit
a
c
h
i

1
8
0
0

C
o
a
l

H
o
e
-

-

-

-

-

-

-

-

3,
0
5
3

-

-

-

-

-

-

-

-

-

3,
0
5
3

Ca
t

1
6
M

G
r
a
d
e
r
-

13
6

-

-

-

-

-

-

-

-

-

7,
2
5
1

-

-

-

-

-

-

7,
3
8
7

Ca
t

1
6
H

G
r
a
d
e
r
,

L
e
a
s
e
-

-

4,
7
4
3

14
4

-

96

-

-

-

-

-

-

-

-

-

-

-

-

4,
9
8
3

Ca
t

1
6
H

G
r
a
d
e
r
-

-

-

-

-

-

-

-

-

-

-

3,
6
2
5

1,
1
3
5

1,
6
2
8

-

2,
8
2
4

-

-

9,
2
1
2

Ca
t

1
3
0
G

M
o
t
o
r

G
r
a
d
e
r
-

-

-

-

-

72
8

-

-

-

-

-

-

-

-

-

-

-

-

72
8

Co
a
l

H
a
u
l
e
r

2
0
0

T
o
n
s
-

-

-

-

-

-

-

-

-

10
,
3
1
7

-

-

-

-

-

-

-

-

10
,
3
1
7

Co
a
l

H
a
u
l
e
r

1
8
0

T
o
n
s
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Co
a
l

H
a
u
l
e
r

2
4
0

T
o
n
s
-

-

-

-

-

-

-

-

-

10
,
9
5
6

-

-

-

-

-

-

-

-

10
,
9
5
6

Ca
t

7
7
7

E
n
d

D
u
m
p
-

-

15
,
8
1
1

-

-

-

-

-

-

-

-

41
1

-

1,
0
0
0

-

8,
4
7
1

-

-

25
,
6
9
3

Vo
l
v
o

T
r
u
c
k
-

77
6

-

-

-

-

-

-

-

-

-

-

4,
6
2
9

4,
0
6
9

-

-

-

-

9,
4
7
3

Ca
t

R
M
3
5
0

R
o
a
d

R
e
c
l
a
i
m
e
r
-

-

-

-

-

-

90
0

-

-

-

-

-

-

-

-

-

-

-

90
0

Ca
t

9
9
2
G

C
o
a
l

L
d
r
,

L
e
a
s
e
-

-

-

-

-

-

76
9

-

60
7

-

-

-

-

-

-

-

-

-

1,
3
7
6

Hi
t
a
c
h
i

1
2
0
0

l
o
a
d
e
r
99
9

27
2

19
0

-

80
0

-

-

-

48

-

-

-

1,
4
9
5

1,
3
0
5

-

-

-

-

5,
1
0
8

Ca
t

9
9
2
G

O
B

L
o
a
d
e
r
,

L
e
a
s
e
1,
5
3
8

-

47
4

-

-

-

-

-

-

-

-

27
4

-

15
3

-

-

-

-

2,
4
4
0

Ca
t

9
7
0
F

L
o
a
d
e
r
-

-

-

-

-

-

3,
0
0
0

30

1,
5
3
8

-

-

-

-

-

-

-

-

-

4,
5
6
8

Ko
m
a
t
s
u

W
A
6
0
0

L
o
a
d
e
r
-

-

-

-

-

-

-

-

76
9

-

-

-

36
0

-

-

-

-

-

1,
1
2
9

Co
a
l

D
r
i
l
l
-

-

-

-

-

-

-

1,
1
1
1

-

-

-

-

-

-

-

-

-

-

1,
1
1
1

Co
a
l

D
r
i
l
l

A
t
l
a
s

C
o
p
c
o
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Ca
t

9
9
3

K

L
o
a
d
e
r
-

-

4,
7
4
3

-

-

-

-

-

-

-

-

-

-

22
5

-

2,
8
2
4

-

-

7,
7
9
2

Ca
t

6
5
7
E

S
c
r
a
p
e
r
-

-

-

-

-

-

-

-

-

-

-

89
8

13
0

-

-

-

-

-

1,
0
2
8

Ca
t

6
5
7
E

S
c
r
a
p
e
r
,

L
e
a
s
e
d
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Ca
t

6
3
1
D

W
a
t
e
r

W
a
g
o
n
-

-

-

14
4

-

-

-

-

-

-

-

1,
9
7
2

1,
1
1
1

38
3

-

70
6

-

-

4,
3
1
6

Re
c

T
r
a
c
t
o
r
-

-

-

-

-

-

-

-

-

-

-

-

-

-

1,
2
3
4

-

-

75
0

1,
9
8
4

Ca
t

7
7
7

W
a
t
e
r

T
r
u
c
k
-

-

94
9

-

-

-

-

-

-

-

-

5,
6
3
5

46

32
6

-

-

-

-

6,
9
5
6

Ca
t

D
9
R

D
o
z
e
r
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

To
t
a
l
7,
8
8
2

1,
4
0
4

32
,
5
0
8

28
,
5
7
4

1,
0
0
0

11
,
9
5
1

4,
7
2
9

1,
1
4
1

##
#
#
#
21
,
2
7
3

6,
1
1
5

21
,
1
4
7

22
,
5
9
8

11
,
9
0
0

1,
2
3
4

22
,
0
1
1

-

75
0

20
6
,
6
0
5

Ov
e
r
b
u
r
d
e
n
Ba
s
e

R
e
c
l
a
m
a
t
i
o
n
Fi
n
a
l

R
e
c
l
a
m
a
t
i
o
n
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
Eq
u
i
p
m
e
n
t

H
o
u
r
s

S
u
m
m
a
r
y
2015 AOP Final Version
Colstrip 3&4
3.4ICNU_DR_183 Attachment A Page 11 of 54
0
20
0
0
0
0
40
0
0
0
0
60
0
0
0
0
80
0
0
0
0
10
0
0
0
0
0
12
0
0
0
0
0
14
0
0
0
0
0
JA
N
FE
B
MA
R
AP
R
MA
Y
JU
N
JU
L
AU
G
SE
P
OC
T
NO
V
DE
C
TONS
MO
N
T
H
S
AR
E
A

C

2
0
1
5

B
U
D
G
E
T
CO
A
L

S
A
L
E
S

v
s

C
O
A
L

I
N
V
E
N
T
O
R
Y
SA
L
E
S
IN
V
E
N
T
O
R
Y
2015 AOP Final Version
Colstrip 3&4
3.5ICNU_DR_183 Attachment A Page 12 of 54
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 AOP
Maps
Maps have been dispersed to the Mine Operating Committee.
2015 AOP Final Version
Colstrip 3&4
3.6ICNU_DR_183 Attachment A Page 13 of 54
2015 Operating Budget
Units 3&4
The costs in the Operating Budget are presented based on the segregation of costs as described in the Coal Supply Agreement. The Colstrip 3&4 Pricing Analysis summarizes the total costs of
the operation. These costs are presented monthly for 2015, quarterly for 2016, and annually for
2017 – 2019.
Components of the Colstrip 3&4 Pricing Analysis:
Variable Costs- The details of the variable costs are listed in detail on a separate page. They are
shown by functional category according to the work being performed. These functional
categories are summarized on the “Summary by Functional Account” and then itemized by function in detail. The definitions of the variable cost categories are:
•Labor and Benefits- includes all operating labor and benefits for both hourly andsupervisory employees
•Materials and Supplies- includes all materials and supplies that are used in the operation
but are not related to equipment
•Outside Services- includes all services rendered by contractors, consultants, or specialists
•Equipment Costs- includes all costs related to maintaining and operating equipment(excluding the operator labor). This includes diesel and electricity to power equipment,and any employee labor and benefits, supplies, parts, or outside services to repair and/or
maintain the equipment.
•Other- includes any costs that do not fall into one of the above categories along with the
allocation of Common Mine costs to Area CDepletion Fees- Overriding Royalties, Incentive Fee, Fixed Fee, Return on Investment, and any Credit for
Third Party to the ROI
Production Taxes
Royalties
The above costs equal Total Commodity Costs.
Fixed Costs- Listed in detail, these costs are billed based on the budgeted amount and trued up at the end of the year
•Depreciation
•Mining Flexibility
•Property Tax
•Permitting and Bonding
•Administrative and General
•Lease Rents and Records
•Leased Mining Equipment
•Production Taxes and Royalties on fixed costs
These costs equal the Total Fixed Costs.
2015 AOP Final Version
Colstrip 3&4
4.0ICNU_DR_183 Attachment A Page 14 of 54
Fuel Cost $3.34 /gal
Natural Gas Price $4.03 /MMBTU
ANFO $0.2384 /lb
Emulsion $0.2903 /lb
Emulsion Plus $0.3732 /lb
Materials (Maint. Parts)3.0%
Union Labor-Estimate 3.0%
Salaried Labor 3.0%
Fringe Rate Salaried 57.1%
Fuel & Lube 3.0%
Outside Services 3.0%
Electrical 3.0%
Supplies & Misc.3.0%
Inflation Rates Beginning 2016
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 AOP
2015 Budget Assumptions
2015 AOP Final Version
Colstrip 3&4
4.1ICNU_DR_183 Attachment A Page 15 of 54
20
1
5
Ja
n
Fe
b
Ma
r
Ap
r
Ma
y
Ju
n
Ju
l
Au
g
Se
p
Oc
t
No
v
De
c
TO
T
A
L
Va
r
i
a
n
c
e
CO
M
M
O
D
I
T
Y

C
O
S
T
S
3&
4

V
A
R
I
A
B
L
E

C
O
S
T
S

$6
,
1
5
7
$6
,
1
2
5
$6
,
6
6
9
$4
,
6
9
8
$6
,
8
5
4
$6
,
0
1
8
$7
,
0
6
0
$6
,
1
8
9
$6
,
5
2
5
$6
,
6
4
0
$6
,
3
0
0
$6
,
5
7
6
$7
5
,
8
1
1
$6
9
,
1
6
0
$6
,
6
5
1
Va
r
i
a
b
l
e

C
o
s
t

P
e
r

T
o
n
$9
.
5
0
$1
0
.
4
6
$1
0
.
3
1
$8
.
4
2
$1
2
.
2
9
$1
3
.
4
6
$1
1
.
2
6
$9
.
6
1
$1
0
.
3
6
$1
0
.
3
5
$1
0
.
1
3
$1
0
.
2
4
$1
0
.
4
6
$9
.
8
9
$0
.
5
7
De
p
l
e
t
i
o
n
$2
8
$2
5
$2
8
$2
4
$2
4
$1
9
$2
7
$2
8
$2
7
$2
8
$2
7
$2
8
$3
1
2
$2
9
4
$1
8
Fe
e
s
Ov
e
r
-
r
i
d
i
n
g

R
o
y
a
l
t
i
e
s
$
$
$2
$
$
$5
8
$
$
$4
$
$
$5
1
$1
1
4
$9
1
$2
2
In
c
e
n
t
i
v
e

F
e
e
$3
0
0
$2
7
1
$3
0
0
$2
5
8
$2
5
8
$2
0
7
$2
9
2
$3
0
0
$2
9
3
$2
9
9
$2
9
0
$2
9
9
$3
,
3
6
9
$3
,
2
4
6
$1
2
2
Fi
x
e
d

F
e
e
$3
4
2
$3
0
9
$3
4
2
$2
9
5
$2
9
4
$2
3
6
$3
3
3
$3
4
2
$3
3
4
$3
4
1
$3
3
0
$3
4
1
$3
,
8
4
0
$3
,
7
0
1
$1
3
9
Re
t
u
r
n

o
n

I
n
v
e
s
t
m
e
n
t
$6
4
2
$5
8
0
$6
4
1
$5
5
3
$5
5
2
$4
4
3
$6
2
1
$6
3
8
$3
0
1
$
$
$
$4
,
9
6
8
$5
,
3
7
1
($
4
0
2
)
To
t
a
l

F
e
e
s
$1
,
2
8
4
$1
,
1
6
0
$1
,
2
8
4
$1
,
1
0
6
$1
,
1
0
5
$9
4
4
$1
,
2
4
5
$1
,
2
8
0
$9
3
2
$6
4
0
$6
2
0
$6
9
1
$1
2
,
2
9
1
$1
2
,
4
0
9
($
1
1
9
)
Pr
o
d
u
c
t
i
o
n

T
a
x
e
s

&

R
o
y
a
l
t
i
e
s
Pr
o
d
u
c
t
i
o
n

T
a
x
e
s
$2
,
0
6
2
$1
,
9
7
8
$2
,
1
6
5
$1
,
6
5
2
$2
,
0
9
1
$1
,
7
9
5
$2
,
2
2
0
$2
,
0
6
4
$2
,
0
5
0
$2
,
0
2
3
$1
,
9
3
3
$2
,
0
2
1
$2
4
,
0
5
5
$2
2
,
5
0
6
$1
,
5
4
9
Ro
y
a
l
t
i
e
s

(
a
n
d

p
r
o
d

t
a
x

o
n

r
o
y
a
l
t
i
e
s
)
$1
,
5
2
5
$1
,
4
8
6
$1
,
6
2
3
$1
,
1
9
7
$1
,
6
1
2
$1
,
4
0
4
$1
,
6
8
8
$1
,
5
3
0
$1
,
5
2
5
$1
,
4
9
3
$1
,
4
2
1
$1
,
4
9
1
$1
7
,
9
9
5
$1
6
,
6
9
9
$1
,
2
9
6
To
t
a
l

P
r
o
d
u
c
t
i
o
n

T
a
x
e
s

&

R
o
y
a
l
t
i
e
s
$3
,
5
8
6
$3
,
4
6
4
$3
,
7
8
9
$2
,
8
4
9
$3
,
7
0
3
$3
,
1
9
9
$3
,
9
0
8
$3
,
5
9
4
$3
,
5
7
5
$3
,
5
1
6
$3
,
3
5
4
$3
,
5
1
2
$4
2
,
0
4
9
$3
9
,
2
0
5
$2
,
8
4
5
To
t
a
l

C
o
m
m
o
d
i
t
y

C
h
a
r
g
e
s
$1
1
,
0
5
5
$1
0
,
7
7
5
$1
1
,
7
7
0
$8
,
6
7
6
$1
1
,
6
8
6
$1
0
,
1
8
0
$1
2
,
2
4
1
$1
1
,
0
9
0
$1
1
,
0
5
9
$1
0
,
8
2
3
$1
0
,
3
0
1
$1
0
,
8
0
6
$1
3
0
,
4
6
3
$1
2
1
,
0
6
7
$9
,
3
9
5
Co
m
m
o
d
i
t
y

C
o
s
t

P
e
r

T
o
n
$1
7
.
0
5
$1
8
.
3
9
$1
8
.
1
9
$1
5
.
5
4
$2
0
.
9
6
$2
2
.
7
6
$1
9
.
5
3
$1
7
.
2
2
$1
7
.
5
6
$1
6
.
8
6
$1
6
.
5
6
$1
6
.
8
2
$1
7
.
9
9
$1
7
.
3
1
$0
.
6
8
Co
m
m
o
d
i
t
y

C
h
a
r
g
e

P
e
r

M
M

B
T
U
0.
9
9
4
1.
0
7
6
1.
0
9
6
0.
9
4
2
1.
2
5
9
1.
3
6
2
1.1
7
4
1.
0
0
8
1.
0
3
2
0.
9
9
4
0.
9
8
8
1.
0
1
7
1.
0
7
0
1.
0
2
9
0.
0
4
1
FI
X
E
D

C
O
S
T
S
De
p
r
e
c
i
a
t
i
o
n
$5
6
8
$5
6
5
$5
8
0
$5
8
0
$5
8
0
$5
9
9
$5
8
9
$5
7
6
$5
8
8
$5
8
2
$5
6
3
$5
7
8
$6
,
9
4
9
$7
,
4
6
3
($
5
1
4
)
Min
i
n
g

F
l
e
x
i
b
i
l
i
t
y
$3
5
$3
5
$3
5
$3
5
$3
5
$3
5
$3
5
$3
5
$3
5
$3
5
$3
5
$3
5
$4
1
8
$6
5
8
($
2
4
0
)
Pr
o
p
e
r
t
y

T
a
x
$3
8
$3
8
$3
8
$3
8
$5
3
$3
8
$3
8
$3
8
$3
8
$3
8
$3
8
$3
8
$4
6
6
$4
7
7
($
1
1
)
Pe
r
m
i
t
t
i
n
g

&

B
o
n
d
i
n
g
$1
0
1
$1
0
1
$1
0
1
$1
0
1
$1
0
1
$1
0
1
$1
0
1
$1
0
1
$1
0
1
$1
0
1
$1
0
1
$1
0
1
$1
,
2
1
5
$1
,
2
5
2
($
3
6
)
Ad
m
i
n
i
s
t
r
a
t
i
v
e

&

G
e
n
e
r
a
l

$6
3
0
$6
3
0
$6
3
0
$6
3
0
$6
3
0
$6
3
0
$6
3
0
$6
3
0
$6
3
0
$6
3
0
$6
3
0
$6
3
0
$7
,
5
5
7
$7
,
0
6
7
$4
9
0
Le
a
s
e

R
e
n
t
s

&

R
e
c
o
r
d
s
$
$3
$
$
$2
1
$1
$
$2
$4
$4
6
$
$1
2
$9
1
$9
2
($
2
)
Le
a
s
e
d

M
i
n
i
n
g

E
q
u
i
p
m
e
n
t
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
To
t
a
l

3
&
4

F
i
x
e
d

C
o
s
t
s
$1
,
3
7
2
$1
,
3
7
2
$1
,
3
8
4
$1
,
3
8
4
$1
,
4
2
1
$1
,
4
0
4
$1
,
3
9
2
$1
,
3
8
1
$1
,
3
9
5
$1
,
4
3
1
$1
,
3
6
6
$1
,
3
9
3
$1
6
,
6
9
5
$1
7
,
0
0
8
($
3
1
3
)
Pr
o
d
u
c
t
i
o
n

T
a
x
e
s

&

R
o
y
a
l
t
i
e
s
Pr
o
d
u
c
t
i
o
n

T
a
x
e
s
$2
8
0
$2
8
0
$2
8
2
$2
8
2
$2
9
0
$2
8
6
$2
8
4
$2
8
2
$2
8
5
$2
9
2
$2
7
9
$2
8
4
$3
,
4
0
6
$3
,
4
7
0
($
6
4
)
Ro
y
a
l
t
i
e
s

(
a
n
d

p
r
o
d

t
a
x

o
n

r
o
y
a
l
t
i
e
s
)
$2
6
4
$2
6
4
$2
6
7
$2
6
7
$2
7
4
$2
7
0
$2
6
8
$2
6
6
$2
6
9
$2
7
6
$2
6
3
$2
6
8
$3
,
2
1
6
$3
,
2
7
6
($
6
0
)
To
t
a
l

P
r
o
d
u
c
t
i
o
n

T
a
x
e
s

&

R
o
y
a
l
t
i
e
s
$5
4
4
$5
4
4
$5
4
9
$5
4
9
$5
6
3
$5
5
7
$5
5
2
$5
4
8
$5
5
3
$5
6
8
$5
4
2
$5
5
3
$6
,
6
2
2
$6
,
7
4
6
($
1
2
4
)
To
t
a
l

F
i
x
e
d

C
o
s
t
s
$1
,
9
1
6
$1
,
9
1
6
$1
,
9
3
3
$1
,
9
3
3
$1
,
9
8
4
$1
,
9
6
0
$1
,
9
4
5
$1
,
9
2
9
$1
,
9
4
9
$1
,
9
9
9
$1
,
9
0
8
$1
,
9
4
6
$2
3
,
3
1
6
$2
3
,
7
5
4
($
4
3
7
)
Fix
e
d

C
o
s
t

P
e
r

T
o
n
$2
.
9
6
$3
.
2
7
$2
.
9
9
$3
.
4
6
$3
.
5
6
$4
.
3
8
$3
.
1
0
$2
.
9
9
$3
.
0
9
$3
.
1
1
$3
.
0
7
$3
.
0
3
$3
.
2
2
$3
.
4
0
-$
0
.
1
8
Fix
e
d

C
o
s
t

P
e
r

M
M

B
T
U
$0
.
1
7
2
$0
.
1
9
1
$0
.
1
8
0
$0
.
2
1
0
$0
.
2
1
4
$0
.
2
6
2
$0
.
1
8
6
$0
.
1
7
5
$0
.
1
8
2
$0
.
1
8
3
$0
.
1
8
3
$0
.
1
8
3
$0
.
1
9
1
$0
.
2
0
2
-$
0
.
0
1
1
ST
A
T
I
S
T
I
C
A
L

&

M
I
S
C
.

I
N
F
O
R
M
A
T
I
O
N
To
t
a
l

A
r
e
a

C

T
o
n
s

S
o
l
d
64
8
58
6
64
7
55
8
55
8
44
7
62
7
64
4
63
0
64
2
62
2
64
2
7,2
5
1
6,9
9
5
25
6
BT
U
'
s
8,
5
8
3
8,
5
4
7
8,
2
9
5
8,
2
4
7
8,
3
2
1
8,
3
5
9
8,
3
1
8
8,
5
4
2
8,
5
0
9
8,4
8
6
8,
3
8
2
8,
2
7
5
8,4
0
8
8,4
0
8
1
TO
T
A
L

C
O
S
T
S

W
/
O

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$1
2
,
9
7
1
$1
2
,
6
9
1
$1
3
,
7
0
3
$1
0
,
6
0
9
$1
3
,
6
7
0
$1
2
,
1
4
1
$1
4
,
1
8
5
$1
3
,
0
1
9
$1
3
,
0
0
8
$1
2
,
8
2
2
$1
2
,
2
0
9
$1
2
,
7
5
2
$1
5
3
,
7
7
9
$1
4
4
,
8
2
1
$8
,
9
5
8
CO
S
T

P
E
R

T
O
N

W
/
O

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$2
0
.
0
1
$2
1
.
6
6
$2
1
.
1
7
$1
9
.
0
1
$2
4
.
5
2
$2
7
.
1
5
$2
2
.
6
3
$2
0
.
2
1
$2
0
.
6
5
$1
9
.
9
8
$1
9
.
6
3
$1
9
.
8
5
$2
1
.
2
1
$2
0
.
7
0
$0
.
5
0
20
1
5

BU
D
G
E
T

FR
O
M

T
H
E

20
1
4

A
O
P
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
5

P
r
i
c
i
n
g

A
n
a
l
y
s
i
s
2015 AOP Final Version
Colstrip 3&4
4.2
1 of 2
ICNU_DR_183 Attachment A Page 16 of 54
20
1
5
Ja
n
Fe
b
Ma
r
Ap
r
Ma
y
Ju
n
Ju
l
Au
g
Se
p
Oc
t
No
v
De
c
TO
T
A
L
Va
r
i
a
n
c
e
20
1
5

BU
D
G
E
T

FR
O
M

T
H
E

20
1
4

A
O
P
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
5

P
r
i
c
i
n
g

A
n
a
l
y
s
i
s
CO
S
T

P
E
R

M
M

B
T
U

W
/
O

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$1
.
1
6
6
$1
.
2
6
7
$1
.
2
7
6
$1
.
1
5
2
$1
.
4
7
3
$1
.
6
2
4
$1
.
3
6
0
$1
.
1
8
3
$1
.
2
1
4
$1
.
1
7
7
$1
.
1
7
1
$1
.
2
0
0
$1
.
2
6
1
$1
.
2
3
1
$0
.
0
3
0
TR
A
N
S
P
O
R
T
A
T
I
O
N

C
O
S
T
S
$9
1
9
$8
3
1
$9
1
8
$7
9
1
$7
9
1
$6
3
4
$8
8
9
$9
1
3
$8
9
3
$9
1
0
$8
8
2
$9
1
1
$1
0
,
2
8
1
$1
0
,
1
0
0
$1
8
1
TO
T
A
L

C
O
S
T
S

W
I
T
H

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$1
3
,
8
9
0
$1
3
,
5
2
1
$1
4
,
6
2
0
$1
1
,
4
0
1
$1
4
,
4
6
0
$1
2
,
7
7
5
$1
5
,
0
7
4
$1
3
,
9
3
2
$1
3
,
9
0
1
$1
3
,
7
3
2
$1
3
,
0
9
1
$1
3
,
6
6
3
$1
6
4
,
0
6
0
$1
5
4
,
9
2
1
$9
,
1
3
9
CO
S
T

P
E
R

T
O
N

W
I
T
H

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$2
1
.
4
3
$2
3
.
0
8
$2
2
.
5
9
$2
0
.
4
2
$2
5
.
9
3
$2
8
.
5
7
$2
4
.
0
5
$2
1
.
6
3
$2
2
.
0
7
$2
1
.
4
0
$2
1
.
0
5
$2
1
.
2
7
$2
2
.
6
3
$2
2
.
1
5
$0
.
4
8
CO
S
T

P
E
R

M
M

B
T
U

W
I
T
H

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$1
.
2
4
8
$1
.
3
5
0
$1
.
3
6
2
$1
.
2
3
8
$1
.
5
5
8
$1
.
7
0
9
$1
.
4
4
6
$1
.
2
6
6
$1
.
2
9
7
$1
.
2
6
1
$1
.
2
5
6
$1
.
2
8
5
$1
.
3
4
5
$1
.
3
1
7
$0
.
0
2
8
2015 AOP Final Version
Colstrip 3&4
4.2
2 of 2
ICNU_DR_183 Attachment A Page 17 of 54
We
s
t
m
o
r
e
l
a
n
d

C
o
a
l

C
o
m
p
a
n
y
Co
s
t

b
y

S
u
b

b
y

C
a
t
e
g
o
r
y

C
o
d
e

-
-

B
u
d
g
e
t
/
F
o
r
e
c
a
s
t
Ar
e
a

C
20
1
5

A
O
P

B
u
d
g
e
t
De
s
c
r
i
p
t
i
o
n
Ja
n
u
a
r
y

20
1
5

Fe
b
r
u
a
r
y

20
1
5

Ma
r
c
h

2
0
1
5

Ap
r
i
l

2
0
1
5

Ma
y

2
0
1
5

Ju
n
e

2
0
1
5

Ju
l
y

2
0
1
5

Au
g
u
s
t

20
1
5

Se
p
t
e
m
b
e
r

20
1
5

Oc
t
o
b
e
r

20
1
5

No
v
e
m
b
e
r

20
1
5

De
c
e
m
b
e
r

20
1
5

To
t
a
l

2
0
1
5
To
t
a
l

2
0
1
4

AO
P

f
o
r

2
0
1
5
Va
r
i
a
n
c
e
To
n
s

S
o
l
d
64
8
,
2
0
0

58
5
,
8
0
0

64
7
,
2
0
0

55
8
,
2
0
0

55
7
,
6
0
0

44
7
,
2
0
0

62
6
,
8
0
0

64
4
,
1
0
0

62
9
,
8
0
0

64
1
,
8
0
0

62
1
,
9
0
0

64
2
,
3
0
0

7,
2
5
0
,
9
0
0

6,9
9
4
,
9
0
0

25
6
,
0
0
0

To
t
a
l

T
o
n
s

S
o
l
d
64
8
,
2
0
0

58
5
,
8
0
0

64
7
,
2
0
0

55
8
,
2
0
0

55
7
,
6
0
0

44
7
,
2
0
0

62
6
,
8
0
0

64
4
,
1
0
0

62
9
,
8
0
0

64
1
,
8
0
0

62
1
,
9
0
0

64
2
,
3
0
0

7,
2
5
0
,
9
0
0

6,9
9
4
,
9
0
0

25
6
,
0
0
0

To
n
s

M
i
n
e
d
64
8
,
2
0
0

58
5
,
8
0
0

64
7
,
2
0
0

55
8
,
2
0
0

55
7
,
6
0
0

44
7
,
2
0
0

62
6
,
8
0
0

64
4
,
1
0
0

62
9
,
8
0
0

64
1
,
8
0
0

62
1
,
9
0
0

64
2
,
3
0
0

7,
2
5
0
,
9
0
0

6,9
9
4
,
9
0
0

25
6
,
0
0
0

To
p
s
o
i
l

Y
a
r
d
s
11
0
,
1
0
0

50
,
6
0
0

59
,
5
0
0

34
,
9
0
0

53
,
0
0
0

10
1
,
5
0
0

50
,
3
0
0

51
,
9
0
0

57
,
1
0
0

10
5
,
9
0
0

56
,
8
0
0

51
,
3
0
0

78
2
,
9
0
0

1,0
1
8
,
2
0
0

(2
3
5
,
3
0
0
)

En
d

D
u
m
p

/

L
o
a
d
e
r

O
B

B
C
Y
80
,
0
0
0

43
1
,
4
0
0

41
0
,
1
0
0

97
,
1
0
0

57
6
,
6
0
0

31
0
,
6
0
0

52
1
,
2
0
0

10
7
,
4
0
0

30
6
,
8
0
0

32
5
,
9
0
0

24
0
,
6
0
0

41
3
,
5
0
0

3,
8
2
1
,
2
0
0

4,3
4
4
,
5
0
0

(5
2
3
,
3
0
0
)

Do
z
e
r

O
B

B
C
Y
20
5
,
9
0
0

18
3
,
6
0
0

20
7
,
0
0
0

12
6
,
4
0
0

19
0
,
0
0
0

18
0
,
2
0
0

20
0
,
1
0
0

19
4
,
5
0
0

20
0
,
6
0
0

20
3
,
7
0
0

19
8
,
0
0
0

20
0
,
9
0
0

2,
2
9
0
,
9
0
0

2,1
8
4
,
0
0
0

10
6
,
9
0
0

Dr
a
g
l
i
n
e

8
2
0
0

O
B

B
C
Y
1,2
2
3
,
5
0
0

1,
0
6
3
,
7
0
0

1,
1
8
7
,
5
0
0

74
0
,
3
0
0

1,1
2
7
,
2
0
0

97
8
,
8
0
0

1,
1
8
6
,
3
0
0

1,
1
9
3
,
1
0
0

1,2
1
1
,
0
0
0

1,1
7
8
,
4
0
0

1,
1
4
1
,
3
0
0

1,
1
8
4
,
6
0
0

13
,
4
1
5
,
7
0
0

12
,
6
8
2
,
6
0
0

73
3
,
1
0
0

Dr
a
g
l
i
n
e

8
0
5
0

O
B

B
C
Y
84
3
,
2
0
0

77
1
,
9
0
0

88
3
,
3
0
0

52
4
,
2
0
0

77
2
,
8
0
0

83
1
,
2
0
0

82
3
,
3
0
0

77
6
,
7
0
0

80
3
,
1
0
0

85
8
,
8
0
0

83
8
,
8
0
0

82
4
,
4
0
0

9,
5
5
1
,
7
0
0

9,6
9
9
,
3
0
0

(1
4
7
,
6
0
0
)

Ca
s
t

B
l
a
s
t

O
B

B
C
Y
1,8
5
2
,
7
0
0

1,
6
5
2
,
0
0
0

1,
8
6
3
,
6
0
0

1,
1
3
8
,
1
0
0

1,7
1
0
,
0
0
0

1,
6
2
1
,
6
0
0

1,
8
0
1
,
3
0
0

1,
7
5
0
,
7
0
0

1,8
0
5
,
4
0
0

1,8
3
3
,
6
0
0

1,
7
8
2
,
1
0
0

1,
8
0
8
,
1
0
0

20
,
6
1
9
,
2
0
0

19
,
6
5
5
,
6
0
0

96
3
,
6
0
0

To
t
a
l

O
B

B
C
Y
4,2
0
5
,
3
0
0

4,
1
0
2
,
6
0
0

4,
5
5
1
,
5
0
0

2,
6
2
6
,
1
0
0

4,3
7
6
,
6
0
0

3,
9
2
2
,
4
0
0

4,
5
3
2
,
2
0
0

4,
0
2
2
,
4
0
0

4,3
2
6
,
9
0
0

4,4
0
0
,
4
0
0

4,
2
0
0
,
8
0
0

4,
4
3
1
,
5
0
0

49
,
6
9
8
,
7
0
0

48
,
5
6
6
,
0
0
0

1,1
3
2
,
7
0
0

25
3
1
0

D
o
z
e
r
s

L
a
b
o
r
41
,
3
5
5

37
,
0
5
0

41
,
4
8
4

28
,
4
4
9

37
,
1
9
0

33
,
6
6
2

40
,
2
9
0

39
,
7
1
1

46
,
2
0
1

40
,
9
4
3

39
,
9
1
6

40
,
5
5
2

46
6
,
8
0
3

43
0
,
1
5
4

36
,
6
4
9

25
3
1
0

D
o
z
e
r
s

E
q
u
i
p
m
e
n
t
73
,
8
5
4

66
,
1
5
6

74
,
1
0
8

50
,
2
7
6

66
,
5
5
2

60
,
5
1
0

71
,
9
7
5

70
,
8
2
4

82
,
9
3
4

73
,
1
3
1

71
,
3
1
0

72
,
4
0
3

83
4
,
0
3
3

64
3
,
4
7
4

19
0
,
5
5
9

25
3
1
0

D
o
z
e
r
s

F
u
e
l
53
,
9
2
2

48
,
2
8
2

54
,
0
8
3

37
,
1
2
0

48
,
5
2
3

43
,
9
2
5

52
,
4
8
7

51
,
7
6
2

58
,
5
0
5

53
,
3
6
4

51
,
9
8
6

52
,
8
5
4

60
6
,
8
1
5

57
8
,
4
1
9

28
,
3
9
6

25
3
1
0

T
o
t
a
l

D
o
z
e
r
s
16
9
,
1
3
2

15
1
,
4
8
8

16
9
,
6
7
4

11
5
,
8
4
5

15
2
,
2
6
6

13
8
,
0
9
8

16
4
,
7
5
2

16
2
,
2
9
7

18
7
,
6
4
0

16
7
,
4
3
8

16
3
,
2
1
2

16
5
,
8
0
8

1,
9
0
7
,
6
5
1

1,6
5
2
,
0
4
8

25
5
,
6
0
3

Do
z
e
r
s

C
o
s
t
s

/

D
o
z
e
r
s

B
C
Y
0.8
2
1
0.
8
3
0
0.
8
2
0
0.9
2
0
0.8
0
0
0.
7
7
0
0.
8
2
0
0.8
3
0
0.9
4
0
0.
8
2
0
0.
8
2
0
0.
8
3
0
0.
8
3
3
0.7
5
6
0.0
7
6
25
3
2
0

S
c
r
a
p
e
r
s
/
A
r
t
i
c
u
l
a
t
e
d

F
l
e
e
t

L
a
b
o
r
8,4
3
8

10
,
3
4
5

5,
7
8
5

3,6
5
7

4,4
6
9

3,
5
9
6

7,
1
3
8

4,9
6
1

6,2
3
1

8,
3
0
1

8,
4
9
3

7,
7
1
8

79
,
1
3
4

76
,
2
7
3

2,8
6
1

25
3
2
0

S
c
r
a
p
e
r
s
/
A
r
t
i
c
u
l
a
t
e
d

F
l
e
e
t

E
q
u
i
p
m
e
n
t
18
,
1
6
8

22
,
2
7
3

12
,
4
5
5

7,8
7
3

9,6
2
3

7,
7
4
3

15
,
3
6
9

10
,
6
8
2

13
,
4
1
5

17
,
8
7
3

18
,
2
8
5

16
,
6
1
6

17
0
,
3
7
5

13
3
,
8
4
8

36
,
5
2
7

25
3
2
0

S
c
r
a
p
e
r
s
/
A
r
t
i
c
u
l
a
t
e
d

F
l
e
e
t

F
u
e
l
5,1
1
4

6,
2
6
9

3,
5
0
6

2,2
1
6

2,7
0
8

2,
1
7
9

4,
3
2
6

3,0
0
7

3,7
7
6

5,
0
3
0

5,
1
4
7

4,
6
7
7

47
,
9
5
4

60
,
6
0
1

(1
2
,
6
4
7
)

25
3
2
0

T
o
t
a
l

S
c
r
a
p
e
r
s
/
A
r
t
i
c
u
l
a
t
e
d

F
l
e
e
t
31
,
7
2
0

38
,
8
8
7

21
,
7
4
6

13
,
7
4
5

16
,
8
0
0

13
,
5
1
9

26
,
8
3
3

18
,
6
5
0

23
,
4
2
2

31
,
2
0
5

31
,
9
2
4

29
,
0
1
1

29
7
,
4
6
2

27
0
,
7
2
1

26
,
7
4
1

25
3
3
0

E
n
d

D
u
m
p
/
L
o
a
d
e
r

L
a
b
o
r
40
,
2
6
6

21
7
,
0
4
7

20
6
,
3
4
8

48
,
8
6
7

29
0
,
0
9
8

15
6
,
2
6
7

26
2
,
2
5
1

54
,
0
2
1

15
4
,
3
5
5

16
3
,
9
5
5

12
1
,
0
7
3

20
8
,
0
4
4

1,
9
2
2
,
5
9
1

2,1
2
9
,
3
5
0

(2
0
6
,
7
5
9
)

25
3
3
0

E
n
d

D
u
m
p
s
/
L
o
a
d
e
r

E
q
u
i
p
m
e
n
t
70
,
6
9
5

38
1
,
0
6
9

36
2
,
2
8
5

85
,
7
9
5

50
9
,
3
2
6

27
4
,
3
5
8

46
0
,
4
3
4

94
,
8
4
4

27
1
,
0
0
1

28
7
,
8
5
7

21
2
,
5
6
8

36
5
,
2
6
3

3,
3
7
5
,
4
9
4

2,4
6
2
,
9
6
6

91
2
,
5
2
7

25
3
3
0

E
n
d

D
u
m
p
s
/
L
o
a
d
e
r

F
u
e
l
36
,
0
8
8

19
4
,
5
2
4

18
4
,
9
3
5

43
,
7
9
6

25
9
,
9
9
5

14
0
,
0
5
1

23
5
,
0
3
7

48
,
4
1
5

13
8
,
3
3
8

14
6
,
9
4
2

10
8
,
5
0
9

18
6
,
4
5
6

1,
7
2
3
,
0
8
5

2,0
8
5
,
7
0
1

(3
6
2
,
6
1
6
)

25
3
3
0

T
o
t
a
l

E
n
d

D
u
m
p
s
/
L
o
a
d
e
r
14
7
,
0
4
9

79
2
,
6
3
9

75
3
,
5
6
8

17
8
,
4
5
8

1,0
5
9
,
4
1
9

57
0
,
6
7
6

95
7
,
7
2
1

19
7
,
2
8
0

56
3
,
6
9
3

59
8
,
7
5
4

44
2
,
1
5
0

75
9
,
7
6
3

7,
0
2
1
,
1
7
0

6,6
7
8
,
0
1
7

34
3
,
1
5
3

En
d

D
u
m
p
s

C
o
s
t
s
/
E
n
d

D
u
m
p
s

B
C
Y
1.8
3
8
1.
8
4
0
1.
8
4
0
1.8
4
0
1.8
4
0
1.
8
4
0
1.
8
4
0
1.8
4
0
1.8
4
0
1.
8
4
0
1.
8
4
0
1.
8
4
0
1.
8
3
7
1.5
3
7
0.3
0
0
25
4
0
0

D
r
a
g
l
i
n
e
s

L
a
b
o
r
22
5
,
7
3
1

20
1
,
1
7
0

22
4
,
2
1
5

13
9
,
7
0
9

20
8
,
8
5
2

21
7
,
8
6
6

23
8
,
1
1
3

22
1
,
9
2
2

21
6
,
8
0
8

22
4
,
2
1
9

21
6
,
5
3
3

22
4
,
2
1
9

2,
5
5
9
,
3
5
7

2,3
7
3
,
7
3
4

18
5
,
6
2
3

25
4
0
0

D
r
a
g
l
i
n
e
s

E
q
u
i
p
m
e
n
t
57
7
,
4
7
6

51
4
,
2
2
0

57
3
,
3
6
5

35
6
,
4
7
9

53
3
,
9
3
6

55
6
,
8
7
3

60
9
,
6
3
7

56
7
,
1
5
0

55
4
,
3
9
6

57
3
,
3
7
6

55
3
,
6
4
8

57
3
,
3
7
6

6,
5
4
3
,
9
3
2

5,6
2
2
,
4
9
1

92
1
,
4
4
1

25
4
0
0

D
r
a
g
l
i
n
e
s

F
u
e
l
70
,
5
6
4

62
,
9
1
8

70
,
0
9
2

43
,
7
8
4

65
,
3
0
9

68
,
1
1
6

74
,
4
1
9

69
,
3
7
8

67
,
7
8
6

70
,
0
9
3

67
,
7
0
1

70
,
0
9
3

80
0
,
2
5
4

78
9
,
4
2
0

10
,
8
3
3

25
4
0
0

D
r
a
g
l
i
n
e
s

E
l
e
c
t
r
i
c
i
t
y
18
9
,
2
5
0

16
8
,
5
9
4

18
8
,
0
4
5

11
6
,
7
2
0

17
5
,
0
7
8

18
2
,
7
5
4

19
9
,
5
6
9

18
6
,
2
2
4

18
1
,
7
8
0

18
8
,
0
4
8

18
1
,
5
6
1

18
8
,
0
4
8

2,
1
4
5
,
6
7
1

2,0
9
9
,
1
0
0

46
,
5
7
0

25
4
0
0

D
r
a
g
l
i
n
e
s

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
2,0
0
0

2,
0
0
0

2,
0
0
0

2,0
0
0

2,0
0
0

2,
0
0
0

2,
0
0
0

2,0
0
0

2,0
0
0

2,
0
0
0

2,
0
0
0

2,
0
0
0

24
,
0
0
0

24
,
7
2
0

(7
2
0
)

25
4
0
0

D
r
a
g
l
i
n
e
s

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
18
,
4
6
0

18
,
4
6
0

18
,
4
6
0

18
,
4
6
0

18
,
4
6
0

18
,
4
6
0

18
,
4
6
0

18
,
4
6
0

18
,
4
6
0

18
,
4
6
0

18
,
4
6
0

18
,
4
6
0

22
1
,
5
2
2

27
4
,
0
7
8

(5
2
,
5
5
6
)

25
4
0
0

T
o
t
a
l

D
r
a
g
l
i
n
e
s
1,0
8
3
,
4
8
1

96
7
,
3
6
2

1,
0
7
6
,
1
7
7

67
7
,
1
5
3

1,0
0
3
,
6
3
6

1,
0
4
6
,
0
6
9

1,
1
4
2
,
1
9
7

1,
0
6
5
,
1
3
5

1,0
4
1
,
2
3
0

1,0
7
6
,
1
9
6

1,
0
3
9
,
9
0
3

1,
0
7
6
,
1
9
6

12
,
2
9
4
,
7
3
6

11
,
1
8
3
,
5
4
4

1,1
1
1
,
1
9
2

Dr
a
g
l
i
n
e
s

C
o
s
t
s

/

D
r
a
g
l
i
n
e

B
C
Y
0.5
2
4
0.
5
3
0
0.
5
2
0
0.5
4
0
0.5
3
0
0.
5
8
0
0.
5
7
0
0.5
4
0
0.5
2
0
0.
5
3
0
0.
5
3
0
0.
5
4
0
0.
5
3
5
0.5
0
0
0.0
3
6
25
7
1
0

P
i
t

D
e
w
a
t
e
r
i
n
g

L
a
b
o
r
61
,
7
3
9

56
,
2
9
1

62
,
1
1
8

59
,
4
1
8

62
,
1
1
8

60
,
1
7
6

61
,
3
6
0

62
,
1
1
8

59
,
7
9
7

61
,
7
3
9

60
,
1
7
6

61
,
3
6
0

72
8
,
4
0
9

71
0
,
7
7
2

17
,
6
3
7

25
7
1
0

P
i
t

D
e
w
a
t
e
r
i
n
g

E
q
u
i
p
m
e
n
t
8,8
6
8

8,
8
6
8

8,
8
6
8

8,8
6
8

8,8
6
8

8,
8
6
8

8,
8
6
8

8,8
6
8

8,8
6
8

8,
8
6
8

8,
8
6
8

8,
8
6
8

10
6
,
4
1
7

71
,
2
4
3

35
,
1
7
5

25
7
1
0

P
i
t

D
e
w
a
t
e
r
i
n
g

F
u
e
l
4,8
1
0

4,
8
1
0

4,
8
1
0

4,8
1
0

4,8
1
0

4,
8
1
0

4,
8
1
0

4,8
1
0

4,8
1
0

4,
8
1
0

4,
8
1
0

4,
8
1
0

57
,
7
1
5

58
,
7
3
1

(1
,
0
1
6
)

25
7
1
0

P
i
t

D
e
w
a
t
e
r
i
n
g

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
3,2
4
1

2,
9
2
9

3,
2
3
6

2,7
9
1

2,7
8
8

2,
2
3
6

3,
1
3
4

3,2
2
1

3,1
4
9

13
,
2
0
9

3,
1
1
0

3,
2
1
2

46
,
2
5
5

36
,
0
2
4

10
,
2
3
1

25
7
1
0

T
o
t
a
l

P
i
t

D
e
w
a
t
e
r
i
n
g
78
,
6
5
8

72
,
8
9
8

79
,
0
3
2

75
,
8
8
6

78
,
5
8
4

76
,
0
8
9

78
,
1
7
2

79
,
0
1
6

76
,
6
2
3

88
,
6
2
6

76
,
9
6
3

78
,
2
4
9

93
8
,
7
9
7

87
6
,
7
7
0

62
,
0
2
7

Pit

D
e
w
a
t
e
r
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.1
2
1
0.
1
2
0
0.
1
2
0
0.1
4
0
0.1
4
0
0.
1
7
0
0.
1
2
0
0.1
2
0
0.1
2
0
0.
1
4
0
0.
1
2
0
0.
1
2
0
0.
1
2
9
0.1
2
5
0.0
0
4
25
8
0
0

D
r
i
l
l

B
l
a
s
t

L
a
b
o
r
10
3
,
3
8
3

95
,
0
5
2

10
6
,
9
8
4

70
,
7
0
1

10
1
,
5
8
6

94
,
9
1
0

10
3
,
1
0
7

10
0
,
1
7
0

10
1
,
7
8
4

10
4
,
1
2
0

10
1
,
3
4
4

10
2
,
6
2
2

1,
1
8
5
,
7
6
4

1,1
0
2
,
0
4
5

83
,
7
2
0

25
8
0
0

D
r
i
l
l

B
l
a
s
t

E
q
u
i
p
m
e
n
t
12
7
,
6
4
7

11
5
,
4
0
9

12
9
,
7
0
2

80
,
0
0
7

12
0
,
4
0
8

11
3
,
1
3
6

12
5
,
8
6
6

12
1
,
1
3
1

12
5
,
1
3
2

12
7
,
2
1
0

12
3
,
4
7
2

12
5
,
7
6
3

1,
4
3
4
,
8
8
3

99
4
,
2
2
3

44
0
,
6
6
0

25
8
0
0

D
r
i
l
l

B
l
a
s
t

F
u
e
l
92
,
3
1
5

84
,
5
3
0

94
,
7
3
4

57
,
5
7
9

88
,
3
8
1

82
,
3
6
3

92
,
3
8
2

87
,
5
4
1

91
,
2
2
9

92
,
7
3
5

89
,
7
4
1

92
,
0
0
3

1,
0
4
5
,
5
3
2

1,0
4
8
,
8
9
7

(3
,
3
6
5
)

25
8
0
0

D
r
i
l
l

B
l
a
s
t

E
x
p
l
o
s
i
v
e
s
1,2
1
9
,
2
8
9

1,
1
4
4
,
5
6
5

1,
2
7
6
,
3
2
0

75
4
,
6
2
9

1,2
0
3
,
1
9
2

1,
1
0
4
,
7
9
1

1,
2
5
6
,
7
2
1

1,
1
6
0
,
8
5
3

1,2
2
4
,
3
2
6

1,2
4
4
,
2
3
2

1,
1
9
7
,
1
8
2

1,
2
4
1
,
7
0
4

14
,
0
2
7
,
8
0
4

12
,
5
0
3
,
0
4
8

1,5
2
4
,
7
5
6

25
8
0
0

T
o
t
a
l

D
r
i
l
l

B
l
a
s
t
1,5
4
2
,
6
3
5

1,
4
3
9
,
5
5
7

1,
6
0
7
,
7
4
0

96
2
,
9
1
6

1,5
1
3
,
5
6
7

1,
3
9
5
,
1
9
9

1,
5
7
8
,
0
7
6

1,
4
6
9
,
6
9
4

1,5
4
2
,
4
7
1

1,5
6
8
,
2
9
7

1,
5
1
1
,
7
3
9

1,
5
6
2
,
0
9
2

17
,
6
9
3
,
9
8
3

15
,
6
4
8
,
2
1
2

2,0
4
5
,
7
7
1

Dr
i
l
l

&

B
l
a
s
t

/

T
o
t
a
l

C
a
s
t

B
l
a
s
t
0.8
3
3
0.
8
7
0
0.
8
6
0
0.8
5
0
0.8
9
0
0.
8
6
0
0.
8
8
0
0.8
4
0
0.8
5
0
0.
8
6
0
0.
8
5
0
0.
8
6
0
0.
8
5
8
0.7
9
6
0.0
6
2
To
t
a
l

O
v
e
r
b
u
r
d
e
n
3,0
5
2
,
6
7
3

3,
4
6
2
,
8
3
1

3,
7
0
7
,
9
3
9

2,
0
2
4
,
0
0
4

3,8
2
4
,
2
7
2

3,
2
3
9
,
6
5
0

3,
9
4
7
,
7
5
2

2,
9
9
2
,
0
7
2

3,4
3
5
,
0
7
9

3,5
3
0
,
5
1
6

3,
2
6
5
,
8
9
2

3,
6
7
1
,
1
1
9

40
,
1
5
3
,
7
9
8

36
,
3
0
9
,
3
1
2

3,8
4
4
,
4
8
7

To
t
a
l

O
v
e
r
b
u
r
d
e
n

/

T
o
t
a
l

B
C
Y
0.7
2
6
0.
8
4
0
0.
8
1
0
0.7
7
0
0.8
7
0
0.
8
3
0
0.
8
7
0
0.7
4
0
0.7
9
0
0.
8
0
0
0.
7
8
0
0.
8
3
0
0.
8
0
8
0.7
4
8
0.0
6
0
35
1
0
0

T
e
s
t
/
A
n
a
l
y
s
i
s

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
3,8
8
9

3,
5
1
5

3,
8
8
3

3,3
4
9

3,3
4
6

2,
6
8
3

3,
7
6
1

3,8
6
5

3,7
7
9

3,
8
5
1

3,
7
3
1

3,
8
5
4

43
,
5
0
5

43
,
2
2
8

27
7

35
1
0
0

T
o
t
a
l

T
e
s
t
/
A
n
a
l
y
s
i
s
3,8
8
9

3,
5
1
5

3,
8
8
3

3,3
4
9

3,3
4
6

2,
6
8
3

3,
7
6
1

3,8
6
5

3,7
7
9

3,
8
5
1

3,
7
3
1

3,
8
5
4

43
,
5
0
5

43
,
2
2
8

27
7

Te
s
t
/
A
n
a
l
y
s
i
s

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.0
0
6
0.
0
1
0
0.
0
1
0
0.0
1
0
0.0
1
0
0.
0
1
0
0.
0
1
0
0.0
1
0
0.0
1
0
0.
0
1
0
0.
0
1
0
0.
0
1
0
0.
0
0
6
0.0
0
6
(0
.
0
0
0
)
35
2
0
0

C
o
a
l

C
l
e
a
n

L
a
b
o
r
22
,
0
2
6

22
,
1
9
7

23
,
3
2
9

21
,
0
7
4

22
,
3
8
3

21
,
5
7
1

22
,
6
0
2

22
,
7
4
9

23
,
2
1
6

22
,
9
6
6

23
,
0
7
3

22
,
8
3
5

27
0
,
0
2
1

26
1
,
3
3
9

8,6
8
2

35
2
0
0

C
o
a
l

C
l
e
a
n

E
q
u
i
p
m
e
n
t
19
,
7
4
5

19
,
9
6
8

21
,
7
7
6

18
,
1
9
9

20
,
2
3
9

18
,
8
9
9

20
,
6
2
8

20
,
8
7
0

21
,
5
9
0

21
,
2
0
6

21
,
3
6
0

21
,
0
0
2

24
5
,
4
8
2

23
0
,
0
7
7

15
,
4
0
5

35
2
0
0

C
o
a
l

C
l
e
a
n

F
u
e
l
15
,
6
7
7

15
,
4
9
5

16
,
8
2
7

14
,
3
5
8

15
,
5
1
2

14
,
2
1
2

16
,
0
7
5

16
,
2
9
8

16
,
6
0
5

16
,
4
8
0

16
,
4
7
1

16
,
3
6
3

19
0
,
3
7
3

19
4
,
0
1
8

(3
,
6
4
4
)

35
2
0
0

T
o
t
a
l

C
o
a
l

C
l
e
a
n
i
n
g
57
,
4
4
8

57
,
6
6
1

61
,
9
3
2

53
,
6
3
1

58
,
1
3
4

54
,
6
8
2

59
,
3
0
5

59
,
9
1
7

61
,
4
1
1

60
,
6
5
3

60
,
9
0
3

60
,
1
9
9

70
5
,
8
7
6

68
5
,
4
3
4

20
,
4
4
2

Co
a
l

C
l
e
a
n
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.0
8
9
0.
1
0
0
0.
1
0
0
0.1
0
0
0.1
0
0
0.
1
2
0
0.
0
9
0
0.0
9
0
0.1
0
0
0.
0
9
0
0.
1
0
0
0.
0
9
0
0.
0
9
7
0.0
9
8
(0
.
0
0
1
)
35
3
0
0

C
o
a
l

D
r
i
l
l

B
l
a
s
t

L
a
b
o
r
23
,
0
0
7

22
,
1
8
9

22
,
3
8
5

18
,
6
6
7

21
,
3
9
0

19
,
6
3
5

21
,
3
2
6

22
,
0
5
2

21
,
0
4
3

22
,
9
0
8

23
,
1
1
1

21
,
6
3
7

25
9
,
3
4
9

25
1
,
5
3
1

7,8
1
7

35
3
0
0

C
o
a
l

D
r
i
l
l

B
l
a
s
t

E
q
u
i
p
m
e
n
t
16
,
9
7
0

16
,
1
5
8

16
,
0
8
7

13
,
4
1
2

13
,
7
2
4

10
,
9
5
6

15
,
9
5
8

15
,
8
2
3

15
,
8
3
6

16
,
7
7
5

16
,
4
8
6

16
,
4
6
9

18
4
,
6
5
6

24
2
,
3
1
7

(5
7
,
6
6
1
)

35
3
0
0

C
o
a
l

D
r
i
l
l

B
l
a
s
t

F
u
e
l
3,8
1
0

3,
6
3
0

3,
6
1
4

3,0
2
0

3,0
8
9

2,
4
7
4

3,
5
8
5

3,5
5
6

3,5
5
8

3,
7
6
7

3,
7
0
3

3,
6
9
9

41
,
5
0
6

42
,
8
6
3

(1
,
3
5
7
)

35
3
0
0

C
o
a
l

D
r
i
l
l

B
l
a
s
t

M
a
t
e
r
i
a
l

&

S
u
p
p
l
i
e
s
15
0

15
0

15
0

15
0

15
0

15
0

15
0

15
0

15
0

15
0

15
0

15
0

1,
8
0
0

1,8
5
4

(5
4
)

35
3
0
0

C
o
a
l

D
r
i
l
l

B
l
a
s
t

E
x
p
l
o
s
i
v
e
s
11
2
,
7
9
3

10
2
,
9
3
5

11
1
,
5
6
7

95
,
6
4
3

95
,
9
4
1

76
,
8
6
3

10
8
,
5
1
1

11
0
,
8
0
2

10
8
,
7
8
7

11
1
,
6
4
5

10
8
,
4
6
3

11
1
,
3
4
0

1,
2
5
5
,
2
8
9

1,1
0
5
,
0
6
5

15
0
,
2
2
4

35
3
0
0

T
o
t
a
l

C
o
a
l

D
r
i
l
l

B
l
a
s
t
15
6
,
7
3
1

14
5
,
0
6
2

15
3
,
8
0
3

13
0
,
8
9
2

13
4
,
2
9
4

11
0
,
0
7
9

14
9
,
5
3
0

15
2
,
3
8
3

14
9
,
3
7
4

15
5
,
2
4
5

15
1
,
9
1
3

15
3
,
2
9
4

1,
7
4
2
,
6
0
0

1,6
4
3
,
6
3
0

98
,
9
7
0

2015 AOP Final Version
Colstrip 3&4
4.3
1 of 3
ICNU_DR_183 Attachment A Page 18 of 54
We
s
t
m
o
r
e
l
a
n
d

C
o
a
l

C
o
m
p
a
n
y
Co
s
t

b
y

S
u
b

b
y

C
a
t
e
g
o
r
y

C
o
d
e

-
-

B
u
d
g
e
t
/
F
o
r
e
c
a
s
t
Ar
e
a

C
20
1
5

A
O
P

B
u
d
g
e
t
De
s
c
r
i
p
t
i
o
n
Ja
n
u
a
r
y

20
1
5

Fe
b
r
u
a
r
y

20
1
5

Ma
r
c
h

2
0
1
5

Ap
r
i
l

2
0
1
5

Ma
y

2
0
1
5

Ju
n
e

2
0
1
5

Ju
l
y

2
0
1
5

Au
g
u
s
t

20
1
5

Se
p
t
e
m
b
e
r

20
1
5

Oc
t
o
b
e
r

20
1
5

No
v
e
m
b
e
r

20
1
5

De
c
e
m
b
e
r

20
1
5

To
t
a
l

2
0
1
5
To
t
a
l

2
0
1
4

AO
P

f
o
r

2
0
1
5
Va
r
i
a
n
c
e
Co
a
l

D
r
i
l
l

B
l
a
s
t

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.2
4
2
0.
2
5
0
0.
2
4
0
0.2
3
0
0.2
4
0
0.
2
5
0
0.
2
4
0
0.2
4
0
0.2
4
0
0.
2
4
0
0.
2
4
0
0.
2
4
0
0.
2
4
0
0.2
3
5
0.0
0
5
35
4
0
0

L
o
a
d
i
n
g

L
a
b
o
r
53
,
3
8
4

48
,
0
4
1

52
,
8
5
7

45
,
7
0
8

45
,
8
5
2

37
,
2
8
9

52
,
6
0
3

52
,
7
3
2

52
,
5
7
3

52
,
5
4
6

50
,
9
9
4

53
,
6
7
0

59
8
,
2
4
9

56
2
,
8
4
1

35
,
4
0
8

35
4
0
0

L
o
a
d
i
n
g

E
q
u
i
p
m
e
n
t
14
3
,
0
0
5

12
8
,
4
9
2

14
1
,
5
0
5

12
2
,
1
7
9

12
2
,
6
8
6

99
,
5
7
6

14
1
,
1
0
6

14
1
,
1
5
5

13
8
,
5
8
0

14
0
,
6
4
2

13
6
,
3
8
9

14
3
,
9
9
5

1,
5
9
9
,
3
0
9

1,2
7
0
,
0
9
2

32
9
,
2
1
7

35
4
0
0

L
o
a
d
i
n
g

F
u
e
l
76
,
8
4
3

68
,
9
7
6

75
,
9
7
3

65
,
5
0
3

65
,
8
0
9

53
,
3
7
7

75
,
9
9
1

75
,
8
0
6

75
,
9
7
0

75
,
5
3
2

73
,
2
7
7

77
,
4
9
9

86
0
,
5
5
8

88
5
,
1
9
4

(2
4
,
6
3
7
)

35
4
0
0

T
o
t
a
l

L
o
a
d
i
n
g
27
3
,
2
3
2

24
5
,
5
0
9

27
0
,
3
3
5

23
3
,
3
9
0

23
4
,
3
4
7

19
0
,
2
4
1

26
9
,
7
0
0

26
9
,
6
9
4

26
7
,
1
2
3

26
8
,
7
2
0

26
0
,
6
6
0

27
5
,
1
6
3

3,
0
5
8
,
1
1
5

2,7
1
8
,
1
2
7

33
9
,
9
8
8

Lo
a
d
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.4
2
2
0.
4
2
0
0.
4
2
0
0.4
2
0
0.4
2
0
0.
4
3
0
0.
4
3
0
0.4
2
0
0.4
2
0
0.
4
2
0
0.
4
2
0
0.
4
3
0
0.
4
2
2
0.3
8
9
0.0
3
3
35
5
0
0

H
a
u
l
i
n
g

L
a
b
o
r
10
1
,
0
2
7

89
,
6
8
2

98
,
7
2
1

84
,
7
3
7

10
3
,
6
8
0

69
,
4
2
7

96
,
5
5
5

98
,
5
3
3

97
,
7
2
2

98
,
4
0
8

11
2
,
1
3
6

98
,
8
2
1

1,
1
4
9
,
4
5
0

1,0
8
1
,
6
3
3

67
,
8
1
7

35
5
0
0

H
a
u
l
i
n
g

E
q
u
i
p
m
e
n
t
28
5
,
9
8
3

25
3
,
8
7
1

27
9
,
4
5
8

23
9
,
8
7
3

29
3
,
4
5
9

19
6
,
5
3
4

27
3
,
3
2
8

27
8
,
9
0
8

27
6
,
6
2
9

27
8
,
5
7
3

31
7
,
3
8
3

27
9
,
7
4
2

3,
2
5
3
,
7
3
9

3,0
4
1
,
1
2
3

21
2
,
6
1
6

35
5
0
0

H
a
u
l
i
n
g

F
u
e
l
19
9
,
7
9
7

17
7
,
3
5
9

19
5
,
2
3
3

16
7
,
5
7
9

20
5
,
0
8
9

13
7
,
3
0
2

19
0
,
9
5
2

19
4
,
8
8
3

19
3
,
2
5
8

19
4
,
6
1
4

22
1
,
8
2
9

19
5
,
4
3
3

2,
2
7
3
,
3
2
8

2,3
4
3
,
1
8
9

(6
9
,
8
6
1
)

35
5
0
0

H
a
u
l
i
n
g

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
1,5
0
0

1,
5
0
0

1,
5
0
0

1,5
0
0

1,5
0
0

1,
5
0
0

1,
5
0
0

1,5
0
0

1,5
0
0

1,
5
0
0

1,
5
0
0

1,
5
0
0

18
,
0
0
0

18
,
5
4
0

(5
4
0
)

35
5
0
0

T
o
t
a
l

H
a
u
l
a
g
e
58
8
,
3
0
6

52
2
,
4
1
2

57
4
,
9
1
2

49
3
,
6
8
8

60
3
,
7
2
8

40
4
,
7
6
3

56
2
,
3
3
5

57
3
,
8
2
4

56
9
,
1
0
8

57
3
,
0
9
5

65
2
,
8
4
9

57
5
,
4
9
7

6,
6
9
4
,
5
1
7

6,4
8
4
,
4
8
5

21
0
,
0
3
2

Co
a
l

H
a
u
l
a
g
e

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.9
0
8
0.
8
9
0
0.
8
9
0
0.8
8
0
1.0
8
0
0.
9
1
0
0.
9
0
0
0.8
9
0
0.9
0
0
0.
8
9
0
1.
0
5
0
0.
9
0
0
0.
9
2
3
0.9
2
7
(0
.
0
0
4
)
35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

L
a
b
o
r
89
,
2
7
5

86
,
4
8
9

90
,
6
6
8

86
,
4
8
9

90
,
6
6
8

89
,
2
7
5

87
,
8
8
2

90
,
6
6
8

87
,
8
8
2

89
,
2
7
5

89
,
2
7
5

87
,
8
8
2

1,
0
6
5
,
7
2
7

91
9
,
4
3
7

14
6
,
2
9
0

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

E
q
u
i
p
m
e
n
t
78
,
6
6
2

73
,
2
9
4

81
,
3
4
7

73
,
2
9
4

81
,
3
4
7

78
,
6
6
2

75
,
9
7
8

81
,
3
4
7

75
,
9
7
8

78
,
6
6
2

78
,
6
6
2

75
,
9
7
8

93
3
,
2
1
2

71
2
,
6
3
1

22
0
,
5
8
1

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

F
u
e
l
25
,
6
0
6

23
,
2
7
8

26
,
7
7
0

23
,
2
7
8

26
,
7
7
0

25
,
6
0
6

24
,
4
4
2

26
,
7
7
0

24
,
4
4
2

25
,
6
0
6

25
,
6
0
6

24
,
4
4
2

30
2
,
6
2
0

32
1
,
0
2
9

(1
8
,
4
0
9
)

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

E
l
e
c
t
r
i
c
i
t
y
23
,
3
8
4

21
,
1
3
4

23
,
3
3
3

16
,
4
7
6

16
,
4
6
0

13
,
1
9
6

18
,
4
8
2

18
,
9
9
4

18
,
5
9
2

23
,
1
5
8

22
,
4
2
0

22
,
4
2
0

23
8
,
0
4
9

22
0
,
2
5
3

17
,
7
9
7

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
51
2

51
2

51
2

51
2

51
2

51
2

51
2

51
2

51
2

51
2

51
2

51
2

6,
1
4
0

5,9
1
8

22
3

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
30
1

30
1

30
1

30
1

30
1

30
1

30
1

30
1

30
1

30
1

30
1

30
1

3,
6
0
8

3,4
7
7

13
1

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
28
2

28
2

28
2

28
2

28
2

28
2

28
2

28
2

28
2

28
2

28
2

28
2

3,
3
8
3

3,2
6
0

12
3

35
6
0
0

T
o
t
a
l

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g
21
8
,
0
2
2

20
5
,
2
9
0

22
3
,
2
1
2

20
0
,
6
3
2

21
6
,
3
3
9

20
7
,
8
3
4

20
7
,
8
7
9

21
8
,
8
7
3

20
7
,
9
8
8

21
7
,
7
9
6

21
7
,
0
5
8

21
1
,
8
1
7

2,
5
5
2
,
7
4
0

2,1
8
6
,
0
0
5

36
6
,
7
3
5

Cr
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.3
3
6
0.
3
5
0
0.
3
4
0
0.3
6
0
0.3
9
0
0.
4
6
0
0.
3
3
0
0.3
4
0
0.3
3
0
0.
3
4
0
0.
3
5
0
0.
3
3
0
0.
3
5
2
0.3
1
3
0.0
4
0
To
t
a
l

C
o
a
l

H
a
n
d
l
i
n
g
1,2
9
7
,
6
2
9

1,
1
7
9
,
4
4
8

1,
2
8
8
,
0
7
7

1,
1
1
5
,
5
8
2

1,2
5
0
,
1
8
8

97
0
,
2
8
2

1,
2
5
2
,
5
1
0

1,
2
7
8
,
5
5
5

1,2
5
8
,
7
8
3

1,2
7
9
,
3
5
9

1,
3
4
7
,
1
1
5

1,
2
7
9
,
8
2
5

14
,
7
9
7
,
3
5
3

13
,
7
6
0
,
9
0
9

1,0
3
6
,
4
4
4

To
t
a
l

C
o
a
l

H
a
n
d
l
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
2.0
0
2
2.
0
1
0
1.
9
9
0
2.0
0
0
2.2
4
0
2.
1
7
0
2.
0
0
0
1.9
9
0
2.0
0
0
1.
9
9
0
2.
1
7
0
1.
9
9
0
2.
0
4
1
1.9
6
7
0.0
7
3
40
0
0
0

R
o
a
d
s

L
a
b
o
r
84
,
4
0
2

72
,
3
3
5

78
,
6
6
4

86
,
0
5
2

96
,
2
8
6

91
,
6
8
1

14
1
,
7
6
9

15
4
,
7
0
9

12
4
,
3
3
8

11
5
,
8
5
4

94
,
0
0
3

83
,
0
2
5

1,
2
2
3
,
1
1
9

99
5
,
5
1
6

22
7
,
6
0
2

40
0
0
0

R
o
a
d
s

E
q
u
i
p
m
e
n
t
11
6
,
9
1
6

87
,
5
5
2

94
,
0
3
2

12
5
,
4
5
3

13
4
,
9
0
6

13
5
,
9
4
9

22
3
,
8
4
0

23
6
,
8
0
1

18
1
,
1
4
5

17
3
,
9
6
7

12
4
,
9
9
4

10
2
,
6
3
2

1,
7
3
8
,
1
8
7

1,1
2
4
,
4
8
4

61
3
,
7
0
3

40
0
0
0

R
o
a
d
s

F
u
e
l
49
,
0
3
5

39
,
7
3
1

42
,
4
3
9

54
,
3
6
6

62
,
1
2
7

63
,
2
2
0

10
0
,
2
0
3

10
9
,
5
1
5

83
,
4
5
2

76
,
6
9
6

57
,
1
2
1

46
,
5
0
6

78
4
,
4
0
9

67
7
,
3
4
6

10
7
,
0
6
3

40
0
0
0

R
o
a
d
s

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
50
,
4
8
7

50
,
4
8
7

50
,
4
8
7

50
,
4
8
7

50
,
4
8
7

50
,
4
8
7

50
,
4
8
7

50
,
4
8
7

50
,
4
8
7

50
,
4
8
7

50
,
4
8
7

50
,
4
8
7

60
5
,
8
4
6

60
5
,
4
8
2

36
5

40
0
0
0

T
o
t
a
l

R
o
a
d
s
30
0
,
8
4
1

25
0
,
1
0
6

26
5
,
6
2
2

31
6
,
3
5
8

34
3
,
8
0
6

34
1
,
3
3
7

51
6
,
2
9
9

55
1
,
5
1
2

43
9
,
4
2
2

41
7
,
0
0
4

32
6
,
6
0
5

28
2
,
6
5
0

4,
3
5
1
,
5
6
1

3,4
0
2
,
8
2
9

94
8
,
7
3
3

Ro
a
d
s

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.4
6
4
0.
4
3
0
0.
4
1
0
0.5
7
0
0.6
2
0
0.
7
6
0
0.
8
2
0
0.8
6
0
0.7
0
0
0.
6
5
0
0.
5
3
0
0.
4
4
0
0.
6
0
0
0.4
8
6
0.1
1
4
45
0
0
0

P
r
o
d
u
c
t
i
o
n

S
a
l
a
r
y

L
a
b
o
r
97
,
3
4
2

97
,
3
4
2

97
,
3
4
2

97
,
3
4
2

97
,
3
4
2

97
,
3
4
2

97
,
3
4
2

97
,
3
4
2

97
,
3
4
2

97
,
3
4
2

97
,
3
4
2

97
,
3
4
2

1,
1
6
8
,
0
9
9

1,2
4
3
,
3
5
2

(7
5
,
2
5
3
)

45
0
0
0

P
r
o
d
u
c
t
i
o
n

E
q
u
i
p
m
e
n
t
46
,
8
1
1

46
,
8
1
1

46
,
8
1
1

46
,
8
1
1

46
,
8
1
1

46
,
8
1
1

46
,
8
1
1

46
,
8
1
1

46
,
8
1
1

46
,
8
1
1

46
,
8
1
1

46
,
8
1
1

56
1
,
7
3
3

49
7
,
8
3
0

63
,
9
0
3

45
0
0
0

P
r
o
d
u
c
t
i
o
n

F
u
e
l
8,9
0
3

8,
9
0
3

8,
9
0
3

8,9
0
3

8,9
0
3

8,
9
0
3

8,
9
0
3

8,9
0
3

8,9
0
3

8,
9
0
3

8,
9
0
3

8,
9
0
3

10
6
,
8
3
8

98
,
3
3
4

8,5
0
4

45
0
0
0

P
r
o
d
u
c
t
i
o
n

O
t
h
e
r
54
2

54
2

54
2

54
2

54
2

54
2

54
2

54
2

54
2

54
2

54
2

54
2

6,
5
0
4

8,7
6
6

(2
,
2
6
1
)

45
0
0
0

P
r
o
d
u
c
t
i
o
n

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
18
2
,
3
9
5

18
2
,
3
9
5

18
2
,
3
9
5

18
2
,
3
9
5

18
2
,
3
9
5

18
2
,
3
9
5

18
2
,
3
9
5

18
2
,
3
9
5

18
2
,
3
9
5

18
2
,
3
9
5

18
2
,
3
9
5

18
2
,
3
9
5

2,
1
8
8
,
7
3
6

2,1
8
0
,
0
7
9

8,6
5
7

45
0
0
0

T
o
t
a
l

P
r
o
d
u
c
t
i
o
n
33
5
,
9
9
3

33
5
,
9
9
3

33
5
,
9
9
3

33
5
,
9
9
3

33
5
,
9
9
3

33
5
,
9
9
3

33
5
,
9
9
3

33
5
,
9
9
3

33
5
,
9
9
3

33
5
,
9
9
3

33
5
,
9
9
3

33
5
,
9
9
3

4,
0
3
1
,
9
1
1

4,0
2
8
,
3
6
1

3,5
5
0

To
t
a
l

O
t
h
e
r

P
r
o
d
u
c
t
i
o
n
63
6
,
8
3
3

58
6
,
0
9
9

60
1
,
6
1
5

65
2
,
3
5
0

67
9
,
7
9
9

67
7
,
3
2
9

85
2
,
2
9
2

88
7
,
5
0
5

77
5
,
4
1
4

75
2
,
9
9
7

66
2
,
5
9
7

61
8
,
6
4
3

8,
3
8
3
,
4
7
2

7,4
3
1
,
1
9
0

95
2
,
2
8
2

55
1
0
0

C
u
r
r
e
n
t

R
e
c
.

E
n
g
i
n
e
e
r
i
n
g

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
62
,
2
2
7

56
,
2
3
7

62
,
1
3
1

53
,
5
8
7

53
,
5
3
0

42
,
9
3
1

60
,
1
7
3

61
,
8
3
4

60
,
4
6
1

61
,
6
1
3

59
,
7
0
2

61
,
6
6
1

69
6
,
0
8
6

66
8
,
5
3
0

27
,
5
5
6

55
1
0
0

T
o
t
a
l

C
u
r
r
e
n
t

R
e
c
l
a
m
a
t
i
o
n

E
n
g
i
n
e
e
r
i
n
g
62
,
2
2
7

56
,
2
3
7

62
,
1
3
1

53
,
5
8
7

53
,
5
3
0

42
,
9
3
1

60
,
1
7
3

61
,
8
3
4

60
,
4
6
1

61
,
6
1
3

59
,
7
0
2

61
,
6
6
1

69
6
,
0
8
6

66
8
,
5
3
0

27
,
5
5
6

Cu
r
r
e
n
t

R
e
c
l
a
m
a
t
i
o
n

E
n
g
i
n
e
e
r
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.0
9
6
0.
1
0
0
0.
1
0
0
0.1
0
0
0.1
0
0
0.
1
0
0
0.
1
0
0
0.1
0
0
0.1
0
0
0.
1
0
0
0.
1
0
0
0.
1
0
0
0.
0
9
6
0.0
9
6
0.0
0
0
55
2
0
0

R
e
g
r
a
d
i
n
g

L
a
b
o
r
12
1
,
2
0
1

81
,
5
9
8

11
4
,
3
5
5

10
1
,
3
0
6

11
4
,
3
1
3

12
4
,
0
3
4

11
2
,
4
1
3

11
3
,
5
9
8

10
6
,
5
2
7

10
5
,
4
9
0

10
6
,
1
5
8

11
3
,
0
0
5

1,
3
1
3
,
9
9
8

1,1
9
7
,
4
9
7

11
6
,
5
0
1

55
2
0
0

R
e
g
r
a
d
i
n
g

E
q
u
i
p
m
e
n
t
24
2
,
6
6
1

16
7
,
2
8
4

22
8
,
7
9
4

19
5
,
8
1
1

21
9
,
0
0
2

23
6
,
7
5
0

21
5
,
6
2
0

21
7
,
7
2
9

20
4
,
7
0
1

20
2
,
8
2
7

20
4
,
0
1
7

21
6
,
6
4
6

2,
5
5
1
,
8
4
2

1,8
1
7
,
6
5
8

73
4
,
1
8
4

55
2
0
0

R
e
g
r
a
d
i
n
g

F
u
e
l
13
4
,
1
8
5

98
,
0
5
9

13
6
,
8
0
9

10
3
,
4
2
2

12
1
,
5
5
1

13
7
,
0
9
1

11
8
,
8
9
4

12
0
,
5
5
0

10
8
,
7
1
7

10
7
,
3
3
2

10
8
,
2
6
6

11
9
,
7
8
7

1,
4
1
4
,
6
6
3

1,2
9
2
,
8
6
6

12
1
,
7
9
8

55
2
0
0

T
o
t
a
l

R
e
g
r
a
d
i
n
g
49
8
,
0
4
8

34
6
,
9
4
0

47
9
,
9
5
8

40
0
,
5
3
8

45
4
,
8
6
6

49
7
,
8
7
5

44
6
,
9
2
7

45
1
,
8
7
7

41
9
,
9
4
6

41
5
,
6
4
9

41
8
,
4
4
2

44
9
,
4
3
8

5,
2
8
0
,
5
0
3

4,3
0
8
,
0
2
0

97
2
,
4
8
3

Re
g
r
a
d
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.7
6
8
0.
5
9
0
0.
7
4
0
0.7
2
0
0.8
2
0
1.
1
1
0
0.
7
1
0
0.7
0
0
0.6
7
0
0.
6
5
0
0.
6
7
0
0.
7
0
0
0.
7
2
8
0.6
1
6
0.1
1
2
55
2
1
0

T
o
p
s
o
i
l

L
a
b
o
r
85
,
4
2
8

47
,
5
5
8

54
,
7
2
9

34
,
9
0
7

49
,
4
9
2

78
,
4
9
8

47
,
3
1
6

48
,
6
0
5

52
,
7
9
5

82
,
0
4
3

52
,
5
5
3

48
,
1
2
2

68
2
,
0
4
6

79
9
,
8
6
7

(1
1
7
,
8
2
1
)

55
2
1
0

T
o
p
s
o
i
l

E
q
u
i
p
m
e
n
t
13
7
,
9
4
4

91
,
7
2
4

10
5
,
8
3
7

66
,
8
2
8

95
,
5
3
0

12
4
,
3
0
6

91
,
2
4
8

93
,
7
8
6

10
2
,
0
3
1

13
1
,
2
8
3

10
1
,
5
5
6

92
,
8
3
4

1,
2
3
4
,
9
0
7

1,1
9
2
,
9
7
9

41
,
9
2
8

55
2
1
0

T
o
p
s
o
i
l

F
u
e
l
55
,
0
8
1

24
,
7
9
8

28
,
7
2
2

17
,
8
7
6

25
,
8
5
6

51
,
2
8
9

24
,
6
6
6

25
,
3
7
1

27
,
6
6
4

53
,
2
2
9

27
,
5
3
2

25
,
1
0
7

38
7
,
1
9
0

61
0
,
9
1
7

(2
2
3
,
7
2
6
)

55
2
1
0

T
o
t
a
l

T
o
p
s
o
i
l
27
8
,
4
5
2

16
4
,
0
8
0

18
9
,
2
8
8

11
9
,
6
1
1

17
0
,
8
7
8

25
4
,
0
9
3

16
3
,
2
3
0

16
7
,
7
6
2

18
2
,
4
9
1

26
6
,
5
5
6

18
1
,
6
4
1

16
6
,
0
6
3

2,
3
0
4
,
1
4
3

2,6
0
3
,
7
6
3

(2
9
9
,
6
2
0
)

To
p
s
o
i
l
i
n
g

/

T
o
t
a
l

T
o
p
s
o
i
l

Y
a
r
d
s
2.5
2
9
3.
2
4
0
3.
1
8
0
3.4
3
0
3.2
2
0
2.
5
0
0
3.
2
5
0
3.2
3
0
3.2
0
0
2.
5
2
0
3.
2
0
0
3.
2
4
0
2.
9
4
3
2.5
5
7
0.3
8
6
55
3
0
0

R
e
v
e
g
e
t
a
t
i
o
n

L
a
b
o
r
8,8
6
6

8,
0
6
0

9,
2
6
9

8,0
6
0

46
,
6
9
2

12
,
7
9
5

15
,
9
6
3

17
,
4
8
3

36
,
4
0
5

12
,
7
9
5

21
,
6
1
9

8,
4
6
3

20
6
,
4
7
2

25
4
,
6
3
3

(4
8
,
1
6
1
)

55
3
0
0

R
e
v
e
g
e
t
a
t
i
o
n

E
q
u
i
p
m
e
n
t
-
-
-
-
27
,
3
6
5

-
-
-
19
,
1
5
3

-
11
,
9
4
8

-
58
,
4
6
6

65
,
8
5
2

(7
,
3
8
5
)

55
3
0
0

R
e
v
e
g
e
t
a
t
i
o
n

F
u
e
l
-
-
-
-
1,9
2
9

-
-
-
1,3
5
0

-
84
2

-
4,
1
2
0

4,7
7
1

(6
5
1
)

55
3
0
0

R
e
v
e
g
e
t
a
t
i
o
n

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
9,0
2
1

9,
0
2
1

9,
0
2
1

9,0
2
1

9,0
2
1

9,
0
2
1

9,
0
2
1

9,0
2
1

9,0
2
1

9,
0
2
1

9,
0
2
1

9,
0
2
1

10
8
,
2
5
0

43
,
7
5
0

64
,
5
0
0

55
3
0
0

R
e
v
e
g
e
t
a
t
i
o
n

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
78
78
11
,
5
7
5

78

23
,
1
7
5

78
78

11
,
5
7
5

16
,
2
4
3

78
10
,
1
6
3

78

73
,
2
7
6

78
,
8
4
3

(5
,
5
6
7
)

55
3
0
0

T
o
t
a
l

R
e
v
e
g
e
t
a
t
i
o
n
17
,
9
6
5

17
,
1
5
9

29
,
8
6
5

17
,
1
5
9

10
8
,
1
8
2

21
,
8
9
4

25
,
0
6
2

38
,
0
7
9

82
,
1
7
2

21
,
8
9
4

53
,
5
9
3

17
,
5
6
2

45
0
,
5
8
5

44
7
,
8
4
9

2,7
3
6

Re
v
e
g
e
t
a
t
i
o
n

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.0
2
8
0.
0
3
0
0.
0
5
0
0.0
3
0
0.1
9
0
0.
0
5
0
0.
0
4
0
0.0
6
0
0.1
3
0
0.
0
3
0
0.
0
9
0
0.
0
3
0
0.
0
6
2
0.0
6
4
(0
.
0
0
2
)
To
t
a
l

C
u
r
r
e
n
t

R
e
c
l
a
m
a
t
i
o
n
85
6
,
6
9
2

58
4
,
4
1
6

76
1
,
2
4
2

59
0
,
8
9
6

78
7
,
4
5
5

81
6
,
7
9
2

69
5
,
3
9
2

71
9
,
5
5
1

74
5
,
0
6
9

76
5
,
7
1
0

71
3
,
3
7
8

69
4
,
7
2
4

8,
7
3
1
,
3
1
7

8,0
2
8
,
1
6
2

70
3
,
1
5
5

2015 AOP Final Version
Colstrip 3&4
4.3
2 of 3
ICNU_DR_183 Attachment A Page 19 of 54
We
s
t
m
o
r
e
l
a
n
d

C
o
a
l

C
o
m
p
a
n
y
Co
s
t

b
y

S
u
b

b
y

C
a
t
e
g
o
r
y

C
o
d
e

-
-

B
u
d
g
e
t
/
F
o
r
e
c
a
s
t
Ar
e
a

C
20
1
5

A
O
P

B
u
d
g
e
t
De
s
c
r
i
p
t
i
o
n
Ja
n
u
a
r
y

20
1
5

Fe
b
r
u
a
r
y

20
1
5

Ma
r
c
h

2
0
1
5

Ap
r
i
l

2
0
1
5

Ma
y

2
0
1
5

Ju
n
e

2
0
1
5

Ju
l
y

2
0
1
5

Au
g
u
s
t

20
1
5

Se
p
t
e
m
b
e
r

20
1
5

Oc
t
o
b
e
r

20
1
5

No
v
e
m
b
e
r

20
1
5

De
c
e
m
b
e
r

20
1
5

To
t
a
l

2
0
1
5
To
t
a
l

2
0
1
4

AO
P

f
o
r

2
0
1
5
Va
r
i
a
n
c
e
To
t
a
l

C
u
r
r
e
n
t

R
e
c
l
a
m
a
t
i
o
n

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
1.4
7
8
1.
1
7
0
1.
3
3
0
1.2
4
0
1.5
9
0
2.
0
5
0
1.
2
7
0
1.2
7
0
1.3
4
0
1.
3
5
0
1.
3
1
0
1.
2
4
0
1.
2
0
4
1.1
4
8
0.0
5
6
60
0
5
0

S
a
f
e
t
y

L
a
b
o
r
-
-
-
-
-
-
-
-
-
-
-
-
-
34
6
,
0
2
4

(3
4
6
,
0
2
4
)

60
0
5
0

S
a
f
e
t
y

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
8,3
3
3

8,
3
3
3

8,
3
3
3

8,3
3
3

8,3
3
3

8,
3
3
3

8,
3
3
3

8,3
3
3

8,3
3
3

8,
3
3
3

8,
3
3
3

8,
3
3
3

10
0
,
0
0
0

10
3
,
0
0
0

(3
,
0
0
0
)

60
0
5
0

S
a
f
e
t
y

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
67
,
6
5
2

67
,
6
5
2

67
,
6
5
2

67
,
6
5
2

67
,
6
5
2

67
,
6
5
2

67
,
6
5
2

67
,
6
5
2

67
,
6
5
2

67
,
6
5
2

67
,
6
5
2

67
,
6
5
2

81
1
,
8
2
8

42
7
,
9
8
3

38
3
,
8
4
5

60
0
5
0

T
o
t
a
l

S
a
f
e
t
y
75
,
9
8
6

75
,
9
8
6

75
,
9
8
6

75
,
9
8
6

75
,
9
8
6

75
,
9
8
6

75
,
9
8
6

75
,
9
8
6

75
,
9
8
6

75
,
9
8
6

75
,
9
8
6

75
,
9
8
6

91
1
,
8
2
8

87
7
,
0
0
7

34
,
8
2
1

60
1
0
0

T
r
a
i
n
/
I
n
s
p
e
c
t

L
a
b
o
r
74
,
1
0
2

74
,
1
0
2

74
,
1
0
2

74
,
1
0
2

74
,
1
0
2

74
,
1
0
2

74
,
1
0
2

74
,
1
0
2

74
,
1
0
2

74
,
1
0
2

74
,
1
0
2

74
,
1
0
2

88
9
,
2
2
7

72
4
,
7
0
5

16
4
,
5
2
2

60
1
0
0

T
r
a
i
n
/
I
n
s
p
e
c
t

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
26
,
0
4
7

26
,
0
4
7

26
,
0
4
7

26
,
0
4
7

26
,
0
4
7

26
,
0
4
7

26
,
0
4
7

26
,
0
4
7

26
,
0
4
7

26
,
0
4
7

26
,
0
4
7

26
,
0
4
7

31
2
,
5
7
0

35
9
,
5
6
8

(4
6
,
9
9
8
)

60
1
0
0

T
o
t
a
l

T
r
a
i
n
/
I
n
s
p
e
c
t
10
0
,
1
5
0

10
0
,
1
5
0

10
0
,
1
5
0

10
0
,
1
5
0

10
0
,
1
5
0

10
0
,
1
5
0

10
0
,
1
5
0

10
0
,
1
5
0

10
0
,
1
5
0

10
0
,
1
5
0

10
0
,
1
5
0

10
0
,
1
5
0

1,
2
0
1
,
7
9
6

1,0
8
4
,
2
7
3

11
7
,
5
2
3

65
2
0
0

W
a
r
e
h
o
u
s
e

L
a
b
o
r
39
,
8
3
2

39
,
8
3
2

39
,
8
3
2

39
,
8
3
2

39
,
8
3
2

39
,
8
3
2

39
,
8
3
2

39
,
8
3
2

39
,
8
3
2

39
,
8
3
2

39
,
8
3
2

39
,
8
3
2

47
7
,
9
8
2

47
7
,
7
1
1

27
0

65
2
0
0

W
a
r
e
h
o
u
s
e

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
-
-
-
-
-
-
-
-
-
-
-
-
-
10
,
3
0
0

(1
0
,
3
0
0
)

65
2
0
0

W
a
r
e
h
o
u
s
e

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
87
5

87
5

87
5

87
5

87
5

87
5

87
5

87
5

87
5

87
5

87
5

87
5

10
,
5
0
0

10
,
8
1
5

(3
1
5
)

65
2
0
0

W
a
r
e
h
o
u
s
e

O
t
h
e
r
2,5
0
0

2,
5
0
0

2,
5
0
0

2,5
0
0

2,5
0
0

2,
5
0
0

2,
5
0
0

2,5
0
0

2,5
0
0

2,
5
0
0

2,
5
0
0

2,
5
0
0

30
,
0
0
0

31
,
3
3
4

(1
,
3
3
4
)

65
2
0
0

W
a
r
e
h
o
u
s
e

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
84
,
7
4
1

84
,
7
4
1

84
,
7
4
1

84
,
7
4
1

84
,
7
4
1

84
,
7
4
1

84
,
7
4
1

84
,
7
4
1

84
,
7
4
1

84
,
7
4
1

84
,
7
4
1

84
,
7
4
1

1,
0
1
6
,
8
8
9

1,0
2
8
,
0
9
2

(1
1
,
2
0
2
)

65
2
0
0

T
o
t
a
l

W
a
r
e
h
o
u
s
e
12
7
,
9
4
8

12
7
,
9
4
8

12
7
,
9
4
8

12
7
,
9
4
8

12
7
,
9
4
8

12
7
,
9
4
8

12
7
,
9
4
8

12
7
,
9
4
8

12
7
,
9
4
8

12
7
,
9
4
8

12
7
,
9
4
8

12
7
,
9
4
8

1,
5
3
5
,
3
7
1

1,5
5
8
,
2
5
2

(2
2
,
8
8
0
)

66
1
0
0

F
a
c
i
l
i
t
i
e
s

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

53
8
,
9
8
4

54
3
,
3
6
8

(4
,
3
8
4
)

66
1
0
0

T
o
t
a
l

F
a
c
i
l
i
t
i
e
s
44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

44
,
9
1
5

53
8
,
9
8
4

54
3
,
3
6
8

(4
,
3
8
4
)

To
t
a
l

O
t
h
e
r

S
u
p
p
o
r
t
34
8
,
9
9
8

34
8
,
9
9
8

34
8
,
9
9
8

34
8
,
9
9
8

34
8
,
9
9
8

34
8
,
9
9
8

34
8
,
9
9
8

34
8
,
9
9
8

34
8
,
9
9
8

34
8
,
9
9
8

34
8
,
9
9
8

34
8
,
9
9
8

4,
1
8
7
,
9
8
0

4,0
6
2
,
9
0
0

12
5
,
0
8
0

Su
b

T
o
t
a
l
6,1
9
2
,
8
2
5

6,
1
6
1
,
7
9
1

6,
7
0
7
,
8
7
0

4,
7
3
1
,
8
3
0

6,8
9
0
,
7
1
2

6,
0
5
3
,
0
5
2

7,
0
9
6
,
9
4
4

6,
2
2
6
,
6
8
2

6,5
6
3
,
3
4
4

6,6
7
7
,
5
8
1

6,
3
3
7
,
9
8
1

6,
6
1
3
,
3
0
9

76
,
2
5
3
,
9
2
1

69
,
5
9
2
,
4
7
3

6,6
6
1
,
4
4
8

Su
b

T
o
t
a
l

/

T
o
n
s

M
i
n
e
d
9.5
5
4
10
.
5
1
9
10
.
3
6
4
8.4
7
7
12
.
3
5
8
13
.
5
3
5
11
.
3
2
3
9.6
6
7
10
.
4
2
1
10
.
4
0
4
10
.
1
9
1
10
.
2
9
6
10
.
5
1
6
9.9
4
9
0.5
6
7
Co
a
l

C
l
e
a
n
i
n
g
(2
8
,
7
2
4
)

(2
8
,
8
3
0
)

(3
0
,
9
6
6
)

(2
6
,
8
1
6
)

(2
9
,
0
6
7
)

(2
7
,
3
4
1
)

(2
9
,
6
5
3
)

(2
9
,
9
5
8
)

(3
0
,
7
0
5
)

(3
0
,
3
2
6
)

(3
0
,
4
5
2
)

(3
0
,
1
0
0
)

(3
5
2
,
9
3
8
)

(3
4
2
,
7
1
7
)

(1
0
,
2
2
1
)

Ce
l
p

L
o
a
d
i
n
g

a
n
d

H
a
u
l
i
n
g
(7
,
5
0
0
)

(7
,
5
0
0
)

(7
,
5
0
0
)

(7
,
5
0
0
)

(7
,
5
0
0
)

(7
,
5
0
0
)

(7
,
5
0
0
)

(7
,
5
0
0
)

(7
,
5
0
0
)

(7
,
5
0
0
)

(7
,
5
0
0
)

(7
,
5
0
0
)

(9
0
,
0
0
0
)

(9
0
,
0
0
0
)

-
To
t
a
l

V
a
r
i
a
b
l
e

C
o
s
t
6,1
5
6
,
6
0
1

6,
1
2
5
,
4
6
1

6,
6
6
9
,
4
0
4

4,
6
9
7
,
5
1
4

6,8
5
4
,
1
4
5

6,
0
1
8
,
2
1
1

7,
0
5
9
,
7
9
1

6,
1
8
9
,
2
2
3

6,5
2
5
,
1
3
9

6,6
3
9
,
7
5
4

6,
3
0
0
,
0
2
9

6,
5
7
5
,
7
0
9

75
,
8
1
0
,
9
8
2

69
,
1
5
9
,
7
5
6

6,6
5
1
,
2
2
7

To
t
a
l

V
a
r
i
a
b
l
e

C
o
s
t

/

T
o
n
s

M
i
n
e
d
9.4
9
8
10
.
4
5
7
10
.
3
0
5
8.4
1
5
12
.
2
9
2
13
.
4
5
8
11
.
2
6
3
9.6
0
9
10
.
3
6
1
10
.
3
4
6
10
.
1
3
0
10
.
2
3
8
10
.
4
5
5
9.8
8
7
0.5
6
8
La
n
d
s
32
7

3,
0
9
9

32
7

32
7

21
,
0
4
4

88
7

32
7

1,6
8
6

4,0
0
5

45
,
9
1
7

32
7

12
,
2
7
9

90
,
5
5
0

92
,
1
7
8

(1
,
6
2
8
)

-
To
t
a
l

P
e
r
m
i
t
t
i
n
g

&

B
o
n
d
i
n
g
10
1
,
2
5
5

10
1
,
2
5
5

10
1
,
2
5
5

10
1
,
2
5
5

10
1
,
2
5
5

10
1
,
2
5
5

10
1
,
2
5
5

10
1
,
2
5
5

10
1
,
2
5
5

10
1
,
2
5
5

10
1
,
2
5
5

10
1
,
2
5
5

1,
2
1
5
,
0
5
8

1,2
5
1
,
5
0
9

(3
6
,
4
5
2
)

0.0
0
0
56
1
0
0

S
a
l
a
r
y

L
a
b
o
r
-
-
-
-
-
-
-
-
-
-
-
-
-
25
,
9
5
7

(2
5
,
9
5
7
)

56
1
0
0

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

12
2
,
6
7
9

31
,
9
6
8

90
,
7
1
0

55
6
1
0
/
5
6
1
0
0

T
o
t
a
l

F
i
n
a
l

P
i
t
10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

10
,
2
2
3

12
2
,
6
7
9

57
,
9
2
5

64
,
7
5
3

55
6
4
0

P
M

E
n
g
i
n
e
e
r
i
n
g

S
a
l
a
r
y

L
a
b
o
r
-
-
-
-
-
-
-
-
-
-
-
-
-
24
,
2
8
8

(2
4
,
2
8
8
)

55
6
4
0

T
o
t
a
l

P
M

E
n
g
i
n
e
e
r
i
n
g
-
-
-
-
-
-
-
-
-
-
-
-
-
24
,
2
8
8

(2
4
,
2
8
8
)

55
6
5
0

R
e
g
r
a
d
i
n
g

L
a
b
o
r
10
8
,
7
4
1

10
8
,
7
4
1

10
8
,
7
4
1

10
8
,
7
4
1

10
8
,
7
4
1

10
8
,
7
4
1

10
8
,
7
4
1

10
8
,
7
4
1

10
8
,
7
4
1

10
8
,
7
4
1

10
8
,
7
4
1

10
8
,
7
4
1

1,
3
0
4
,
8
8
8

40
0
,
2
8
1

90
4
,
6
0
7

55
6
5
0

R
e
g
r
a
d
i
n
g

E
q
u
i
p
m
e
n
t
14
7
,
5
5
4

14
7
,
5
5
4

14
7
,
5
5
4

14
7
,
5
5
4

14
7
,
5
5
4

14
7
,
5
5
4

14
7
,
5
5
4

14
7
,
5
5
4

14
7
,
5
5
4

14
7
,
5
5
4

14
7
,
5
5
4

14
7
,
5
5
4

1,
7
7
0
,
6
4
6

62
9
,
7
7
9

1,1
4
0
,
8
6
8

55
6
5
0

R
e
g
r
a
d
i
n
g

F
u
e
l
10
9
,
1
3
8

10
9
,
1
3
8

10
9
,
1
3
8

10
9
,
1
3
8

10
9
,
1
3
8

10
9
,
1
3
8

10
9
,
1
3
8

10
9
,
1
3
8

10
9
,
1
3
8

10
9
,
1
3
8

10
9
,
1
3
8

10
9
,
1
3
8

1,
3
0
9
,
6
5
2

51
2
,
7
4
1

79
6
,
9
1
1

55
6
5
0

T
o
t
a
l

R
e
g
r
a
d
i
n
g
36
5
,
4
3
2

36
5
,
4
3
2

36
5
,
4
3
2

36
5
,
4
3
2

36
5
,
4
3
2

36
5
,
4
3
2

36
5
,
4
3
2

36
5
,
4
3
2

36
5
,
4
3
2

36
5
,
4
3
2

36
5
,
4
3
2

36
5
,
4
3
2

4,
3
8
5
,
1
8
6

1,5
4
2
,
8
0
1

2,8
4
2
,
3
8
5

55
6
6
0

R
e
v
e
g
e
t
a
t
i
o
n

L
a
b
o
r
-
-
37
,
9
3
8

-
-
-
-
-
-
-
-
-
37
,
9
3
8

-
37
,
9
3
8

55
6
6
0

R
e
v
e
g
e
t
a
t
i
o
n

E
q
u
i
p
m
e
n
t
-
-
35
,
5
4
4

-
-
-
-
-
-
-
-
-
35
,
5
4
4

-
35
,
5
4
4

55
6
6
0

R
e
v
e
g
e
t
a
t
i
o
n

F
u
e
l
-
-
2,
5
0
5

-
-
-
-
-
-
-
-
-
2,
5
0
5

-
2,5
0
5

55
6
6
0

R
e
v
e
g
e
t
a
t
i
o
n

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
-
-
-
-
-
-
-
-
-
-
-
-
-
43
,
7
5
0

(4
3
,
7
5
0
)

55
6
6
0

R
e
v
e
g
e
t
a
t
i
o
n

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
-
-
30
,
0
0
0

-
-
-
-
-
-
-
-
-
30
,
0
0
0

-
30
,
0
0
0

55
6
6
0

T
o
t
a
l

R
e
v
e
g
e
t
a
t
i
o
n
-
-
10
5
,
9
8
7

-
-
-
-
-
-
-
-
-
10
5
,
9
8
7

43
,
7
5
0

62
,
2
3
7

Po
s
t

M
i
n
e

R
e
c
l
a
m
a
t
i
o
n
37
5
,
6
5
5

37
5
,
6
5
5

48
1
,
6
4
2

37
5
,
6
5
5

37
5
,
6
5
5

37
5
,
6
5
5

37
5
,
6
5
5

37
5
,
6
5
5

37
5
,
6
5
5

37
5
,
6
5
5

37
5
,
6
5
5

37
5
,
6
5
5

4,
6
1
3
,
8
5
1

1,6
6
8
,
7
6
4

2,9
4
5
,
0
8
7

2015 AOP Final Version
Colstrip 3&4
4.3
3 of 3
ICNU_DR_183 Attachment A Page 20 of 54
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
De
c
e
m
b
e
r

o
f

2
0
1
3

B
a
s
e

-

A
r
e
a

C
32
,
4
7
3
,
9
3
5

De
c
e
m
b
e
r

o
f

2
0
1
3

B
a
s
e

-

C
o
m
m
o
n
2,
7
3
2
,
4
8
9
De
c
e
m
b
e
r

o
f

2
0
1
3

B
a
s
e

-

I
n
t
a
n
g
i
b
l
e
s
2,
3
1
0
,
7
0
3

De
c
e
m
b
e
r

o
f

2
0
1
3

B
a
s
e

-

W
o
r
k
i
n
g

C
a
p
i
t
a
l
6,
4
7
0
,
1
7
6

20
1
4

C
a
p
i
t
a
l

P
u
r
c
h
a
s
e
s
2,
2
7
8
,
6
2
0
20
1
4

D
e
p
r
e
c
i
a
t
i
o
n
(6
,
7
7
8
,
2
2
4
)
20
1
4

D
e
p
l
e
t
i
o
n
(2
9
1
,
7
6
8
)
Be
g
i
n
n
i
n
g

Y
e
a
r

"
I
n
v
e
s
t
m
e
n
t

B
a
s
e
"
39
,
1
9
5
,
9
3
1
38
,
4
3
6
,
6
4
1
44
,
3
1
8
,
3
7
5
42
,
5
0
2
,
0
7
6
46
,
8
7
4
,
4
7
6
Cu
r
r
e
n
t

Y
e
a
r

C
a
p
i
t
a
l

P
u
r
c
h
a
s
e
s

6,
5
0
1
,
2
3
5
13
,
4
0
3
,
0
0
0
6,
5
3
1
,
0
6
8
11
,
9
5
6
,
5
8
5
12
,
6
6
2
,
1
0
2
Cu
r
r
e
n
t

Y
e
a
r

D
e
p
r
e
c
i
a
t
i
o
n
(6
,
9
4
8
,
7
3
6
)
(7
,
2
2
5
,
5
1
2
)
(8
,
0
5
4
,
1
0
7
)
(7
,
2
6
8
,
9
1
0
)
(6
,
5
2
2
,
4
0
8
)
Cu
r
r
e
n
t

Y
e
a
r

D
e
p
l
e
t
i
o
n
(3
1
1
,
7
8
9
)
(2
9
5
,
7
5
4
)
(2
9
3
,
2
6
0
)
(3
1
5
,
2
7
6
)
(2
9
7
,
0
8
7
)
En
d

o
f

Y
e
a
r

"
I
n
v
e
s
t
m
e
n
t

B
a
s
e
"
38
,
4
3
6
,
6
4
1
44
,
3
1
8
,
3
7
5
42
,
5
0
2
,
0
7
6
46
,
8
7
4
,
4
7
6
52
,
7
1
7
,
0
8
2
Av
e
r
a
g
e

I
n
v
e
s
t
m
e
n
t

B
a
s
e

f
o
r

t
h
e

Y
e
a
r
38
,
8
1
6
,
2
8
6
41
,
3
7
7
,
5
0
8
43
,
4
1
0
,
2
2
6
44
,
6
8
8
,
2
7
6
49
,
7
9
5
,
7
7
9
RO
I

@

1
2
.
8
%
0.
1
2
8
$4
,
9
6
8
,
4
8
5
$5
,
2
9
6
,
3
2
1
$5
,
5
5
6
,
5
0
9
$5
,
7
2
0
,
0
9
9
$6
,
3
7
3
,
8
6
0
Ra
t
e

P
e
r

t
o
n

o
n

1
s
t

5

m
i
l
l
i
o
n
0.
9
9
1.
0
6
1.
1
1
1.
1
4
1.
2
7
Pr
o
p
e
r
t
y

T
a
x

E
s
t
i
m
a
t
e
46
5
,
9
5
8
47
9
,
9
3
7
49
4
,
3
3
5
50
9
,
1
6
5
52
4
,
4
4
0
De
p
l
e
t
i
o
n

R
a
t
e

p
e
r

t
o
n

0.
0
4
3
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
2
0
1
5

R
e
t
u
r
n

o
n

I
n
v
e
s
t
m
e
n
t

C
a
l
c
u
l
a
t
i
o
n

2015 AOP Final Version
Colstrip 3&4
4.4ICNU_DR_183 Attachment A Page 21 of 54
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
AO
P
Va
r
i
a
n
c
e
AO
P
AO
P
AO
P
AO
P
AO
P
A&
G

-

P
r
e
s
i
d
e
n
t
Sa
l
a
r
i
e
s
19
1
,
0
6
5

(2
3
,
7
8
7
)

16
7
,
2
7
8

17
2
,
2
9
6

17
7
,
4
6
5

18
2
,
7
8
9

18
8
,
2
7
3

Bo
n
u
s
35
9
,
0
7
0

86
,
5
3
0

44
5
,
6
0
0

45
8
,
9
6
8

47
2
,
7
3
7

48
6
,
9
1
9

50
1
,
5
2
7

Fr
i
n
g
e

&

T
a
x
e
s
10
5
,
0
8
6

(9
,
5
7
0
)

95
,
5
1
6

98
,
3
8
1

10
1
,
3
3
3

10
4
,
3
7
3

10
7
,
5
0
4

Tr
a
n
s

&

L
o
d
g
e
25
,
0
0
0

(1
0
,
0
0
0
)

15
,
0
0
0

15
,
4
5
0

15
,
9
1
4

16
,
3
9
1

16
,
8
8
3

Me
a
l
s
5,
0
0
0

(0
)

5,
0
0
0

5,
1
5
0

5,
3
0
5

5,
4
6
4

5,
6
2
8

Ot
h
e
r

F
e
e
s
10
,
0
0
0

0
10
,
0
0
0

10
,
3
0
0

10
,
6
0
9

10
,
9
2
7

11
,
2
5
5

T
o
t
a
l
69
5
,
2
2
1

43
,
1
7
3

73
8
,
3
9
4

76
0
,
5
4
6

78
3
,
3
6
2

80
6
,
8
6
3

83
1
,
0
6
9

A&
G

G
e
n
e
r
a
l
Sa
l
a
r
i
e
s
53
8
,
9
4
6

(1
4
,
4
7
4
)

52
4
,
4
7
2

54
0
,
2
0
6

55
6
,
4
1
2

57
3
,
1
0
5

59
0
,
2
9
8

No
n
v
e
s
t
e
d

S
h
a
r
e
s
33
,
1
2
0

(1
6
,
5
6
0
)

16
,
5
6
0

17
,
0
5
7

17
,
5
6
9

18
,
0
9
6

18
,
6
3
8

Fr
i
n
g
e

&

T
a
x
e
s
29
6
,
4
2
0

3,
0
5
4

29
9
,
4
7
4

30
8
,
4
5
8

31
7
,
7
1
2

32
7
,
2
4
3

33
7
,
0
6
1

Tr
a
n
s

&

L
o
d
g
e
25
,
0
0
0

0
25
,
0
0
0

25
,
7
5
0

26
,
5
2
3

27
,
3
1
8

28
,
1
3
8

Me
a
l
s
3,
5
0
0

(0
)

3,
5
0
0

3,
6
0
5

3,
7
1
3

3,
8
2
5

3,
9
3
9

Du
e
s

&

S
u
b
s
c
r
i
p
t
i
o
n
s
40
,
0
0
0

0
40
,
0
0
0

41
,
2
0
0

42
,
4
3
6

43
,
7
0
9

45
,
0
2
0

Tr
a
i
n
i
n
g
/
C
o
n
f
e
r
e
n
c
e
s
10
,
0
0
0

0
10
,
0
0
0

10
,
3
0
0

10
,
6
0
9

10
,
9
2
7

11
,
2
5
5

Of
f
i
c
e

S
u
p
p
l
i
e
s
12
0
,
0
0
0

-
12
0
,
0
0
0

12
3
,
6
0
0

12
7
,
3
0
8

13
1
,
1
2
7

13
5
,
0
6
1

Ut
i
l
i
t
i
e
s
20
,
0
0
0

47
,
0
0
0

67
,
0
0
0

69
,
0
1
0

71
,
0
8
0

73
,
2
1
3

75
,
4
0
9

Eq
u
i
p

R
e
n
t
5,
0
0
0

(0
)

5,
0
0
0

5,
1
5
0

5,
3
0
5

5,
4
6
4

5,
6
2
8

Ou
t
s
i
d
e

S
e
r
v
i
c
e
s
60
,
0
0
0

5,
0
0
0

65
,
0
0
0

66
,
9
5
0

68
,
9
5
9

71
,
0
2
7

73
,
1
5
8

Pr
o
p
e
r
t
y

I
n
s
2,
8
2
4
,
7
6
7

25
1
,
8
6
5

3,
0
7
6
,
6
3
2

3,
1
6
8
,
9
3
1

3,
2
6
3
,
9
9
9

3,
3
6
1
,
9
1
9

3,
4
6
2
,
7
7
6

Li
a
b
i
l
i
t
y

i
n
s
32
5
,
1
3
0

78
,
1
3
2

40
3
,
2
6
2

41
5
,
3
6
0

42
7
,
8
2
1

44
0
,
6
5
5

45
3
,
8
7
5

Au
t
o

I
n
s
40
,
0
0
0

(3
,
7
2
0
)

36
,
2
8
0

37
,
3
6
8

38
,
4
8
9

39
,
6
4
4

40
,
8
3
3

Ot
h
e
r

I
n
s
5,
0
0
0

(5
,
0
0
0
)

-
-
-
-
-
Ou
t
s
i
d
e

L
e
g
a
l
30
0
,
0
0
0

10
0
,
0
0
0

40
0
,
0
0
0

41
2
,
0
0
0

42
4
,
3
6
0

43
7
,
0
9
1

45
0
,
2
0
4

Au
d
i
t

F
e
e
s
-
A
l
l
o
c
a
t
i
o
n
16
0
,
0
0
0

15
,
0
0
0

17
5
,
0
0
0

18
0
,
2
5
0

18
5
,
6
5
8

19
1
,
2
2
7

19
6
,
9
6
4

SO
X

4
0
4

C
o
n
s
u
l
t
i
n
g
-
A
l
l
o
c
a
t
i
o
n
69
,
7
6
4

20
,
2
3
6

90
,
0
0
0

92
,
7
0
0

95
,
4
8
1

98
,
3
4
5

10
1
,
2
9
6

Ot
h
e
r

F
e
e
s
45
0
,
0
0
0

-
45
0
,
0
0
0

46
3
,
5
0
0

47
7
,
4
0
5

49
1
,
7
2
7

50
6
,
4
7
9

Do
n
a
t
i
o
n
s
33
,
0
0
0

(3
3
,
0
0
0
)

-
-
-
-
-
Te
l
e
p
h
o
n
e
25
,
0
0
0

8,
0
0
0

33
,
0
0
0

33
,
9
9
0

35
,
0
1
0

36
,
0
6
0

37
,
1
4
2

T
o
t
a
l
5,
3
8
4
,
6
4
7
.
2
8
45
5
,
5
3
2
.
7
2
5,
8
4
0
,
1
8
0
.
0
0
6,
0
1
5
,
3
8
5
.
4
0
6,
1
9
5
,
8
4
6
.
9
6
6,
3
8
1
,
7
2
2
.
3
7
6,
5
7
3
,
1
7
4
.
0
4
In
f
o
r
m
a
t
i
o
n

S
y
s
t
e
m

O
v
e
r
h
e
a
d
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
5

-

2
0
1
9

A
c
c
o
u
n
t

D
e
t
a
i
l

f
o
r

3
&
4

A
&
G
2015 AOP Final Version
Colstrip 3&4
4.51 of 3
ICNU_DR_183 Attachment A Page 22 of 54
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
AO
P
Va
r
i
a
n
c
e
AO
P
AO
P
AO
P
AO
P
AO
P
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
5

-

2
0
1
9

A
c
c
o
u
n
t

D
e
t
a
i
l

f
o
r

3
&
4

A
&
G
Sa
l
a
r
i
e
s
22
6
,
3
6
1

(5
8
,
6
5
5
)

16
7
,
7
0
6

17
2
,
7
3
7

17
7
,
9
1
9

18
3
,
2
5
7

18
8
,
7
5
5

Fr
i
n
g
e

&

T
a
x
e
s
12
4
,
4
9
9

(2
8
,
7
3
9
)

95
,
7
6
0

98
,
6
3
3

10
1
,
5
9
2

10
4
,
6
4
0

10
7
,
7
7
9

Tr
a
n
s

&

L
o
d
g
e
2,
4
0
0

10
0

2,
5
0
0

2,
5
7
5

2,
6
5
2

2,
7
3
2

2,
8
1
4

Me
a
l
s
1,
5
0
0

-
1,
5
0
0

1,
5
4
5

1,
5
9
1

1,
6
3
9

1,
6
8
8

Of
f
i
c
e

S
u
p
p
l
i
e
s
12
5
,
0
0
0

(2
8
,
0
0
0
)

97
,
0
0
0

99
,
9
1
0

10
2
,
9
0
7

10
5
,
9
9
5

10
9
,
1
7
4

Ou
t
s
i
d
e

S
e
r
v
i
c
e
s
60
,
0
0
0

(4
1
,
1
0
5
)

18
,
8
9
5

19
,
4
6
2

20
,
0
4
6

20
,
6
4
7

21
,
2
6
6

Te
l
e
p
h
o
n
e
75
,
0
0
0

27
,
0
0
0

10
2
,
0
0
0

10
5
,
0
6
0

10
8
,
2
1
2

11
1
,
4
5
8

11
4
,
8
0
2

So
f
t
w
a
r
e

M
a
i
n
t
e
n
a
n
c
e
85
,
0
0
0

(5
,
0
0
0
)

80
,
0
0
0

82
,
4
0
0

84
,
8
7
2

87
,
4
1
8

90
,
0
4
1

Co
r
p

A
l
l
o
c
a
t
i
o
n
-

I
T

F
e
e
s
24
9
,
3
9
3

15
8
,
6
0
7

40
8
,
0
0
0

42
0
,
2
4
0

43
2
,
8
4
7

44
5
,
8
3
3

45
9
,
2
0
8

So
f
t
w
a
r
e
24
1
,
0
0
0

(1
8
2
,
0
0
0
)

59
,
0
0
0

60
,
7
7
0

62
,
5
9
3

64
,
4
7
1

66
,
4
0
5

T
o
t
a
l
1,
1
9
0
,
1
5
3

(1
5
7
,
7
9
2
)

1,
0
3
2
,
3
6
1

1,
0
6
3
,
3
3
2

1,
0
9
5
,
2
3
2

1,
1
2
8
,
0
8
9

1,
1
6
1
,
9
3
1

HR

&

P
a
y
r
o
l
l
HR
&
P
a
y
r
o
l
l

L
A
B
.

S
A
58
3
,
3
4
5

(2
5
3
,
3
6
7
)

32
9
,
9
7
8

33
9
,
8
7
7

35
0
,
0
7
4

36
0
,
5
7
6

37
1
,
3
9
3

HR
&
P
a
y
r
o
l
l

F
R
I
N
G
/
T
32
0
,
8
4
0

(1
3
2
,
4
2
3
)

18
8
,
4
1
7

19
4
,
0
7
0

19
9
,
8
9
2

20
5
,
8
8
8

21
2
,
0
6
5

HR
&
P
a
y
r
o
l
l

T
R
A
V
E
L
15
,
6
0
0

40
0

16
,
0
0
0

16
,
4
8
0

16
,
9
7
4

17
,
4
8
4

18
,
0
0
8

HR
&
P
a
y
r
o
l
l

M
E
A
L
S
&
E
4,
0
0
0

1,
0
0
0

5,
0
0
0

5,
1
5
0

5,
3
0
5

5,
4
6
4

5,
6
2
8

HR

D
U
E
S
3,
6
0
0

-
3,
6
0
0

3,
7
0
8

3,
8
1
9

3,
9
3
4

4,
0
5
2

HR
&
P
a
y
r
o
l
l

E
D
.
&
T
R
A
20
0
,
0
0
0

(0
)

20
0
,
0
0
0

20
6
,
0
0
0

21
2
,
1
8
0

21
8
,
5
4
5

22
5
,
1
0
2

HR

&

P
a
y
r
o
l
l

S
u
p
p
l
i
e
s
1,
0
0
0

0
1,
0
0
0

1,
0
3
0

1,
0
6
1

1,
0
9
3

1,
1
2
6

HR
&
P
a
y
r
o
l
l

O
U
T
S
I
D
E

S
E
R
V
47
,
0
0
0

(3
2
,
0
0
0
)

15
,
0
0
0

15
,
4
5
0

15
,
9
1
4

16
,
3
9
1

16
,
8
8
3

Wo
r
k
e
r
s

C
o
m
p
91
5
,
0
0
0

14
5
,
0
0
0

1,
0
6
0
,
0
0
0

1,
0
9
1
,
8
0
0

1,
1
2
4
,
5
5
4

1,
1
5
8
,
2
9
1

1,
1
9
3
,
0
3
9

HR
&
P
a
y
r
o
l
l

L
E
G
.
O
U
T
90
,
0
0
0

-
90
,
0
0
0

92
,
7
0
0

95
,
4
8
1

98
,
3
4
5

10
1
,
2
9
6

Ot
h
e
r

F
e
e
s
19
,
0
0
0

26
,
0
0
0

45
,
0
0
0

46
,
3
5
0

47
,
7
4
1

49
,
1
7
3

50
,
6
4
8

Do
n
a
t
i
o
n
s
-
35
,
0
0
0

35
,
0
0
0

36
,
0
5
0

37
,
1
3
2

38
,
2
4
5

39
,
3
9
3

HR
&
P
a
y
r
o
l
l

R
E
C
R
U
I
T
85
,
0
0
0

(1
0
,
0
0
0
)

75
,
0
0
0

77
,
2
5
0

79
,
5
6
8

81
,
9
5
5

84
,
4
1
3

2,
2
8
4
,
3
8
5

(2
2
0
,
3
9
0
)

2,
0
6
3
,
9
9
5

2,
1
2
5
,
9
1
5

2,
1
8
9
,
6
9
2

2,
2
5
5
,
3
8
3

2,
3
2
3
,
0
4
5

AR
E
A

C

C
a
l
c
u
l
a
t
i
o
n
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
To
t
a
l

C
o
m
m
o
n
9,
5
5
4
,
4
0
5

12
0
,
5
2
5

9,
6
7
4
,
9
3
0

9,
9
6
5
,
1
7
8

10
,
2
6
4
,
1
3
3

10
,
5
7
2
,
0
5
7

10
,
8
8
9
,
2
1
9

Al
l
o
c
a
t
i
o
n

%

t
o

A
r
e
a

C
53
.
6
9
%
5.
6
9
%
59
.
3
8
%
64
.
5
1
%
60
.
7
4
%
64
.
9
1
%
64
.
1
2
%
$$

A
l
l
o
c
a
t
e
d

t
o

A
r
e
a

C
$5
,
1
2
9
,
7
0
5
61
5
,
0
8
6
.
4
5
$5
,
7
4
4
,
7
9
2
$6
,
4
2
8
,
4
8
7
$6
,
2
3
4
,
5
9
8
$6
,
8
6
2
,
0
1
3
$6
,
9
8
2
,
4
6
9
2015 AOP Final Version
Colstrip 3&4
4.5
2 of 3
ICNU_DR_183 Attachment A Page 23 of 54
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
AO
P
Va
r
i
a
n
c
e
AO
P
AO
P
AO
P
AO
P
AO
P
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
5

-

2
0
1
9

A
c
c
o
u
n
t

D
e
t
a
i
l

f
o
r

3
&
4

A
&
G
Ar
e
a

C

D
e
s
i
g
n

E
n
g
i
n
e
e
r
i
n
g
De
s
i
g
n

E
n
g

S
a
l
a
r
y
&

F
r
i
n
g
e
s
$1
,
1
3
4
,
4
2
3
19
1
,
3
2
3

$1
,
3
2
5
,
7
4
6
1,
3
6
5
,
5
1
8

1,
4
0
6
,
4
8
4

1,
4
4
8
,
6
7
9

1,
4
9
2
,
1
3
9

De
s
i
g
n

E
n
g

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
$3
5
7
,
0
0
0
(7
1
,
0
0
0
)

$2
8
6
,
0
0
0
24
8
,
2
3
0

21
8
,
5
4
5

22
5
,
1
0
2

23
1
,
8
5
5

De
s
i
g
n

E
n
g

M
&
S
$7
3
,
6
4
0
0
$7
3
,
6
4
0
75
,
8
4
9

78
,
1
2
5

80
,
4
6
8

82
,
8
8
2

De
s
i
g
n

E
n
g

O
t
h
e
r
$1
2
5
,
4
4
0
91
0

$1
2
6
,
3
5
0
13
0
,
1
4
1

13
4
,
0
4
5

13
8
,
0
6
6

14
2
,
2
0
8

$1
,
6
9
0
,
5
0
3
$1
2
1
,
2
3
3
$1
,
8
1
1
,
7
3
6
1,
8
1
9
,
7
3
8

1,
8
3
7
,
1
9
9

1,
8
9
2
,
3
1
5

1,
9
4
9
,
0
8
4

To
t
a
l

A
&
G

e
x
p
e
n
s
e
s

A
r
e
a

C
6,
8
2
0
,
2
0
8
$

$7
3
6
,
3
1
9
7,
5
5
6
,
5
2
8
$

8,
2
4
8
,
2
2
6
$

8,
0
7
1
,
7
9
7
$

8,
7
5
4
,
3
2
8
$

8,
9
3
1
,
5
5
3
$

Ar
e
a

1
1

A
l
l
o
c
a
t
i
o
n
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
AB
D
27
.
3
2
%
25
.
6
8
%
27
.
6
7
%
31
.
9
0
%
27
.
9
3
%
28
.
8
6
%
AB
D

-

F
i
n
a
l
3.
2
2
%
4.
0
1
%
0.
6
7
%
0.
2
3
%
0.
0
3
%
0.
0
5
%
C
53
.
6
9
%
59
.
3
8
%
64
.
5
1
%
60
.
7
4
%
64
.
9
1
%
64
.
1
2
%
C
-

F
i
n
a
l
1.
3
9
%
5.
3
4
%
1.
4
1
%
1.
4
3
%
1.
4
2
%
1.
3
8
%
Lo
c
a
t
i
o
n

2
6
12
.
1
5
%
3.
8
1
%
3.
9
1
%
3.
8
9
%
3.
8
9
%
3.
8
1
%
Lo
c
a
t
i
o
n

2
7
2.
2
4
%
1.
7
7
%
1.
8
2
%
1.
8
1
%
1.
8
1
%
1.
7
8
%
To
t
a
l
10
0
.
0
0
%
10
0
.
0
0
%
10
0
.
0
0
%
10
0
.
0
0
%
10
0
.
0
0
%
10
0
.
0
0
%
A&
G

A
l
l
o
c
a
t
i
o
n
Ar
e
a

C
53
.
6
9
%
59
.
3
8
%
64
.
5
1
%
60
.
7
4
%
64
.
9
1
%
64
.
1
2
%
Ar
e
a

A
B
D
27
.
3
2
%
25
.
6
8
%
27
.
6
7
%
31
.
9
0
%
27
.
9
3
%
28
.
8
6
%
To
t
a
l
81
.
0
1
%
85
.
0
6
%
92
.
1
8
%
92
.
6
5
%
92
.
8
4
%
92
.
9
8
%
2015 AOP Final Version
Colstrip 3&4
4.5
3 of 3
ICNU_DR_183 Attachment A Page 24 of 54
2013 2015 Variance
Actuals AOP
A&G - President
Salaries 178,335 167,278 (11,057)
Bonus 289,480 445,600 156,120
Fringe & Taxes 96,009 95,516 (493)
Trans & Lodge 3,580 15,000 11,420
Meals 2,345 5,000 2,655
Other Fees - 10,000 10,000
Total 569,749 738,394 168,645
A&G General
Salaries 531,657 524,472 (7,185)
Nonvested Shares 29,238 16,560 (12,678)
Relocation 18,490 - (18,490)
Fringe & Taxes 254,040 299,474 45,434
Trans & Lodge 2,904 25,000 22,096
Meals 3,201 3,500 299
Dues & Subscriptions 17,444 40,000 22,556
Training/Conferences 5,315 10,000 4,686
Office Supplies 119,186 120,000 814
Utilities 64,509 67,000 2,491
Equip Rent - 5,000 5,000
Outside Services 63,696 65,000 1,304
Property Ins 2,799,566 3,076,632 277,066
Liability ins 294,010 403,262 109,252
Auto Ins 32,922 36,280 3,358
Other Ins 5,331 - (5,331)
Outside Legal 281,703 400,000 118,297
Audit Fees-Allocation 163,807 175,000 11,193
SOX 404 Consulting 82,993 90,000 7,007
Other Fees 453,495 450,000 (3,495)
Donations 4,029 - (4,029)
Telephone 29,354 33,000 3,646
Total 5,256,890 5,840,180 583,290
Information System Overhead
Salaries 164,043 167,706 3,663
Fringe & Taxes 71,695 95,760 24,065
Trans & Lodge 1,728 2,500 772
Meals 72 1,500 1,428
Office Supplies 109,791 97,000 (12,791)
Outside Services 57,448 18,895 (38,553)
Telephone 116,968 102,000 (14,968)
IT Equipment 150 - (150)
Software Maintenance 115,033 80,000 (35,033)
Corp Allocation-IT Fees 261,837 408,000 146,163
Software 10,712 59,000 48,288
Total 909,476 1,032,361 122,885
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 AOP
2015 A&G Budget Comparison to 2013 Actuals
2015 AOP Final Version
Colstrip 3&4
4.6
1 of 2
ICNU_DR_183 Attachment A Page 25 of 54
2013 2015 Variance
Actuals AOP
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 AOP
2015 A&G Budget Comparison to 2013 Actuals
HR & Payroll
HR&Payroll LAB. SA 465,185 329,978 (135,207)
Relocation 55,004 - (55,004)
HR&Payroll FRING/T 204,738 188,417 (16,321)
HR&Payroll TRAVEL 12,359 16,000 3,641
HR&Payroll MEALS&E 21,687 5,000 (16,687)
HR DUES 4,750 3,600 (1,150)
HR&Payroll ED.&TRA 153,532 200,000 46,468
Office Expense 131 - (131)
HR & Payroll Supplies 654 1,000 347
HR&Payroll OUTSIDE SERV 30,363 15,000 (15,363)
Workers Comp 1,041,142 1,060,000 18,858
HR&Payroll LEG.OUT 72,832 90,000 17,168
Other Fees 50,559 45,000 (5,559)
HR&Payroll RECRUIT 46,034 75,000 28,966
Donations 13,095 35,000 21,905
2,172,065 2,063,995 (108,070)
Total Common 8,908,180 9,674,930 766,750
Allocation % to Area C 52.33%59.38%7.05%
$$ Allocated to Area C 4,661,651 $5,744,792 1,083,141
Area 11 Allocation 2013 2015
ABD 37.65%25.68%
ABD - Final 4.08%4.01%
C 52.33%59.38%
C - Final 0.92%5.34%
Location 26 2.94%3.81%
Location 27 2.08%1.77%
Total 100.00%100.00%
A&G Allocation
Area C 52.33%59.38%
Area ABD 37.65%25.68%
Total 89.98%85.06%
2015 AOP Final Version
Colstrip 3&4
4.6
2 of 2
ICNU_DR_183 Attachment A Page 26 of 54
1S
T

Q
T
R
2N
D

Q
T
R
3R
D

Q
T
R
4T
H

Q
T
R
TO
T
A
L
20
1
7
20
1
8
20
1
9
CO
M
M
O
D
I
T
Y

C
O
S
T
S
3&
4

V
A
R
I
A
B
L
E

C
O
S
T
S

$1
9
,
7
9
3
$1
7
,
7
9
6
$1
9
,
7
5
9
$1
9
,
9
9
4
$7
7
,
3
4
2
$7
4
,
4
3
2
$8
1
,
8
5
9
$8
5
,
0
4
2
Va
r
i
a
b
l
e

C
o
s
t

P
e
r

T
o
n
$1
0
.
4
3
$1
5
.
1
8
$1
0
.
4
9
$1
0
.
3
9
$1
1
.
2
4
$1
0
.
9
1
$1
1
.
1
6
$1
2
.
3
1
De
p
l
e
t
i
o
n
$8
2
$5
0
$8
1
$8
3
$2
9
6
$2
9
3
$3
1
5
$2
9
7
Fe
e
s
Ov
e
r
-
r
i
d
i
n
g

R
o
y
a
l
t
i
e
s
$4
$1
$5
9
$4
2
$1
0
5
$9
9
$1
1
4
$5
1
In
c
e
n
t
i
v
e

F
e
e
$8
9
0
$5
5
0
$8
8
9
$9
0
8
$3
,
2
3
7
$3
,
2
4
0
$3
,
5
0
5
$3
,
3
2
3
Fi
x
e
d

F
e
e
$1
,
0
1
3
$6
2
6
$1
,
0
1
1
$1
,
0
3
4
$3
,
6
8
4
$3
,
6
9
3
$4
,
0
0
3
$3
,
8
0
3
Re
t
u
r
n

o
n

I
n
v
e
s
t
m
e
n
t
$2
,
0
1
2
$1
,
2
4
3
$2
,
0
4
2
$5
,
2
9
6
$5
,
5
5
7
$5
,
7
2
0
$6
,
3
7
4
To
t
a
l

F
e
e
s
$3
,
9
1
9
$2
,
4
2
0
$4
,
0
0
0
$1
,
9
8
4
$1
2
,
3
2
3
$1
2
,
5
8
8
$1
3
,
3
4
2
$1
3
,
5
5
2
Pr
o
d
u
c
t
i
o
n

T
a
x
e
s

&

R
o
y
a
l
t
i
e
s
Pr
o
d
u
c
t
i
o
n

T
a
x
e
s
$6
,
4
2
9
$5
,
1
0
8
$6
,
4
2
6
$6
,
0
9
8
$2
4
,
0
6
1
$2
3
,
4
7
2
$2
5
,
5
7
1
$2
5
,
9
0
8
Ro
y
a
l
t
i
e
s

(
a
n
d

p
r
o
d

t
a
x

o
n

r
o
y
a
l
t
i
e
s
)
$4
,
8
3
6
$4
,
0
6
0
$4
,
8
4
3
$4
,
5
0
5
$1
8
,
2
4
3
$1
7
,
7
2
6
$1
9
,
3
7
4
$1
9
,
9
6
8
To
t
a
l

P
r
o
d
u
c
t
i
o
n

T
a
x
e
s

&

R
o
y
a
l
t
i
e
s
$1
1
,
2
6
4
$9
,
1
6
7
$1
1
,
2
6
9
$1
0
,
6
0
3
$4
2
,
3
0
4
$4
1
,
1
9
8
$4
4
,
9
4
5
$4
5
,
8
7
6
To
t
a
l

C
o
m
m
o
d
i
t
y

C
h
a
r
g
e
s
$3
5
,
0
5
8
$2
9
,
4
3
4
$3
5
,
1
1
0
$3
2
,
6
6
4
$1
3
2
,
2
6
5
$1
2
8
,
5
1
1
$1
4
0
,
4
6
1
$1
4
4
,
7
6
7
Co
m
m
o
d
i
t
y

C
o
s
t

P
e
r

T
o
n
$1
8
.
4
7
$2
5
.
1
0
$1
8
.
6
5
$1
6
.
9
7
$1
9
.
2
3
$1
8
.
8
4
$1
9
.
1
6
$2
0
.
9
5
Co
m
m
o
d
i
t
y

C
h
a
r
g
e

P
e
r

M
M

B
T
U
1.
1
0
0
1.
4
8
5
1.
1
0
3
1.
0
1
2
1.
1
4
2
1.
1
1
5
1.
1
3
6
1.
2
4
1
FI
X
E
D

C
O
S
T
S
De
p
r
e
c
i
a
t
i
o
n
$1
,
7
2
9
$1
,
7
3
5
$1
,
8
4
6
$1
,
9
1
6
$7
,
2
2
6
$8
,
0
5
4
$7
,
2
6
9
$6
,
5
2
2
Mi
n
i
n
g

F
l
e
x
i
b
i
l
i
t
y
$1
5
1
$1
5
1
$1
5
1
$1
5
1
$6
0
5
$5
8
0
$6
2
9
$6
1
0
Pr
o
p
e
r
t
y

T
a
x
$1
1
6
$1
3
2
$1
1
6
$1
1
6
$4
8
0
$4
9
4
$5
0
9
$5
2
4
Pe
r
m
i
t
t
i
n
g

&

B
o
n
d
i
n
g
$2
7
9
$2
7
9
$2
7
9
$2
7
9
$1
,
1
1
8
$1
,
5
6
0
$1
,
5
6
3
$1
,
7
5
0
Ad
m
i
n
i
s
t
r
a
t
i
v
e

&

G
e
n
e
r
a
l

$2
,
0
6
2
$2
,
0
6
2
$2
,
0
6
2
$2
,
0
6
2
$8
,
2
4
8
$8
,
0
7
2
$8
,
7
5
4
$8
,
9
3
2
Le
a
s
e

R
e
n
t
s

&

R
e
c
o
r
d
s
$4
$2
2
$6
$6
0
$9
2
$9
4
$9
6
$9
7
Le
a
s
e
d

M
i
n
i
n
g

E
q
u
i
p
m
e
n
t
$
$
$
$
$
$
$
$
To
t
a
l

3
&
4

F
i
x
e
d

C
o
s
t
s
$4
,
3
4
1
$4
,
3
8
3
$4
,
4
6
0
$4
,
5
8
5
$1
7
,
7
6
9
$1
8
,
8
5
4
$1
8
,
8
2
1
$1
8
,
4
3
5
Pr
o
d
u
c
t
i
o
n

T
a
x
e
s

&

R
o
y
a
l
t
i
e
s
Pr
o
d
u
c
t
i
o
n

T
a
x
e
s
$8
8
6
$8
9
4
$9
1
0
$9
3
5
$3
,
6
2
5
$3
,
8
4
6
$3
,
8
3
9
$3
,
7
6
1
Ro
y
a
l
t
i
e
s

(
a
n
d

p
r
o
d

t
a
x

o
n

r
o
y
a
l
t
i
e
s
)
$8
3
6
$8
4
4
$8
5
9
$8
8
3
$3
,
4
2
3
$3
,
6
3
2
$3
,
6
2
6
$3
,
5
5
1
20
1
6
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
6

-

2
0
1
9

P
r
i
c
i
n
g

A
n
a
l
y
s
i
s
2015 AOP Final Version
Colstrip 3&4
4.7
1 of 2
ICNU_DR_183 Attachment A Page 27 of 54
1S
T

Q
T
R
2N
D

Q
T
R
3R
D

Q
T
R
4T
H

Q
T
R
TO
T
A
L
20
1
7
20
1
8
20
1
9
20
1
6
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
20
1
6

-

2
0
1
9

P
r
i
c
i
n
g

A
n
a
l
y
s
i
s
To
t
a
l

P
r
o
d
u
c
t
i
o
n

T
a
x
e
s

&

R
o
y
a
l
t
i
e
s
$1
,
7
2
2
$1
,
7
3
8
$1
,
7
6
9
$1
,
8
1
8
$7
,
0
4
8
$7
,
4
7
8
$7
,
4
6
5
$7
,
3
1
2
To
t
a
l

F
i
x
e
d

C
o
s
t
s
$6
,
0
6
3
$6
,
1
2
1
$6
,
2
2
9
$6
,
4
0
3
$2
4
,
8
1
7
$2
6
,
3
3
3
$2
6
,
2
8
6
$2
5
,
7
4
8
Fi
x
e
d

C
o
s
t

P
e
r

T
o
n
$3
.
2
0
$5
.
2
2
$3
.
3
1
$3
.
3
3
$3
.
6
1
$3
.
8
6
$3
.
5
9
$3
.
7
3
Fi
x
e
d

C
o
s
t

P
e
r

M
M

B
T
U
$0
.
1
9
0
$0
.
3
0
9
$0
.
1
9
6
$0
.
1
9
8
$0
.
2
1
4
$0
.
2
2
9
$0
.
2
1
3
$0
.
2
2
1
ST
A
T
I
S
T
I
C
A
L

&

M
I
S
C
.

I
N
F
O
R
M
A
T
I
O
N
To
t
a
l

A
r
e
a

C

T
o
n
s

S
o
l
d
1,
8
9
8
1,
1
7
3
1,
8
8
3
1,
9
2
5
6,
8
7
8
6,
8
2
0
7,
3
3
2
6,
9
0
9
BT
U
'
s
8,
3
9
9
8,
4
5
2
8,
4
4
9
8,
3
8
4
8,
4
1
7
8,
4
4
7
8,
4
3
1
8,
4
4
2
TO
T
A
L

C
O
S
T
S

W
/
O

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$4
1
,
1
2
1
$3
5
,
5
5
5
$4
1
,
3
3
9
$3
9
,
0
6
7
$1
5
7
,
0
8
2
$1
5
4
,
8
4
3
$1
6
6
,
7
4
7
$1
7
0
,
5
1
5
CO
S
T

P
E
R

T
O
N

W
/
O

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$2
1
.
6
7
$3
0
.
3
2
$2
1
.
9
5
$2
0
.
3
0
$2
2
.
8
4
$2
2
.
7
0
$2
2
.
7
4
$2
4
.
6
8
CO
S
T

P
E
R

M
M

B
T
U

W
/
O

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$1
.
2
9
0
$1
.
7
9
4
$1
.
2
9
9
$1
.
2
1
1
$1
.
3
5
7
$1
.
3
4
4
$1
.
3
4
9
$1
.
4
6
2
TR
A
N
S
P
O
R
T
A
T
I
O
N

C
O
S
T
S
$2
,
7
9
7
$1
,
7
2
8
$2
,
7
7
5
$2
,
8
3
6
$1
0
,
1
3
6
$1
0
,
0
1
0
$9
,
9
0
4
$9
,
5
7
1
TO
T
A
L

C
O
S
T
S

W
I
T
H

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$4
3
,
9
1
7
$3
7
,
2
8
3
$4
4
,
1
1
4
$4
1
,
9
0
3
$1
6
7
,
2
1
8
$1
6
4
,
8
5
3
$1
7
6
,
6
5
1
$1
8
0
,
0
8
6
CO
S
T

P
E
R

T
O
N

W
I
T
H

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$2
3
.
1
4
$3
1
.
7
9
$2
3
.
4
3
$2
1
.
7
7
$2
4
.
3
1
$2
4
.
1
7
$2
4
.
0
9
$2
6
.
0
7
CO
S
T

P
E
R

M
M

B
T
U

W
I
T
H

T
R
A
N
S
P
O
R
T
A
T
I
O
N
$1
.
3
7
8
$1
.
8
8
1
$1
.
3
8
6
$1
.
2
9
8
$1
.
4
4
4
$1
.
4
3
1
$1
.
4
2
9
$1
.
5
4
4
2015 AOP Final Version
Colstrip 3&4
4.7
2 of 2
ICNU_DR_183 Attachment A Page 28 of 54
We
s
t
m
o
r
e
l
a
n
d

C
o
a
l

C
o
m
p
a
n
y
Co
s
t

b
y

S
u
b

b
y

C
a
t
e
g
o
r
y

C
o
d
e

-
-

B
u
d
g
e
t
/
F
o
r
e
c
a
s
t
Ar
e
a

C
20
1
6

-

2
0
1
9
20
1
5

A
O
P

B
u
d
g
e
t
De
s
c
r
i
p
t
i
o
n
1s
t

Q
t
r
.

2
0
1
6
2n
d

Q
t
r
.

2
0
1
6
3r
d

Q
t
r
.

2
0
1
6
4t
h

Q
t
r
.

2
0
1
6
To
t
a
l

2
0
1
6
To
t
a
l

2
0
1
7
To
t
a
l

2
0
1
8
To
t
a
l

2
0
1
9
To
n
s

S
o
l
d
1,
8
9
7
,
7
0
0

1,
1
7
2
,
6
0
0

1,
8
8
3
,
0
0
0

1,
9
2
4
,
7
0
0

6,
8
7
8
,
0
0
0

6,
8
2
0
,
0
0
0

7,
3
3
2
,
0
0
0

6,
9
0
9
,
0
0
0

To
t
a
l

T
o
n
s

S
o
l
d
1,
8
9
7
,
7
0
0

1,
1
7
2
,
6
0
0

1,
8
8
3
,
0
0
0

1,
9
2
4
,
7
0
0

6,
8
7
8
,
0
0
0

6,
8
2
0
,
0
0
0

7,
3
3
2
,
0
0
0

6,
9
0
9
,
0
0
0

To
n
s

M
i
n
e
d
1,
8
9
7
,
7
0
0

1,
1
7
2
,
6
0
0

1,
8
8
3
,
0
0
0

1,
9
2
4
,
7
0
0

6,
8
7
8
,
0
0
0

6,
8
2
0
,
0
0
0

7,
3
3
2
,
0
0
0

6,
9
0
9
,
0
0
0

To
p
s
o
i
l

Y
a
r
d
s
15
2
,
5
0
0

38
9
,
1
0
0

32
3
,
0
0
0

21
9
,
5
0
0

1,
0
8
4
,
1
0
0

79
6
,
9
0
0

87
9
,
4
0
0

76
3
,
5
0
0

En
d

D
u
m
p

/

L
o
a
d
e
r

O
B

B
C
Y
1,
7
6
3
,
8
0
0

88
9
,
6
0
0

1,
2
2
6
,
3
0
0

1,
3
7
7
,
8
0
0

5,
2
5
7
,
5
0
0

4,
2
2
9
,
0
0
0

4,
9
1
8
,
8
0
0

6,
3
9
9
,
3
0
0

Do
z
e
r

O
B

B
C
Y
56
8
,
8
0
0

60
0
,
7
0
0

57
3
,
8
0
0

60
7
,
2
0
0

2,
3
5
0
,
5
0
0

2,
0
8
6
,
8
0
0

2,
1
7
7
,
3
0
0

2,
1
5
3
,
5
0
0

Dr
a
g
l
i
n
e

8
2
0
0

O
B

B
C
Y
3,
3
1
4
,
9
0
0

3,
5
2
3
,
8
0
0

3,
3
1
9
,
2
0
0

3,
5
9
1
,
5
0
0

13
,
7
4
9
,
4
0
0

12
,
7
1
2
,
4
0
0

13
,
2
7
9
,
6
0
0

13
,
1
3
6
,
6
0
0

Dr
a
g
l
i
n
e

8
0
5
0

O
B

B
C
Y
2,
3
9
0
,
1
0
0

2,
4
9
9
,
4
0
0

2,
4
3
5
,
0
0
0

2,
4
9
6
,
8
0
0

9,
8
2
1
,
3
0
0

8,
4
8
0
,
3
0
0

8,
9
0
5
,
1
0
0

8,
8
0
9
,
8
0
0

Ca
s
t

B
l
a
s
t

O
B

B
C
Y
5,
1
1
9
,
8
0
0

5,
4
0
6
,
1
0
0

5,
1
6
4
,
1
0
0

5,
4
6
4
,
8
0
0

21
,
1
5
4
,
8
0
0

18
,
7
8
0
,
6
0
0

19
,
5
9
5
,
4
0
0

19
,
3
8
0
,
9
0
0

To
t
a
l

O
B

B
C
Y
13
,
1
5
7
,
4
0
0

12
,
9
1
9
,
6
0
0

12
,
7
1
8
,
4
0
0

13
,
5
3
8
,
1
0
0

52
,
3
3
3
,
5
0
0

46
,
2
8
9
,
1
0
0

48
,
8
7
6
,
2
0
0

49
,
8
8
0
,
1
0
0

25
3
1
0

D
o
z
e
r
s

L
a
b
o
r
12
0
,
1
6
6

10
9
,
2
4
2

12
0
,
7
0
3

12
5
,
9
4
6

47
6
,
0
5
7

45
0
,
4
9
3

48
1
,
5
5
9

49
5
,
8
9
9

25
3
1
0

D
o
z
e
r
s

E
q
u
i
p
m
e
n
t
15
2
,
4
4
6

13
9
,
9
8
5

15
3
,
1
1
5

16
0
,
0
2
3

60
5
,
5
6
9

57
2
,
0
3
0

60
9
,
7
8
9

63
1
,
3
1
5

25
3
1
0

D
o
z
e
r
s

F
u
e
l
15
6
,
5
5
7

14
2
,
5
6
1

15
7
,
2
3
3

16
4
,
1
5
5

62
0
,
5
0
7

58
7
,
1
1
4

62
6
,
5
1
0

64
7
,
3
5
0

25
3
1
0

T
o
t
a
l

D
o
z
e
r
s
42
9
,
1
6
9

39
1
,
7
8
8

43
1
,
0
5
2

45
0
,
1
2
4

1,
7
0
2
,
1
3
3

1,
6
0
9
,
6
3
6

1,
7
1
7
,
8
5
7

1,
7
7
4
,
5
6
4

Do
z
e
r
s

C
o
s
t
s

/

D
o
z
e
r
s

B
C
Y
0.
7
5
0
0.
6
5
0
0.
7
5
0
0.
7
4
0
0.
7
2
4
0.
7
7
1
0.
7
8
9
0.
8
2
0
25
3
2
0

S
c
r
a
p
e
r
s
/
A
r
t
i
c
u
l
a
t
e
d

F
l
e
e
t

L
a
b
o
r
15
,
6
6
7

13
,
1
6
9

22
,
3
4
4

18
,
5
9
4

69
,
7
7
4

87
,
2
8
0

93
,
1
4
8

93
,
6
4
9

25
3
2
0

S
c
r
a
p
e
r
s
/
A
r
t
i
c
u
l
a
t
e
d

F
l
e
e
t

E
q
u
i
p
m
e
n
t
14
,
1
3
0

11
,
8
7
7

20
,
1
5
3

16
,
7
7
0

62
,
9
3
0

78
,
7
1
8

84
,
0
1
0

84
,
4
6
3

25
3
2
0

S
c
r
a
p
e
r
s
/
A
r
t
i
c
u
l
a
t
e
d

F
l
e
e
t

F
u
e
l
9,
4
9
4

7,
9
8
0

13
,
5
4
0

11
,
2
6
8

42
,
2
8
2

52
,
8
9
0

56
,
4
4
6

56
,
7
5
0

25
3
2
0

T
o
t
a
l

S
c
r
a
p
e
r
s
/
A
r
t
i
c
u
l
a
t
e
d

F
l
e
e
t
39
,
2
9
0

33
,
0
2
7

56
,
0
3
7

46
,
6
3
2

17
4
,
9
8
6

21
8
,
8
8
8

23
3
,
6
0
4

23
4
,
8
6
2

25
3
3
0

E
n
d

D
u
m
p
/
L
o
a
d
e
r

L
a
b
o
r
91
4
,
1
0
6

46
1
,
0
1
0

63
5
,
5
6
2

71
4
,
0
8
1

2,
7
2
4
,
7
6
0

2,
2
5
7
,
3
7
0

2,
7
0
4
,
4
0
5

3,
6
2
3
,
9
5
2

25
3
3
0

E
n
d

D
u
m
p
s
/
L
o
a
d
e
r

E
q
u
i
p
m
e
n
t
1,
5
9
0
,
3
6
0

80
2
,
0
6
6

1,
1
0
5
,
7
5
1

1,
2
4
2
,
3
5
8

4,
7
4
0
,
5
3
5

3,
9
2
7
,
3
7
1

4,
7
0
5
,
1
2
2

6,
3
0
4
,
9
4
9

25
3
3
0

E
n
d

D
u
m
p
s
/
L
o
a
d
e
r

F
u
e
l
81
9
,
2
5
0

41
3
,
1
7
2

56
9
,
6
1
1

63
9
,
9
8
2

2,
4
4
2
,
0
1
4

2,
0
2
3
,
1
2
5

2,
4
2
3
,
7
7
1

3,
2
4
7
,
8
9
8

25
3
3
0

T
o
t
a
l

E
n
d

D
u
m
p
s
/
L
o
a
d
e
r
3,
3
2
3
,
7
1
6

1,
6
7
6
,
2
4
8

2,
3
1
0
,
9
2
4

2,
5
9
6
,
4
2
1

9,
9
0
7
,
3
0
9

8,
2
0
7
,
8
6
7

9,
8
3
3
,
2
9
8

13
,
1
7
6
,
8
0
0

En
d

D
u
m
p
s

C
o
s
t
s
/
E
n
d

D
u
m
p
s

B
C
Y
1.
8
8
0
1.
8
8
0
1.
8
8
0
1.
8
8
0
1.
8
8
4
1.
9
4
1
1.
9
9
9
2.
0
6
0
25
4
0
0

D
r
a
g
l
i
n
e
s

L
a
b
o
r
66
7
,
3
3
0

68
5
,
7
1
0

66
6
,
8
5
7

70
3
,
5
1
6

2,
7
2
3
,
4
1
3

2,
5
4
9
,
2
8
8

2,
7
7
0
,
7
2
9

2,
7
0
8
,
9
7
2

25
4
0
0

D
r
a
g
l
i
n
e
s

E
q
u
i
p
m
e
n
t
1,
5
8
8
,
4
7
6

1,
6
3
5
,
5
0
2

1,
5
9
1
,
8
8
6

1,
6
7
3
,
9
8
9

6,
4
8
9
,
8
5
3

6,
0
5
7
,
2
4
2

6,
5
8
5
,
5
2
8

6,
4
3
7
,
3
1
5

25
4
0
0

D
r
a
g
l
i
n
e
s

F
u
e
l
20
8
,
6
4
8

21
4
,
3
7
0

20
8
,
5
0
1

21
9
,
9
1
3

85
1
,
4
3
1

79
7
,
3
3
1

86
6
,
3
8
0

84
7
,
2
6
9

25
4
0
0

D
r
a
g
l
i
n
e
s

E
l
e
c
t
r
i
c
i
t
y
56
0
,
1
5
3

57
4
,
6
2
4

55
8
,
1
9
9

59
1
,
0
6
5

2,
2
8
4
,
0
4
1

2,
1
4
1
,
8
1
2

2,
3
2
8
,
5
3
0

2,
2
7
5
,
7
9
1

25
4
0
0

D
r
a
g
l
i
n
e
s

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
6,
1
8
0

6,
1
8
0

6,
1
8
0

6,
1
8
0

24
,
7
2
0

33
,
9
4
9

10
4
,
9
0
2

10
8
,
0
4
9

25
4
0
0

D
r
a
g
l
i
n
e
s

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
57
,
0
4
2

57
,
0
4
2

57
,
0
4
2

57
,
0
4
2

22
8
,
1
6
7

23
5
,
0
1
2

24
2
,
0
6
3

24
9
,
3
2
5

25
4
0
0

T
o
t
a
l

D
r
a
g
l
i
n
e
s
3,
0
8
7
,
8
2
8

3,
1
7
3
,
4
2
8

3,
0
8
8
,
6
6
5

3,
2
5
1
,
7
0
6

12
,
6
0
1
,
6
2
6

11
,
8
1
4
,
6
3
4

12
,
8
9
8
,
1
3
1

12
,
6
2
6
,
7
2
0

Dr
a
g
l
i
n
e
s

C
o
s
t
s

/

D
r
a
g
l
i
n
e

B
C
Y
0.
5
4
0
0.
5
3
0
0.
5
4
0
0.
5
3
0
0.
5
3
5
0.
5
5
7
0.
5
8
1
0.
5
8
0
25
7
1
0

P
i
t

D
e
w
a
t
e
r
i
n
g

L
a
b
o
r
18
7
,
1
6
3

18
7
,
1
6
3

18
8
,
7
7
3

18
8
,
7
7
3

75
1
,
8
7
2

77
3
,
1
7
2

79
6
,
3
6
7

82
0
,
2
5
8

25
7
1
0

P
i
t

D
e
w
a
t
e
r
i
n
g

E
q
u
i
p
m
e
n
t
12
,
3
2
1

12
,
3
2
1

12
,
3
2
1

12
,
3
2
1

49
,
2
8
3

50
,
7
6
2

52
,
2
8
4

53
,
8
5
3

25
7
1
0

P
i
t

D
e
w
a
t
e
r
i
n
g

F
u
e
l
14
,
8
6
2

14
,
8
6
2

14
,
8
6
2

14
,
8
6
2

59
,
4
4
7

61
,
2
3
0

63
,
0
6
7

64
,
9
5
9

25
7
1
0

P
i
t

D
e
w
a
t
e
r
i
n
g

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
9,
7
7
3

6,
0
3
9

9,
6
9
7

9,
9
1
2

35
,
4
2
2

36
,
1
7
7

40
,
0
5
9

38
,
8
8
1

25
7
1
0

T
o
t
a
l

P
i
t

D
e
w
a
t
e
r
i
n
g
22
4
,
1
1
8

22
0
,
3
8
4

22
5
,
6
5
3

22
5
,
8
6
8

89
6
,
0
2
3

92
1
,
3
4
0

95
1
,
7
7
8

97
7
,
9
5
0

Pi
t

D
e
w
a
t
e
r
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
1
2
0
0.
1
9
0
0.
1
2
0
0.
1
2
0
0.
1
3
0
0.
1
3
5
0.
1
3
0
0.
1
4
0
25
8
0
0

D
r
i
l
l

B
l
a
s
t

L
a
b
o
r
31
0
,
2
0
6

31
6
,
2
1
9

30
7
,
7
2
7

32
2
,
4
2
3

1,
2
5
6
,
5
7
4

1,
1
7
8
,
9
8
2

1,
2
5
7
,
1
7
0

1,
2
9
6
,
6
4
7

2015 AOP Final Version
Colstrip 3&4
4.8
1 of 5
ICNU_DR_183 Attachment A Page 29 of 54
We
s
t
m
o
r
e
l
a
n
d

C
o
a
l

C
o
m
p
a
n
y
Co
s
t

b
y

S
u
b

b
y

C
a
t
e
g
o
r
y

C
o
d
e

-
-

B
u
d
g
e
t
/
F
o
r
e
c
a
s
t
Ar
e
a

C
20
1
6

-

2
0
1
9
20
1
5

A
O
P

B
u
d
g
e
t
De
s
c
r
i
p
t
i
o
n
1s
t

Q
t
r
.

2
0
1
6
2n
d

Q
t
r
.

2
0
1
6
3r
d

Q
t
r
.

2
0
1
6
4t
h

Q
t
r
.

2
0
1
6
To
t
a
l

2
0
1
6
To
t
a
l

2
0
1
7
To
t
a
l

2
0
1
8
To
t
a
l

2
0
1
9
25
8
0
0

D
r
i
l
l

B
l
a
s
t

E
q
u
i
p
m
e
n
t
34
3
,
1
7
2

35
4
,
3
5
6

34
1
,
3
2
1

36
1
,
4
5
6

1,
4
0
0
,
3
0
5

1,
2
8
3
,
0
7
2

1,
3
7
8
,
8
7
3

1,
4
1
7
,
5
2
1

25
8
0
0

D
r
i
l
l

B
l
a
s
t

F
u
e
l
27
3
,
4
7
8

28
1
,
6
4
9

27
1
,
4
8
6

28
7
,
8
6
6

1,
1
1
4
,
4
7
9

1,
0
1
8
,
2
6
7

1,
0
9
5
,
8
6
6

1,
1
2
8
,
1
4
7

25
8
0
0

D
r
i
l
l

B
l
a
s
t

E
x
p
l
o
s
i
v
e
s
3,
7
2
1
,
9
6
3

3,
7
6
6
,
5
8
7

3,
6
6
5
,
0
0
8

3,
8
8
9
,
1
1
6

15
,
0
4
2
,
6
7
3

13
,
7
6
9
,
3
8
9

14
,
9
0
8
,
1
5
6

15
,
4
6
6
,
0
6
8

25
8
0
0

T
o
t
a
l

D
r
i
l
l

B
l
a
s
t
4,
6
4
8
,
8
1
8

4,
7
1
8
,
8
1
1

4,
5
8
5
,
5
4
1

4,
8
6
0
,
8
6
1

18
,
8
1
4
,
0
3
1

17
,
2
4
9
,
7
0
9

18
,
6
4
0
,
0
6
5

19
,
3
0
8
,
3
8
3

Dr
i
l
l

&

B
l
a
s
t

/

T
o
t
a
l

C
a
s
t

B
l
a
s
t
0.
9
1
0
0.
8
7
0
0.
8
9
0
0.
8
9
0
0.
8
8
9
0.
9
1
8
0.
9
5
1
1.
0
0
0
To
t
a
l

O
v
e
r
b
u
r
d
e
n
11
,
7
5
2
,
9
4
0

10
,
2
1
3
,
6
8
5

10
,
6
9
7
,
8
7
1

11
,
4
3
1
,
6
1
2

44
,
0
9
6
,
1
0
8

40
,
0
2
2
,
0
7
4

44
,
2
7
4
,
7
3
4

48
,
0
9
9
,
2
8
0

To
t
a
l

O
v
e
r
b
u
r
d
e
n

/

T
o
t
a
l

B
C
Y
0.
8
9
0
0.
7
9
0
0.
8
4
0
0.
8
4
0
0.
8
4
3
0.
8
6
5
0.
9
0
6
0.
9
6
0
35
1
0
0

T
e
s
t
/
A
n
a
l
y
s
i
s

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
11
,
7
2
8

7,
2
4
7

11
,
6
3
7

11
,
8
9
5

42
,
5
0
6

43
,
4
1
2

48
,
0
7
1

46
,
6
5
7

35
1
0
0

T
o
t
a
l

T
e
s
t
/
A
n
a
l
y
s
i
s
11
,
7
2
8

7,
2
4
7

11
,
6
3
7

11
,
8
9
5

42
,
5
0
6

43
,
4
1
2

48
,
0
7
1

46
,
6
5
7

Te
s
t
/
A
n
a
l
y
s
i
s

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
0
1
0
0.
0
1
0
0.
0
1
0
0.
0
1
0
0.
0
0
6
0.
0
0
6
0.
0
0
7
0.
0
1
0
35
2
0
0

C
o
a
l

C
l
e
a
n

L
a
b
o
r
69
,
9
6
5

66
,
5
7
8

69
,
8
5
9

71
,
2
9
5

27
7
,
6
9
7

24
4
,
8
1
0

25
9
,
3
9
9

26
0
,
9
8
2

35
2
0
0

C
o
a
l

C
l
e
a
n

E
q
u
i
p
m
e
n
t
63
,
5
5
9

57
,
9
3
4

63
,
3
8
3

65
,
6
5
3

25
0
,
5
2
9

23
2
,
0
3
8

25
0
,
5
7
2

24
8
,
1
9
3

35
2
0
0

C
o
a
l

C
l
e
a
n

F
u
e
l
49
,
8
6
5

42
,
9
4
5

49
,
6
8
7

51
,
2
1
7

19
3
,
7
1
5

18
1
,
1
8
9

19
6
,
0
1
3

19
3
,
8
6
8

35
2
0
0

T
o
t
a
l

C
o
a
l

C
l
e
a
n
i
n
g
18
3
,
3
9
0

16
7
,
4
5
8

18
2
,
9
2
9

18
8
,
1
6
5

72
1
,
9
4
1

65
8
,
0
3
7

70
5
,
9
8
5

70
3
,
0
4
2

Co
a
l

C
l
e
a
n
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
1
0
0
0.
1
4
0
0.
1
0
0
0.
1
0
0
0.
1
0
5
0.
0
9
6
0.
0
9
6
0.
1
0
0
35
3
0
0

C
o
a
l

D
r
i
l
l

B
l
a
s
t

L
a
b
o
r
64
,
7
0
1

61
,
6
9
6

68
,
0
4
8

66
,
1
8
3

26
0
,
6
2
9

27
6
,
7
9
4

28
7
,
4
9
1

24
2
,
3
5
5

35
3
0
0

C
o
a
l

D
r
i
l
l

B
l
a
s
t

E
q
u
i
p
m
e
n
t
23
,
5
1
7

15
,
2
1
3

24
,
4
1
7

24
,
2
5
2

87
,
3
9
8

91
,
6
4
7

10
0
,
7
1
7

83
,
6
7
5

35
3
0
0

C
o
a
l

D
r
i
l
l

B
l
a
s
t

F
u
e
l
10
,
7
7
2

6,
9
9
2

11
,
1
8
1

11
,
1
0
6

40
,
0
5
0

41
,
9
9
3

46
,
1
2
9

38
,
3
8
1

35
3
0
0

C
o
a
l

D
r
i
l
l

B
l
a
s
t

M
a
t
e
r
i
a
l

&

S
u
p
p
l
i
e
s
46
4

46
4

46
4

46
4

1,
8
5
4

2,
5
4
6

1,
9
6
7

2,
0
2
6

35
3
0
0

C
o
a
l

D
r
i
l
l

B
l
a
s
t

E
x
p
l
o
s
i
v
e
s
33
6
,
1
3
0

20
9
,
1
7
2

33
6
,
2
4
3

34
1
,
9
2
7

1,
2
2
3
,
4
7
1

1,
2
5
5
,
5
3
2

1,
3
8
8
,
5
5
4

1,
3
1
2
,
1
1
2

35
3
0
0

T
o
t
a
l

C
o
a
l

D
r
i
l
l

B
l
a
s
t
43
5
,
5
8
4

29
3
,
5
3
6

44
0
,
3
5
2

44
3
,
9
3
1

1,
6
1
3
,
4
0
2

1,
6
6
8
,
5
1
1

1,
8
2
4
,
8
5
8

1,
6
7
8
,
5
4
9

Co
a
l

D
r
i
l
l

B
l
a
s
t

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
2
3
0
0.
2
5
0
0.
2
3
0
0.
2
3
0
0.
2
3
5
0.
2
4
5
0.
2
4
9
0.
2
4
0
35
4
0
0

L
o
a
d
i
n
g

L
a
b
o
r
16
0
,
3
2
7

10
1
,
1
4
1

15
9
,
3
4
6

16
2
,
6
6
2

58
3
,
4
7
5

59
6
,
5
9
7

65
0
,
8
6
6

63
0
,
4
8
3

35
4
0
0

L
o
a
d
i
n
g

E
q
u
i
p
m
e
n
t
30
4
,
3
6
7

19
0
,
0
8
5

30
2
,
2
9
9

30
8
,
7
6
3

1,
1
0
5
,
5
1
6

1,
1
2
9
,
9
5
0

1,
2
4
0
,
2
5
6

1,
2
0
2
,
1
1
6

35
4
0
0

L
o
a
d
i
n
g

F
u
e
l
23
0
,
5
6
3

14
4
,
2
9
0

22
9
,
2
1
8

23
3
,
9
0
7

83
7
,
9
7
8

85
6
,
8
5
9

93
3
,
1
9
7

90
2
,
4
4
8

35
4
0
0

T
o
t
a
l

L
o
a
d
i
n
g
69
5
,
2
5
7

43
5
,
5
1
6

69
0
,
8
6
3

70
5
,
3
3
2

2,
5
2
6
,
9
6
9

2,
5
8
3
,
4
0
6

2,
8
2
4
,
3
2
0

2,
7
3
5
,
0
4
6

Lo
a
d
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
3
7
0
0.
3
7
0
0.
3
7
0
0.
3
7
0
0.
3
6
7
0.
3
7
9
0.
3
8
5
0.
4
0
0
35
5
0
0

H
a
u
l
i
n
g

L
a
b
o
r
30
0
,
2
5
3

20
5
,
0
7
6

29
6
,
6
5
0

32
0
,
2
6
9

1,
1
2
2
,
2
4
7

1,
1
4
9
,
1
5
0

1,
3
6
1
,
9
4
5

1,
2
8
7
,
6
3
2

35
5
0
0

H
a
u
l
i
n
g

E
q
u
i
p
m
e
n
t
84
9
,
9
1
9

58
0
,
5
1
8

83
9
,
6
9
2

90
6
,
5
8
9

3,
1
7
6
,
7
1
7

3,
2
5
9
,
7
6
1

3,
8
7
5
,
1
7
8

3,
6
5
9
,
8
9
5

35
5
0
0

H
a
u
l
i
n
g

F
u
e
l
59
3
,
8
3
2

40
5
,
5
7
9

58
6
,
7
4
1

63
3
,
4
0
3

2,
2
1
9
,
5
5
5

2,
2
6
3
,
9
4
8

2,
6
6
8
,
0
9
7

2,
5
2
7
,
4
2
5

35
5
0
0

H
a
u
l
i
n
g

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
4,
6
3
5

4,
6
3
5

4,
6
3
5

4,
6
3
5

18
,
5
4
0

7,
6
3
8

7,
8
6
8

8,
1
0
4

35
5
0
0

T
o
t
a
l

H
a
u
l
a
g
e
1,
7
4
8
,
6
3
9

1,
1
9
5
,
8
0
8

1,
7
2
7
,
7
1
7

1,
8
6
4
,
8
9
6

6,
5
3
7
,
0
6
0

6,
6
8
0
,
4
9
7

7,
9
1
3
,
0
8
7

7,
4
8
3
,
0
5
5

Co
a
l

H
a
u
l
a
g
e

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
9
2
0
1.
0
2
0
0.
9
2
0
0.
9
7
0
0.
9
5
0
0.
9
8
0
1.
0
7
9
1.
0
8
0
35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

L
a
b
o
r
27
4
,
4
2
5

27
4
,
4
2
5

27
4
,
4
2
5

27
4
,
4
2
5

1,
0
9
7
,
6
9
9

1,
1
3
2
,
1
0
8

1,
1
6
6
,
0
7
1

1,
2
0
1
,
0
5
3

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

E
q
u
i
p
m
e
n
t
15
5
,
1
6
0

15
5
,
1
6
0

15
5
,
1
6
0

15
5
,
1
6
0

62
0
,
6
4
0

64
0
,
7
5
8

65
9
,
9
8
1

67
9
,
7
8
0

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

F
u
e
l
77
,
9
2
5

77
,
9
2
5

77
,
9
2
5

77
,
9
2
5

31
1
,
6
9
9

32
2
,
2
8
4

33
1
,
9
5
3

34
1
,
9
1
2

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

E
l
e
c
t
r
i
c
i
t
y
61
,
4
9
6

61
,
4
9
6

61
,
4
9
6

61
,
4
9
6

24
5
,
9
8
4

25
3
,
3
6
3

26
0
,
9
6
4

26
8
,
7
9
3

2015 AOP Final Version
Colstrip 3&4
4.8
2 of 5
ICNU_DR_183 Attachment A Page 30 of 54
We
s
t
m
o
r
e
l
a
n
d

C
o
a
l

C
o
m
p
a
n
y
Co
s
t

b
y

S
u
b

b
y

C
a
t
e
g
o
r
y

C
o
d
e

-
-

B
u
d
g
e
t
/
F
o
r
e
c
a
s
t
Ar
e
a

C
20
1
6

-

2
0
1
9
20
1
5

A
O
P

B
u
d
g
e
t
De
s
c
r
i
p
t
i
o
n
1s
t

Q
t
r
.

2
0
1
6
2n
d

Q
t
r
.

2
0
1
6
3r
d

Q
t
r
.

2
0
1
6
4t
h

Q
t
r
.

2
0
1
6
To
t
a
l

2
0
1
6
To
t
a
l

2
0
1
7
To
t
a
l

2
0
1
8
To
t
a
l

2
0
1
9
35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
1,
5
8
1

1,
5
8
1

1,
5
8
1

1,
5
8
1

6,
3
2
5

6,
5
1
4

6,
7
1
0

6,
9
1
1

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
92
9

92
9

92
9

92
9

3,
7
1
7

3,
8
2
8

3,
9
4
3

4,
0
6
1

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
87
1

87
1

87
1

87
1

3,
4
8
4

3,
5
8
9

3,
6
9
6

3,
8
0
7

35
6
0
0

T
o
t
a
l

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g
57
2
,
3
8
7

57
2
,
3
8
7

57
2
,
3
8
7

57
2
,
3
8
7

2,
2
8
9
,
5
4
7

2,
3
6
2
,
4
4
5

2,
4
3
3
,
3
1
8

2,
5
0
6
,
3
1
8

Cr
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
3
0
0
0.
4
9
0
0.
3
0
0
0.
3
0
0
0.
3
3
3
0.
3
4
6
0.
3
3
2
0.
3
6
0
To
t
a
l

C
o
a
l

H
a
n
d
l
i
n
g
3,
6
4
6
,
9
8
4

2,
6
7
1
,
9
5
1

3,
6
2
5
,
8
8
4

3,
7
8
6
,
6
0
6

13
,
7
3
1
,
4
2
5

13
,
9
9
6
,
3
0
7

15
,
7
4
9
,
6
3
9

15
,
1
5
2
,
6
6
7

To
t
a
l

C
o
a
l

H
a
n
d
l
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
1.
9
2
0
2.
2
8
0
1.
9
3
0
1.
9
7
0
1.
9
9
6
2.
0
5
2
2.
1
4
8
2.
1
9
0
40
0
0
0

R
o
a
d
s

L
a
b
o
r
24
4
,
1
7
6

22
6
,
2
3
7

42
8
,
2
3
2

30
2
,
0
5
1

1,
2
0
0
,
6
9
5

1,
2
2
1
,
5
4
1

1,
3
6
1
,
2
6
0

1,
3
1
7
,
0
2
7

40
0
0
0

R
o
a
d
s

E
q
u
i
p
m
e
n
t
28
5
,
3
4
9

28
5
,
1
2
3

51
7
,
7
6
3

35
5
,
1
2
1

1,
4
4
3
,
3
5
6

1,
4
7
2
,
3
6
4

1,
6
3
0
,
0
3
4

1,
5
8
6
,
7
8
0

40
0
0
0

R
o
a
d
s

F
u
e
l
13
5
,
8
5
9

15
4
,
5
6
4

29
8
,
2
2
8

18
5
,
1
7
4

77
3
,
8
2
5

78
7
,
8
2
9

87
6
,
7
1
3

85
0
,
3
4
8

40
0
0
0

R
o
a
d
s

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
15
6
,
0
0
5

15
6
,
0
0
5

15
6
,
0
0
5

15
6
,
0
0
5

62
4
,
0
2
2

64
2
,
7
4
2

70
7
,
9
1
9

53
6
,
8
2
4

40
0
0
0

T
o
t
a
l

R
o
a
d
s
82
1
,
3
8
9

82
1
,
9
2
9

1,
4
0
0
,
2
2
9

99
8
,
3
5
1

4,
0
4
1
,
8
9
8

4,
1
2
4
,
4
7
7

4,
5
7
5
,
9
2
7

4,
2
9
0
,
9
7
9

Ro
a
d
s

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
4
3
0
0.
7
0
0
0.
7
4
0
0.
5
2
0
0.
5
8
8
0.
6
0
5
0.
6
2
4
0.
6
2
0
45
0
0
0

P
r
o
d
u
c
t
i
o
n

S
a
l
a
r
y

L
a
b
o
r
30
0
,
7
8
5

30
0
,
7
8
5

30
0
,
7
8
5

30
0
,
7
8
5

1,
2
0
3
,
1
4
2

1,
2
3
9
,
2
3
6

1,
2
7
6
,
4
1
3

1,
3
1
4
,
7
0
5

45
0
0
0

P
r
o
d
u
c
t
i
o
n

E
q
u
i
p
m
e
n
t
14
8
,
9
8
6

14
8
,
9
8
6

14
8
,
9
8
6

14
8
,
9
8
6

59
5
,
9
4
3

61
3
,
8
2
1

63
2
,
2
3
6

65
1
,
2
0
3

45
0
0
0

P
r
o
d
u
c
t
i
o
n

F
u
e
l
28
,
3
3
6

28
,
3
3
6

28
,
3
3
6

28
,
3
3
6

11
3
,
3
4
5

11
6
,
7
4
5

12
0
,
2
4
8

12
3
,
8
5
5

45
0
0
0

P
r
o
d
u
c
t
i
o
n

O
t
h
e
r
1,
7
2
5

1,
7
2
5

1,
7
2
5

1,
7
2
5

6,
9
0
0

7,
1
0
7

7,
3
2
1

7,
5
4
0

45
0
0
0

P
r
o
d
u
c
t
i
o
n

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
54
5
,
0
2
0

54
5
,
0
2
0

54
5
,
0
2
0

54
5
,
0
2
0

2,
1
8
0
,
0
7
9

2,
3
2
2
,
0
3
0

2,
3
9
1
,
6
9
1

2,
4
6
3
,
4
4
2

45
0
0
0

T
o
t
a
l

P
r
o
d
u
c
t
i
o
n
1,
0
2
4
,
8
5
2

1,
0
2
4
,
8
5
2

1,
0
2
4
,
8
5
2

1,
0
2
4
,
8
5
2

4,
0
9
9
,
4
0
9

4,
2
9
8
,
9
4
0

4,
4
2
7
,
9
0
8

4,
5
6
0
,
7
4
5

To
t
a
l

O
t
h
e
r

P
r
o
d
u
c
t
i
o
n
1,
8
4
6
,
2
4
1

1,
8
4
6
,
7
8
2

2,
4
2
5
,
0
8
1

2,
0
2
3
,
2
0
4

8,
1
4
1
,
3
0
7

8,
4
2
3
,
4
1
6

9,
0
0
3
,
8
3
5

8,
8
5
1
,
7
2
4

55
1
0
0

C
u
r
r
e
n
t

R
e
c
.

E
n
g
i
n
e
e
r
i
n
g

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
18
2
,
1
7
9

11
2
,
5
7
0

18
0
,
7
6
8

18
4
,
7
7
1

66
0
,
2
8
8

65
4
,
7
2
0

70
3
,
8
7
2

66
3
,
2
6
4

55
1
0
0

T
o
t
a
l

C
u
r
r
e
n
t

R
e
c
l
a
m
a
t
i
o
n

E
n
g
i
n
e
e
r
i
n
g
18
2
,
1
7
9

11
2
,
5
7
0

18
0
,
7
6
8

18
4
,
7
7
1

66
0
,
2
8
8

65
4
,
7
2
0

70
3
,
8
7
2

66
3
,
2
6
4

Cu
r
r
e
n
t

R
e
c
l
a
m
a
t
i
o
n

E
n
g
i
n
e
e
r
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
1
0
0
0.
1
0
0
0.
1
0
0
0.
1
0
0
0.
0
9
6
0.
0
9
6
0.
0
9
6
0.
1
0
0
55
2
0
0

R
e
g
r
a
d
i
n
g

L
a
b
o
r
31
5
,
1
3
4

32
7
,
3
1
4

31
5
,
4
8
0

32
7
,
6
2
8

1,
2
8
5
,
5
5
6

1,
6
5
3
,
8
8
6

1,
8
2
7
,
1
3
6

1,
9
0
1
,
0
7
4

55
2
0
0

R
e
g
r
a
d
i
n
g

E
q
u
i
p
m
e
n
t
37
0
,
3
8
7

38
7
,
5
7
3

37
0
,
8
7
4

38
8
,
0
1
6

1,
5
1
6
,
8
5
0

1,
8
4
1
,
1
4
7

2,
0
2
0
,
8
7
2

2,
0
8
5
,
5
4
3

55
2
0
0

R
e
g
r
a
d
i
n
g

F
u
e
l
31
7
,
6
0
9

33
4
,
6
4
4

31
8
,
0
9
2

33
5
,
0
8
4

1,
3
0
5
,
4
3
0

1,
5
2
9
,
1
2
0

1,
6
5
9
,
8
9
9

1,
7
0
3
,
7
1
7

55
2
0
0

T
o
t
a
l

R
e
g
r
a
d
i
n
g
1,
0
0
3
,
1
3
0

1,
0
4
9
,
5
3
1

1,
0
0
4
,
4
4
7

1,
0
5
0
,
7
2
9

4,
1
0
7
,
8
3
6

5,
0
2
4
,
1
5
3

5,
5
0
7
,
9
0
7

5,
6
9
0
,
3
3
4

Re
g
r
a
d
i
n
g

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
5
3
0
0.
9
0
0
0.
5
3
0
0.
5
5
0
0.
5
9
7
0.
7
3
7
0.
7
5
1
0.
8
2
0
55
2
1
0

T
o
p
s
o
i
l

L
a
b
o
r
14
7
,
5
3
4

29
8
,
2
4
6

25
3
,
7
6
2

19
2
,
7
6
5

89
2
,
3
0
7

78
6
,
7
2
9

87
6
,
3
6
7

81
3
,
4
2
1

55
2
1
0

T
o
p
s
o
i
l

E
q
u
i
p
m
e
n
t
11
5
,
7
8
0

26
5
,
9
7
3

22
3
,
5
4
6

15
8
,
8
1
2

76
4
,
1
1
1

63
5
,
2
0
7

71
1
,
8
4
2

65
1
,
1
2
1

55
2
1
0

T
o
p
s
o
i
l

F
u
e
l
76
,
9
4
4

20
2
,
7
4
0

16
8
,
5
5
1

11
1
,
5
4
1

55
9
,
7
7
6

44
1
,
0
0
8

49
6
,
6
4
1

44
7
,
6
4
6

55
2
1
0

T
o
t
a
l

T
o
p
s
o
i
l
34
0
,
2
5
8

76
6
,
9
5
9

64
5
,
8
6
0

46
3
,
1
1
8

2,
2
1
6
,
1
9
5

1,
8
6
2
,
9
4
5

2,
0
8
4
,
8
5
0

1,
9
1
2
,
1
8
8

To
p
s
o
i
l
i
n
g

/

T
o
t
a
l

T
o
p
s
o
i
l

Y
a
r
d
s
2.
2
3
0
1.
9
7
0
2.
0
0
0
2.
1
1
0
2.
0
4
4
2.
3
3
8
2.
3
7
1
2.
5
0
0
55
3
0
0

R
e
v
e
g
e
t
a
t
i
o
n

L
a
b
o
r
26
,
9
8
2

97
,
3
4
3

10
6
,
6
1
2

51
,
7
4
8

28
2
,
6
8
5

21
9
,
3
4
8

21
5
,
0
0
4

21
7
,
4
1
2

55
3
0
0

R
e
v
e
g
e
t
a
t
i
o
n

E
q
u
i
p
m
e
n
t
-
24
,
3
9
4

41
,
0
0
5

11
,
8
3
0

77
,
2
3
0

62
,
0
8
7

53
,
7
1
4

51
,
5
3
9

55
3
0
0

R
e
v
e
g
e
t
a
t
i
o
n

F
u
e
l
-
1,
7
1
9

2,
8
9
0

83
4

5,
4
4
3

4,
3
7
6

3,
7
8
6

3,
6
3
2

2015 AOP Final Version
Colstrip 3&4
4.8
3 of 5
ICNU_DR_183 Attachment A Page 31 of 54
We
s
t
m
o
r
e
l
a
n
d

C
o
a
l

C
o
m
p
a
n
y
Co
s
t

b
y

S
u
b

b
y

C
a
t
e
g
o
r
y

C
o
d
e

-
-

B
u
d
g
e
t
/
F
o
r
e
c
a
s
t
Ar
e
a

C
20
1
6

-

2
0
1
9
20
1
5

A
O
P

B
u
d
g
e
t
De
s
c
r
i
p
t
i
o
n
1s
t

Q
t
r
.

2
0
1
6
2n
d

Q
t
r
.

2
0
1
6
3r
d

Q
t
r
.

2
0
1
6
4t
h

Q
t
r
.

2
0
1
6
To
t
a
l

2
0
1
6
To
t
a
l

2
0
1
7
To
t
a
l

2
0
1
8
To
t
a
l

2
0
1
9
55
3
0
0

R
e
v
e
g
e
t
a
t
i
o
n

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
17
,
9
7
1

17
,
9
7
1

17
,
9
7
1

17
,
9
7
1

71
,
8
8
5

74
,
0
4
2

76
,
2
6
3

78
,
5
5
1

55
3
0
0

R
e
v
e
g
e
t
a
t
i
o
n

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
11
,
8
4
2

20
,
5
8
9

46
,
4
5
1

9,
9
8
5

88
,
8
6
7

64
,
3
5
6

52
,
5
2
4

49
,
3
5
1

55
3
0
0

T
o
t
a
l

R
e
v
e
g
e
t
a
t
i
o
n
56
,
7
9
5

16
2
,
0
1
7

21
4
,
9
2
9

92
,
3
6
8

52
6
,
1
0
9

42
4
,
2
0
8

40
1
,
2
9
2

40
0
,
4
8
5

Re
v
e
g
e
t
a
t
i
o
n

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
0
3
0
0.
1
4
0
0.
1
1
0
0.
0
5
0
0.
0
7
6
0.
0
6
2
0.
0
5
5
0.
0
6
0
To
t
a
l

C
u
r
r
e
n
t

R
e
c
l
a
m
a
t
i
o
n
1,
5
8
2
,
3
6
2

2,
0
9
1
,
0
7
7

2,
0
4
6
,
0
0
4

1,
7
9
0
,
9
8
6

7,
5
1
0
,
4
2
8

7,
9
6
6
,
0
2
5

8,
6
9
7
,
9
2
1

8,
6
6
6
,
2
7
1

To
t
a
l

C
u
r
r
e
n
t

R
e
c
l
a
m
a
t
i
o
n

/

T
o
t
a
l

T
o
n
s

M
i
n
e
d
0.
9
8
0
2.
0
2
0
1.
2
3
0
1.
0
8
0
1.
0
9
2
1.
1
6
8
1.
4
0
0
1.
5
1
0
60
0
5
0

S
a
f
e
t
y

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
25
,
7
5
0

25
,
7
5
0

25
,
7
5
0

25
,
7
5
0

10
3
,
0
0
0

10
6
,
0
9
0

10
9
,
2
7
3

11
2
,
5
5
1

60
0
5
0

S
a
f
e
t
y

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
20
9
,
0
4
6

20
9
,
0
4
6

20
9
,
0
4
6

20
9
,
0
4
6

83
6
,
1
8
3

86
1
,
2
6
9

88
7
,
1
0
7

91
3
,
7
2
0

60
0
5
0

T
o
t
a
l

S
a
f
e
t
y
23
4
,
7
9
6

23
4
,
7
9
6

23
4
,
7
9
6

23
4
,
7
9
6

93
9
,
1
8
3

96
7
,
3
5
9

99
6
,
3
8
0

1,
0
2
6
,
2
7
1

60
1
0
0

T
r
a
i
n
/
I
n
s
p
e
c
t

L
a
b
o
r
22
8
,
9
7
6

22
8
,
9
7
6

22
8
,
9
7
6

22
8
,
9
7
6

91
5
,
9
0
4

94
3
,
3
8
1

97
1
,
6
8
2

1,
0
0
0
,
8
3
3

60
1
0
0

T
r
a
i
n
/
I
n
s
p
e
c
t

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
80
,
4
8
7

80
,
4
8
7

80
,
4
8
7

80
,
4
8
7

32
1
,
9
4
7

33
1
,
6
0
5

34
1
,
5
5
3

35
1
,
8
0
0

60
1
0
0

T
o
t
a
l

T
r
a
i
n
/
I
n
s
p
e
c
t
30
9
,
4
6
3

30
9
,
4
6
3

30
9
,
4
6
3

30
9
,
4
6
3

1,
2
3
7
,
8
5
0

1,
2
7
4
,
9
8
6

1,
3
1
3
,
2
3
5

1,
3
5
2
,
6
3
2

65
2
0
0

W
a
r
e
h
o
u
s
e

L
a
b
o
r
12
3
,
0
8
0

12
3
,
0
8
0

12
3
,
0
8
0

12
3
,
0
8
0

49
2
,
3
2
1

50
7
,
0
9
1

52
2
,
3
0
3

53
7
,
9
7
3

65
2
0
0

W
a
r
e
h
o
u
s
e

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
2,
7
0
4

2,
7
0
4

2,
7
0
4

2,
7
0
4

10
,
8
1
5

11
,
1
3
9

11
,
4
7
4

11
,
8
1
8

65
2
0
0

W
a
r
e
h
o
u
s
e

O
t
h
e
r
7,
7
2
5

7,
7
2
5

7,
7
2
5

7,
7
2
5

30
,
9
0
0

31
,
8
2
7

32
,
7
8
2

33
,
7
6
5

65
2
0
0

W
a
r
e
h
o
u
s
e

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
26
1
,
8
4
9

26
1
,
8
4
9

26
1
,
8
4
9

26
1
,
8
4
9

1,
0
4
7
,
3
9
6

1,
0
7
8
,
8
1
8

1,
1
1
1
,
1
8
3

1,
1
4
4
,
5
1
8

65
2
0
0

T
o
t
a
l

W
a
r
e
h
o
u
s
e
39
5
,
3
5
8

39
5
,
3
5
8

39
5
,
3
5
8

39
5
,
3
5
8

1,
5
8
1
,
4
3
2

1,
6
2
8
,
8
7
5

1,
6
7
7
,
7
4
2

1,
7
2
8
,
0
7
4

66
1
0
0

F
a
c
i
l
i
t
i
e
s

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
13
8
,
7
8
8

13
8
,
7
8
8

13
8
,
7
8
8

13
8
,
7
8
8

55
5
,
1
5
3

57
1
,
8
0
8

58
8
,
9
6
2

60
6
,
6
3
1

66
1
0
0

T
o
t
a
l

F
a
c
i
l
i
t
i
e
s
13
8
,
7
8
8

13
8
,
7
8
8

13
8
,
7
8
8

13
8
,
7
8
8

55
5
,
1
5
3

57
1
,
8
0
8

58
8
,
9
6
2

60
6
,
6
3
1

To
t
a
l

O
t
h
e
r

S
u
p
p
o
r
t
1,
0
7
8
,
4
0
5

1,
0
7
8
,
4
0
5

1,
0
7
8
,
4
0
5

1,
0
7
8
,
4
0
5

4,
3
1
3
,
6
1
9

4,
4
4
3
,
0
2
8

4,
5
7
6
,
3
1
9

4,
7
1
3
,
6
0
8

Su
b

T
o
t
a
l
19
,
9
0
6
,
9
3
2

17
,
9
0
1
,
9
0
0

19
,
8
7
3
,
2
4
6

20
,
1
1
0
,
8
1
1

77
,
7
9
2
,
8
8
8

74
,
8
5
0
,
8
5
0

82
,
3
0
2
,
4
4
7

85
,
4
8
3
,
5
5
0

Su
b

T
o
t
a
l

/

T
o
n
s

M
i
n
e
d
10
.
4
9
0
15
.
2
6
7
10
.
5
5
4
10
.
4
4
9
11
.
3
1
0
10
.
9
7
5
11
.
2
2
5
12
.
3
7
3
Co
a
l

C
l
e
a
n
i
n
g
(9
1
,
6
9
5
)

(8
3
,
7
2
9
)

(9
1
,
4
6
5
)

(9
4
,
0
8
2
)

(3
6
0
,
9
7
1
)

(3
2
9
,
0
1
8
)

(3
5
2
,
9
9
3
)

(3
5
1
,
5
2
1
)

Ce
l
p

L
o
a
d
i
n
g

a
n
d

H
a
u
l
i
n
g
(2
2
,
5
0
0
)

(2
2
,
5
0
0
)

(2
2
,
5
0
0
)

(2
2
,
5
0
0
)

(9
0
,
0
0
0
)

(9
0
,
0
0
0
)

(9
0
,
0
0
0
)

(9
0
,
0
0
0
)

To
t
a
l

V
a
r
i
a
b
l
e

C
o
s
t
19
,
7
9
2
,
7
3
7

17
,
7
9
5
,
6
7
1

19
,
7
5
9
,
2
8
1

19
,
9
9
4
,
2
2
9

77
,
3
4
1
,
9
1
7

74
,
4
3
1
,
8
3
2

81
,
8
5
9
,
4
5
4

85
,
0
4
2
,
0
2
9

To
t
a
l

V
a
r
i
a
b
l
e

C
o
s
t

/

T
o
n
s

M
i
n
e
d
10
.
4
3
0
15
.
1
7
6
10
.
4
9
4
10
.
3
8
8
11
.
2
4
5
10
.
9
1
4
11
.
1
6
5
12
.
3
0
9
La
n
d
s
3,
8
6
5

22
,
3
6
9

6,
0
4
6

59
,
9
2
0

92
,
2
0
0

93
,
9
0
0

95
,
6
5
0

97
,
4
5
4

To
t
a
l

P
e
r
m
i
t
t
i
n
g

&

B
o
n
d
i
n
g
27
9
,
4
0
1

27
9
,
4
0
1

27
9
,
4
0
1

27
9
,
4
0
1

1,
1
1
7
,
6
0
3

1,
5
6
0
,
4
3
0

1,
5
6
3
,
4
3
5

1,
7
4
9
,
8
1
8

56
1
0
0

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
31
,
5
9
0

31
,
5
9
0

31
,
5
9
0

31
,
5
9
0

12
6
,
3
5
9

13
0
,
1
5
0

13
4
,
0
5
4

13
8
,
0
7
6

55
6
1
0
/
5
6
1
0
0

T
o
t
a
l

F
i
n
a
l

P
i
t
31
,
5
9
0

31
,
5
9
0

31
,
5
9
0

31
,
5
9
0

12
6
,
3
5
9

13
0
,
1
5
0

13
4
,
0
5
4

13
8
,
0
7
6

2015 AOP Final Version
Colstrip 3&4
4.8
4 of 5
ICNU_DR_183 Attachment A Page 32 of 54
We
s
t
m
o
r
e
l
a
n
d

C
o
a
l

C
o
m
p
a
n
y
Co
s
t

b
y

S
u
b

b
y

C
a
t
e
g
o
r
y

C
o
d
e

-
-

B
u
d
g
e
t
/
F
o
r
e
c
a
s
t
Ar
e
a

C
20
1
6

-

2
0
1
9
20
1
5

A
O
P

B
u
d
g
e
t
De
s
c
r
i
p
t
i
o
n
1s
t

Q
t
r
.

2
0
1
6
2n
d

Q
t
r
.

2
0
1
6
3r
d

Q
t
r
.

2
0
1
6
4t
h

Q
t
r
.

2
0
1
6
To
t
a
l

2
0
1
6
To
t
a
l

2
0
1
7
To
t
a
l

2
0
1
8
To
t
a
l

2
0
1
9
55
6
5
0

R
e
g
r
a
d
i
n
g

L
a
b
o
r
15
6
,
3
6
4

66
,
5
4
2

66
,
5
4
2

66
,
5
4
2

35
5
,
9
9
0

34
2
,
6
9
2

35
2
,
9
7
2

36
3
,
5
6
1

55
6
5
0

R
e
g
r
a
d
i
n
g

E
q
u
i
p
m
e
n
t
18
3
,
1
4
2

90
,
7
7
6

90
,
7
7
6

90
,
7
7
6

45
5
,
4
7
0

46
7
,
4
9
7

48
1
,
5
2
1

49
5
,
9
6
7

55
6
5
0

R
e
g
r
a
d
i
n
g

F
u
e
l
18
2
,
4
6
7

10
5
,
0
8
2

10
5
,
0
8
2

10
5
,
0
8
2

49
7
,
7
1
4

54
1
,
1
7
5

55
7
,
4
1
0

57
4
,
1
3
2

55
6
5
0

T
o
t
a
l

R
e
g
r
a
d
i
n
g
52
1
,
9
7
3

26
2
,
4
0
1

26
2
,
4
0
1

26
2
,
4
0
1

1,
3
0
9
,
1
7
5

1,
3
5
1
,
3
6
3

1,
3
9
1
,
9
0
4

1,
4
3
3
,
6
6
1

55
6
5
5

T
o
p
s
o
i
l

L
a
b
o
r
-
-
-
-
-
-
-
-
55
6
5
5

T
o
p
s
o
i
l

E
q
u
i
p
m
e
n
t
-
-
-
-
-
-
-
-
55
6
5
5

T
o
p
s
o
i
l

F
u
e
l
-
-
-
-
-
-
-
-
55
6
5
5

T
o
t
a
l

T
o
p
s
o
i
l
-
-
-
-
-
-
-
-
55
6
6
0

R
e
v
e
g
e
t
a
t
i
o
n

L
a
b
o
r
-
-
-
-
-
29
,
6
3
2

29
,
1
7
8

24
,
3
6
0

55
6
6
0

R
e
v
e
g
e
t
a
t
i
o
n

E
q
u
i
p
m
e
n
t
-
-
-
-
-
-
5,
1
7
9

-
55
6
6
0

R
e
v
e
g
e
t
a
t
i
o
n

F
u
e
l
-
-
-
-
-
-
36
5

-
55
6
6
0

R
e
v
e
g
e
t
a
t
i
o
n

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
3,
5
9
4

3,
5
9
4

3,
5
9
4

3,
5
9
4

14
,
3
7
7

14
,
8
0
8

15
,
2
5
3

15
,
7
1
0

55
6
6
0

R
e
v
e
g
e
t
a
t
i
o
n

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
-
-
-
-
-
-
4,
3
7
1

-
55
6
6
0

T
o
t
a
l

R
e
v
e
g
e
t
a
t
i
o
n
3,
5
9
4

3,
5
9
4

3,
5
9
4

3,
5
9
4

14
,
3
7
7

44
,
4
4
1

54
,
3
4
5

40
,
0
7
1

Po
s
t

M
i
n
e

R
e
c
l
a
m
a
t
i
o
n
55
7
,
1
5
7

29
7
,
5
8
5

29
7
,
5
8
5

29
7
,
5
8
5

1,
4
4
9
,
9
1
1

1,
5
2
5
,
9
5
3

1,
5
8
0
,
3
0
3

1,
6
1
1
,
8
0
7

2015 AOP Final Version
Colstrip 3&4
4.8
5 of 5
ICNU_DR_183 Attachment A Page 33 of 54
2015 IN
2015 AOP 2014 AOP VARIANCE
2015 In BCY 49,817,200 48,683,300 1,133,900
2015 AOP 2014 Budget CY 61,897,000 60,411,200 1,485,800
TOTAL TOTAL VARIANCE Tons 7,250,900 6,994,900 256,000
Total Dozer Overburden $1,907,651 $1,652,048 $255,603 0.263 $0.236 $0.027
Total Scraper Overburden $297,462 $270,721 $26,741 0.041 $0.039 $0.002
Total Truck/Loader Overburden $7,021,170 $6,678,017 $343,153 0.968 $0.955 $0.014
Total Dragline Overburden $12,294,736 $11,183,544 $1,111,192 1.696 $1.599 $0.098
Total Dewatering Overburden $938,797 $876,770 $62,027 0.129 $0.125 $0.003
Total Drill/Blast Overburden $17,693,983 $15,648,212 $2,045,771 2.440 $2.237 $0.204
TOTAL OVERBURDEN $40,153,798 $36,309,312 $3,844,487 5.538 $5.191 $0.3470.649 $0.601 $0.048
Total Coal Testing & Analysis $43,505 $43,228 $277 0.006 $0.006 $0.000
Total Coal Removal Cleaning $352,938 $342,717 $10,221 0.049 $0.049 $0.000
Total Coal Removal Drilling & Blasting $1,742,600 $1,643,630 $98,970 0.240 $0.235 $0.005
Total Coal Removal Loading $3,058,115 $2,718,127 $339,988 0.422 $0.389 $0.033
Total Coal Removal Hauling $6,604,517 $6,394,485 $210,032 0.911 $0.914 -$0.004
Total Coal Removal Crushing & Loadout $2,552,740 $2,186,005 $366,735 0.352 $0.313 $0.040
Total Coal Removal Haul Roads $4,351,561 $3,402,829 $948,733 0.600 $0.486 $0.114
TOTAL COAL REMOVAL $18,705,976 $16,731,021 $1,974,956 2.580 $2.392 $0.188
Total Other Supervision $4,031,911 $4,028,361 $3,550 0.556 $0.576 -$0.020
Total Other Safety Adm $911,828 $877,007 $34,821 0.126 $0.125 $0.000
Total Other Training/Inspection $1,201,796 $1,084,273 $117,523 0.166 $0.155 $0.011
Total Other Warehouse $1,535,371 $1,558,252 -$22,880 0.212 $0.223 -$0.011
Total Other Buildings $538,984 $543,368 -$4,384 0.074 $0.078 -$0.003
TOTAL OTHER $8,219,891 $8,091,261 $128,629 1.134 $1.157 -$0.023
Total Reclamation Engineering $696,086 $668,530 $27,556 0.096 $0.096 $0.000
Total Regrading $5,280,503 $4,308,020 $972,483 0.728 $0.616 $0.112
Total Topsoil/Sub Soil Redistribution $2,304,143 $2,603,763 -$299,620 0.318 $0.372 -$0.053
Total Revegetation $450,585 $447,849 $2,736 0.062 $0.064 -$0.002
TOTAL BASE RECLAMATION $8,731,317 $8,028,162 $703,155 1.204 $1.148 $0.056
TOTAL MINING COSTS $75,810,982 $69,159,756 $6,651,227
10.455 $9.887 $0.5680.649 $0.601 $0.048
Overburden Cost Per CY
Cost Per Ton
Cost Per Ton
Overburden Cost Per CY
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 AOP
2015 AOP VS. 2015 in the 2014 AOP
2015 AOP Final Version
Colstrip 3&4
4.9ICNU_DR_183 Attachment A Page 34 of 54
2015 AOP 2014 AOP VARIANCE
BCY 49,817,200 48,312,100 1,505,100
2015 AOP 2014 AOP CY 61,897,000 60,092,200 1,804,800
TOTAL TOTAL VARIANCE Tons 7,250,900 6,785,300 465,600
Total Dozer Overburden $1,907,651 $1,635,285 $272,366 $0.263 $0.241 $0.022
Total Scraper Overburden $297,462 $214,704 $82,758 $0.041 $0.032 $0.009
Total Truck/Loader Overburden $7,021,170 $4,769,846 $2,251,324 $0.968 $0.703 $0.265
Total Dragline Overburden $12,294,736 $10,928,641 $1,366,094 $1.696 $1.812 -$0.115
Total Dewatering Overburden $938,797 $858,707 $80,090 $0.129 $0.127 $0.002
Total Drill/Blast Overburden $17,693,983 $15,250,133 $2,443,850 $2.440 $2.248 $0.194
TOTAL OVERBURDEN $40,153,798 $33,657,316 $6,496,482
$5.538 $4.960 $0.577
$0.649 $0.560 $0.089
Total Coal Testing & Analysis $43,505 $40,712 $2,794 $0.006 $0.006 $0.000
Total Coal Removal Cleaning $352,938 $328,417 $24,521 $0.049 $0.048 $0.000
Total Coal Removal Drilling & Blasting $1,742,600 $1,537,146 $205,454 $0.240 $0.227 $0.014
Total Coal Removal Loading $3,058,115 $2,465,581 $592,534 $0.422 $0.363 $0.058
Total Coal Removal Hauling $6,604,517 $6,064,439 $540,078 $0.911 $0.894 $0.016
Total Coal Removal Crushing & Loadout $2,552,740 $2,121,835 $430,904 $0.352 $0.313 $0.039
Total Coal Removal Haul Roads $4,351,561 $3,215,270 $1,136,292 $0.600 $0.474 $0.126
TOTAL COAL REMOVAL $18,705,976 $15,773,399 $2,932,577 $2.580 $2.325 $0.255
Total Other Supervision $4,031,911 $3,916,266 $115,644 $0.556 $0.577 -$0.021
Total Other Safety Adm $911,828 $844,955 $66,873 $0.126 $0.125 $0.001
Total Other Training/Inspection $1,201,796 $1,052,692 $149,104 $0.166 $0.155 $0.011
Total Other Warehouse $1,535,371 $1,512,865 $22,506 $0.212 $0.223 -$0.011
Total Other Buildings $538,984 $527,542 $11,442 $0.074 $0.078 -$0.003
TOTAL OTHER $8,219,891 $7,854,321 $365,570 $1.134 $1.158 -$0.024
Total Engineering $696,086 $665,912 $30,174 $0.096 $0.098 -$0.002
Total Regrading $5,280,503 $4,484,038 $796,464 $0.728 $0.661 $0.067
Total Topsoil/Sub Soil Redistribution $2,304,143 $2,204,234 $99,909 $0.318 $0.325 -$0.006
Total Revegetation $450,585 $381,756 $68,829 $0.062 $0.056 $0.006
TOTAL BASE RECLAMATION $8,731,317 $7,735,940 $995,377 $1.204 $1.140 $0.064
TOTAL MINING COSTS $75,810,982 $65,020,976 $10,790,007
$10.455 $9.583 $0.873$0.649 $0.560 $0.089
Overburden Cost Per CY
Cost Per Ton
Overburden Cost Per CY
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 AOP
2015 AOP VS. 2014 AOP
Cost Per Ton
2015 AOP Final Version
Colstrip 3&4
4.10ICNU_DR_183 Attachment A Page 35 of 54
Budget Total 2015 Total 2015
Number Description Budget Cash Budget
WECo-01 Major Equipment Repair 1,350,000.00 1,350,000.00
WECo-02 Major Equipment Replacements & Additions - -
WECo-03 Mobile Equipment Replacements 2,098,900.00 2,098,900.00
WECo-04 Mobile Equipment Additions - -
WECo-05 Support Equipment Replacements 665,774.75 665,774.75
WECo-06 Support Equipment Additions - -
WECo-07 Facilities Modifications 1,123,800.00 1,123,800.00
WECo-08 IT Development & Upgrades 715,760.00 715,760.00
WECo-09 Vehicles 422,000.00 422,000.00
WECo-10 Miscellaneous Capital Items 125,000.00 125,000.00
Total $6,501,235 $6,501,235
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 Capital Recap
*The Area 13 common capital charge is estimated at 62.89% for 2015
2015 AOP
2015 AOP Final Version
Colstrip 3&4
5.0ICNU_DR_183 Attachment A Page 36 of 54
2015 MOC Portion of 2015
Budget Priority LOC 11/13 LOC C Total
Number Description Ranking "Common" Budget Area Budget 2015 Budget
WECo-01 Major Equipment Repair
01-C1 Gear Case Rebuild -- DL3126 HIGH - 200,000 200,000
01-D1 Gear Case Rebuild -- DL3127 HIGH - 200,000 200,000
01-D2 Rebuild Hoist Bull Gear -- DL3127 HIGH - 350,000 350,000
01-D3 Hoist Drum Replacement -- DL3127 HIGH - 600,000 600,000
Subtotal - 1,350,000 1,350,000
WECo-02 Major Equipment Replacement and Additions - - -
Subtotal - - -
WECo-03 Mobile Equipment Replacements & Rebuilds
03-5 DOZER, CAT 1996 D10R (Stock pile)HIGH - 1,455,800 1,455,800
03-11 WATER TRUCK, 1989 CAT 777B HIGH - 643,100 643,100
Subtotal - 2,098,900 2,098,900
WECo-04 Mobile Equipment Additions - - -
Subtotal - - -
WECo-05 Support Equipment Replacements
05-1 Cable Tractor Ford/Case/JD HIGH *180,000 - 180,000
05-3 Knuckle Boom Crane Used 1994 Mack Weld Truck HIGH *240,000 - 240,000
05-4 Pumps/Generators (common)HIGH *50,000 - 50,000
05-5 Reclamation (Farm Equipment - disc, seeder)HIGH *47,461 - 47,461
05-7 1992 CASE 5160 1992 Farm Tractor 100 hp HIGH *148,314 - 148,314
Subtotal 665,775 - 665,775
WECo-06 Support Equipment Additions - - - Subtotal - - -
WECo-07 Facilities Modifications
07-5 Dust Suppression Upgrade - Primary & Truck Dump HIGH - 1,123,800 1,123,800
Subtotal - 1,123,800 1,123,800
WECo-08 IT Development & Upgrades
08-1 Server Consolidation and VM Ware Virtualization HIGH *42,000 - 42,000
08-2 JD Edwards Program Update HIGH *183,600 - 183,600
08-3 Shortel Phone System HIGH *115,160 - 115,160
08-4 Profiler/Total Station HIGH *75,000 - 75,000
08-5 Dragline Tracking Software HIGH - 300,000 300,000
Subtotal 415,760 300,000 715,760
WECo-09 Vehicles
A Light Vehicles (common)HIGH *422,000 - 422,000
Subtotal 422,000 - 422,000
WECo-10 Miscellaneous Capital Items
A2 Tools & Equip. Replacement (common)HIGH *80,000 - 80,000
A3 Welder/Air Pack HIGH *45,000 - 45,000
Subtotal 125,000 - 125,000
Total 2015 Budget 1,628,535 4,872,700 6,501,235
Total Common Capital Charges Based on Percentage $1,024,186 4,872,700 $5,896,886
*The Area 13 common capital charge is estimated at 62.89% for 2015
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 Capital Summary
2015 AOP
2015 AOP Final Version
Colstrip 3&4
5.1ICNU_DR_183 Attachment A Page 37 of 54
Budget 1s t 2nd 3rd 4th
Number Description Location Quarter Quarter Quarter Quarter Total
WECo-01 Major Equipment Repair
Draglines DL3126 C
01-C1 Gear Case Rebuild - 200,000 - - 200,000
Draglines DL3127 C
01-D1 Gear Case Rebuild - 200,000 - - 200,000
01-D2 Rebuild Hoist Bull Gear - 350,000 - - 350,000
01-D3 Hoist Drum Replacement - - 600,000 - 600,000
- 750,000 600,000 - 1,350,000
WECo-02 Major Equipment Replacement and Additions - - - - -
- - - - -
WECo-03 Mobile Equipment Replacements & Rebuilds
03-5 DOZER, CAT 1996 D10R (Stock pile)C 1,455,800 - - - 1,455,800 Replace
03-11 WATER TRUCK, 1989 CAT 777B C - - - 643,100 643,100 Replace
1,455,800 - - 643,100 2,098,900
WECo-04 Mobile Equipment Additions - - - - -
- - - - -
WECo-05 Support Equipment Replacements
05-1 Cable Tractor Ford/Case/JD COMMON 180,000 - - - 180,000
05-3 Knuckle Boom Crane Used 1994 Mack Weld Truck COMMON 240,000 - - - 240,000
05-4 Pumps/Generators (common)COMMON 50,000 - - - 50,000
05-5 Reclamation (Farm Equipment - disc, seeder)COMMON 47,461 - - - 47,461
05-7 1992 CASE 5160 1992 Farm Tractor 100 hp COMMON - 148,314 - - 148,314 517,461 148,314 - - 665,775
WECo-06 Support Equipment Additions - - - - -
- - - - -
WECo-07 Facilities Modifications
07-5 Dust Suppression Upgrade - Primary & Truck Dump C 112,400 1,011,400 1,123,800
112,400 - - 1,011,400 1,123,800
WECo-08 IT Development & Upgrades
08-1 Server Consolidation and VM Ware Virtualization COMMON - - - 42,000 42,000
08-2 JD Edwards Program Update COMMON - - - 183,600 183,600
08-3 Shortel Phone System COMMON - - - 115,160 115,160
08-4 Profiler/Total Station COMMON - 75,000 - - 75,000
08-5 Dragline Tracking Software C - - 300,000 - 300,000
- 75,000 300,000 340,760 715,760
WECo-09 Vehicles
A1 Light Vehicles (common)COMMON - 422,000 - - 422,000 - 422,000 - - 422,000
WECo-10 Miscellaneous Capital Items
10-1 Tools & Equip. Replacement (common)COMMON 20,000 20,000 20,000 20,000 80,000
10-2 Welder/Air Pack COMMON - 45,000 - - 45,000
20,000 65,000 20,000 20,000 125,000
Total
$2,105,660.5 $1,460,314.2 $920,000.0 $2,015,260.0 $6,501,234.8
*The Area 13 common capital charge is estimated at 62.89% for 2015.
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 Capital Cashflow
2015 AOP
2015 AOP Final Version
Colstrip 3&4
5.2ICNU_DR_183 Attachment A Page 38 of 54
Equip 2016 2017 2018 2019
No Area 1.06 1.12 1.19 1.26
Draglines DL3126 DL3126 C
#126 Dragline Tub Rebuild C - - - 4,292.4
Complete Machine electrical upgrade C - - 893.3 -
60 cu. yd. Bucket 14 (2005 Used)C 901.0 - - -
Gear Case Rebuild C 400.0 400.0 476.4 505.0
Rebuild Drag Bull Gear C - 372.4 - -
Rebuild Hoist Bull Gear C - - 443.5 -
Replace Main Suspension Ropes C - 337.1 - -
Boom Point Sheave Rebuild C - 280.9 - -
Draglines DL3127 DL3127 C
#127 Dragline Rollers/Rails Rebuild C - - 5,352.9 -
Complete Machine electrical upgrade C - 842.7 - -
78 cu. yd. Esco Bucket No. 16 (2006)C - - - 1,073.1
80 cu. yd. Bucket No. 20 (2010)C - - - -
Gear Case Rebuild C - 750.0 536.0 568.1
Rebuild Drag Bull Gear C - - 416.9 -
Replace Main Suspension Ropes C - - - -
Boom Point Sheave Rebuild C - - - -
Mass Excavator
Loaders
LOADER, CAT 2005 992G LD3001 C - - - 3,543.4
Aux. Loaders
LOADER, 980H Caterpillar LD3008 COMMON - 280.9 - -
Haul Trucks
HAULER, 2000 KRESS 200 TON HL3806 C 3,577.5 - - -
HAULER, 2000 KRESS 200 TON HL3807 C 3,577.5 - - -
HAULER, 2000 KRESS 200 TON HL3808 C 3,577.5 - - -
Drills
DRILL, DRILLTECH D75, OVB.-DR3007 DR3137 C - - - 757.5
Dozers
DOZER, CAT 2004 D10R-DZ987 DZ3312 C - - - -
DOZER, CAT 2005 D10R DZ3313 C - - - -
Dozer Cat D11T Add C - 2,447.4 - -
KOMATSU 2011 D375A-6 DZ3317 C - - - -
KOMATSU 2011 D375A-6 DZ3318 C - - - -
Motor Grader
MOTOR GRADER, CAT 2003 16H MG3502 C - - - -
MOTOR GRADER, CAT 2008 16M-MG3004 MG3504 C - - - 1,232.0
MOTOR GRADER, CAT 2008 16M-MG3005 MG3505 C - - 1,162.3 -
MOTOR GRADER, CAT 1998 16H-MG3727 MG3507 C - - 1,162.3 -
Water Trucks
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 AOP
Capital Schedule 2016 - 2019
2015 AOP Final Version
Colstrip 3&4
5.3
1 of 2
ICNU_DR_183 Attachment A Page 39 of 54
Equip 2016 2017 2018 2019
No Area 1.06 1.12 1.19 1.26
Western Energy Company
Mine Operating Committee
3&4 Contract
2015 AOP
Capital Schedule 2016 - 2019
Support Equipment
Welder Service Truck (common)COMMON - - 176.6 -
Kenworth T300 Welder Truck, 2006 HT3002 COMMON - - 154.8 -
Mechanics Truck 2006 Freightliner M HT3003 C - 207.9 - -
Fuel/Lube Truck 2008 Western Star HT3006 C - - 327.5 -
Service Truck (Area C)1998 Freightliner FL80 HT3711 C 180.2 - - -
1982 FMC HSP8040- 40 Ton Crane CR3213 C 609.5 - - -
Pumps/Generators (common)COMMON - - 70.9 -
2008 Cat 236B Skidsteer Loader for Steambay cleanoutUN3731 COMMON - - 47.6 -
Light Vehicles (common)COMMON 447.3 474.2 502.6 532.8
Miscellaneous Capital Items
JD Edwards Program Update COMMON - - 137.8 -
Tools & Equip. Replacement (common)COMMON 84.8 89.9 95.3 101.0
Welder/Air Pack COMMON 47.7 47.7 - 56.8
Electric Cable/Junction Boxes C - - - -
Total $13,403.0 $6,531.1 $11,956.6 $12,662.1
68.43%64.41%68.84%67.92%
Replace
Rebuild
Replace
Replace
Replace
Rebuild
Rebuild
Replace
Replace
Replace
*The Area 13 common capital charge is estimated at:
LOADER, CAT 2005 992G
LOADER, 980H Caterpillar
HAULER, 2000 KRESS 200 TON
HAULER, 2000 KRESS 200 TON
HAULER, 2000 KRESS 200 TON
DRILL, DRILLTECH D75, OVB.-DR3007
DOZER, CAT 2004 D10R-DZ987
DOZER, CAT 2005 D10R
Dozer Cat D11T
KOMATSU 2011 D375A-6
KOMATSU 2011 D375A-6
MOTOR GRADER, CAT 2003 16H
MOTOR GRADER, CAT 2008 16M-MG3004
MOTOR GRADER, CAT 2008 16M-MG3005
MOTOR GRADER, CAT 1998 16H-MG3727
2015 AOP Final Version
Colstrip 3&4
5.3
2 of 2
ICNU_DR_183 Attachment A Page 40 of 54
Eq
u
i
p
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
No
Ar
e
a
20
1
4

A
O
P
1.
0
0
20
1
4

A
O
P
1.
0
6
20
1
4

A
O
P
1.
1
2
20
1
4

A
O
P
1.
1
9
20
1
4

A
O
P
1.
2
6
Dr
a
g
l
i
n
e
s

D
L
3
1
2
6
DL
3
1
2
6
C
#1
2
6

D
r
a
g
l
i
n
e

T
u
b

R
e
b
u
i
l
d
C
-
-
-
-
-
-
-
-
-
4,
2
9
2
.
4

Co
m
p
l
e
t
e

M
a
c
h
i
n
e

e
l
e
c
t
r
i
c
a
l

u
p
g
r
a
d
e
C
-
-
-
-
89
3
.
3

-
-
89
3
.
3

-
60

c
u
.

y
d
.

B
u
c
k
e
t

1
4

(
2
0
0
5

U
s
e
d
)
C
-
-
88
2
.
0

90
1
.
0

-
-
-
-
-
-
Ge
a
r

C
a
s
e

R
e
b
u
i
l
d
C
65
0
.
0

20
0
.
0

65
0
.
0

40
0
.
0

47
6
.
4

40
0
.
0

-
47
6
.
4

-
50
5
.
0

Re
b
u
i
l
d

D
r
a
g

B
u
l
l

G
e
a
r
C
-
-
39
4
.
7

-
-
37
2
.
4

50
5
.
0

-
-
-
Re
b
u
i
l
d

H
o
i
s
t

B
u
l
l

G
e
a
r
C
-
-
-
-
44
3
.
5

-
-
44
3
.
5

-
-
Re
p
l
a
c
e

M
a
i
n

S
u
s
p
e
n
s
i
o
n

R
o
p
e
s
C
-
-
-
-
35
7
.
3

33
7
.
1

-
-
-
-
Bo
o
m

P
o
i
n
t

S
h
e
a
v
e

R
e
b
u
i
l
d
C
-
-
-
-
29
7
.
8

28
0
.
9

-
-
-
-
Dr
a
g
l
i
n
e
s

D
L
3
1
2
7
DL
3
1
2
7
C
#1
2
7

D
r
a
g
l
i
n
e

R
o
l
l
e
r
s
/
R
a
i
l
s

R
e
b
u
i
l
d
C
-
-
-
-
5,
3
5
2
.
9

-
-
5,
3
5
2
.
9

-
-
Co
m
p
l
e
t
e

M
a
c
h
i
n
e

e
l
e
c
t
r
i
c
a
l

u
p
g
r
a
d
e
C
-
-
84
2
.
7

-
-
84
2
.
7

-
-
-
78

c
u
.

y
d
.

E
s
c
o

B
u
c
k
e
t

N
o
.

1
6

(
2
0
0
6
)
C
-
-
-
-
-
-
1,
0
7
3
.
1

-
-
1,
0
7
3
.
1

80

c
u
.

y
d
.

B
u
c
k
e
t

N
o
.

2
0

(
2
0
1
0
)
C
-
-
-
-
-
-
-
-
-
-
Ge
a
r

C
a
s
e

R
e
b
u
i
l
d
C
75
0
.
0

20
0
.
0

70
0
.
0

-
53
6
.
0

75
0
.
0

67
6
.
6

53
6
.
0

-
56
8
.
1

Re
b
u
i
l
d

D
r
a
g

B
u
l
l

G
e
a
r
C
-
-
41
6
.
9

-
-
-
-
41
6
.
9

-
-
Re
b
u
i
l
d

H
o
i
s
t

B
u
l
l

G
e
a
r
C
39
3
.
3

35
0
.
0

-
-
-
-
-
-
-
-
Ho
i
s
t

D
r
u
m

R
e
p
l
a
c
e
m
e
n
t
C
-
60
0
.
0

-
-
-
-
-
-
-
-
Re
p
l
a
c
e

M
a
i
n

S
u
s
p
e
n
s
i
o
n

R
o
p
e
s
C
-
-
-
-
-
-
-
-
-
-
Bo
o
m

P
o
i
n
t

S
h
e
a
v
e

R
e
b
u
i
l
d
C
-
-
-
-
-
-
-
-
-
-
Ma
s
s

E
x
c
a
v
a
t
o
r
20
0
2

H
i
t
a
c
h
i

1
8
0
0
ME
3
6
0
1
C
-
-
-
-
-
-
2,
3
4
1
.
9

-
-
-
Lo
a
d
e
r
s
LO
A
D
E
R
,

C
A
T

2
0
0
5

9
9
2
G
LD
3
0
0
1
C
-
-
-
-
-
-
3,
6
4
6
.
3

-
-
3,
5
4
3
.
4

Au
x
.

L
o
a
d
e
r
s
LO
A
D
E
R
,

9
8
0
H

C
a
t
e
r
p
i
l
l
a
r
LD
3
0
0
8
CO
M
M
O
N
-
-
28
0
.
9

-
-
28
0
.
9

-
-
-
-
Ha
u
l

T
r
u
c
k
s
HA
U
L
E
R
,

2
0
0
0

K
R
E
S
S

2
0
0

T
O
N
HL
3
8
0
6
C
2,
7
1
4
.
1

-
-
3,
5
7
7
.
5

-
-
-
-
-
-
HA
U
L
E
R
,

2
0
0
0

K
R
E
S
S

2
0
0

T
O
N
HL
3
8
0
7
C
2,
7
1
4
.
1

-
-
3,
5
7
7
.
5

-
-
-
-
-
-
HA
U
L
E
R
,

2
0
0
0

K
R
E
S
S

2
0
0

T
O
N
HL
3
8
0
8
C
2,
7
1
4
.
1

-
-
3,
5
7
7
.
5

-
-
-
-
-
-
Dr
i
l
l
s
DR
I
L
L
,

D
R
I
L
L
T
E
C
H

D
7
5
,

O
V
B
.
-
D
R
3
0
0
7
DR
3
1
3
7
C
-
-
-
-
-
-
2,
8
0
0
.
0

-
-
75
7
.
5

Do
z
e
r
s
DO
Z
E
R
,

C
A
T

2
0
0
7

D
1
0
T
DZ
3
3
0
5
C
87
1
.
3

-
-
-
-
-
-
-
-
-
DO
Z
E
R
,

C
A
T

1
9
9
6

D
1
0
R

(
S
t
o
c
k

p
i
l
e
)
DZ
3
3
0
4
C
-
1,
4
5
5
.
8

-
-
-
-
-
-
-
-
DO
Z
E
R
,

C
A
T

2
0
0
4

D
1
0
R
-
D
Z
9
8
7
DZ
3
3
1
2
C
-
-
-
-
-
-
-
-
-
-
DO
Z
E
R
,

C
A
T

2
0
0
5

D
1
0
R
DZ
3
3
1
3
C
-
-
-
-
-
-
-
-
-
-
DO
Z
E
R
,

C
A
T

2
0
1
0

D
1
1
R

C
D
DZ
3
3
1
4
C
-
-
2,
4
4
7
.
4

-
-
-
-
-
-
-
Do
z
e
r

C
a
t

D
1
1
T
Ad
d
C
-
-
-
-
-
2,
4
4
7
.
4

-
-
-
-
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
Ca
p
i
t
a
l

S
c
h
e
d
u
l
e

-
-

2
0
1
4

A
O
P

V
s
.

2
0
1
5

A
O
P
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
2015 AOP Final Version
Colstrip 3&4
5.4
1 of 3
ICNU_DR_183 Attachment A Page 41 of 54
Eq
u
i
p
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
No
Ar
e
a
20
1
4

A
O
P
1.
0
0
20
1
4

A
O
P
1.
0
6
20
1
4

A
O
P
1.
1
2
20
1
4

A
O
P
1.
1
9
20
1
4

A
O
P
1.
2
6
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
Ca
p
i
t
a
l

S
c
h
e
d
u
l
e

-
-

2
0
1
4

A
O
P

V
s
.

2
0
1
5

A
O
P
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
KO
M
A
T
S
U

2
0
1
1

D
3
7
5
A
-
6
DZ
3
3
1
7
C
-
-
-
-
-
-
-
-
-
-
KO
M
A
T
S
U

2
0
1
1

D
3
7
5
A
-
6
DZ
3
3
1
8
C
-
-
-
-
-
-
-
-
-
-
Mo
t
o
r

G
r
a
d
e
r
MO
T
O
R

G
R
A
D
E
R
,

C
A
T

2
0
0
3

1
6
H

MG
3
5
0
2
C
-
-
-
-
-
-
-
-
-
-
MO
T
O
R

G
R
A
D
E
R
,

C
A
T

2
0
0
8

1
6
M
-
M
G
3
0
0
4
MG
3
5
0
4
C
-
-
-
-
52
7
.
1

-
-
-
-
1,
2
3
2
.
0

MO
T
O
R

G
R
A
D
E
R
,

C
A
T

2
0
0
8

1
6
M
-
M
G
3
0
0
5
MG
3
5
0
5
C
-
-
-
-
52
7
.
1

-
-
1,
1
6
2
.
3

-
-
MO
T
O
R

G
R
A
D
E
R
,

C
A
T

1
9
9
8

1
6
H
-
M
G
3
7
2
7
MG
3
5
0
7
C
-
-
-
-
1,
1
6
1
.
2

-
-
1,
1
6
2
.
3

-
-
Wa
t
e
r

T
r
u
c
k
s
WA
T
E
R

T
R
U
C
K
,

1
9
8
9

C
A
T

7
7
7
B
-
W
T
3
8
1
4
WT
3
7
0
4
C
64
3
.
1

64
3
.
1

-
-
-
-
-
-
-
-
Wa
t
e
r

W
a
g
o
n
s
Su
p
p
o
r
t

E
q
u
i
p
m
e
n
t
Ca
b
l
e

T
r
a
c
t
o
r

F
o
r
d
/
C
a
s
e
/
J
D
CO
M
M
O
N
-
18
0
.
0

-
-
-
-
-
-
-
-
We
l
d
e
r

S
e
r
v
i
c
e

T
r
u
c
k

(
c
o
m
m
o
n
)
CO
M
M
O
N
-
-
-
-
20
4
.
3

-
-
17
6
.
6

-
-
Ke
n
w
o
r
t
h

T
3
0
0

W
e
l
d
e
r

T
r
u
c
k
,

2
0
0
6
HT
3
0
0
2
CO
M
M
O
N
-
-
-
-
15
4
.
8

-
-
15
4
.
8

-
-
Me
c
h
a
n
i
c
s

T
r
u
c
k

2
0
0
6

F
r
e
i
g
h
t
l
i
n
e
r

M
HT
3
0
0
3
C
-
-
-
-
-
20
7
.
9

-
-
-
-
Fu
e
l
/
L
u
b
e

T
r
u
c
k

2
0
0
8

W
e
s
t
e
r
n

S
t
a
r
HT
3
0
0
6
C
-
-
-
-
-
-
-
32
7
.
5

-
-
Se
r
v
i
c
e

T
r
u
c
k

(
A
r
e
a

C
)
1
9
9
8

F
r
e
i
g
h
t
l
i
n
e
r

F
L
8
0
HT
3
7
1
1
C
-
-
22
7
.
5

18
0
.
2

-
-
-
-
-
-
19
8
2

F
M
C

H
S
P
8
0
4
0
-

4
0

T
o
n

C
r
a
n
e
CR
3
2
1
3
C
-
-
61
7
.
4

60
9
.
5

-
-
-
-
-
-
Kn
u
c
k
l
e

B
o
o
m

C
r
a
n
e

U
s
e
d

1
9
9
4

M
a
c
k

W
e
l
d

T
r
u
c
k
HT
3
9
7
9
CO
M
M
O
N
-
24
0
.
0

-
-
-
-
-
-
-
-
Pu
m
p
s
/
G
e
n
e
r
a
t
o
r
s

(
c
o
m
m
o
n
)
CO
M
M
O
N
59
.
6

50
.
0

-
-
70
.
9

-
-
70
.
9

-
-
Re
c
l
a
m
a
t
i
o
n

(
F
a
r
m

E
q
u
i
p
m
e
n
t

-

d
i
s
c
,

s
e
e
d
e
r
)
CO
M
M
O
N
-
47
.
5

-
-
-
-
-
-
-
-
19
9
2

C
A
S
E

5
1
6
0

1
9
9
2

F
a
r
m

T
r
a
c
t
o
r

1
0
0

h
p
TC
3
2
6
6
CO
M
M
O
N
-
14
8
.
3

-
-
-
-
-
-
-
-
20
0
8

C
a
t

2
3
6
B

S
k
i
d
s
t
e
e
r

L
o
a
d
e
r

f
o
r

S
t
e
a
m
b
a
y

c
l
e
a
n
o
u
t
UN
3
7
3
1
CO
M
M
O
N
-
-
-
-
-
-
-
47
.
6

-
-
Li
g
h
t

V
e
h
i
c
l
e
s

(
c
o
m
m
o
n
)
CO
M
M
O
N
44
6
.
9

42
2
.
0

47
3
.
7

44
7
.
3

50
2
.
1

47
4
.
2

53
2
.
3

50
2
.
6

56
4
.
2

53
2
.
8

Cr
u
s
h
e
r
/
C
o
n
v
e
y
o
r
Du
s
t

S
u
p
p
r
e
s
s
i
o
n

U
p
g
r
a
d
e

-

S
e
c
o
n
d
a
r
y

&

P
r
i
m
a
r
y
C
-
1,
1
2
3
.
8

-
-
-
-
-
-
-
-
Mi
s
c
e
l
l
a
n
e
o
u
s

C
a
p
i
t
a
l

I
t
e
m
s
Se
r
v
e
r

C
o
n
s
o
l
i
d
a
t
i
o
n

a
n
d

V
M

W
a
r
e

V
i
r
t
u
a
l
i
z
a
t
i
o
n
CO
M
M
O
N
-
42
.
0

-
-
-
-
-
-
-
-
Vi
r
t
u
a
l
i
z
e
d

D
e
s
k
t
o
p
s
CO
M
M
O
N
73
.
5

-
-
-
-
-
-
-
-
-
Pa
y
r
o
l
l

&

H
R

S
o
f
t
w
a
r
e

I
m
p
l
e
m
e
n
t
a
t
i
o
n
CO
M
M
O
N
-
-
-
-
-
-
-
-
-
-
JD

E
d
w
a
r
d
s

P
r
o
g
r
a
m

U
p
d
a
t
e
CO
M
M
O
N
-
18
3
.
6

-
-
-
-
-
13
7
.
8

23
3
.
0

-
Sh
o
r
t
e
l

P
h
o
n
e

S
y
s
t
e
m
CO
M
M
O
N
-
11
5
.
2

-
-
-
-
-
-
-
-
Pr
o
f
i
l
e
r
/
T
o
t
a
l

S
t
a
t
i
o
n
CO
M
M
O
N
-
75
.
0

-
-
-
-
-
-
-
-
Dr
a
g
l
i
n
e

T
r
a
c
k
i
n
g

S
o
f
t
w
a
r
e
C
-
30
0
.
0

-
-
-
-
-
-
-
-
To
o
l
s

&

E
q
u
i
p
.

R
e
p
l
a
c
e
m
e
n
t

(
c
o
m
m
o
n
)
CO
M
M
O
N
12
6
.
2

80
.
0

13
3
.
8

84
.
8

14
1
.
9

89
.
9

15
0
.
4

95
.
3

15
9
.
4

10
1
.
0

We
l
d
e
r
/
A
i
r

P
a
c
k
CO
M
M
O
N
45
.
0

45
.
0

47
.
7

47
.
7

-
47
.
7

50
.
6

-
-
56
.
8

To
t
a
l
$1
2
,
2
0
1
.
2
$6
,
5
0
1
.
2
$8
,
1
1
4
.
7
$1
3
,
4
0
3
.
0
$1
1
,
6
4
6
.
6
$6
,
5
3
1
.
1
$1
1
,
7
7
6
.
3
$1
1
,
9
5
6
.
6
$9
5
6
.
5
$1
2
,
6
6
2
.
1
2015 AOP Final Version
Colstrip 3&4
5.4
2 of 3
ICNU_DR_183 Attachment A Page 42 of 54
Eq
u
i
p
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
2
0
1
5

A
O
P
.
No
Ar
e
a
20
1
4

A
O
P
1.
0
0
20
1
4

A
O
P
1.
0
6
20
1
4

A
O
P
1.
1
2
20
1
4

A
O
P
1.
1
9
20
1
4

A
O
P
1.
2
6
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
Ca
p
i
t
a
l

S
c
h
e
d
u
l
e

-
-

2
0
1
4

A
O
P

V
s
.

2
0
1
5

A
O
P
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
To
t
a
l

W
/
O
u
t

K
r
e
s
s

H
a
u
l
e
r
s
$4
,
0
5
8
.
9
$6
,
5
0
1
.
2
$8
,
1
1
4
.
7
$2
,
6
7
0
.
5
$1
1
,
6
4
6
.
6
$6
,
5
3
1
.
1
$1
1
,
7
7
6
.
3
$1
1
,
9
5
6
.
6
$9
5
6
.
5
$1
2
,
6
6
2
.
1
2015 AOP Final Version
Colstrip 3&4
5.4
3 of 3
ICNU_DR_183 Attachment A Page 43 of 54
ENVIRONMENTAL INFORMATION
Permits
A mining permit is required by state and federal law and is renewed every five years. This permit contains information on the pre-mining environmental conditions, the methods and rate of mining the reserve, an assessment of the impacts on the
environmental resources, and a reclamation plan to meet the post-mining land uses
required by state law (grazing and wildlife). Revisions to the permits are required when
modifications are made to the approved mine plan or reclamation plan.
Compliance
The Montana Department of Environmental Quality (DEQ) conducts inspections monthly
as required by state regulation. These inspections focus on compliance with state regulations and permit compliance. Engineering staff accompany the state inspectors. Items that are noted as maintenance items by the inspector are many times resolved prior
to the completion of the inspection. A closeout meeting is held with Operations to
discuss the inspector’s findings. Engineering staff works with Operations to assure the
closure of maintenance items prior to the next inspection or as soon as practicable.
The following state and federal authorities conduct annual inspections:
•Montana Industrial & Energy Minerals Bureau;
•Montana Water Protection Bureau;
•Montana Solid & Hazardous Waste Bureau;
•Montana Air Resources Management Bureau;
•EPA; and,
•Office of Surface Mining (including oversight inspection of DEQ).
Environmental Accomplishments
•No environmental violations through May of 2014.
Goals
•Zero environmental violations for 2015.
2015 AOP Final Version
Colstrip 3&4
6.0ICNU_DR_183 Attachment A Page 44 of 54
Environmental Inspection Summary
0
1
2
2006 2007 2008 2009 2010 2011
#
o
f

V
i
o
l
a
t
i
o
n
s
Year
Violations
0
1000
2000
3000
4000
5000
2006 2007 2008 2009 2010 2011
Pe
n
a
l
t
y

D
o
l
l
a
r
s
Year
Penalties Assessed in $
0
10
20
30
40
50
2006 2007 2008 2009 2010 2011
In
s
p
e
c
t
i
o
n

D
a
y
s
Year
Inspection Days
0
1
2
2006 2007 2008 2009 2010 2011 2012
#
o
f

V
i
o
l
a
t
i
o
n
s
Year
Violations
0
1000
2000
3000
4000
5000
2006 2007 2008 2009 2010 2011 2012
Pe
n
a
l
t
y

D
o
l
l
a
r
s
Year
Penalties Assessed in $
0
10
20
30
40
50
2006 2007 2008 2009 2010 2011 2012
In
s
p
e
c
t
i
o
n

D
a
y
s
Year
Inspection Days
0
1
2
2006 2007 2008 2009 2010 2011 2012 2013
#
o
f

V
i
o
l
a
t
i
o
n
s
Year
Violations
0
1000
2000
3000
4000
5000
2006 2007 2008 2009 2010 2011 2012 2013
Pe
n
a
l
t
y

D
o
l
l
a
r
s
Year
Penalties Assessed in $
0
10
20
30
40
50
2006 2007 2008 2009 2010 2011 2012 2013
In
s
p
e
c
t
i
o
n

D
a
y
s
Year
Inspection Days
2015 AOP Final Version
Colstrip 3&4
6.1ICNU_DR_183 Attachment A Page 45 of 54
SAFETY
Inspections
During the calendar year 2013, Western Energy Co. was inspected by MSHA 3 times, all three
were EO1 inspections. During the EO1 inspections 20 citations were written.
There were two Montana State DOL inspections during 2013 resulting in no citations and 16
recommendations.
Safety Programs
Behavior Based Safety (BBS) Behavioral Based Safety continued through 2013 and participation has remained steady. The
Steering Committees have been doing safety audits throughout the workplace. This has helped
increase safety awareness with the work crews. The safety tool box meeting continues at two per
month for each crew.
MedX
MedX continues to be an option for healthier backs for interested employees. All employees at
the mine are encouraged to utilize MedX for strengthening their backs. The gift card incentive
continued for 2013.
Continuous Safety Improvement
The total number of incidents for 2013 is 114. There was one “Lost Time” and one “Medical
Reportable” incident reported in 2013. Twelve “Occupational Illness” injuries were reported. Eleven injury incidents required medical evaluation or treatment. Thirty eight injury reports did
not require medical attention. There were 50 incidents of property damage and one “near hit”
incident.
2015 AOP Final Version
Colstrip 3&4
6.2ICNU_DR_183 Attachment A Page 46 of 54
0
0.
5
1
1.
5
2
2.
5
3
3.
5
4
Per 100 FTE
Ye
a
r
NF
D
L

R
a
t
e
s
(N
o
n

F
a
t
a
l

D
a
y
s

L
o
s
t
)
Na
t
i
o
n
a
l

A
v
e
r
a
g
e
Ro
s
e
b
u
d
Na
t
i
o
n
a
l

A
v
e
r
a
g
e
*B
B
S

b
e
g
a
n

i
n
Oc
t

2
0
0
7
*B
B
S

b
e
g
a
n

i
n
Oc
t

2
0
0
7
*B
B
S

b
e
g
a
n

i
n
Oc
t

2
0
0
7
20
1
4

T
h
r
o
u
g
h

Ap
r
i
l
2015 AOP Final Version
Colstrip 3&4
6.3ICNU_DR_183 Attachment A Page 47 of 54
0.
0
2.
0
4.
0
6.
0
8.
0
10
.
0
Per 100 FTE
Ye
a
r
Re
p
o
r
t
a
b
l
e

I
n
c
i
d
e
n
t

R
a
t
e
Ro
s
e
b
u
d
Na
t
i
o
n
a
l
Ro
s
e
b
u
d
Na
t
i
o
n
a
l
20
1
3

T
h
r
o
u
g
h

A
p
r
i
l
*B
B
S

b
e
g
a
n
in

O
c
t

2
0
0
7
*B
B
S

b
e
g
a
n
in

O
c
t

2
0
0
7
2015 AOP Final Version
Colstrip 3&4
6.4ICNU_DR_183 Attachment A Page 48 of 54
Incentive Fee will be forwarded at a later time.
2015 AOP
Western Energy Company
Mine Operating Committee
3&4 Contract
Incentive Fee
2015 AOP Final Version
Colstrip 3&4
7.0ICNU_DR_183 Attachment A Page 49 of 54
Western Energy Company
Mine Operating Committee
3&4 Contract
Outside Coal Sales
There are no outside coal sales projected at this time.
2015 AOP
2015 AOP Final Version
Colstrip 3&4
8.0ICNU_DR_183 Attachment A Page 50 of 54
20
1
5
20
1
5
20
1
6
20
1
6
20
1
7
20
1
7
20
1
8
20
1
8
20
1
9
20
1
9
Va
r
i
a
b
l
e

C
o
s
t
s
Co
s
t
s

Pe
r

T
o
n
Co
s
t
s

Pe
r

T
o
n
Co
s
t
s

Pe
r

T
o
n
Co
s
t
s

Pe
r

T
o
n
Co
s
t
s

Pe
r

T
o
n
La
b
o
r
1,
0
9
2
,
5
8
0

0.1
5
1
1,1
2
5
,
3
5
8
0.
1
6
4
1,
1
6
1
,
6
3
9
0.1
7
0
1,
1
9
6
,
4
8
8
0.
1
6
3
1,2
3
2
,
3
8
2
0.
1
7
8
Ma
i
n
t
e
n
a
n
c
e

L
a
b
o
r
37
8
,
9
2
3
0.0
5
2
39
0
,
2
9
0
0.
0
5
7
40
1
,
9
9
9
0.0
5
9
41
4
,
0
5
9
0.
0
5
6
42
6
,
4
8
1
0.
0
6
2
M&
S

C
o
s
t
s
1,
3
7
7
,
4
4
6
0.1
9
0
1,4
2
5
,
2
2
9
0.
2
0
7
1,
4
6
7
,
9
8
5
0.2
1
5
1,
5
1
2
,
0
2
5
0.
2
0
6
1,5
5
7
,
3
8
6
0.
2
2
5
F
e
e

O
p
e
r
a
t
i
n
g

P
r
o
f
i
t

5,
4
3
0
,
9
2
4
0.7
4
9
5,1
7
9
,
1
3
4
0.
7
5
3
5,
1
6
2
,
7
4
0
0.7
5
7
5,
5
7
9
,
6
5
2
0.
7
6
1
5,2
8
5
,
3
8
5
0.
7
6
5
To
t
a
l

V
a
r
i
a
b
l
e

C
o
s
t
s
:
8,
2
7
9
,
8
7
4
1.1
4
2
8,1
2
0
,
0
1
1
1.
1
8
1
8,
1
9
4
,
3
6
3
1.2
0
2
8,
7
0
2
,
2
2
4
1.
1
8
7
8,5
0
1
,
6
3
4
1.
2
3
1
Fi
x
e
d

C
o
s
t
s
De
p
r
e
c
i
a
t
i
o
n
61
3
,
6
7
2
68
3
,
9
3
1
61
8
,
9
5
0
36
8
,
4
8
8
16
1
,
5
8
6
Pro
p
e
r
t
y

T
a
x
0.0
0
5
5
53
,
2
7
8
61
,
4
7
6
63
,
3
2
1
66
,
8
8
4
68
,
8
9
1
Ov
e
r
h
e
a
d

@

2
0
%

o
f

D
i
r
e
c
t

L
a
b
o
r
29
4
,
3
0
1
30
3
,
1
3
0
31
2
,
7
2
8
32
2
,
1
0
9
33
1
,
7
7
3
To
t
a
l

F
i
x
e
d

C
o
s
t
s
:
96
1
,
2
5
1
0.1
3
3
1,
0
4
8
,
5
3
7
0.
1
5
2
99
4
,
9
9
8
0.1
4
6
75
7
,
4
8
2
0.
1
0
3
56
2
,
2
5
0
0.
0
8
1
Pe
r

M
o
n
t
h
80
,
1
0
4
.
2
5
87
,
3
7
8
.
1
0
82
,
9
1
6
.
4
9
63
,
1
2
3
.
4
7
46
,
8
5
4
.
1
5
PE
R

T
O
N

C
O
S
T

B
E
F
O
R
E

T
A
X
1.2
7
5
1.
3
2
9
1.3
4
7
1.
2
9
0
1.
3
1
1
Fe
d
e
r
a
l

t
o
n
s
2,
6
0
3
,
0
0
0
2,4
9
1
,
5
0
0
2,
5
5
2
,
9
0
0
2,
8
2
6
,
0
0
0
2,0
0
1
,
2
0
0
To
t
a
l

T
o
n
n
a
g
e
7,
2
5
0
,
9
0
0
6,8
7
8
,
0
0
0
6,
8
2
0
,
0
0
0
7,
3
3
2
,
0
0
0
6,9
0
9
,
0
0
0
Fe
d
e
r
a
l

T
o
n
n
a
g
e

P
e
r
c
e
n
t
a
g
e
35
.
8
9
9
0
%
36
.
2
2
4
2
%
37
.
4
3
2
6
%
38
.
5
4
3
4
%
28
.
9
6
5
1
%
Mo
n
t
a
n
a

T
a
x
e
s
60
4
,
5
1
3
.
7
4
55
1
,
2
9
7
.
7
3
54
6
,
0
2
9
.
5
1
62
3
,
5
2
3
.
5
4
58
3
,
3
5
5
.
9
3
To
t
a
l

F
e
d
e
r
a
l

R
o
y
a
l
t
i
e
s
49
2
,
6
1
7
.
7
5
49
0
,
5
1
4
.
0
7
50
7
,
7
0
7
.
9
9
54
1
,
5
3
2
.
2
5
38
9
,
2
3
3
.
4
0
3&
4

F
e
d
e
r
a
l

R
o
y
a
l
t
i
e
s
39
4
,
0
9
4
.
2
0
39
2
,
4
1
1
.
2
6
40
6
,
1
6
6
.
3
9
43
3
,
2
2
5
.
8
0
31
1
,
3
8
6
.
7
2
3&
4

S
t
a
t
e

R
o
y
a
l
t
i
e
s
61
,
6
3
4
.
9
4
65
,
5
6
7
.
2
6
17
2
,
7
6
6
.
7
0
27
1
,
7
8
5
.
5
8
24
7
,
8
3
9
.
6
8
To
t
a
l

C
o
s
t
10
,
3
0
1
,
3
6
7
.
4
4
10
,
1
7
7
,
8
2
4
.
2
0
10
,
3
1
4
,
3
2
3
.
7
0
10
,
7
8
8
,
2
4
0
.
4
4
10
,
2
0
6
,
4
6
6
.
1
9
TO
T
A
L

C
O
S
T
/
T
O
N

1.4
2
1
1.
4
8
0
1.5
1
2
1.
4
7
1
1.
4
7
7
Pr
o
p
e
r
t
y

T
a
x

&

D
e
p
r
e
c
i
a
t
i
o
n
Pu
r
c
h
a
s
e
s
Co
s
t

Sa
l
v
a
g
e
Lif
e
Ye
a
r
l
y

D
e
p
r
.
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
No
.

3

B
e
l
t

C
h
a
n
g
e

O
u
t
1,
2
0
0
,
0
0
0
0
20
60
,
0
0
0
.
0
0
0.
0
0
60
,
0
0
0
.
0
0
60
,
0
0
0
.
0
0
60
,
0
0
0
.
0
0
60
,
0
0
0
.
0
0
No
.

4

&

N
o
.

5

B
e
l
t

C
h
a
n
g
e

O
u
t
0
0
10
0.0
0
0.
0
0
0.
0
0
0.
0
0
0.0
0
0.0
0
No
.

2

B
e
l
t

c
h
a
n
g
e

O
u
t
0
0
20
0.0
0
0.
0
0
0.
0
0
0.
0
0
0.0
0
0.0
0
Se
r
v
i
c
e

T
r
u
c
k

(
F
a
c
i
l
i
t
i
e
s
)

2
0
1
3

P
e
t
e
r
b
u
i
l
t

3
3
7
16
9
,
1
0
0
16
,
9
1
0
10
15
,
2
1
9
.
0
0
0.
0
0
0.
0
0
0.
0
0
7,
6
0
9
.
5
0
15
,
2
1
9
.
0
0
Wa
t
e
r

T
r
u
c
k

(
2
0
0
9

I
H
C
)
13
3
,
4
0
0
13
,
3
4
0
10
12
,
0
0
6
.
0
0
0.
0
0
0.
0
0
0.
0
0
6,
0
0
3
.
0
0
12
,
0
0
6
.
0
0
CA
T

2
3
6
B
2

S
k
i
d

S
t
e
e
r

L
o
a
d
e
r
41
,
0
0
0
4,1
0
0
10
3,
6
9
0
.
0
0
92
2
.
5
0
3,6
9
0
.
0
0
3,6
9
0
.
0
0
3,
6
9
0
.
0
0
3,
6
9
0
.
0
0
Du
s
t

S
u
p
p
r
e
s
s
i
o
n

S
y
s
t
e
m

-

T
e
s
t

&

I
n
s
t
a
l
l
47
5
,
0
0
0
0
10
47
,
5
0
0
.
0
0
35
,
6
2
5
.
0
0
47
,
5
0
0
.
0
0
47
,
5
0
0
.
0
0
47
,
5
0
0
.
0
0
47
,
5
0
0
.
0
0
To
t
a
l
36
,
5
4
7
.
5
0
11
1
,
1
9
0
.
0
0
11
1
,
1
9
0
.
0
0
12
4
,
8
0
2
.
5
0
13
8
,
4
1
5
.
0
0
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

T
r
a
n
s
p
o
r
t
a
t
i
o
n
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
2015 AOP Final Version
Colstrip 3&4
9.0ICNU_DR_183 Attachment A Page 51 of 54
We
s
t
m
o
r
e
l
a
n
d

C
o
a
l

C
o
m
p
a
n
y
Co
s
t

b
y

S
u
b

b
y

C
a
t
e
g
o
r
y

C
o
d
e

-
-

B
u
d
g
e
t
/
F
o
r
e
c
a
s
t
Co
n
v
e
y
o
r
20
1
5

A
O
P

B
u
d
g
e
t
De
s
c
r
i
p
t
i
o
n
Ja
n
u
a
r
y

20
1
5

Fe
b
r
u
a
r
y

20
1
5

Ma
r
c
h

20
1
5

Ap
r
i
l

2
0
1
5

Ma
y

2
0
1
5

Ju
n
e

2
0
1
5

Ju
l
y

2
0
1
5

Au
g
u
s
t

20
1
5

Se
p
t
e
m
b
e
r

20
1
5

Oc
t
o
b
e
r

20
1
5

No
v
e
m
b
e
r

20
1
5

De
c
e
m
b
e
r

20
1
5

To
t
a
l

2
0
1
5
To
t
a
l

2
0
1
4

AO
P

f
o
r

20
1
5
Va
r
i
a
n
c
e
35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

L
a
b
o
r
79
,
0
3
2

79
,
0
3
2

79
,
0
3
2

79
,
0
3
2

79
,
0
3
2

79
,
0
3
2

79
,
0
3
2

79
,
0
3
2

79
,
0
3
2

79
,
0
3
2

79
,
0
3
2

79
,
0
3
2

94
8
,
3
8
8

89
5
,
2
2
4

53
,
1
6
5

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

E
q
u
i
p
m
e
n
t
82
,
5
8
1

82
,
5
8
1

82
,
5
8
1

82
,
5
8
1

82
,
5
8
1

82
,
5
8
1

82
,
5
8
1

82
,
5
8
1

82
,
5
8
1

82
,
5
8
1

82
,
5
8
1

82
,
5
8
1

99
0
,
9
7
3

87
8
,
2
1
0

11
2
,
7
6
3

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

E
l
e
c
t
r
i
c
i
t
y
55
,
8
9
9

50
,
5
2
0

55
,
7
7
6

39
,
3
8
5

39
,
3
4
7

31
,
5
4
4

44
,
1
8
0

45
,
4
0
4

44
,
4
4
2

55
,
3
5
7

53
,
5
9
5

53
,
5
9
5

56
9
,
0
4
2

52
6
,
5
0
0

42
,
5
4
2

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
2,8
1
3

2,
8
1
3

2,
8
1
3

2,8
1
3

2,
8
1
3

2,
8
1
3

2,
8
1
3

2,8
1
3

2,
8
1
3

2,
8
1
3

2,
8
1
3

2,
8
1
3

33
,
7
6
0

32
,
5
3
5

1,2
2
5

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
44
2

44
2

44
2

44
2

44
2

44
2

44
2

44
2

44
2

44
2

44
2

44
2

5,
3
0
4

5,1
1
2

19
2

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
17
5

17
5

17
5

17
5

17
5

17
5

17
5

17
5

17
5

17
5

17
5

17
5

2,
1
0
0

2,0
2
3

76

35
6
0
0

T
o
t
a
l

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g
22
0
,
9
4
3

21
5
,
5
6
3

22
0
,
8
2
0

20
4
,
4
2
9

20
4
,
3
9
1

19
6
,
5
8
8

20
9
,
2
2
4

21
0
,
4
4
8

20
9
,
4
8
6

22
0
,
4
0
1

21
8
,
6
3
8

21
8
,
6
3
8

2,
5
4
9
,
5
6
8

2,
3
3
9
,
6
0
5

20
9
,
9
6
3

To
t
a
l

C
o
a
l

H
a
n
d
l
i
n
g
22
0
,
9
4
3

21
5
,
5
6
3

22
0
,
8
2
0

20
4
,
4
2
9

20
4
,
3
9
1

19
6
,
5
8
8

20
9
,
2
2
4

21
0
,
4
4
8

20
9
,
4
8
6

22
0
,
4
0
1

21
8
,
6
3
8

21
8
,
6
3
8

2,
5
4
9
,
5
6
8

2,
3
3
9
,
6
0
5

20
9
,
9
6
3

45
0
0
0

P
r
o
d
u
c
t
i
o
n

S
a
l
a
r
y

L
a
b
o
r
7,9
1
4

7,
9
1
4

7,
9
1
4

7,9
1
4

7,
9
1
4

7,
9
1
4

7,
9
1
4

7,9
1
4

7,
9
1
4

7,
9
1
4

7,
9
1
4

7,
9
1
4

94
,
9
6
6

10
4
,
8
4
3

(9
,
8
7
7
)

45
0
0
0

P
r
o
d
u
c
t
i
o
n

E
q
u
i
p
m
e
n
t
11
,
9
0
9

11
,
9
0
9

11
,
9
0
9

11
,
9
0
9

11
,
9
0
9

11
,
9
0
9

11
,
9
0
9

11
,
9
0
9

11
,
9
0
9

11
,
9
0
9

11
,
9
0
9

11
,
9
0
9

14
2
,
9
1
0

18
3
,
4
9
2

(4
0
,
5
8
2
)

45
0
0
0

P
r
o
d
u
c
t
i
o
n

F
u
e
l
39
7

39
7

39
7

39
7

39
7

39
7

39
7

39
7

39
7

39
7

39
7

39
7

4,
7
6
5

5,1
1
9

(3
5
4
)

45
0
0
0

T
o
t
a
l

P
r
o
d
u
c
t
i
o
n
20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

24
2
,
6
4
1

29
3
,
4
5
4

(5
0
,
8
1
3
)

To
t
a
l

O
t
h
e
r

P
r
o
d
u
c
t
i
o
n
20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

20
,
2
2
0

24
2
,
6
4
1

29
3
,
4
5
4

(5
0
,
8
1
3
)

60
0
5
0

S
a
f
e
t
y

L
a
b
o
r
-
-
-
-
-
-
-
-
-
-
-
-
-
15
,
3
6
0

(1
5
,
3
6
0
)

60
0
5
0

T
o
t
a
l

S
a
f
e
t
y
-
-
-
-
-
-
-
-
-
-
-
-
-
15
,
3
6
0

(1
5
,
3
6
0
)

60
1
0
0

T
r
a
i
n
/
I
n
s
p
e
c
t

L
a
b
o
r
2,3
5
7

2,
3
5
7

2,
3
5
7

2,3
5
7

2,
3
5
7

2,
3
5
7

2,
3
5
7

2,3
5
7

2,
3
5
7

2,
3
5
7

2,
3
5
7

2,
3
5
7

28
,
2
8
6

27
,
2
5
9

1,0
2
6

60
1
0
0

T
r
a
i
n
/
I
n
s
p
e
c
t

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
44
2

44
2

44
2

44
2

44
2

44
2

44
2

44
2

44
2

44
2

44
2

44
2

5,
3
0
4

5,1
1
2

19
2

60
1
0
0

T
o
t
a
l

T
r
a
i
n
/
I
n
s
p
e
c
t
2,7
9
9

2,
7
9
9

2,
7
9
9

2,7
9
9

2,
7
9
9

2,
7
9
9

2,
7
9
9

2,7
9
9

2,
7
9
9

2,
7
9
9

2,
7
9
9

2,
7
9
9

33
,
5
9
0

32
,
3
7
1

1,2
1
9

65
2
0
0

W
a
r
e
h
o
u
s
e

S
a
l
a
r
y

L
a
b
o
r
1,7
4
5

1,
7
4
5

1,
7
4
5

1,7
4
5

1,
7
4
5

1,
7
4
5

1,
7
4
5

1,7
4
5

1,
7
4
5

1,
7
4
5

1,
7
4
5

1,
7
4
5

20
,
9
4
0

26
,
1
8
6

(5
,
2
4
5
)

65
2
0
0

W
a
r
e
h
o
u
s
e

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
18
4

18
4

18
4

18
4

18
4

18
4

18
4

18
4

18
4

18
4

18
4

18
4

2,
2
1
0

23
4
,
7
8
6

(2
3
2
,
5
7
6
)

65
2
0
0

T
o
t
a
l

W
a
r
e
h
o
u
s
e
1,9
2
9

1,
9
2
9

1,
9
2
9

1,9
2
9

1,
9
2
9

1,
9
2
9

1,
9
2
9

1,9
2
9

1,
9
2
9

1,
9
2
9

1,
9
2
9

1,
9
2
9

23
,
1
5
1

26
0
,
9
7
2

(2
3
7
,
8
2
2
)

To
t
a
l

O
t
h
e
r

S
u
p
p
o
r
t
4,7
2
8

4,
7
2
8

4,
7
2
8

4,7
2
8

4,
7
2
8

4,
7
2
8

4,
7
2
8

4,7
2
8

4,
7
2
8

4,
7
2
8

4,
7
2
8

4,
7
2
8

56
,
7
4
1

30
8
,
7
0
4

(2
5
1
,
9
6
3
)

Su
b

T
o
t
a
l
24
5
,
8
9
1

24
0
,
5
1
2

24
5
,
7
6
8

22
9
,
3
7
7

22
9
,
3
3
9

22
1
,
5
3
6

23
4
,
1
7
2

23
5
,
3
9
6

23
4
,
4
3
4

24
5
,
3
4
9

24
3
,
5
8
7

24
3
,
5
8
7

2,
8
4
8
,
9
4
9

2,
9
4
1
,
7
6
3

(9
2
,
8
1
3
)

To
t
a
l

V
a
r
i
a
b
l
e

C
o
s
t
24
5
,
8
9
1

24
0
,
5
1
2

24
5
,
7
6
8

22
9
,
3
7
7

22
9
,
3
3
9

22
1
,
5
3
6

23
4
,
1
7
2

23
5
,
3
9
6

23
4
,
4
3
4

24
5
,
3
4
9

24
3
,
5
8
7

24
3
,
5
8
7

2,
8
4
8
,
9
4
9

2,
9
4
1
,
7
6
3

(9
2
,
8
1
3
)

2015 AOP Final Version
Colstrip 3&4
9.1ICNU_DR_183 Attachment A Page 52 of 54
We
s
t
m
o
r
e
l
a
n
d

C
o
a
l

C
o
m
p
a
n
y
Co
s
t

b
y

S
u
b

b
y

C
a
t
e
g
o
r
y

C
o
d
e

-
-

B
u
d
g
e
t
/
F
o
r
e
c
a
s
t
Co
n
v
e
y
o
r
20
1
6

-

2
0
1
9
20
1
5

A
O
P

B
u
d
g
e
t
De
s
c
r
i
p
t
i
o
n
1s
t

Q
t
r
.

2
0
1
6
2n
d

Q
t
r
.

2
0
1
6
3r
d

Q
t
r
.

2
0
1
6
4t
h

Q
t
r
.

2
0
1
6
To
t
a
l

2
0
1
6
To
t
a
l

2
0
1
7
To
t
a
l

2
0
1
8
To
t
a
l

2
0
1
9
35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

L
a
b
o
r
24
4
,
2
1
0

24
4
,
2
1
0

24
4
,
2
1
0

24
4
,
2
1
0

97
6
,
8
4
0

1,
0
0
6
,
1
4
5

1,
0
3
6
,
3
2
9

1,
0
6
7
,
4
1
9

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

E
q
u
i
p
m
e
n
t
25
5
,
1
7
6

25
5
,
1
7
6

25
5
,
1
7
6

25
5
,
1
7
6

1,
0
2
0
,
7
0
2

1,
0
5
1
,
3
2
3

1,
0
8
2
,
8
6
3

1,
1
1
5
,
3
4
9

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

E
l
e
c
t
r
i
c
i
t
y
14
7
,
0
0
2

14
7
,
0
0
2

14
7
,
0
0
2

14
7
,
0
0
2

58
8
,
0
0
9

60
5
,
6
5
0

62
3
,
8
1
9

64
2
,
5
3
4

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

O
u
t
s
i
d
e

S
e
r
v
i
c
e
s
8,
6
9
3

8,
6
9
3

8,
6
9
3

8,
6
9
3

34
,
7
7
3

35
,
8
1
6

36
,
8
9
1

37
,
9
9
7

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
1,
3
6
6

1,
3
6
6

1,
3
6
6

1,
3
6
6

5,
4
6
4

5,
6
2
7

5,
7
9
6

5,
9
7
0

35
6
0
0

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
54
1

54
1

54
1

54
1

2,
1
6
3

2,
2
2
8

2,
2
9
4

2,
3
6
3

35
6
0
0

T
o
t
a
l

C
r
u
s
h
i
n
g
/
H
a
n
d
l
i
n
g
65
6
,
9
8
8

65
6
,
9
8
8

65
6
,
9
8
8

65
6
,
9
8
8

2,
6
2
7
,
9
5
1

2,
7
0
6
,
7
8
9

2,
7
8
7
,
9
9
3

2,
8
7
1
,
6
3
3

To
t
a
l

C
o
a
l

H
a
n
d
l
i
n
g
65
6
,
9
8
8

65
6
,
9
8
8

65
6
,
9
8
8

65
6
,
9
8
8

2,
6
2
7
,
9
5
1

2,
7
0
6
,
7
8
9

2,
7
8
7
,
9
9
3

2,
8
7
1
,
6
3
3

45
0
0
0

P
r
o
d
u
c
t
i
o
n

S
a
l
a
r
y

L
a
b
o
r
24
,
4
5
4

24
,
4
5
4

24
,
4
5
4

24
,
4
5
4

97
,
8
1
5

10
3
,
2
7
0

10
6
,
3
6
8

10
9
,
5
5
9

45
0
0
0

P
r
o
d
u
c
t
i
o
n

E
q
u
i
p
m
e
n
t
37
,
9
0
3

37
,
9
0
3

37
,
9
0
3

37
,
9
0
3

15
1
,
6
1
3

15
6
,
1
6
2

16
0
,
8
4
7

16
5
,
6
7
2

45
0
0
0

P
r
o
d
u
c
t
i
o
n

F
u
e
l
1,
2
6
4

1,
2
6
4

1,
2
6
4

1,
2
6
4

5,
0
5
5

5,
2
0
7

5,
3
6
3

5,
5
2
4

45
0
0
0

T
o
t
a
l

P
r
o
d
u
c
t
i
o
n
63
,
6
2
1

63
,
6
2
1

63
,
6
2
1

63
,
6
2
1

25
4
,
4
8
3

26
4
,
6
3
8

27
2
,
5
7
7

28
0
,
7
5
4

To
t
a
l

O
t
h
e
r

P
r
o
d
u
c
t
i
o
n
63
,
6
2
1

63
,
6
2
1

63
,
6
2
1

63
,
6
2
1

25
4
,
4
8
3

26
4
,
6
3
8

27
2
,
5
7
7

28
0
,
7
5
4

60
1
0
0

T
r
a
i
n
/
I
n
s
p
e
c
t

L
a
b
o
r
7,
2
8
4

7,
2
8
4

7,
2
8
4

7,
2
8
4

29
,
1
3
4

30
,
0
0
8

30
,
9
0
8

31
,
8
3
6

60
1
0
0

T
r
a
i
n
/
I
n
s
p
e
c
t

M
a
t
e
r
i
a
l
s

&

S
u
p
p
l
i
e
s
1,
3
6
6

1,
3
6
6

1,
3
6
6

1,
3
6
6

5,
4
6
4

5,
6
2
7

5,
7
9
6

5,
9
7
0

60
1
0
0

T
o
t
a
l

T
r
a
i
n
/
I
n
s
p
e
c
t
8,
6
4
9

8,
6
4
9

8,
6
4
9

8,
6
4
9

34
,
5
9
8

35
,
6
3
6

36
,
7
0
5

37
,
8
0
6

65
2
0
0

W
a
r
e
h
o
u
s
e

S
a
l
a
r
y

L
a
b
o
r
5,
3
9
2

5,
3
9
2

5,
3
9
2

5,
3
9
2

21
,
5
6
9

22
,
2
1
6

22
,
8
8
2

23
,
5
6
9

65
2
0
0

W
a
r
e
h
o
u
s
e

C
o
m
m
o
n

A
l
l
o
c
a
t
i
o
n
56
9

56
9

56
9

56
9

2,
2
7
6

2,
3
4
5

2,
4
1
5

2,
4
8
8

65
2
0
0

T
o
t
a
l

W
a
r
e
h
o
u
s
e
5,
9
6
1

5,
9
6
1

5,
9
6
1

5,
9
6
1

23
,
8
4
5

24
,
5
6
0

25
,
2
9
7

26
,
0
5
6

To
t
a
l

O
t
h
e
r

S
u
p
p
o
r
t
14
,
6
1
1

14
,
6
1
1

14
,
6
1
1

14
,
6
1
1

58
,
4
4
3

60
,
1
9
6

62
,
0
0
2

63
,
8
6
2

Su
b

T
o
t
a
l
73
5
,
2
1
9

73
5
,
2
1
9

73
5
,
2
1
9

73
5
,
2
1
9

2,
9
4
0
,
8
7
7

3,
0
3
1
,
6
2
3

3,
1
2
2
,
5
7
2

3,
2
1
6
,
2
4
9

To
t
a
l

V
a
r
i
a
b
l
e

C
o
s
t
73
5
,
2
1
9

73
5
,
2
1
9

73
5
,
2
1
9

73
5
,
2
1
9

2,
9
4
0
,
8
7
7

3,
0
3
1
,
6
2
3

3,
1
2
2
,
5
7
2

3,
2
1
6
,
2
4
9

2015 AOP Final Version
Colstrip 3&4
9.2ICNU_DR_183 Attachment A Page 53 of 54
De
s
c
r
i
p
t
i
o
n
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
3
&

4

T
o
t
a
l

T
o
n
s
7,
2
5
0
,
9
0
0
.
0
0
6,
8
7
8
,
0
0
0
.
0
0
6,
8
2
0
,
0
0
0
.
0
0
7,
3
3
2
,
0
0
0
.
0
0
6,
9
0
9
,
0
0
0
.
0
0
3
&

4

F
e
d
e
r
a
l

T
o
n
s
2,
6
0
3
,
0
0
0
.
0
0
2,
4
9
1
,
5
0
0
.
0
0
2,
5
5
2
,
9
0
0
.
0
0
2,
8
2
6
,
0
0
0
.
0
0
2,
0
0
1
,
2
0
0
.
0
0
Fe
d
e
r
a
l

P
e
r
c
e
n
t
a
g
e

35
.
9
0
%
36
.
2
2
%
37
.
4
3
%
38
.
5
4
%
28
.
9
7
%
Fe
d
e
r
a
l

C
o
n
v
e
y
o
r

R
e
v
e
n
u
e
s
3,
5
4
5
,
9
0
6
.
7
0
3,
5
3
1
,
4
4
6
.
3
6
3,
6
5
4
,
9
6
2
.
6
0
3,
8
9
9
,
0
6
5
.
2
3
2,
8
0
3
,
2
2
7
.
5
3
Re
v
e
n
u
e

P
e
r

T
o
n
1.
3
6
2
1.
4
1
7
1.
4
3
2
1.
3
8
0
1.
4
0
1
[1
-
(
1
2
.
5
%
x
8
0
%
)
]
.
Re
v
e
n
u
e

P
e
r

t
o
n

(
w
/

g
r
o
s
s
-
u
p
)
1.
5
1
1.
5
8
1.
5
9
1.
5
3
1.
5
6
Ro
y
a
l
t
y

R
a
t
e

P
e
r

T
o
n
0.
1
8
9
2
5
0
0.
1
9
6
8
7
5
0.
1
9
8
8
7
5
0
0.
1
9
1
6
2
5
0
0.
1
9
4
5
0
0
0
To
t
a
l

R
o
y
a
l
t
y

D
u
e
$4
9
2
,
6
1
7
.
7
5
$4
9
0
,
5
1
4
.
0
7
$5
0
7
,
7
0
7
.
9
9
$5
4
1
,
5
3
2
.
2
5
$3
8
9
,
2
3
3
.
4
0
3&
4

A
m
o
u
n
t
$3
9
4
,
0
9
4
.
2
0
$3
9
2
,
4
1
1
.
2
6
$4
0
6
,
1
6
6
.
3
9
$4
3
3
,
2
2
5
.
8
0
$3
1
1
,
3
8
6
.
7
2
WE
C
o
'
s

A
m
o
u
n
t
$9
8
,
5
2
3
.
5
5
$9
8
,
1
0
2
.
8
1
$1
0
1
,
5
4
1
.
6
0
$1
0
8
,
3
0
6
.
4
5
$7
7
,
8
4
6
.
6
8
De
s
c
r
i
p
t
i
o
n
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
3
&

4

T
o
t
a
l

T
o
n
s
7,
2
5
0
,
9
0
0
.
0
0
6,
8
7
8
,
0
0
0
.
0
0
6,
8
2
0
,
0
0
0
.
0
0
7,
3
3
2
,
0
0
0
.
0
0
6,
9
0
9
,
0
0
0
.
0
0
3
&

4

S
t
a
t
e

T
o
n
s
40
7
,
1
0
0
.
0
0
41
6
,
3
0
0
.
0
0
1,
0
8
5
,
9
0
0
.
0
0
1,
7
7
2
,
9
0
0
.
0
0
1,
5
9
2
,
8
0
0
.
0
0
St
a
t
e

P
e
r
c
e
n
t
a
g
e

5.
6
1
%
6.
0
5
%
15
.
9
2
%
24
.
1
8
%
23
.
0
5
%
St
a
t
e

C
o
n
v
e
y
o
r

R
e
v
e
n
u
e
s
55
4
,
5
6
7
.
2
7
59
0
,
0
6
2
.
6
6
1,
5
5
4
,
6
7
2
.
6
8
2,
4
4
6
,
0
9
0
.
8
5
2,
2
3
1
,
1
5
1
.
7
1
Re
v
e
n
u
e

P
e
r

T
o
n
1.
3
6
2
1.
4
1
7
1.
4
3
2
1.
3
8
0
1.
4
0
1
/[
1
-
(
1
2
.
5
%
x
8
0
%
)
]
Re
v
e
n
u
e

P
e
r

t
o
n

(
w
/

g
r
o
s
s
-
u
p
)
1.
5
1
4
1.
5
7
5
1.
5
9
1
1.
5
3
3
1.
5
5
6
Ro
y
a
l
t
y

R
a
t
e

P
e
r

T
o
n
0.
1
8
9
2
5
0
0.
1
9
6
8
7
5
0.
1
9
8
8
7
5
0.
1
9
1
6
2
5
0.
1
9
4
5
0
0
To
t
a
l

R
o
y
a
l
t
y

D
u
e
77
,
0
4
3
.
6
8
81
,
9
5
9
.
0
7
21
5
,
9
5
8
.
3
7
33
9
,
7
3
1
.
9
7
30
9
,
7
9
9
.
6
0
3&
4

A
m
o
u
n
t
61
,
6
3
4
.
9
4
65
,
5
6
7
.
2
6
17
2
,
7
6
6
.
7
0
27
1
,
7
8
5
.
5
8
24
7
,
8
3
9
.
6
8
WE
C
o
'
s

A
m
o
u
n
t
15
,
4
0
8
.
7
4
16
,
3
9
1
.
8
1
43
,
1
9
1
.
6
7
67
,
9
4
6
.
3
9
61
,
9
5
9
.
9
2
We
s
t
e
r
n

E
n
e
r
g
y

C
o
m
p
a
n
y
Mi
n
e

O
p
e
r
a
t
i
n
g

C
o
m
m
i
t
t
e
e
3&
4

C
o
n
t
r
a
c
t
20
1
5

A
O
P
Co
n
v
e
y
o
r

R
o
y
a
l
t
i
e
s
2015 AOP Final Version
Colstrip 3&4
9.3ICNU_DR_183 Attachment A Page 54 of 54

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: Thomas C Dempsey
TYPE: Data Request DEPT: Generation Production Support
REQUEST NO.: ICNU – 183 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the Western Energy Company (“WECO”) 2015 Annual Operating Plan used to forecast Colstrip fuel prices in this proceeding.

RESPONSE:
The 2015 WECO Annual Operating Plan is attached (ICNU_DR_183 Attachment A).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/28/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Scott Kinney
REQUESTER: ICNU RESPONDER: Tara Moses
TYPE: Data Request DEPT: Resource Accounting
REQUEST NO.: ICNU – 184 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Provide the actual WECO results used to establish the cost of coal for the Colstrip facility for the periods 2010 through 2014. Please provide the results in their native format, in the same manner as received by
the Company.

RESPONSE: Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 184C. Please note that
Avista’s response to ICNU – 184C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.
Invoices from WECO for the periods 2012-2014 are attached as ICNU_DR_184-Attachment A through
C. Invoices from WECO for the periods 2010-2011 are not readily available.

Internal workbooks that track the cost of Coal, Transportation, Royalties and True-ups as invoiced by
WECO are attached for the periods 2010-2014 as ICNU_DR_184 – Attachment D through H.
Due to the voluminous nature of these attachments they are being provided in electronic format only.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: Thomas C Dempsey
TYPE: Data Request DEPT: Generation Production Support
REQUEST NO.: ICNU – 185 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all contract notifications and correspondence received from, or sent to, PPL Montana regarding PPL Montana’s decision to spin-off its ownership interest in Colstrip into Talen Energy

RESPONSE:
No such notifications or correspondence has been received or sent by Avista.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 186 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a copy of the contracts underlying the line entitled “SMUD Sale - (Energy America)” in Exh. No. WGJ-2.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 186C. Please note that
Avista’s response to ICNU – 186C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

Please see ICNU_DR_186C Confidential Attachments A - C for a copy of the contracts.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 187 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a narrative explanation for the $9.7 million reduction to revenues associated with the contract entitled “SMUD Sale - (Energy America)” in Exh. No. WGJ-2 between the test period and the
2016 pro-forma period.

RESPONSE:
Please see the Company’s response to ICNU_DR_174.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 188 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please reconcile the revenues calculated in the AURORA Model for the contract entitled “SMUD Sale - (Energy America),” with the level of revenue calculated in Exh. No. WGJ-2.

RESPONSE:
Please see the Company’s response to ICNU_DR_174.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 189 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a narrative explanation for the $5.7 million increase in the cost of the “Rocky Reach/Rock Island Purchase” payments between the test period and the 2016 pro-forma period as detailed in Exh. No.
WGJ-2. In addition, provide all documents that support the $5/7 million increase.

RESPONSE:
Please see the Company’s response to Staff_DR_059. The Rocky Reach/Rock Island purchase expense is
now a known expense and not an estimate. The purchase in 2016 is a 5% share versus a 3% share in the
test-year.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 186 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a copy of the contracts underlying the line entitled “SMUD Sale - (Energy America)” in Exh. No. WGJ-2.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 186C. Please note that
Avista’s response to ICNU – 186C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

Please see ICNU_DR_186C Confidential Attachments A - C for a copy of the contracts.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 191 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an explanation, including all supporting documentation and workpapers, regarding how the Company forecasts the price for the contract entitled “Rocky Reach/Rock Island Purchase” included
in Exh. No. WGJ-2.

RESPONSE:
Please see the Company’s response to ICNU_DR_189.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 192 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an explanation, including all supporting documentation and workpapers, of the 65%/35% HLH/LLH market price weighting used to forecast the predicted auction price for the Priest Rapids
project in the pro forma period. See workbook “UE-15____Johnson Exhibit WGJ-2,4,5 (AVA_Feb15),”
sheet “Index”, cell “D26:O26.”

RESPONSE:
Grant conducts an annual auction that sets the price that Avista pays for its Meaningful Priority share of
the Priest Rapids Project (includes both the Priest Rapids and Wanapum developments). Historically, the
winner bidder has priced their bid at the forward energy price plus an adder for capacity and other ancillary products provided by a slice hydro share less an adjustment for hydro risk. One of those additional products provided by a slice purchase is the ability to load factor the slice output, i.e.,
proportionately more energy can be scheduled into heavy load hours than light load hours. The 65%/35%
HLH/LLH market price weighting used to forecast the predicted auction price is Avista’s estimate of what
bidders will use as the load shape in developing their bid. Avista’s estimate of Priest Rapids Projects costs assume a bidder will pay a premium over forward energy
prices for the additional products provided by a slice hydro resource. Without knowing exactly what
winning bidders have assumed for energy amount or forward prices, Avista has estimated that the
premium paid in past auctions has ranged from $2/MWh to $6/MWh. Grant will conduct the auction in late October or early November. Once the auctions occurs, Avista will
know that piece of the total Priest Rapids Project cost equation. Then, on or around December 1, Grant
provides a final pro forma that sets the final total price for 2016, including the auction price, project cost
and the amount of Reasonable Portion revenue (auction revenue) that Grant will need to buy power to meet its load in excess of its share of the Project.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 193 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an explanation, including all supporting documentation and workpapers, of the $5/MWh adder included predicted auction price for the Priest Rapids project in the pro forma period. See
workbook “UE-15____Johnson Exhibit WGJ-2,4,5 (AVA_Feb15),” sheet “Index,” cell “D26:O26.”

RESPONSE: Please see the Company’s response to ICNU_DR_192.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 194 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the contracts underlying the line item entitled “Palouse Wind” in Exh. No. WGJ-2. RESPONSE:

Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 190C. Please note that Avista’s response to ICNU – 194C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

Please see ICNU_DR_194C Confidential Attachment A for a copy of the contract.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/24/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 195 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide an explanation of apprentice credits and how those credits are incorporated into the price paid for Palouse Wind output. See, e.g., comment in AURORA workpaper “XDB WA 2016 Filing_80
Years_Test_Period_Load_040315_Fix,” sheet “Cost ($000s),” cell “B47.”

RESPONSE: The apprentice credit increases the Palouse Wind contract price by $1/MWh, which has been included in
the pro forma Palouse Wind expense. The apprentice credit allows each REC generated by Palouse Wind
to count as 1.2 RECs for purposes of complying with the Washington Energy Independence Act. While
not a tradable REC, the apprentice credit frees up other RECs for sale.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/12/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 196 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to WAC § 480-07-510(3)(e)(i). Please provide a work paper demonstrating how the Company’s proposed electric rate adjustment in this proceeding would be calculated under the
methodology most recently accepted or authorized for the Company, excluding methodologies underlying
settlements unless specifically accepted by the Commission in a settlement order (i.e., the most recently
authorized method used prior to the Company’s proposed methodological changes via attrition and pro
forma cross-check calculations). RESPONSE:

Please see workpapers included with original filing supporting both the pro forma and attrition studies. With respect to attrition, the Commission, in Dockets UE-120436 and UG-120437, found that, “on the basis of the evidence presented, that consideration of attrition in setting rates for 2013 is appropriate.”
(Id., at Para.10.) In that proceeding, the attrition adjustment in the Multiparty Settlement was contested,
and while the Commission did not specifically endorse the Staff’s or the Company’s attrition
methodology, it did find that the “trending data supplied by Avista, wherein the Company pledged to continue its multi-year capital program for both 2013 and 2014, forms a cornerstone of our approval of the two-step rate increases.” (Id., at Para. 73)

Workpapers provided in the present case, along with pre-filed testimony, provides the same type of
trending data relied upon by the Commission in Dockets UE-120436 and UG-120437. Similar trending data was supplied in support of the attrition analysis in the subsequent Dockets UE-140188 and UG-140189. In these prior Dockets, workpapers also supported the pro forma studies.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 197 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to ICNU Data Request (“DR”) 40 and the Company’s response. Besides the information provided in the Company’s response to ICNU DR 40, has the Company conducted any studies of the
economic impact upon ratepayers that may result from the annual rate increases forecasted by Avista?

RESPONSE: No, the Company has not conducted studies of the economic impact of current or future rate increases on
its ratepayers.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/03/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Scott Kinney
REQUESTER: ICNU RESPONDER: Jacob Reidt/Karen Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU - 198 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exhibit No. __ (SJK-1T) at 13. What is the currently expected operational date for the Nine Mile Redevelopment? If later than 2016, please provide expected capital costs beyond 2016.
RESPONSE:
The Nine Mile rehabilitation project consists of several projects. The two main projects consist of the
Tailrace Gate System and the completion of Units 1 and 2. The Tailrace Gate System is expected to be operational in August of 2015. The Company had originally expected Units 1 and 2 to be operational in
December of 2015 and now the revised schedule shows a September of 2016 completion date. There are
three main reasons for the delay of Units 1 and 2:
1. Delays to dewatering the plant
a. The Company assumed that the stoplog slot conditions would support the tailrace gates with minimal modifications. However, when the contractor did the inspection of the slots,
they found the stoplog slots were in poor condition and required installation of embedded
steel guides and sills. This additional design and fabrication added approximately five-
months to the scheduled dewatering.
b. The delayed dewatering impacted the ability to complete the demolition of the powerhouse. Portions of the powerhouse were not accessible for demolition until after the
dewatering was complete.
2. Delays to powerhouse demolition
a. Due to the plant not being dewatered, a new means and method was selected to complete
demolition, use of a Brokk robot vs. saw cutting, was selected, delaying the demolition from mid March to mid June 2015.
b. Delays to the demolition will impact concrete placement and placement of the new
equipment.
3. Electrical Completion
a. The Company assumed that the cable tray system would be supported by an “off the shelf” solution because it would be lower than ten feet and would not require additional design,
fabrication, or more than approximately 2 months to install. However the final design of
the cable tray system was higher than ten feet due to the final electrical design. An “off-
the shelf” support solution was not viable and a specialized support structure is necessary.
The additional design, fabrication, and installation could take up to nine months. b. The Electrical Completion Design Package was expected to be completed by December
2014 but was delayed to May 2015 due to the delayed delivery of information from
equipment suppliers and equipment installers.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 199 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to ICNU Data Request (“DR”) 65 and the Company’s response. For the role of “project manager,” please explain the positions or ranks within the Company from which project managers are
customarily drawn.

RESPONSE:
Project managers are generally drawn from employees who have the technical requirements and
knowledge from the relevant functional area that matches the complexity of the project. These
individuals report to the relevant functional area managers or directors.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/27/15
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU - 200 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exhibit (“Exh.”) No. KKS-5 and the Company’s response to ICNU DR 007. Please explain and reconcile all differences between the “Assessment Score” for particular business cases
contained in Exh. No. KKS-5 and the “Assessment Score” for the same cases listed in the Company’s
response to ICNU DR 007.

RESPONSE: Some of the Business Case forms included in KKS-5 had a printing problem in the assessment score box,
when they were printed. The following business cases have been reprinted showing the assessment score
and are attached:

• ET-06 - Enterprise Security
• ET-07 - Technology Expansion to Enable Business Process Program Business Case
• ETD-01 - Colstrip Transmission
• ETD-06 - Distribution Wood Pole Management
• ETD-07 - Minor Meter Blanket
• ETD-11 - Transmission - Reconductors and Rebuilds
• ETD-23 - Clearwater Sub Upgrades
• ETD-25 - Harrington Upgrades
• ETD-28 - Transmission - Asset Management
• ETD-30 - Transmission - NERC Low Priority Lines Mitigation Work
• ETD-31 - Transmission - NERC Med Priority Lines Mitigation Work
• ETD-32 - SCADA - SOO and BUCC
• ETD-35 - Street Light Management
• ETD-36 - Westside Rebuild Phase One
• ETD-37 - Washington AMI Project
• G-06 - Apprentice Training
• G-10 - COF LngTrm Restruct Ph2
• GP-01 - Base Load Hydro
• GP-06 - Nine Mile Rehab Program
• GP-10 - Peaking Generation
• GP-16 - Cabinet Unit 1 Rehab
• NGD-06 - Gas Telemetry Program
• NGD-08 - Gas Overbuilt Pipe Replacement Program
• NGD-13 - Gas Goldendale HP Main Reinforcement Project

Page 2 of 2
• NGD-14 - Gas N-S Corridor Greene St HP Main Project
• NGD-15 - Gas ERT Replacement Program
• T-01 - Fleet Budget
All other business case assessment scores reconcile to what is included in KKS-5.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/22/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 201 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to ICNU DR 69 and the Company’s response. Please provide, from January 2012 to the present, a chart, graph, spreadsheet, or other form of presentation illustrating the amount of capital
spending approved by the Capital Planning Group for each and every month, inclusive of all months from
January 2012 to the present.

RESPONSE:
Business case owners submit requests for additional funds that are needed based on changing needs and
priorities. These requests for additional funds are reviewed and approved or remain pending depending on
the priority level and the amount of capital funding that is available. Business case owners are also expected to release funds that will not be spent during the year so that pending requests may be
funded. These approvals and releases are balanced such that the capital spending target will be met at the
end of the year.

ICNU_DR_201 Attachment A details the capital target, approvals and releases on a monthly basis. At the end of the years 2012 – 2014 the expected spend variance was less than a 1% variance from target.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/27/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU - 202 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to ICNU DR 70 and the Company’s response. Please identify and provide the “variances between the approved amount” of the original forecasted capital budgets, as approved by the Finance
Committee of the Board, “and the amounts listed in Table 1” of Ms. Schuh’s direct testimony.

RESPONSE:
Please see the table below for variances between the filed case and what was approved by the finance
committee of the board of directors. In all years except 2009, there are immaterial variances. The
Company inadvertently included the incorrect amount for this year. With this correction, the overall total
nine year average decreases 1%, which continues to show that the Company has generally spent close to
or more than budgeted for several years.

Planned
Expenditures
Actual
Expenditures
Planned
Expenditures
($ millions) ($ millions)($ millions)
Nine Year Average $232.48 102%$236.18 $234.90 101%
Actual as a
Percentage of
Planned
TABLE NO. 1
Planned vs. Actual Expenditures
Actual as a
Percentage of
Planned
PER FC BOD MINS. PER FILED CASE

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Lauren Pendergraft
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 203 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exh. No. MTT-1T at 10:5-6. Please provide any studies considered by the Company concerning “the degree of overall rate pressure faced by our customers” when setting the
overall level of capital investments each year.

RESPONSE:
Planned capital investments, and the need for increased revenues associated with those
investments, are embedded in the Company’s five-year financial forecast. The forecast shows, on
an annual basis, the need for revenue, or rate increases, on a system basis. The Company’s
financial forecast was provided in response to ICNU_DR_040C Confidential Attachment A

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/27/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU - 204 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the Company’s responses to Staff DR 63, Attachment (“Att.”) A and ICNU DR 68. In regard to the “Washington AMI” business case presented to Avista management in the response
attachment, please confirm that: a) the business case did not include a numerical “Assessment Score”;
and b) Avista senior management, including Scott Morris and Dennis Vermillion, reviewed and signed
the business case. If the Company cannot confirm any subpart, please explain.
RESPONSE: The business case in the Company’s response to Staff_DR_063 Attachment A, that was printed for
signing by Scott Morris and Dennis Vermillion (Senior Management, as discussed in ICNU_DR_068),
had a formula problem in the assessment score box. Senior Management however, does not typically use the assessment score to approve or decline projects. The assessment score is used by the Capital Planning
Group to prioritize capital projects during the budget process (as discussed in the Company’s response to
ICNU_DR_067). Typically, when the CPG reviews these Assessment Scores they are from a different
form that pulls in this formula. All of the assessment scores are verified by the Financial Planning and
Analysis Department prior to the prioritization process each year; therefore, this is simply a printing problem on this business case.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/29/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Don Kopczynski
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 205 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the Company’s response to Staff DR 71, Att. A, “AMI RFP Proposal” at 5. Please provide an update of progress in relation to the “RFP Proposed Project Schedule.”

RESPONSE:
Since the time the RFP schedule was developed, as presented in Staff_DR_071 Attachment A, “AMI RFP
Proposal” at 5, the Company has selected the vendor, Boreas Group, LLC, as the technical consultant
supporting the advanced metering project. Contracts with Boreas were signed and executed on April 20th
and the Company is in the process of working on the deliverables of that contract.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: James A. Kensok
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 206 TELEPHONE: (509) 495- EMAIL: [e-mail]

REQUEST:

Please refer to Exh. No. JMK-1T at 20:5-6. Please provide: a) the date on which the Board authorized a $3 million Project Compass spending limit increase; and b) the Board minutes confirming this
authorization.

RESPONSE:
On November 13, 2014, the Finance Committee of the Company’s Board of Directors acknowledged the
revised budget estimate of $107 million for Project Compass, and approved a revision of the capital
budget to $110 million. An excerpt from page 2 of the minutes of the Finance Committee, referring to
Project Compass, is provided below.
Compass Project Update

Mr. Kensok provided the Committee with an update on Project Compass, which is the project to replace
the Company’s customer service and work and asset management applications. Two dress rehearsals have been completed and user acceptance testing and training is on schedule. The expected go-live date is February 2, 2015 and the revised project budget estimate is $107 million. After discussion, the
Committee approved increasing the Project Compass budget from $100 million to $110 million.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/28/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 207 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide Mr. Ehrbar’s rate design workpapers, updated to reflect the multiparty settlement stipulation filed on May 1, 2015.
RESPONSE:
See the attachments labeled “ICNU_DR_207 Attachment A” for electric and “ICNU_DR_207
Attachment B” for natural gas, which were updated to reflect the multiparty settlement stipulation. The electronic models supporting the rate calculations have been included electronically.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith/Mark Thies
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 208 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the Company’s response to ICNU Data Request (“DR”) 30. In regard to the stated changes resulting from the 2013 benefit plan review, for each bullet point please explain the reduction in expenses
relative to Avista’s current executive officers (e.g., for the first bullet point, explain whether the described
change to the defined benefit pension plan has resulted in any actual reduction in expenses in relation to
the Company’s current executives).
RESPONSE: Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 208C. Please note that
Avista’s response to ICNU – 208C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205. The Company’s response to ICNU_DR_030 describes changes to the benefit plans for all non-union
employees (executives and non-executives) related to the defined benefit plan (pension) and 401(k),
revisions to the lump sum calculation for the defined benefit plan, health care benefit changes and health
insurance premiums. The actuarial analysis performed in relation to each bullet point included assumptions for all employees, and were not specific to the executive officer vs non-executive officer.
The limitation on new entrants to the defined benefit plan is expected to reduce the periodic pension
expense for the plan that would have otherwise been experienced. Instead, the Company will experience the cost of its non-elective contributions to the eligible employees’ defined contribution plan accounts.
The defined benefit pension eligibility revisions allow the pension obligation and required pension assets
to grow more slowly or to decline, in comparison to a hypothetical unchanged pension eligibility case.
The prepaid pension asset level could be expected to become less than it would have been absent the revisions, though the change is expected to be very gradual, assuming that consistent actuarial practices would continue in both the revised pension eligibility case and the hypothetical unchanged pension
eligibility case (e.g., funding practices, benefit payments and investment returns). Likewise, the pension
eligibility revisions could be expected to move the pension obligation very gradually to a lower level than
it would have been absent the revisions, again assuming consistent actuarial practices would continue in either case.
The lump sum payment option was also revised to allow non-union employees between 55 and 64 with 15
or more years of service at retirement to elect a lump sum that is a comparable value to the lifetime
annuity at the time of the lump sum payout. The rate of lump sum elections is expected to increase. Lump sum benefit payments will reduce the pension asset more quickly than benefits paid as annuities, but it

Page 2 of 2
will also relieve the Company of the obligation, and risk associated with, managing the pension asset
balance at a level sufficient to provide the defined benefit lifetime annuity to the retiree.
The changes to the health care benefit plan related to the elimination of the Company contribution
towards medical premiums for new hires effective January 1, 2014 combined with the change in
calculating health insurance premiums for non-union retirees under age 65 will reduce the benefit cost and
associated Accumulated Postretirement Benefit Obligation for the Company. Savings related to the
change for this component of the overall benefit plan will gradually increase year over year. In addition, this change allows the Company to gradually exit the retiree medical benefits while providing benefits
based on market analysis.

Please see ICNU_DR_208C Confidential Attachment A for a copy of the Avista Retirement Program
Design – Proposed Program Changes provided by Towers Watson in June 2013. Embedded within this report is the actuarial analysis for the reduced expense and liability related to the changes in pension and
medical plans.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 209 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the Company’s response to ICNU DR 31. Please provide an explanation as to what constitutes “material changes” sufficient to cause executive officer allocation estimates for time spent on
non-utility operations to be updated in the timekeeping system.

RESPONSE:
Material changes that cause an executive officer to change the estimated percent of time allocated to non-
utility operations may include, but not be limited to, the purchase or sale of a subsidiary, the evaluation or
development of a new subsidiary or new business line, change in roles and/or responsibilities, change in
strategic initiatives and priorities, or unforeseen external factors which require additional time such as
changes in federal or state laws. The purpose of the annual survey is to have the officer, with first-hand knowledge and experience, reflect any appropriate changes in the time estimates.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 210 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

From 2012 to the present, please provide supporting documentation for all reviews and updates made in the timekeeping system related to executive officer estimate allocations for time spent on non-utility
operations.

RESPONSE:

The information included as ICNU_DR_210C Confidential Attachment A is Confidential per
protective Order in UTC Dockets UE-150204 and UG-150205.

As noted in the Company’s response to PC_DR_007:
“Executive officers allocate time for tasks associated with Utility Operations to either a corporate planning/management project or those that are specific to his/her department. Time is also allocated for
work performed on non-utility operations and any direct charges related to AERC or AEL&P as part of
the Company’s subsidiary billing process. Avista’s timekeeping system is set up such that all employees
input their time electronically through their computer bi-weekly by project number for each day within the two week period.”
These allocation percentages are based on the informed judgment of each executive officer and are not
part of a process which requires documentation or quantifying analysis, and therefore no formal
documentation is maintained for timekeeping inputs. Please see ICNU_DR_210C Confidential Attachment A for 2012 and B for 2013 the output from the
timekeeping system by executive officer. PC_DR_008C Confidential Attachment B provides the same
information for the test period 12 months ending September 2013. In addition, PC_DR_008C
Confidential Attachment A provides a reference for project names associated with each project number.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 211 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the Company’s response to Public Counsel DR 6. Please provide narrative explanations supporting the non-utility allocation of each executive officer, including information accounting for
differences with allocations in prior years, similar to the explanations provided for Mr. Vermillion and
Ms. Feltes.
RESPONSE:
Below is summary of changes in allocation percentages by executive officer:

Executive Officer and Title Prior Non-Utility % New Non-Utility %
30% 25%
1.5% 8.5%
1.5% 1.5%
13% 1.5%
11% 11%
7% 8%
Senior Vice President, General Counsel and Chief 16% 12%
15% 3.5%
1.5% 1.5%
6% 3%
6% 1.5%
80% 90%

Page 2 of 2
As noted in the Company’s response to PC_DR_006, during 2014 the Company sold its biggest
subsidiary (ECOVA) and acquired Alaska Energy and Resources Company (AERC) and its subsidiary
Alaska Electric Light & Power (AEL&P). The complex nature of these transactions required input and oversight from several functional areas, which required a higher level of non-utility allocation during
2014 for Ms. Burmeister-Smith, Mr. Morris, and Ms. Durkin, Ms. Feltes, Mr. Meyer and Mr. Norwood.
The 2015 survey reflects this change with a reduction in the non-utility allocation in order to reflect on-
going responsibilities in each respective area. Estimates are based on the informed judgment of each
executive officer taking into consideration job responsibilities, projects specific to 2015, overall Company strategic initiatives, and associated roles.

Mr. Vermillion and Mr. Thies do not anticipate material changes to their non-utility allocations. As noted
in the Company’s response to PC_DR_006 Mr. Vermillion’s non-utility allocation is based on the number
of Monthly Strategy Meetings, weekly “check-in” calls and Board Meetings/Site Visits he attended during 2014 and anticipates during 2015. Mr. Thies, in his role as Chief Financial Officer is responsible
for the overall financial health of the Company which includes both utility and non-utility operations.
This percentage reflects on-going internal and external meetings and associated financial matters at the
corporate level.
Mr. Thackston and Mr. Kensok have limited interaction with non-utility operations in their current
positions, which is reflected in the 1.5% assigned to non-utility operations.

Mr. Woodworth and Mr. Kopczynski have increased their non-utility allocation to reflect increased time
spent on non-utility matters.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/2/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith/Mark Thies
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 212 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the Company’s response to ICNU DR 31. In regard to Avista’s Short Term Incentive Plan (“STIP”) for executive officers, please: a) describe the capital expenditures performance component
formerly included in the Company’s STIP; and b) explain why the Company no longer includes this
component in the current STIP, especially given the response statement that STIP operational components
“reflect measures that are designed to drive cost-control.”
RESPONSE: The STIP incentive plan is comprised of an operational component which accounts for 40% of the overall
award opportunity and an earnings-per-share component which accounts for 60% of the overall award
opportunity. Operational components are further broken down into O & M cost per customer (20%), Customer Satisfaction (8%), Reliability (8%), and Response time (4%).

The Capital expenditure component of the executive officer STIP was eliminated in 2009 in order to, in
part, align the STIP operational components for the executive officers with the STIP for non-executive
employees. The Compensation Committee of the Board of Directors believes that having similar metrics for both the executive plan and the non-executive plan encourages employees at al levels of the Company
to focus on common objectives. Please see the Company’s response to Staff_DR_007 Attachment A for a
copy of the Short Term Incentive Plan.

With regard to the capital expenditure plan itself, as explained in Mr. Thies’ testimony, the Company has chosen not to fund all of the capital investment projects proposed by the various departments within the
Company. Ms Schuh explains in her testimony that the Company, through executive officer oversight and
the Capital Planning Group, manages the actual capital expenditures each year to be close to the planned
amount.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 213 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

For each year from 2005 to the present, please provide the STIP O&M Cost-Per-Customer: a) target level; b) threshold; and c) actual amount.
RESPONSE:

The information on the Short Term Incentive Plan O & M Cost-Per-Customer is included in the Company’s electronic work paper folder: INCENTIVE, workbook: 1) 2.14 (2014) RI – Restate incentive,
tab: Average Percent Data.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 214 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

For each year from 2005 to the present, please provide the target levels and actual figures for the following STIP Reliability Indices: a) Customer Average Interruption Duration Index; b) System
Average Interruption Frequency Index; and c) Customer Experiencing Multiple Interruptions.

RESPONSE:
Please see the Company’s response to ICNU_DR_213.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/29/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 215 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the Company’s response to ICNU DR 32. For each year from 2005 to the present, for each STIP component included in rates, please indicate whether “[m]aximum performance levels” were
achieved.

RESPONSE:
Please see the Company’s response to ICNU_DR_213.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/27/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Mark Thies/Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 216 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exh. No. JSS-1T at 21-22 and the Company’s response to ICNU DR 31. Please reconcile the Company’s proposed inclusion in rates of the Restricted Stock portion of the Avista’s Long Term
Incentive Plan (“LTIP”) for executive officers, with Company testimony in prior cases explaining that “all
components” of the LTIP, including the Restricted Stock portion, would be “borne by shareholders,”
based on testimony that these were “amounts focusing on shareholder value” (e.g., UE-120436 et al., Exh.
No. KSF-1T at 29:22-26).
RESPONSE:
As noted in the Company’s response to ICNU_DR_031 and PC_DR_010 the Restricted Stock portion of
the Long Term Incentive Plan is designed to provide an incentive for employees to remain employed by the Company and is therefore appropriate to be included in rates.
Not including this amount in previous rate cases was an oversight by the Company.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith/Mark Thies
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 217 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the Company’s response to ICNU DR 32, Att. A at 27. Please provide the Director Compensation Report provided by Meridian Compensation Partners LLC and reviewed by the Board in
2014.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 217C. Please note that
Avista’s response to ICNU – 217C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

Please see ICNU_DR_217C Confidential Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith/Mark Thies
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 218 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the Company’s response to ICNU DR 32, Att. A at 40. Please provide any “Peer Proxy Group” data reviewed by the Compensation Committee, in addition to any information provided in the
Company’s response to Staff DR 9.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 218C. Please note that
Avista’s response to ICNU – 218C is Confidential per Protective Order in UTC Dockets UE-150204
and UG-150205.

Please see ICNU_DR_218C Confidential Attachment A for the 2014 Meridian Compensation Partners LLC Report “Market Analysis of Senior Executives”.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 219 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please refer to Exh. No. JSS-1T at 17:15-17 and 45:5-7. Please provide the reduction to revenue
requirement if, in addition to removing 50% of director meeting expenses, the Company also removed 50% of director fees, as ordered in Docket UE-090135, Order 10 at ¶ 142.

RESPONSE:
The reduction to revenue requirement if the Company removed 50% of director fees would be
approximately $45,000 Electric and $88,000 Gas.
In May of 2014, the Company requested each of its Directors, based on their actual experience, to
estimate the time they spend on utility versus non-utility duties and responsibilities. The responses from
the Directors indicated that, in the aggregate, approximately 90% of the Directors’ time is dedicated to
utility matters, and approximately 10% to non-utility. After the sale of the Company’s subsidiary Ecova and purchase of Alaska Energy Light and Power (AEL&P), the Company requested an updated survey be
completed to reflect the change in time spent between utility and non-utility operations. The result of that
survey was that 97% of the Directors’ time will be dedicated to utility while 3% will allocated to the
Company’s remaining subsidiaries.
In Docket Nos. UE-090134 and UG-090135. Order No. 10, in reference to a 90/10 sharing for D&O
insurance, the Commission stated:

D&O insurance is a benefit that is part of the compensation package offered to
attract and retain qualified officers and directors. Accordingly, it makes sense to split the costs in the same manner we require other elements of their compensation
to be shared. Based on the formula currently used to allocate officer compensation
between ratepayers and shareholders, this results in 90 percent of the costs being
included for recovery in rates. (emphasis added) (See page 56, paragraph 137)
This Commission, as shown above, has recognized that D&O insurance is part of the “compensation
package”. Similarly, Directors’ fees, like D&O insurance referred to above, are a part of the Directors’
compensation package offered to attract and retain qualified Directors. Based on the estimated time that
will be dedicated to the utility, a 97/3 sharing should be applied to Directors’ fees. Director fees paid to
board members for their duties specific to other Avista boards are otherwise charged 100% to non-utility.
This approach to the Board of Directors’ level of expense included in utility operations and the adjustment
proposed in the Company’s filed cases is consistent with prior Washington general rate cases since 2010.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 220 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all Board of Director meeting minutes from 2014 to the present.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 220C. Please note that
Avista’s response to ICNU – 220C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205.

The Company has prepared a Virtual Data Room, as in previous cases, which houses the above referenced
agendas and meeting minutes. Please contact Paul Kimball via email – [e-mail] – to
get the required login and password information.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 221 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exh. No. JSS-1T at 17:19-18:3 and the Company’s responses to ICNU DR 77 and Public Counsel DR 15. Specifically, please indicate when: a) in 2014, the Company requested each of its
directors to provide new estimates of time spent on utility versus non-utility activities; and b) the
Company received “the 2015 Survey results,” as that term is used in Att. A of the Company’s response to
ICNU DR 77.
RESPONSE:
Initially the Company had requested and completed a directors’ survey of time allocation in May 2014
prior to the sale of Ecova, a subsidiary of the Company and purchase of Alaska Electric Light and Power
Company (AELP). A revised survey was requested and completed during the November 2014 board meeting in order to reflect the impact of these changes. Please also see the Company’s response to
ICNU_DR_219.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 222 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exh. No. JSS-1T at 17:19-18:3 and the Company’s responses to ICNU DRs 31 and 77 and Public Counsel DR 16. For director survey estimate allocations of time spent on utility versus non-utility
activities, does the Company conduct any further review of and make updates to these allocations, similar
to the review and updates made to executive officer estimate allocations? If yes, please provide all
supporting documentation.
RESPONSE:
The Company conducts an annual survey of the Board, unless as occurred in 2014; a significant change to
Company operations occurs. Directors’ are not salaried employees such as the officers of the Company
and are not required to submit weekly timesheets. Please also see the Company’s response to INCU DR’s 219 and 221.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Dawnell Ellenson
TYPE: Data Request DEPT: Human Resources
REQUEST NO.: ICNU – 223 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the Company’s response to ICNU DR 33. For each year from 2005 to 2014, inclusive, please provide the total percentage of the pay-at-risk portion of executive officer compensation paid out by
the Company (i.e., the percentage paid out each year in relation to the total pay-at-risk compensation
potential in each year for all executive officers combined).

RESPONSE: Below are charts showing the actual results as a percent of target for each performance based pay-at-risk
plan (STIP, LTIP – Performance Shares and CEO Restricted Stock Units). Restricted Stock Units were not
granted prior to 2006.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/29/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jen Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 224 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

In regard to the Company’s continued use of and justification for its corporate jet, please provide: a) any studies considered by the Company; and b) a narrative response explaining the Company’s policy and/or
position.

RESPONSE:
Our retail service area offices, generating resources, and the state commissions that regulate Avista are
located across a broad geographic area covering parts of Washington, Idaho, Oregon and Montana, and
many locations have limited or no commercial airline service. As a regional company we have utilized a small business aircraft for over 50 years. The majority of the trips the plane is utilized for involves meetings, hearings and workshops at the state utility commission offices in Olympia, WA Boise, ID, and
Salem, OR. The aircraft is used for business purposes only, and any non-utility business use is charged to
shareholders.
The corporate aircraft may be scheduled as an alternative to commercial travel when it is the most cost effective means of travel and/or the importance of the meeting or timing warrants its use. The importance
of each trip or timing issues are addressed based on the specific circumstances of each individual trip, and
are therefore handled on a “case by case basis.” Flights are approved by the Vice President in charge of
that area of responsibility according to the company aircraft use policy. Each Vice President determines if the business reason for the flight warrants use of the aircraft. Executive approval is required for all scheduling.

The process of scheduling the corporate aircraft for a given trip begins when an employee traveling on
company business submits a completed Corporate Aircraft Request & Approval Form to the travel scheduling office. If the aircraft is available, a cost analysis is performed using the planned date, location, meeting/hearing times, and participants. The first step is to compute the cost of traveling on commercial
airlines or driving. This cost includes airfare plus any meals, hotel, ground transportation, and work time
lost due to airline schedules, check-in, ticketing, security, boarding and drive time (if applicable). The
results of this analysis is compared to the direct (variable) cost of using the corporate aircraft. The aircraft is automatically put on the schedule if it is the most cost effective option, subject to Executive approval.
In certain cases use of the aircraft is based on other factors such as situations where the trip is to a city
with little or no airline service, timing issues cannot be dealt with effectively with commercial schedules,
the scheduling commitments and workload of passengers, or the meeting/hearing is of a critical nature.

Page 1

January 16, 2014
Steven V. King Executive Director and Secretary
Washington Utilities and Transportation Commission
P.O. Box 47250
Olympia, WA 98504-7250
Re: Docket No. UE-011595, Monthly Power Cost Deferral Report,
December 2013

Dear Mr. King:
Enclosed are an original and five copies of Avista Corporation’s Power Cost Deferral
Report for the month of December 2013.

The report includes the monthly energy recovery mechanism (ERM) accounting journal together with backup workpapers (Attachment A (pages 7-23)). In December,
actual net power costs were greater than authorized costs by $2,804,277. Year-to-
date actual net power costs were greater than authorized costs by $5,037,302. A
deferral entry of $518,651 was made in the surcharge direction, which reflects 50% of
the amount within the $4 million to $10 million sharing band.
In December 2013, the Company recorded two additional journal entries to the ERM
deferral. First, $70,084 was recorded in the rebate direction for the estimated amount
of excess actual fixed over authorized costs in 2013 for the Colstrip plant. Colstrip
Unit 4 suffered a generator fault on July 1, 2013, which put Colstrip below 70% availability in 2013. Please see the accounting journal and supporting workpapers
that have been provided in Attachment C (pages 32-56) for additional information.
Second, the Company identified an error relating to the allocation of natural gas
transport costs between the Company’s Power Supply operations (“thermal”) and the
Company’s natural gas operations (“LDC”). This resulted in $808,681 entry in the surcharge direction, for Washington’s share of the allocated gas transport costs and
interest. Please see the accounting journal and supporting workpapers that have been
provided in Attachment D (pages 57-75) for additional information.

The ERM deferral at December 30, 2013 was $1,256,477 in the surcharge direction.
In Order 09, Docket UE-120436, the Company was authorized to return a portion of
the accumulated ERM deferral balance to customers effective January 1, 2013. Total
rebate revenue amounted to $432,776 for the month of December 2013. After
adjusting for revenue-sensitive expenses, $413,344 of amortization of the deferral balance was recorded.
Avista Corp. 1411 East Mission P.O. Box 3727
Spokane. Washington 99220-3727 Telephone [phone]
Toll Free 800-727-9170

ICNU_DR_225 Attachment A Page 1 of 79
Page 2

Actual net power costs for December 2013 were greater than the authorized level
due primarily to loss of generation from Colstrip Unit 4 lower hydro generation and high power and natural gas prices. On July 1, 2013, Colstrip Unit 4 suffered a generator fault and is expected to be out of service through January 2014.
Colstrip generation was 86 aMW below the authorized level.

Hydro generation was 69 aMW below the authorized level. Kettle Falls generated 1 aMW above the authorized level. Natural gas-fired generation was 58 aMW above the authorized level.

The average power purchase price was $49.41/MWh compared to an authorized
price of $31.43/MWh. The average natural gas purchase price was $4.47/dth compared to an authorized price of $3.71/dth. The net transmission expense (transmission expense less transmission revenue) was above the authorized level.
Washington retail sales were 7 aMW above the authorized level.

The report also includes the monthly renewable energy credits (REC) accounting journal together with backup workpapers (Attachment B (pages 24-31)). In December 2013, actual net REC revenues were greater than authorized revenues by
$293,266. The Company records 100% of the net REC revenues in a separate
deferral account per Order 09, Docket UE-120436.
Interest is calculated pursuant to the Settlement Stipulation approved by the Commission’s Fifth Supplemental Order in Docket No. UE-011595, dated June 18,
2002. Interest is applied to the average of the beginning and ending month deferral
balances net of associated deferred federal income tax. The Company’s weighted
cost of debt is used as the interest rate. The interest rate is updated semi-annually and interest is compounded semi-annually. The January and July reports contain the
supporting workpapers for the semi-annual updates of the weighted cost of debt used
in the interest calculations. Page 28 of this report for July 2013 shows the calculation
of the weighted cost of debt at June 30, 2013, which is used for the July through
December 2013 period.
There were no forward long-term power contracts executed in December 2013.

If you have any questions, please contact Bill Johnson at [phone] or Jeanne
Pluth at [phone].
Sincerely,

Kelly Norwood
Vice President, State and Federal Regulation
JP
Enclosure
C: Mary Kimball, S. Bradley Van Cleve
ICNU_DR_225 Attachment A Page 2 of 79
Page 3

Mary Kimball
Office of the Attorney General Public Counsel Section 800 Fifth Avenue, Suite 2000
Seattle, WA 98104-3188

S. Bradley Van Cleve Davison Van Cleve PC Industrial Customers of Northwest Utilities
333 S.W. Taylor, Ste. 400
Portland, OR 97204
Steven V. King Executive Director and Secretary
Washington Utilities and Transportation Commission
1300 S. Evergreen Park Drive, S.W.
P.O. Box 47250 Olympia, WA 98504-7250
ICNU_DR_225 Attachment A Page 3 of 79

AVISTA CORPORATION

STATE OF WASHINGTON
DOCKET NO. UE-011595
POWER COST DEFERRAL REPORT

MONTH OF DECEMBER 2013

ICNU_DR_225 Attachment A Page 4 of 79

ERM Deferral Balance (Current Year - 2013)
Account 186280.ED.WA Amount Journal ID
Balance 11/30/2013 $0.00
Deferral - Current Month 518,651.00 481 - WA ERM
Interest - Current Month (1) -801.00 481 - WA ERM
Colstrip 70% Availability Liability -70,084.00 NSJ003
Intercompany Gas Transport Costs 808,681.00 NSJ019
Balance 12/31/13 $1,256,447.00
Year to date deferrals $518,651.00
Year to date interest -801.00
Colstrip 70% Availability Liability -70,084.00
Intercompany Gas Transport Costs 808,681.00
Balance in account $1,256,447.00
Total Absorbed Deferred
First $4,000,000 at 100%$4,000,000.00 $4,000,000.00 $0.00
$4,000,000 to $10,000,000 at 50% 1,037,302.00 518,651.00 518,651.00
Over $10,000,000 at 10%0.00 0.00 0.00
Total $5,037,302.00 $4,518,651.00 $518,651.00
(1) Interest of $801 was recorded backwards for December 2013. Amount will be corrected
in January 2014.
Deferral Report Month of Dec 2013
Page 1 of 75
ICNU_DR_225 Attachment A Page 5 of 79

ERM Deferral Balance (Prior year - 2012)
Account 186290.ED.WA Amount Journal ID
Balance 11/30/2013 -$9,252,504.14
Interest - Current Month -28,137.00 481 - WA ERM
Balance 12/31/13 -$9,280,641.14
Deferral Report Month of Dec 2013
Page 2 of 75
ICNU_DR_225 Attachment A Page 6 of 79

Recoverable Deferral Balance
Account 182350.ED.WA Amount Journal ID
Balance 11/30/2013 -$10,262,209.00
Surcharge Amortization 413,344.00 481 - WA ERM
Interest -30,529.00 481 - WA ERM
Balance 12/31/13 -$9,879,394.00
Deferral Report Month of Dec 2013
Page 3 of 75
ICNU_DR_225 Attachment A Page 7 of 79

DFIT Associated with ERM Deferrals
Account 283280.ED.WA
Account 186280.ED.WA balance $1,256,447.00
Account 186290.ED.WA balance -9,280,641.14
Account 182350.ED.WA balance -9,879,394.00
Total -$17,903,588.14
Federal income tax rate -35%
Deferred FIT related to deferrals $6,266,256
Rounding 1
Balance that should be in account - Dec 31, 2013 $6,266,257
Deferral Report Month of Dec 2013
Page 4 of 75
ICNU_DR_225 Attachment A Page 8 of 79

REC Deferral Balance
Account 186322.ED.WA Amount Journal ID
Balance 11/30/2013 -$1,309,240.81
Deferral -293,266.00 475 - WA REC DEFERRAL
Interest -4,441.00 475 - WA REC DEFERRAL
Balance 12/31/13 -$1,606,947.81
Balance 1/1/2013 -$361,849
Year to date deferrals -1,212,070
Year to date interest -33,029
Balance in account -$1,606,948
Deferral Report Month of Dec 2013
Page 5 of 75
ICNU_DR_225 Attachment A Page 9 of 79

DFIT Associated with REC Deferrals
Account 283305.ED.WA
Account 186322.ED.WA balance -$1,606,947.81
Total -1,606,947.81
Federal income tax rate -35%
Deferred FIT related to deferrals $562,432
Rounding 0
Balance that should be in account - Dec 31, 2013 $562,432
Deferral Report Month of Dec 2013
Page 6 of 75
ICNU_DR_225 Attachment A Page 10 of 79
Attachment A

Avista Corporation

Monthly Power Cost Deferral Report

Month of December 2013

ERM Deferral Journal

Deferral Report Month of Dec 2013
Page 7 of 75
ICNU_DR_225 Attachment A Page 11 of 79
Deferral Report Month of Dec 2013
Page 8 of 75
ICNU_DR_225 Attachment A Page 12 of 79
Deferral Report Month of Dec 2013
Page 9 of 75
ICNU_DR_225 Attachment A Page 13 of 79
Lin
eNo
.
WA
S
H
I
N
G
T
O
N

A
C
T
U
A
L
S
Ja
n
-
1
3
Fe
b
-
1
3
Ma
r
-
1
3
Ap
r
-
1
3
Ma
y
-
1
3
Ju
n
-
1
3
Ju
l
-
1
3
Au
g
-
1
3
Se
p
-
1
3
Oc
t
-
1
3
No
v
-
1
3
De
c
-
1
3
1
55
5

P
u
r
c
h
a
s
e
d

P
o
w
e
r
$2
1
,
5
3
9
,
7
4
5
$2
2
,
1
0
4
,
0
1
5
$2
0
,
9
6
0
,
0
7
3
$2
0
,
9
0
6
,
3
0
9
$1
6
,
0
4
1
,
0
1
3
$1
3
,
9
6
7
,
0
5
6
$1
3
,
7
8
6
,
6
9
6
$1
5
,
5
3
5
,
0
0
1
$1
3
,
9
9
2
,
6
1
2
$1
4
,
0
7
6
,
4
1
8
$1
8
,
0
1
5
,
2
0
8
$1
5
,
9
5
7
,
9
5
5
2
44
7

S
a
l
e

f
o
r

R
e
s
a
l
e
($
1
2
,
9
0
5
,
9
7
5
)
($
1
5
,
5
1
7
,
4
0
5
)
($
1
6
,
5
8
3
,
5
9
2
)
($
1
7
,
8
7
6
,
0
6
0
)
($
1
5
,
2
6
1
,
7
4
2
)
($
9
,
7
7
7
,
0
6
4
)
($
9
,
0
5
8
,
1
3
3
)
($
9
,
2
0
3
,
9
9
5
)
($
8
,
2
5
5
,
2
3
3
)
($
1
0
,
2
8
0
,
2
8
2
)
($
1
1
,
6
4
6
,
2
8
1
)
($
7
,
0
2
4
,
8
0
3
)
3
Le
s
s

S
M
U
D

R
E
C
s
$3
8
6
,
6
4
5
$4
1
3
,
7
7
5
$3
9
2
,
7
3
4
$4
4
9
,
0
3
4
$4
6
1
,
1
2
4
$4
8
7
,
5
7
5
$2
9
4
,
9
4
7
$2
8
8
,
5
1
4
$2
8
7
,
7
6
8
$2
8
6
,
6
2
4
$2
8
8
,
3
7
6
$2
9
6
,
7
3
6
4
50
1

T
h
e
r
m
a
l

F
u
e
l
$2
,
6
2
3
,
1
1
1
$2
,
2
6
7
,
9
0
1
$2
,
8
5
9
,
6
5
9
$2
,
9
1
6
,
3
3
1
$7
0
1
,
3
4
9
$1
,
0
5
1
,
5
8
6
$1
,
0
4
0
,
7
1
6
$2
,
0
3
3
,
6
0
1
$1
,
9
6
9
,
3
1
2
$1
,
8
4
2
,
3
4
1
$1
,
9
1
9
,
7
9
5
$1
,
9
7
5
,
5
5
4
5
54
7

C
T

F
u
e
l
$9
,
2
0
4
,
9
6
2
$8
,
5
3
6
,
3
5
6
$1
0
,
6
8
1
,
5
8
9
$4
,
6
5
4
,
5
9
7
$5
,
9
6
4
,
7
3
4
$3
,
1
4
9
,
9
6
8
$9
,
3
4
6
,
0
6
3
$1
1
,
1
5
1
,
6
9
8
$1
0
,
5
1
8
,
7
0
3
$1
0
,
5
4
7
,
8
1
9
$1
0
,
6
6
1
,
0
4
0
$1
6
,
0
4
4
,
8
0
6
6
45
6

T
r
a
n
s
m
i
s
s
i
o
n

R
e
v
e
n
u
e
($
9
5
1
,
7
4
0
)
($
1
,
1
9
5
,
6
1
7
)
($
2
5
2
,
9
9
5
)
($
7
1
4
,
2
0
4
)
($
8
2
2
,
3
1
1
)
($
1
,
1
6
0
,
1
3
5
)
($
1
,
2
1
0
,
0
0
5
)
($
1
,
0
6
7
,
0
6
4
)
($
8
4
1
,
0
2
6
)
($
7
8
2
,
9
2
6
)
($
8
0
7
,
2
3
6
)
($
6
9
6
,
9
9
3
)
7
56
5

T
r
a
n
s
m
i
s
s
i
o
n

E
x
p
e
n
s
e
$1
,
4
8
4
,
5
0
1
$1
,
4
6
6
,
6
7
9
$1
,
4
9
1
,
3
2
2
$1
,
4
7
4
,
5
4
2
$1
,
4
2
2
,
3
1
7
$1
,
3
9
8
,
4
1
5
$1
,
4
6
0
,
0
3
2
$1
,
4
5
0
,
3
5
2
$1
,
4
0
5
,
5
1
6
$1
,
5
5
0
,
5
3
8
$1
,
6
8
5
,
2
4
6
$1
,
6
3
7
,
4
4
1
8
55
7

B
r
o
k
e
r

F
e
e
s
$8
7
,
8
8
4
$7
8
,
6
1
2
$9
7
,
8
8
8
$1
0
6
,
9
6
2
$1
0
0
,
8
0
9
$6
8
,
5
5
6
$9
2
,
5
4
5
$1
0
0
,
9
0
1
$1
0
3
,
4
6
8
$9
5
,
1
6
9
$3
6
,
1
7
4
$5
2
,
3
5
5
9
Le
s
s

C
l
e
a
r
w
a
t
e
r

d
i
r
e
c
t
l
y

a
s
s
i
g
n
e
d

t
o

I
D
($
1
,
6
5
3
,
4
5
0
)
($
1
,
3
8
6
,
7
0
2
)
($
1
,
5
3
5
,
0
3
4
)
($
1
,
4
9
0
,
7
4
0
)
($
1
,
6
1
2
,
4
1
9
)
($
1
,
5
0
9
,
9
6
9
)
$0
$0
$0
$0
$0
$0
10
Ad
j
u
s
t
e
d

A
c
t
u
a
l

N
e
t

E
x
p
e
n
s
e
$1
9
,
8
1
5
,
6
8
3
$1
6
,
7
6
7
,
6
1
4
$1
8
,
1
1
1
,
6
4
4
$1
0
,
4
2
6
,
7
7
1
$6
,
9
9
4
,
8
7
4
$7
,
6
7
5
,
9
8
8
$1
5
,
7
5
2
,
8
6
1
$2
0
,
2
8
9
,
0
0
8
$1
9
,
1
8
1
,
1
2
0
$1
7
,
3
3
5
,
7
0
1
$2
0
,
1
5
2
,
3
2
2
$2
8
,
2
4
3
,
0
5
1
A
U
T
H
O
R
I
Z
E
D

N
E
T

E
X
P
E
N
S
E
-
S
Y
S
T
E
M
Ja
n
-
1
3
Fe
b
-
1
3
Ma
r
-
1
3
Ap
r
-
1
3
Ma
y
-
1
3
Ju
n
-
1
3
Ju
l
-
1
3
Au
g
-
1
3
Se
p
-
1
3
Oc
t
-
1
3
No
v
-
1
3
De
c
-
1
3
11
55
5

P
u
r
c
h
a
s
e
d

P
o
w
e
r
$1
4
,
9
9
7
,
4
4
6
$1
3
,
2
3
2
,
4
4
3
$1
2
,
7
1
0
,
6
0
8
$1
0
,
4
2
9
,
5
2
4
$8
,
5
3
0
,
8
6
3
$8
,
2
7
7
,
5
2
4
$8
,
2
1
3
,
5
3
3
$1
0
,
2
4
0
,
2
2
3
$8
,
0
3
9
,
7
8
3
$9
,
4
1
4
,
5
5
0
$1
2
,
7
8
8
,
4
0
1
$1
3
,
4
5
4
,
2
3
2
12
44
7

S
a
l
e

f
o
r

R
e
s
a
l
e
($
6
,
9
0
3
,
0
3
8
)
($
6
,
2
5
3
,
7
6
6
)
($
6
,
5
7
4
,
9
1
9
)
($
8
,
0
3
5
,
1
3
6
)
($
7
,
4
6
2
,
4
1
1
)
($
6
,
3
5
8
,
8
1
1
)
($
7
,
7
5
2
,
3
6
9
)
($
4
,
8
1
0
,
4
1
8
)
($
6
,
2
8
9
,
9
8
5
)
($
7
,
4
0
1
,
0
9
1
)
($
8
,
4
0
5
,
1
5
3
)
($
8
,
7
3
3
,
7
2
7
)
13
Le
s
s

S
M
U
D

R
E
C
s
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
$3
8
3
,
9
6
9
14
50
1

T
h
e
r
m
a
l

F
u
e
l
$2
,
7
7
9
,
0
5
1
$2
,
6
6
7
,
7
4
4
$2
,
7
7
5
,
5
0
1
$2
,
0
2
0
,
5
5
7
$1
,
7
0
4
,
4
2
6
$1
,
4
7
5
,
2
9
5
$2
,
7
3
9
,
0
3
2
$2
,
9
6
7
,
3
3
2
$2
,
9
1
9
,
9
3
9
$3
,
0
5
2
,
5
8
8
$2
,
9
1
3
,
8
2
3
$3
,
0
1
0
,
1
0
8
15
54
7

C
T

F
u
e
l
$9
,
3
2
4
,
0
6
0
$8
,
6
4
6
,
8
9
9
$8
,
3
7
7
,
1
1
7
$4
,
9
9
8
,
7
7
5
$3
,
0
3
4
,
9
9
1
$2
,
5
9
2
,
3
5
9
$7
,
5
2
2
,
8
2
5
$8
,
8
2
0
,
6
6
7
$9
,
2
1
4
,
6
4
3
$9
,
2
7
9
,
2
9
7
$9
,
8
6
3
,
1
1
6
$1
0
,
7
0
7
,
6
4
1
16
45
6

T
r
a
n
s
m
i
s
s
i
o
n

R
e
v
e
n
u
e
($
9
6
3
,
3
8
8
)
($
6
9
9
,
8
5
7
)
($
8
4
5
,
4
9
2
)
($
7
2
9
,
6
1
3
)
($
8
3
7
,
6
3
9
)
($
1
,
0
0
3
,
3
2
6
)
($
1
,
1
6
0
,
2
6
7
)
($
1
,
0
2
4
,
6
0
7
)
($
9
4
7
,
4
7
2
)
($
1
,
0
8
1
,
2
4
6
)
($
8
9
4
,
8
3
4
)
($
8
7
8
,
2
2
0
)
17
56
5

T
r
a
n
s
m
i
s
s
i
o
n

E
x
p
e
n
s
e
$1
,
5
2
0
,
3
6
1
$1
,
4
6
5
,
3
8
2
$1
,
5
0
8
,
7
3
9
$1
,
4
4
3
,
5
3
8
$1
,
4
2
6
,
2
6
8
$1
,
3
9
6
,
7
5
2
$1
,
4
4
1
,
1
7
5
$1
,
4
8
9
,
0
4
8
$1
,
4
9
2
,
1
6
3
$1
,
5
5
6
,
7
3
4
$1
,
6
7
4
,
1
8
7
$1
,
6
4
4
,
3
7
2
18
55
7

B
r
o
k
e
r

F
e
e
s
$4
2
,
6
5
6
$6
4
,
0
1
5
$1
2
9
,
8
6
0
$9
7
,
3
9
0
$5
2
,
5
7
7
$7
0
,
2
8
1
$6
5
,
8
0
8
$7
6
,
8
4
8
$8
6
,
9
4
4
$4
3
,
9
6
6
$5
2
,
6
9
6
$1
0
0
,
6
7
0
19
Au
t
h
o
r
i
z
e
d

N
e
t

E
x
p
e
n
s
e
$2
1
,
1
8
1
,
1
1
7
$1
9
,
5
0
6
,
8
2
9
$1
8
,
4
6
5
,
3
8
2
$1
0
,
6
0
9
,
0
0
4
$6
,
8
3
3
,
0
4
4
$6
,
8
3
4
,
0
4
3
$1
1
,
4
5
3
,
7
0
6
$1
8
,
1
4
3
,
0
6
2
$1
4
,
8
9
9
,
9
8
4
$1
5
,
2
4
8
,
7
6
7
$1
8
,
3
7
6
,
2
0
5
$1
9
,
6
8
9
,
0
4
5
20
Ac
t
u
a
l

-

A
u
t
h
o
r
i
z
e
d

N
e
t

E
x
p
e
n
s
e
($
1
,
3
6
5
,
4
3
4
)
($
2
,
7
3
9
,
2
1
5
)
($
3
5
3
,
7
3
9
)
($
1
8
2
,
2
3
3
)
$1
6
1
,
8
3
0
$8
4
1
,
9
4
5
$4
,
2
9
9
,
1
5
5
$2
,
1
4
5
,
9
4
6
$4
,
2
8
1
,
1
3
6
$2
,
0
8
6
,
9
3
4
$1
,
7
7
6
,
1
1
7
$8
,
5
5
4
,
0
0
6
21
Re
s
o
u
r
c
e

O
p
t
i
m
i
z
a
t
i
o
n

-

S
u
b
t
o
t
a
l
($
6
,
7
8
0
)
$7
6
,
2
2
6
($
1
,
0
9
7
,
1
8
9
)
($
7
5
0
,
1
0
0
)
($
5
4
4
,
8
7
2
)
($
7
3
2
,
4
8
4
)
$1
8
1
,
0
2
6
$7
7
9
,
9
8
3
$8
3
1
,
6
0
3
($
3
4
0
,
6
8
8
)
($
6
9
9
,
9
2
3
)
($
2
,
4
1
3
,
3
3
0
)
22
In
t
r
a
c
o
m
p
a
n
y

G
a
s

A
d
j
u
s
t
m
e
n
t
($
1
,
5
9
3
,
5
1
5
)
23
Ad
j
u
s
t
e
d

R
e
s
o
u
r
c
e

O
p
t
i
m
i
z
a
t
i
o
n
($
6
,
7
8
0
)
$7
6
,
2
2
6
($
1
,
0
9
7
,
1
8
9
)
($
7
5
0
,
1
0
0
)
($
5
4
4
,
8
7
2
)
($
7
3
2
,
4
8
4
)
$1
8
1
,
0
2
6
$7
7
9
,
9
8
3
$8
3
1
,
6
0
3
($
3
4
0
,
6
8
8
)
($
6
9
9
,
9
2
3
)
($
4
,
0
0
6
,
8
4
5
)
24
Ad
j
u
s
t
e
d

N
e
t

E
x
p
e
n
s
e
($
1
,
3
7
2
,
2
1
4
)
($
2
,
6
6
2
,
9
8
9
)
($
1
,
4
5
0
,
9
2
8
)
($
9
3
2
,
3
3
3
)
($
3
8
3
,
0
4
2
)
$1
0
9
,
4
6
1
$4
,
4
8
0
,
1
8
1
$2
,
9
2
5
,
9
2
9
$5
,
1
1
2
,
7
3
9
$1
,
7
4
6
,
2
4
6
$1
,
0
7
6
,
1
9
4
$4
,
5
4
7
,
1
6
1
25
Wa
s
h
i
n
g
t
o
n

A
l
l
o
c
a
t
i
o
n
65
.
2
4
%
65
.
2
4
%
65
.
2
4
%
65
.
2
4
%
65
.
2
4
%
65
.
2
4
%
65
.
2
4
%
65
.
2
4
%
65
.
2
4
%
65
.
2
4
%
65
.
2
4
%
65
.
2
4
%
26
Wa
s
h
i
n
g
t
o
n

S
h
a
r
e
($
8
9
5
,
2
3
3
)
($
1
,
7
3
7
,
3
3
4
)
($
9
4
6
,
5
8
5
)
($
6
0
8
,
2
5
4
)
($
2
4
9
,
8
9
7
)
$7
1
,
4
1
2
$2
,
9
2
2
,
8
7
0
$1
,
9
0
8
,
8
7
6
$3
,
3
3
5
,
5
5
1
$1
,
1
3
9
,
2
5
1
$7
0
2
,
1
0
9
$2
,
9
6
6
,
5
6
8
27
($
7
7
7
,
9
5
0
)
$6
0
1
,
5
5
0
$6
9
9
,
6
0
7
($
3
9
1
,
9
2
4
)
($
6
0
1
,
7
0
7
)
$2
6
6
,
5
7
1
($
1
,
6
1
1
,
4
5
3
)
($
6
9
2
,
4
8
0
)
($
3
1
7
,
8
2
2
)
($
3
1
8
,
3
1
0
)
$1
8
1
,
0
9
6
($
1
6
2
,
2
9
1
)
28
($
1
,
6
7
3
,
1
8
3
)
($
1
,
1
3
5
,
7
8
4
)
($
2
4
6
,
9
7
8
)
($
1
,
0
0
0
,
1
7
8
)
($
8
5
1
,
6
0
4
)
$3
3
7
,
9
8
3
$1
,
3
1
1
,
4
1
7
$1
,
2
1
6
,
3
9
6
$3
,
0
1
7
,
7
2
9
$8
2
0
,
9
4
1
$8
8
3
,
2
0
5
$2
,
8
0
4
,
2
7
7
29
($
4
4
6
,
9
2
0
)
30
Cu
m
u
l
a
t
i
v
e

B
a
l
a
n
c
e
($
1
,
6
7
3
,
1
8
3
)
($
2
,
8
0
8
,
9
6
7
)
($
3
,
0
5
5
,
9
4
5
)
($
4
,
0
5
6
,
1
2
3
)
($
4
,
9
0
7
,
7
2
7
)
($
4
,
5
6
9
,
7
4
3
)
($
3
,
7
0
5
,
2
4
6
)
($
2
,
4
8
8
,
8
5
0
)
$5
2
8
,
8
7
9
$1
,
3
4
9
,
8
2
0
$2
,
2
3
3
,
0
2
5
$5
,
0
3
7
,
3
0
2
De
f
e
r
r
a
l

A
m
o
u
n
t
,

C
u
m
u
l
a
t
i
v
e

(
C
u
s
t
o
m
e
r
)
$0
$0
$0
($
4
2
,
0
9
2
)
($
6
8
0
,
7
9
5
)
($
4
2
7
,
3
0
7
)
$0
$0
$0
$0
$0
$5
1
8
,
6
5
1
De
f
e
r
r
a
l

A
m
o
u
n
t
,

M
o
n
t
h
l
y
$0
$0
$0
($
4
2
,
0
9
2
)
($
6
3
8
,
7
0
3
)
$2
5
3
,
4
8
8
$4
2
7
,
3
0
7
$0
$0
$0
$0
$5
1
8
,
6
5
1
$0
$0
$0
$4
2
,
0
9
2
$6
3
8
,
7
0
3
($
2
5
3
,
4
8
8
)
($
4
2
7
,
3
0
7
)
$0
$0
$0
$0
($
5
1
8
,
6
5
1
)
($
1
,
6
7
3
,
1
8
3
)
($
2
,
8
0
8
,
9
6
7
)
($
3
,
0
5
5
,
9
4
5
)
($
4
,
0
1
4
,
0
3
1
)
($
4
,
2
2
6
,
9
3
2
)
($
4
,
1
4
2
,
4
3
6
)
($
3
,
7
0
5
,
2
4
6
)
($
2
,
4
8
8
,
8
5
0
)
$5
2
8
,
8
7
9
$1
,
3
4
9
,
8
2
0
$2
,
2
3
3
,
0
2
5
$4
,
5
1
8
,
6
5
1
$4
,
3
3
3
,
8
5
2
$2
0
6
,
8
8
2
,
1
0
0
($
1
4
3
,
3
9
0
,
5
6
5
)
$3
1
,
0
2
5
,
3
9
6
$2
3
,
2
0
1
,
2
5
6
$1
1
0
,
4
6
2
,
3
3
5
-$
1
0
,
5
0
2
,
2
5
2
$1
7
,
9
2
6
,
9
0
1
$1
,
0
2
1
,
3
2
3
-$
9
,
1
8
8
,
3
1
4
To
t
a
l

t
h
r
o
u
g
h

$1
3
0
,
3
2
9
,
1
3
0
($
8
4
,
9
8
0
,
8
2
4
)
$4
,
6
0
7
,
6
2
7
$8
,
6
0
9
,
3
3
5
$9
2
,
3
8
2
,
3
9
0
($
1
1
,
0
6
5
,
9
6
1
)
$1
8
,
0
5
8
,
7
1
9
$8
8
3
,
7
1
1
-$
4
,
7
1
6
,
5
2
8
($
1
,
5
9
3
,
5
1
5
)
($
6
,
3
1
0
,
0
4
3
)
$1
3
,
1
9
6
,
4
0
5
WA

R
e
t
a
i
l

R
e
v
e
n
u
e

A
d
j
u
s
t
m
e
n
t

(+
)

S
u
r
c
h
a
r
g
e

(
-
)

R
e
b
a
t
e
($
3
,
1
2
5
,
1
1
3
)
Ne
t

P
o
w
e
r

C
o
s
t

(
+
)

S
u
r
c
h
a
r
g
e

(
-
)

Re
b
a
t
e
$5
,
4
8
4
,
2
2
2
WN
P

C
o
r
r
e
c
t
i
o
n
*
Ac
c
t

5
5
7
2
8
0

E
n
t
r
y
;

(
+
)

R
e
b
a
t
e
,

(
-
)

S
u
r
c
h
a
r
g
e
($
5
1
8
,
6
5
1
)
Pr
i
o
r

P
e
r
i
o
d

I
n
t
r
a
c
o
m
p
a
n
y

G
a
s

A
d
j
u
s
t
m
e
n
t

-
NS
J
0
1
7

a
n
d

N
S
J
0
1
9

Deferral Report Month of Dec 2013
Page 10 of 75
ICNU_DR_225 Attachment A Page 14 of 79
Lin
e
No
.
Ja
n
-
1
3
Fe
b
-
1
3
Ma
r
-
1
3
Ap
r
-
1
3
Ma
y
-
1
3
Ju
n
-
1
3
Ju
l
-
1
3
Au
g
-
1
3
Se
p
-
1
3
Oc
t
-
1
3
No
v
-
1
3
De
c
-
1
3
55
5

P
U
R
C
H
A
S
E
D

P
O
W
E
R
1
Sh
o
r
t
-
T
e
r
m

P
u
r
c
h
a
s
e
s
$1
0
,
0
5
2
,
7
7
1
$1
0
,
8
8
8
,
0
6
6
$1
0
,
6
6
9
,
4
8
4
$1
0
,
3
4
4
,
1
5
4
$8
,
1
8
0
,
1
1
0
$6
,
4
3
6
,
1
9
8
$7
,
8
6
2
,
2
4
5
$9
,
6
6
8
,
9
7
9
$7
,
3
0
3
,
9
0
7
$8
,
0
9
8
,
7
5
3
$8
,
2
6
4
,
2
1
8
$5
,
4
6
7
,
0
9
7
2
Ch
e
l
a
n

C
o
u
n
t
y

P
U
D

(
R
o
c
k
y

R
e
a
c
h

S
l
i
c
e
)
$9
8
5
,
4
0
1
$9
8
5
,
4
0
1
$9
8
5
,
4
0
1
$9
8
5
,
4
0
1
$9
8
5
,
4
0
1
$9
8
5
,
4
0
1
$9
8
5
,
4
0
1
$9
8
5
,
4
0
1
$9
8
5
,
4
0
1
$9
8
5
,
4
0
1
$9
8
5
,
4
9
9
$9
8
5
,
4
0
1
3
Do
u
g
l
a
s

C
o
u
n
t
y

P
U
D

(
W
e
l
l
s

S
e
t
t
l
e
m
e
n
t
)
$8
9
,
2
9
9
$4
2
,
5
8
3
$3
8
,
2
4
4
$1
3
5
,
7
4
5
$1
6
7
,
1
4
0
$1
7
2
,
8
9
1
$1
3
8
,
3
8
1
$1
0
9
,
2
5
7
$5
1
,
1
6
8
$4
5
,
9
0
0
$4
2
,
5
0
7
$1
0
,
8
6
5
4
Do
u
g
l
a
s

C
o
u
n
t
y

P
U
D

(
W
e
l
l
s
)
$1
5
1
,
5
9
3
$1
5
1
,
5
9
3
$1
5
1
,
5
9
3
$1
5
1
,
5
9
3
$1
5
1
,
5
9
3
$1
5
1
,
5
9
3
$1
5
1
,
5
9
3
$1
5
1
,
5
9
3
$1
5
0
,
5
0
6
$1
5
0
,
5
0
6
$1
5
0
,
5
0
6
$1
5
0
,
5
0
6
5
$5
1
3
,
3
7
6
$5
1
3
,
3
7
6
$5
1
3
,
2
3
9
$5
1
3
,
3
7
6
$5
1
3
,
3
7
6
$5
1
3
,
3
7
6
$5
1
3
,
0
4
7
$5
1
3
,
6
3
8
$5
1
3
,
3
7
6
$5
1
3
,
3
7
6
$5
1
3
,
3
7
6
$5
1
3
,
3
7
6
67
In
l
a
n
d

P
o
w
e
r

&

L
i
g
h
t

-

D
e
e
r

L
a
k
e
$6
4
4
$8
2
1
$6
8
5
$7
9
8
$6
7
6
$5
2
1
$5
6
7
$5
5
3
$6
5
3
$4
2
2
$3
4
9
$2
2
8
Sm
a
l
l

P
o
w
e
r
$1
2
7
,
6
2
4
$1
6
8
,
7
0
8
$1
2
8
,
3
0
0
$1
4
0
,
5
7
6
$1
1
1
,
0
0
1
$1
2
6
,
1
1
4
$1
3
9
,
3
6
4
$8
6
,
2
5
1
$7
3
,
6
3
8
$8
1
,
2
0
7
$8
7
,
0
6
8
$5
7
,
8
0
4
9
Sti
m
s
o
n

L
u
m
b
e
r
$1
7
7
,
4
0
3
$1
5
4
,
9
1
9
$1
3
5
,
3
1
9
$1
2
5
,
1
7
9
$1
2
9
,
0
1
2
$8
1
,
8
8
5
$1
9
4
,
4
6
4
$1
9
5
,
5
9
3
$1
8
2
,
9
2
7
$1
8
9
,
1
7
8
$1
8
2
,
8
9
3
$1
7
5
,
4
3
6
10
Ci
t
y

o
f

S
p
o
k
a
n
e
-
U
p
r
i
v
e
r
$2
3
1
,
6
3
7
$2
7
5
,
6
3
9
$4
0
6
,
1
0
0
$3
0
7
,
4
9
8
$3
2
4
,
2
2
4
$2
3
1
,
4
2
6
$3
2
,
8
8
8
$1
2
,
0
2
7
$1
3
,
6
7
6
$1
1
0
,
8
0
6
$1
5
9
,
3
2
0
$2
8
0
,
4
5
6
11
Ci
t
y

o
f

S
p
o
k
a
n
e

-

W
a
s
t
e
-
t
o
-
E
n
e
r
g
y
$5
9
1
,
6
6
4
$4
6
6
,
7
0
8
$5
0
9
,
1
9
4
$5
0
9
,
2
4
1
$5
0
5
,
5
8
8
$4
8
9
,
7
8
3
$4
7
2
,
5
4
6
$6
1
5
,
4
0
9
$6
0
8
,
1
9
7
$6
1
4
,
4
7
7
$5
1
1
,
0
0
9
$4
6
7
,
6
4
0
12
JP

M
o
r
g
a
n

V
e
n
t
u
r
e
s

-

S
t
a
t
e
l
i
n
e

W
i
n
d

$2
3
5
,
6
4
1
$3
4
5
,
7
8
6
$2
9
3
,
4
9
6
$4
1
1
,
8
0
0
$3
1
2
,
8
2
6
$2
0
8
,
2
2
8
$2
5
4
,
9
2
6
$2
1
0
,
4
6
9
$3
0
3
,
0
7
3
$1
5
3
,
1
8
4
$2
3
8
,
6
7
2
$2
6
2
,
7
8
9
13
Ra
t
h
d
r
u
m

P
o
w
e
r
,

L
L
C

(
L
a
n
c
a
s
t
e
r

P
P
A

)
$2
,
1
0
9
,
7
4
4
$2
,
1
1
0
,
0
0
0
$2
,
1
6
0
,
2
6
3
$1
,
9
4
3
,
6
1
6
$1
,
9
8
4
,
5
5
7
$1
,
9
0
8
,
5
8
3
$2
,
1
2
8
,
4
2
2
$2
,
2
0
2
,
4
6
4
$2
,
1
5
8
,
7
0
5
$2
,
2
0
6
,
7
9
3
$2
,
1
6
4
,
8
1
5
$2
,
2
2
2
,
6
9
7
14
Pa
l
o
u
s
e

W
i
n
d
$1
,
2
1
5
,
9
9
4
$1
,
5
7
8
,
2
1
3
$1
,
7
2
1
,
8
5
7
$2
,
2
2
1
,
2
1
1
$1
,
0
5
3
,
3
8
8
$1
,
0
1
1
,
1
0
1
$9
6
2
,
7
6
5
$7
5
1
,
2
1
8
$1
,
5
2
1
,
7
9
3
$9
1
4
,
4
8
4
$1
,
4
0
1
,
0
9
0
$1
,
9
8
0
,
3
0
0
15
Cl
e
a
r
w
a
t
e
r

(
P
F
I
)
$1
,
6
5
3
,
4
5
0
$1
,
3
8
6
,
7
0
2
$1
,
5
3
5
,
0
3
4
$1
,
4
9
0
,
7
4
0
$1
,
6
1
2
,
4
1
9
$1
,
5
0
9
,
9
6
9
$0
$0
$0
$0
$0
$0
16
WP
M

A
n
c
i
l
l
a
r
y

S
e
r
v
i
c
e
s
$6
1
,
8
7
8
$5
2
,
6
0
9
$5
2
,
1
8
2
$5
1
,
7
4
5
$5
1
,
4
6
3
$4
8
,
9
7
7
$5
6
,
2
9
2
$5
1
,
7
8
1
$4
8
,
2
3
0
$5
0
,
7
9
4
$5
7
,
9
9
2
$7
0
,
5
6
9
17
No
n
-
M
o
n
.

A
c
c
r
u
a
l
s
($
1
4
,
4
8
0
)
($
4
9
,
7
0
2
)
$2
,
8
3
8
($
3
5
,
1
4
7
)
($
4
1
,
7
6
1
)
$9
1
,
0
1
0
($
1
0
6
,
2
0
5
)
($
1
9
,
6
3
2
)
$7
7
,
3
6
2
($
3
8
,
8
6
3
)
($
8
7
,
8
1
4
)
($
1
4
1
,
7
6
4
)
18
To
t
a
l

5
5
5

P
u
r
c
h
a
s
e
d

P
o
w
e
r
$2
1
,
5
3
9
,
7
4
5
$2
2
,
1
0
4
,
0
1
5
$2
0
,
9
6
0
,
0
7
3
$2
0
,
9
0
6
,
3
0
9
$1
6
,
0
4
1
,
0
1
3
$1
3
,
9
6
7
,
0
5
6
$1
3
,
7
8
6
,
6
9
6
$1
5
,
5
3
5
,
0
0
1
$1
3
,
9
9
2
,
6
1
2
$1
4
,
0
7
6
,
4
1
8
$1
8
,
0
1
5
,
2
0
8
$1
5
,
9
5
7
,
9
5
5

(1
)

E
f
f
e
c
t
i
v
e

N
o
v
e
m
b
e
r
,

2
0
0
8
,

W
N
P
-
3

p
u
r
c
h
a
s
e

e
x
p
e
n
s
e

h
a
s

b
e
e
n

a
d
j
u
s
t
e
d

t
o

r
e
f
l
e
c
t

t
h
e

m
i
d
-
p
o
i
n
t

p
r
i
c
e
,

p
e
r

S
e
t
t
l
e
m
e
n
t

A
g
r
e
e
m
e
n
t
,

C
a
u
s
e

N
o
.

U
-
8
6
-
9
9
44
7

S
A
L
E
S

F
O
R

R
E
S
A
L
E
19
Sh
o
r
t
-
T
e
r
m

S
a
l
e
s
($
9
,
0
5
6
,
9
5
6
)
($
1
1
,
3
4
8
,
6
8
3
)
($
1
1
,
7
7
5
,
4
3
8
)
($
1
3
,
0
8
2
,
5
3
5
)
($
1
0
,
8
0
9
,
8
3
6
)
($
5
,
8
3
7
,
0
6
6
)
($
5
,
8
4
5
,
4
9
3
)
($
6
,
2
5
5
,
1
4
2
)
($
5
,
0
6
1
,
3
7
9
)
($
6
,
9
7
8
,
8
6
8
)
($
8
,
0
4
6
,
2
6
0
)
($
2
,
9
5
3
,
8
5
0
)
20
Pe
a
k
e
r

L
L
C
/
P
G
E

C
a
p

S
a
l
e
($
1
4
5
,
9
5
5
)
($
1
4
6
,
4
1
0
)
($
1
4
6
,
1
5
0
)
($
1
4
5
,
1
5
0
)
($
1
4
5
,
9
5
5
)
($
1
4
6
,
0
8
5
)
($
1
4
5
,
2
5
0
)
($
1
4
5
,
2
5
0
)
($
1
4
5
,
1
5
0
)
($
1
4
6
,
0
2
0
)
($
1
4
6
,
0
8
5
)
($
1
4
4
,
9
5
5
)
21
Nic
h
o
l
s

P
u
m
p
i
n
g

I
n
d
e
x

S
a
l
e
($
9
9
,
5
2
4
)
($
9
3
,
6
5
1
)
($
1
3
3
,
7
6
8
)
($
1
0
1
,
8
5
6
)
($
1
0
1
,
9
3
6
)
($
1
0
2
,
2
5
1
)
($
1
6
9
,
0
4
5
)
($
1
2
4
,
8
4
2
)
($
1
5
0
,
1
3
0
)
($
1
6
2
,
5
8
2
)
($
1
2
1
,
9
5
1
)
($
1
9
0
,
3
4
6
)
22
So
v
e
r
i
g
n
/
K
a
i
s
e
r

L
o
a
d

F
o
l
l
o
w
i
n
g
($
6
,
5
4
3
)
($
5
,
9
8
4
)
($
6
,
7
7
9
)
($
6
,
5
6
3
)
($
6
,
4
4
4
)
($
6
,
1
3
7
)
($
6
,
4
6
1
)
($
6
,
4
5
2
)
($
6
,
4
4
8
)
($
6
,
6
8
4
)
($
6
,
6
4
5
)
($
6
,
7
4
5
)
23
Pe
n
d

O
r
e
i
l
l
e

D
E
S
($
4
2
,
3
4
0
)
($
3
6
,
7
7
6
)
($
4
0
,
3
4
0
)
($
3
6
,
2
2
8
)
($
3
3
,
9
5
2
)
($
3
0
,
7
2
9
)
($
3
6
,
0
3
0
)
($
3
0
,
8
8
8
)
($
3
2
,
6
0
8
)
($
4
1
,
0
6
8
)
($
3
8
,
0
9
2
)
($
3
9
,
0
9
4
)
24
SM
U
D

5
0

+

2
5
($
1
,
8
0
1
,
8
6
2
)
($
1
,
8
5
6
,
3
9
9
)
($
2
,
0
8
1
,
2
7
7
)
($
2
,
0
5
2
,
8
2
4
)
($
2
,
0
0
6
,
5
8
3
)
($
2
,
1
4
2
,
2
6
7
)
($
1
,
7
1
8
,
2
8
3
)
($
1
,
6
1
6
,
0
5
1
)
($
1
,
6
2
2
,
2
4
4
)
($
1
,
6
1
2
,
2
6
2
)
($
1
,
6
0
6
,
1
6
7
)
($
2
,
2
0
2
,
2
5
8
)
25
Me
r
c
h
a
n
t

A
n
c
i
l
l
a
r
y

S
e
r
v
i
c
e
s
($
1
,
7
5
2
,
7
9
5
)
($
2
,
0
2
9
,
5
0
2
)
($
2
,
3
9
9
,
8
4
0
)
($
2
,
4
5
0
,
9
0
4
)
($
2
,
1
5
7
,
0
3
6
)
($
1
,
5
1
2
,
5
2
9
)
($
1
,
1
3
7
,
5
7
1
)
($
1
,
0
2
5
,
3
7
0
)
($
1
,
2
3
7
,
2
7
4
)
($
1
,
3
3
2
,
7
9
8
)
($
1
,
6
8
1
,
0
8
1
)
($
1
,
4
8
7
,
5
5
5
)
26
To
t
a
l

4
4
7

S
a
l
e
s

f
o
r

R
e
s
a
l
e
($
1
2
,
9
0
5
,
9
7
5
)
($
1
5
,
5
1
7
,
4
0
5
)
($
1
6
,
5
8
3
,
5
9
2
)
($
1
7
,
8
7
6
,
0
6
0
)
($
1
5
,
2
6
1
,
7
4
2
)
($
9
,
7
7
7
,
0
6
4
)
($
9
,
0
5
8
,
1
3
3
)
($
9
,
2
0
3
,
9
9
5
)
($
8
,
2
5
5
,
2
3
3
)
($
1
0
,
2
8
0
,
2
8
2
)
($
1
1
,
6
4
6
,
2
8
1
)
($
7
,
0
2
4
,
8
0
3
)
27
Ke
t
t
l
e

F
a
l
l
s

W
o
o
d
-
5
0
1
1
1
0
$6
7
8
,
2
5
3
$5
3
1
,
7
1
8
$7
3
9
,
3
4
0
$5
1
0
,
4
2
1
$1
3
3
,
4
5
9
($
1
7
2
,
4
4
3
)
$5
9
3
,
7
0
0
$6
3
9
,
2
0
2
$7
3
8
,
3
0
6
$5
9
5
,
9
6
4
$6
8
8
,
4
9
1
$7
1
0
,
8
1
7
28
Ke
t
t
l
e

F
a
l
l
s

G
a
s
-
5
0
1
1
2
0
($
5
3
)
$2
,
2
2
7
$5
2
2
$3
,
9
8
7
($
8
)
$2
,
3
8
9
$3
,
3
7
7
$7
4
6
$1
9
3
$1
,
6
2
1
($
2
0
)
$2
,
2
9
7
29
Co
l
s
t
r
i
p

C
o
a
l
-
5
0
1
1
4
0
$1
,
9
1
6
,
7
6
0
$1
,
7
3
3
,
7
5
7
$2
,
1
1
3
,
3
8
4
$2
,
3
8
7
,
0
7
7
$5
6
5
,
7
1
4
$1
,
1
8
0
,
6
1
4
$4
0
0
,
9
4
3
$1
,
3
5
0
,
6
7
8
$1
,
2
3
0
,
8
1
3
$1
,
2
4
3
,
2
0
5
$1
,
1
9
9
,
8
5
1
$1
,
2
4
9
,
9
2
3
30
Co
l
s
t
r
i
p

O
i
l
-
5
0
1
1
6
0
$2
8
,
1
5
1
$1
9
9
$6
,
4
1
3
$1
4
,
8
4
6
$2
,
1
8
4
$4
1
,
0
2
6
$4
2
,
6
9
6
$4
2
,
9
7
5
$0
$1
,
5
5
1
$3
1
,
4
7
3
$1
2
,
5
1
7
31
To
t
a
l

5
0
1

F
u
e
l

E
x
p
e
n
s
e
$2
,
6
2
3
,
1
1
1
$2
,
2
6
7
,
9
0
1
$2
,
8
5
9
,
6
5
9
$2
,
9
1
6
,
3
3
1
$7
0
1
,
3
4
9
$1
,
0
5
1
,
5
8
6
$1
,
0
4
0
,
7
1
6
$2
,
0
3
3
,
6
0
1
$1
,
9
6
9
,
3
1
2
$1
,
8
4
2
,
3
4
1
$1
,
9
1
9
,
7
9
5
$1
,
9
7
5
,
5
5
4
50
1

F
U
E
L
-
T
O
N
S
32
Ke
t
t
l
e

F
a
l
l
s
43
,
0
2
3

36
,
0
5
6

51
,
3
2
8

37
,
3
8
7

10
,
0
7
3

2,
6
9
1

42
,
5
4
6

47
,
0
7
2

54
,
9
1
6

46
,
0
4
8

53
,
2
1
9

54
,
5
8
9

33
Co
l
s
t
r
i
p
97
,
6
8
7

92
,
2
2
3

95
,
6
5
6

90
,
4
0
1

56
,
1
1
9

47
,
5
3
3

48
,
2
8
6

50
,
2
7
6

47
,
8
8
9

46
,
1
1
0

45
,
0
3
7

51
,
3
4
2

50
1

F
U
E
L
-
C
O
S
T

P
E
R

T
O
N
34
Ke
t
t
l
e

F
a
l
l
s
$1
5
.
7
6
$1
4
.
7
5
$1
4
.
4
0
$1
3
.
6
5
$1
3
.
2
5
($
6
4
.
0
8
)
$1
3
.
9
5
$1
3
.
5
8
$1
3
.
4
4
$1
2
.
9
4
$1
2
.
9
4
$1
3
.
0
2
35
Co
l
s
t
r
i
p

$1
9
.
6
2
$1
8
.
8
0
$2
2
.
0
9
$2
6
.
4
1
$1
0
.
0
8
$2
4
.
8
4
$8
.
3
0
$2
6
.
8
7
$2
5
.
7
0
$2
6
.
9
6
$2
6
.
6
4
$2
4
.
3
5
54
7

F
U
E
L
36
NE

C
T

G
a
s
/
O
i
l
-
5
4
7
2
1
3
($
1
4
)
$1
,
2
8
1
$3
6
$4
,
6
4
3
$5
1
($
1
1
4
)
$1
,
0
0
3
$8
($
5
4
)
$2
,
7
4
4
$4
3
$3
,
5
0
5
37
Bo
u
l
d
e
r

P
a
r
k
-
5
4
7
2
1
6
$5
2
,
3
7
9
($
1
9
)
$4
5
,
8
3
8
$1
2
,
9
4
5
$3
2
,
6
4
5
$3
2
,
2
2
7
$1
3
1
,
0
8
3
$1
9
5
,
5
9
7
$1
2
1
,
9
9
9
$8
1
,
4
0
6
$1
2
6
,
3
5
1
$1
9
4
,
3
5
5
38
Ke
t
t
l
e

F
a
l
l
s

C
T
-
5
4
7
2
1
1
$1
4
,
8
9
0
$0
$7
,
8
0
6
$2
,
3
7
6
$1
,
7
9
5
($
3
4
)
$3
7
,
8
7
3
$5
7
,
7
5
6
$4
8
,
4
0
5
$2
6
,
9
8
0
$5
3
,
1
4
7
$3
1
,
7
8
7
39
Co
y
o
t
e

S
p
r
i
n
g
s
2
-
5
4
7
6
1
0
$4
,
4
6
3
,
4
7
1
$4
,
3
0
1
,
4
8
8
$5
,
3
3
1
,
0
1
7
$2
,
3
4
9
,
2
5
9
$3
,
1
2
1
,
5
0
9
$1
,
4
7
1
,
8
5
9
$4
,
6
3
7
,
8
0
8
$5
,
3
9
9
,
2
1
8
$5
,
4
7
4
,
7
0
4
$5
,
1
6
2
,
7
3
9
$5
,
7
6
6
,
4
3
2
$8
,
8
8
7
,
1
6
4
40
La
n
c
a
s
t
e
r
-
5
4
7
3
1
2
$4
,
5
9
9
,
4
2
5
$4
,
2
3
3
,
7
3
5
$5
,
2
0
8
,
2
4
3
$2
,
2
7
5
,
4
8
7
$2
,
7
8
4
,
9
7
2
$1
,
6
0
9
,
0
5
5
$4
,
2
8
2
,
8
1
7
$5
,
1
7
5
,
7
9
5
$4
,
7
2
4
,
8
6
8
$5
,
2
7
3
,
3
0
2
$4
,
6
5
5
,
2
7
2
$6
,
4
7
6
,
1
8
1
41
Ra
t
h
d
r
u
m

C
T
-
5
4
7
3
1
0
$7
4
,
8
1
1
($
1
2
9
)
$8
8
,
6
4
9
$9
,
8
8
7
$2
3
,
7
6
2
$3
6
,
9
7
5
$2
5
5
,
4
7
9
$3
2
3
,
3
2
4
$1
4
8
,
7
8
1
$6
4
8
$5
9
,
7
9
5
$4
5
1
,
8
1
4
42
To
t
a
l

5
4
7

F
u
e
l

E
x
p
e
n
s
e
$9
,
2
0
4
,
9
6
2
$8
,
5
3
6
,
3
5
6
$1
0
,
6
8
1
,
5
8
9
$4
,
6
5
4
,
5
9
7
$5
,
9
6
4
,
7
3
4
$3
,
1
4
9
,
9
6
8
$9
,
3
4
6
,
0
6
3
$1
1
,
1
5
1
,
6
9
8
$1
0
,
5
1
8
,
7
0
3
$1
0
,
5
4
7
,
8
1
9
$1
0
,
6
6
1
,
0
4
0
$1
6
,
0
4
4
,
8
0
6
Deferral Report Month of Dec 2013
Page 11 of 75
ICNU_DR_225 Attachment A Page 15 of 79
Lin
e
Ja
n
-
1
3
Fe
b
-
1
3
Ma
r
-
1
3
Ap
r
-
1
3
Ma
y
-
1
3
Ju
n
-
1
3
Ju
l
-
1
3
Au
g
-
1
3
Se
p
-
1
3
Oc
t
-
1
3
No
v
-
1
3
De
c
-
1
3
Av
i
s
t
a

C
o
r
p
.

-

R
e
s
o
u
r
c
e

A
c
c
o
u
n
t
i
n
g
WA
S
H
I
N
G
T
O
N

D
E
F
E
R
R
E
D

P
O
W
E
R

C
O
S
T

C
A
L
C
U
L
A
T
I
O
N

-

A
C
T
U
A
L

S
Y
S
T
E
M

P
O
W
E
R

S
U
P
P
L
Y

E
X
P
E
N
S
E
S
43
TO
T
A
L

N
E
T

E
X
P
E
N
S
E
$2
0
,
4
6
1
,
8
4
3
$1
7
,
3
9
0
,
8
6
7
$1
7
,
9
1
7
,
7
2
9
$1
0
,
6
0
1
,
1
7
7
$7
,
4
4
5
,
3
5
4
$8
,
3
9
1
,
5
4
6
$1
5
,
1
1
5
,
3
4
2
$1
9
,
5
1
6
,
3
0
5
$1
8
,
2
2
5
,
3
9
4
$1
6
,
1
8
6
,
2
9
6
$1
8
,
9
4
9
,
7
6
2
$2
6
,
9
5
3
,
5
1
2
44
45
6
1
0
0

E
D

A
N
($
9
5
1
,
7
4
0
)
($
6
6
3
,
6
1
7
)
($
7
8
4
,
9
9
5
)
($
7
1
4
,
2
0
4
)
($
8
2
2
,
3
1
1
)
($
1
,
1
6
0
,
1
3
5
)
($
1
,
2
1
0
,
0
0
5
)
($
1
,
0
6
7
,
0
6
4
)
($
8
4
1
,
0
2
6
)
($
7
8
2
,
9
2
6
)
($
8
0
7
,
2
3
6
)
($
6
9
6
,
9
9
3
)
45
45
6
1
2
0

E
D

A
N

-

B
P
A

S
e
t
t
l
e
m
e
n
t
$0
($
1
2
,
2
2
4
,
0
0
0
)
($
2
6
6
,
0
0
0
)
$0
$0
$0
$0
$0
$0
$0
$0
$0
46
Ex
c
l
u
d
e

P
r
i
o
r

Y
e
a
r

B
P
A

S
e
t
t
l
e
m
e
n
t

$0
$1
1
,
6
9
2
,
0
0
0
$7
9
8
,
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
47
45
6
7
0
5

E
D

A
N

-

D
o

n
o
t

i
n
c
l
u
d
e

L
o
w

V
o
l
t
a
g
e
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
48
To
t
a
l

4
5
6

T
r
a
n
s
m
i
s
s
i
o
n

R
e
v
e
n
u
e
($
9
5
1
,
7
4
0
)
($
1
,
1
9
5
,
6
1
7
)
($
2
5
2
,
9
9
5
)
($
7
1
4
,
2
0
4
)
($
8
2
2
,
3
1
1
)
($
1
,
1
6
0
,
1
3
5
)
($
1
,
2
1
0
,
0
0
5
)
($
1
,
0
6
7
,
0
6
4
)
($
8
4
1
,
0
2
6
)
($
7
8
2
,
9
2
6
)
($
8
0
7
,
2
3
6
)
($
6
9
6
,
9
9
3
)
49
56
5
0
0
0

E
D

A
N
$1
,
4
8
2
,
4
7
1
$1
,
4
6
4
,
6
4
9
$1
,
4
8
9
,
2
9
2
$1
,
4
7
2
,
5
1
2
$1
,
4
2
0
,
2
8
7
$1
,
3
9
6
,
3
8
5
$1
,
4
5
8
,
0
0
2
$1
,
4
4
8
,
3
2
2
$1
,
4
0
3
,
4
8
6
$1
,
5
4
8
,
5
0
8
$1
,
6
8
3
,
2
1
6
$1
,
6
3
5
,
4
1
1
50
56
5
3
1
2

E
D

A
N
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
51
56
5
7
1
0

E
D

A
N
$2
,
0
3
0
$2
,
0
3
0
$2
,
0
3
0
$2
,
0
3
0
$2
,
0
3
0
$2
,
0
3
0
$2
,
0
3
0
$2
,
0
3
0
$2
,
0
3
0
$2
,
0
3
0
$2
,
0
3
0
$2
,
0
3
0
52
To
t
a
l

5
6
5

T
r
a
n
s
m
i
s
s
i
o
n

E
x
p
e
n
s
e
$1
,
4
8
4
,
5
0
1
$1
,
4
6
6
,
6
7
9
$1
,
4
9
1
,
3
2
2
$1
,
4
7
4
,
5
4
2
$1
,
4
2
2
,
3
1
7
$1
,
3
9
8
,
4
1
5
$1
,
4
6
0
,
0
3
2
$1
,
4
5
0
,
3
5
2
$1
,
4
0
5
,
5
1
6
$1
,
5
5
0
,
5
3
8
$1
,
6
8
5
,
2
4
6
$1
,
6
3
7
,
4
4
1
53
To
t
a
l

5
5
7
1
7
0

E
D

A
N

B
r
o
k
e
r

F
e
e
s
$8
7
,
8
8
4
$7
8
,
6
1
2
$9
7
,
8
8
8
$1
0
6
,
9
6
2
$1
0
0
,
8
0
9
$6
8
,
5
5
6
$9
2
,
5
4
5
$1
0
0
,
9
0
1
$1
0
3
,
4
6
8
$9
5
,
1
6
9
$3
6
,
1
7
4
$5
2
,
3
5
5
54
Ec
o
n

D
i
s
p
a
t
c
h
-
5
5
7
0
1
0
$9
8
8
,
6
2
9
$1
,
0
3
0
,
5
7
0
$1
,
8
0
8
,
0
0
7
$7
5
1
,
8
8
9
$2
8
4
,
6
8
8
$8
1
4
,
6
8
8
$2
,
3
0
4
,
3
1
0
$4
,
4
0
5
,
6
2
3
$5
,
5
5
8
,
3
9
2
$4
,
5
3
5
,
0
2
1
$5
6
3
,
9
9
7
$2
,
4
7
1
,
3
7
5
55
Ec
o
n

D
i
s
p
a
t
c
h
-
5
5
7
1
5
0
$5
,
1
6
5
,
5
8
6
$4
,
9
5
0
,
7
8
2
$4
,
8
9
7
,
7
3
4
$7
,
7
2
5
,
8
8
0
$1
0
,
9
8
1
,
6
7
6
$5
,
3
7
8
,
5
9
6
$4
,
8
0
6
,
7
7
8
$2
,
4
2
4
,
8
2
6
$2
,
7
2
7
,
6
9
2
$6
,
5
2
1
,
3
3
9
($
1
,
6
8
3
,
5
3
2
)
($
3
,
8
7
8
,
8
1
4
)
56
Ga
s

B
o
o
k
o
u
t
s
-
5
5
7
7
0
0
$0
$5
,
1
0
0
$1
,
7
4
3
,
6
9
2
$0
$0
$0
$1
9
4
,
4
2
5
$1
6
8
,
1
1
8
$3
7
2
,
9
1
6
$1
1
1
,
2
0
0
$3
0
6
,
2
5
7
$1
1
5
,
0
1
2
57
Ga
s

B
o
o
k
o
u
t
s
-
5
5
7
7
1
1
$0
($
5
,
1
0
0
)
($
1
,
7
4
3
,
6
9
2
)
$0
$0
$0
($
1
9
4
,
4
2
5
)
($
1
6
8
,
1
1
8
)
($
3
7
2
,
9
1
6
)
($
1
1
1
,
2
0
0
)
($
3
0
6
,
2
5
7
)
($
1
1
5
,
0
1
2
)
58
In
t
r
a
c
o

T
h
e
r
m
a
l

G
a
s
-
5
5
7
7
3
0
$4
,
4
4
6
,
5
5
9
$4
,
4
7
3
,
1
2
9
$4
,
6
8
5
,
0
8
3
$1
,
9
2
0
,
6
4
2
$2
,
4
7
1
,
1
9
0
$1
,
1
6
8
,
1
6
1
$1
,
5
2
9
,
0
4
6
$5
,
1
4
5
,
8
3
7
$2
,
7
4
1
,
7
5
8
$4
,
0
7
8
,
9
7
5
$7
,
8
2
2
,
9
9
6
$8
,
9
8
4
,
5
0
6
59
Fu
e
l

D
i
s
p
a
t
c
h
F
i
n

-
4
5
6
0
1
0
($
1
,
0
8
6
,
9
6
1
)
($
9
5
6
,
8
1
0
)
($
1
,
5
5
1
,
2
6
4
)
($
5
6
1
,
3
6
0
)
($
4
9
5
,
5
5
7
)
($
1
,
2
7
0
,
1
6
3
)
($
1
,
2
9
8
,
2
9
8
)
($
2
,
0
0
9
,
4
5
1
)
($
2
,
5
8
8
,
6
4
0
)
($
2
,
5
7
9
,
7
5
3
)
($
6
3
1
,
0
4
1
)
($
2
,
2
3
2
,
5
5
8
)
60
Fu
e
l

D
i
s
p
a
t
c
h
-
4
5
6
0
1
5
($
1
,
6
6
4
,
4
2
6
)
($
1
3
0
,
2
7
1
)
($
3
0
3
,
6
3
2
)
($
1
,
2
9
4
,
3
5
1
)
($
3
,
4
4
5
,
1
7
8
)
($
9
7
,
7
5
3
)
($
5
7
0
,
7
8
4
)
($
4
7
5
,
2
7
0
)
($
1
5
8
,
7
2
8
)
($
1
,
4
9
7
,
8
6
3
)
($
2
1
3
,
2
9
0
)
($
1
5
8
,
4
1
8
)
61
In
t
r
a
c
o

T
h
e
r
m
a
l

G
a
s
-
4
5
6
7
3
0
($
7
,
8
9
3
,
9
9
6
)
($
9
,
3
1
1
,
9
4
4
)
($
1
0
,
6
2
1
,
4
8
0
)
($
9
,
2
7
6
,
4
5
6
)
($
1
0
,
3
2
9
,
3
1
2
)
($
6
,
7
1
7
,
8
0
0
)
($
6
,
5
8
0
,
0
1
0
)
($
8
,
7
0
3
,
2
9
9
)
($
7
,
4
3
9
,
0
3
8
)
($
1
1
,
3
9
0
,
2
1
4
)
($
6
,
5
4
9
,
5
8
2
)
($
7
,
5
8
8
,
9
9
8
)
62
Fu
e
l

B
o
o
k
o
u
t
s
-
4
5
6
7
1
1
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
63
Fu
e
l

B
o
o
k
o
u
t
s
-
4
5
6
7
2
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
64
R
e
s
o
u
r
c
e

O
p
t
i
m
i
z
a
t
o
n

S
u
b
t
o
t
a
l
($
4
4
,
6
0
9
)
$5
5
,
4
5
6
($
1
,
0
8
5
,
5
5
2
)
($
7
3
3
,
7
5
6
)
($
5
3
2
,
4
9
3
)
($
7
2
4
,
2
7
1
)
$1
9
1
,
0
4
2
$7
8
8
,
2
6
6
$8
4
1
,
4
3
6
($
3
3
2
,
4
9
5
)
($
6
9
0
,
4
5
2
)
($
2
,
4
0
2
,
9
0
7
)
65
Mis
c
.

P
o
w
e
r

E
x
p
.

A
u
t
h
o
r
i
z
e
d
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
66
Mis
c
.

P
o
w
e
r

E
x
p
.

A
c
t
u
a
l
-
5
5
7
1
6
0

E
D

A
N
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
67
KF
W
F

C
o
n
t
r
a
c
t

B
u
y
o
u
t
$4
7
,
2
0
0
$3
4
,
4
0
0
$3
4
,
4
0
0
$1
4
,
4
0
0
$0
$0
$0
$0
$0
$0
$0
$0
68
Mis
c
.

P
o
w
e
r

E
x
p
.

S
u
b
t
o
t
a
l
$4
7
,
2
0
0
$3
4
,
4
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
69
Win
d

R
E
C

E
x
p

A
u
t
h
o
r
i
z
e
d
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
70
Wi
n
d

R
E
C

E
x
p

A
c
t
u
a
l

5
5
7
3
9
5

($
9
,
3
7
1
)
($
1
3
,
6
3
0
)
($
1
1
,
6
3
7
)
($
1
6
,
3
4
4
)
($
1
2
,
3
7
9
)
($
8
,
2
1
3
)
($
1
0
,
0
1
6
)
($
8
,
2
8
3
)
($
9
,
8
3
3
)
($
8
,
1
9
3
)
($
9
,
4
7
1
)
($
1
0
,
4
2
3
)
71
Wi
n
d

R
E
C

S
u
b
t
o
t
a
l
($
9
,
3
7
1
)
($
1
3
,
6
3
0
)
($
1
1
,
6
3
7
)
($
1
6
,
3
4
4
)
($
1
2
,
3
7
9
)
($
8
,
2
1
3
)
($
1
0
,
0
1
6
)
($
8
,
2
8
3
)
($
9
,
8
3
3
)
($
8
,
1
9
3
)
($
9
,
4
7
1
)
($
1
0
,
4
2
3
)
72
Ne
t

R
e
s
o
u
r
c
e

O
p
t
i
m
i
z
a
t
i
o
n
($
6
,
7
8
0
)
$7
6
,
2
2
6
($
1
,
0
9
7
,
1
8
9
)
($
7
5
0
,
1
0
0
)
($
5
4
4
,
8
7
2
)
($
7
3
2
,
4
8
4
)
$1
8
1
,
0
2
6
$7
7
9
,
9
8
3
$8
3
1
,
6
0
3
($
3
4
0
,
6
8
8
)
($
6
9
9
,
9
2
3
)
($
2
,
4
1
3
,
3
3
0
)
73
Ad
j
u
s
t
e
d

A
c
t
u
a
l

N
e
t

E
x
p
e
n
s
e
$2
1
,
0
7
5
,
7
0
8
$1
7
,
8
1
6
,
7
6
7
$1
8
,
1
5
6
,
7
5
5
$1
0
,
7
1
8
,
3
7
7
$7
,
6
0
1
,
2
9
7
$7
,
9
6
5
,
8
9
8
$1
5
,
6
3
8
,
9
4
0
$2
0
,
7
8
0
,
4
7
7
$1
9
,
7
2
4
,
9
5
5
$1
6
,
7
0
8
,
3
8
9
$1
9
,
1
6
4
,
0
2
3
$2
5
,
5
3
2
,
9
8
5
Deferral Report Month of Dec 2013
Page 12 of 75
ICNU_DR_225 Attachment A Page 16 of 79
Re
t
a
i
l

S
a
l
e
s

-

M
W
h
Ja
n
-
1
3
Fe
b
-
1
3
Ma
r
-
1
3
Ap
r
-
1
3
Ma
y
-
1
3
Ju
n
-
1
3
Ju
l
-
1
3
Au
g
-
1
3
Se
p
-
1
3
Oc
t
-
1
3
No
v
-
1
3
De
c
-
1
3
YT
D
To
t
a
l

B
i
l
l
e
d

S
a
l
e
s
55
1
,
6
6
4

54
7
,
3
3
0

47
8
,
0
5
9

45
0
,
8
2
6

43
0
,
3
6
8

42
7
,
7
1
2

43
4
,
9
0
3

47
8
,
7
5
4

46
7
,
5
1
8

44
5
,
8
3
4

43
3
,
9
2
9

54
1
,
6
3
2

5,6
8
8
,
5
2
8

De
d
u
c
t

P
r
i
o
r

M
o
n
t
h

U
n
b
i
l
l
e
d
(3
9
6
,
4
3
2
)

(3
9
4
,
3
1
3
)

(3
4
5
,
3
6
3
)

(3
2
4
,
6
7
3
)

(2
9
9
,
7
6
0
)

(3
0
0
,
9
2
2
)

(2
8
8
,
2
5
6
)

(3
4
1
,
1
4
8
)

(3
6
6
,
1
9
0
)

(3
1
6
,
3
3
7
)

(3
2
8
,
8
6
2
)

(3
6
4
,
5
9
6
)

(4
,
0
6
6
,
8
5
1
)

Ad
d

C
u
r
r
e
n
t

M
o
n
t
h

U
n
b
i
l
l
e
d
39
4
,
3
1
3

34
5
,
3
6
3

32
4
,
6
7
3

29
9
,
7
6
0

30
0
,
9
2
2

28
8
,
2
5
6

34
1
,
1
4
8

36
6
,
1
9
0

31
6
,
3
3
7

32
8
,
8
6
2

36
4
,
5
9
6

37
9
,
9
6
4

4,0
5
0
,
3
8
3

To
t
a
l

R
e
t
a
i
l

S
a
l
e
s
54
9
,
5
4
5

49
8
,
3
8
0

45
7
,
3
6
8

42
5
,
9
1
2

43
1
,
5
3
1

41
5
,
0
4
6

48
7
,
7
9
5

50
3
,
7
9
6

41
7
,
6
6
6

45
8
,
3
5
9

46
9
,
6
6
3

55
7
,
0
0
0

5,6
7
2
,
0
6
0

Te
s
t

Y
e
a
r

R
e
t
a
i
l

S
a
l
e
s
52
5
,
3
4
7

51
7
,
0
9
1

47
9
,
1
2
9

41
3
,
7
2
2

41
2
,
8
1
5

42
3
,
3
3
7

43
7
,
6
7
2

48
2
,
2
5
7

40
7
,
7
8
0

44
8
,
4
5
8

47
5
,
2
9
6

55
1
,
9
5
2

5,
5
7
4
,
8
5
6

Di
f
f
e
r
e
n
c
e

f
r
o
m

T
e
s
t

Y
e
a
r
24
,
1
9
8

(1
8
,
7
1
1
)

(2
1
,
7
6
1
)

12
,
1
9
0

18
,
7
16

(8
,
2
9
1
)

50
,
1
2
3

21
,
5
3
9

9,
8
8
6

9,9
0
1

(5
,
6
3
3
)

5,
0
4
8

97
,
2
0
4

Pr
o
d
u
c
t
i
o
n

R
a
t
e

-

$
/
M
W
h
$3
2
.
1
5
$3
2
.
1
5
$3
2
.
1
5
$3
2
.
1
5
$3
2
.
1
5
$3
2
.
1
5
$3
2
.
1
5
$3
2
.
1
5
$3
2
.
1
5
$3
2
.
1
5
$3
2
.
1
5
$3
2
.
1
5
To
t
a
l

R
e
v
e
n
u
e

C
r
e
d
i
t

-

$
$7
7
7
,
9
5
0
($
6
0
1
,
5
5
0
)
($
6
9
9
,
6
0
7
)
$3
9
1
,
9
2
4
$6
0
1
,
7
0
7
($
2
6
6
,
5
7
1
)
$1
,
6
1
1
,
4
5
3
$6
9
2
,
4
8
0
$3
1
7
,
8
2
2
$3
1
8
,
3
1
0
($
1
8
1
,
0
9
6
)
$1
6
2
,
2
9
1
$3
,
1
2
5
,
1
1
3
Deferral Report Month of Dec 2013
Page 13 of 75
ICNU_DR_225 Attachment A Page 17 of 79
Deferral Report Month of Dec 2013
Page 14 of 75
ICNU_DR_225 Attachment A Page 18 of 79
Deferral Report Month of Dec 2013
Page 15 of 75
ICNU_DR_225 Attachment A Page 19 of 79
Ja
n
-
1
3
Fe
b
-
1
3
Ma
r
-
1
3
Ap
r
-
1
3
Ma
y
-
1
3
Ju
n
-
1
3
Ju
l
-
1
3
Au
g
-
1
3
Se
p
-
1
3
Oc
t
-
1
3
No
v
-
1
3
De
c
-
1
3
To
t
a
l
De
a
l

#
MW
h
s
Sy
s
t
e
m

N
R
14
1
8
8
8
12

-

-

-

-

-

1,
2
9
8

89
3

-

1,
6
2
3

-

10
1

3,
9
2
7

Sy
s
t
e
m
14
2
3
0
5
1,
7
5
0

1,
4
7
5

10
0

9,
6
9
7

6,
9
4
1

14
,
3
5
0

34
,
3
1
3

Sy
s
t
e
m
14
1
8
6
8
6,
5
9
9

2,
9
5
0

20
0

21
,
1
0
0

14
,
7
5
0

28
,
7
0
0

5,
1
5
4

30
0

-

1,
2
0
0

-

-

80
,
9
5
3

CS
2
14
1
8
7
8
27
,
9
2
9

30
,
6
5
0

34
,
7
9
4

14
,
8
0
0

22
,
4
5
0

7,
3
0
0

30
,
7
4
8

35
,
7
0
8

35
,
9
7
1

33
,
2
5
3

36
,
0
4
7

37
,
0
9
2

34
6
,
7
4
2

CS
2
14
2
3
1
4
7,
9
4
2

12
,
8
1
4

14
,
5
6
4

5,
5
6
6

10
,
5
2
4

3,
6
5
0

55
,
0
6
0

Mi
d

C
14
1
8
8
0
2,
4
0
0

-

-

-

-

-

-

-

-

45
0

-

-

2,
8
5
0

Mi
d

C
14
2
3
1
5
80
1

-

-

-

-

-

80
1

La
n
c
16
6
0
1
9
-

-

-

10
0

-

-

-

-

-

70
0

-

-

80
0

La
n
c
16
6
0
2
0
-

-

-

50

-

-

50

To
t
a
l

A
l
l

D
e
a
l
s
47
,
4
3
3

47
,
8
8
9

49
,
6
5
8

51
,
3
1
3

54
,
6
6
5

54
,
0
0
0

37
,
2
0
0

36
,
9
0
1

35
,
9
7
1

37
,
2
2
6

36
,
0
4
7

37
,
1
9
3

52
5
,
4
9
6

47
,
4
2
1

47
,
8
8
9

49
,
6
5
8

51
,
3
1
3

54
,
6
6
5

54
,
0
0
0

35
,
9
0
2

36
,
0
0
8

35
,
9
7
1

35
,
6
0
3

36
,
0
4
7

37
,
0
9
2

52
1
,
5
6
9

Do
l
l
a
r
s
Sy
s
t
e
m

N
R
14
1
8
8
8
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
Sy
s
t
e
m
14
2
3
0
5
$1
5
,
7
5
0
$1
3
,
2
7
5
$9
0
0
$8
7
,
2
7
3
$6
2
,
4
6
9
$1
2
9
,
1
5
0
$0
$0
$0
$0
$0
$0
$3
0
8
,
8
1
7
Sy
s
t
e
m
14
1
8
6
8
$6
2
,
6
9
1
$2
8
,
0
2
5
$1
,
9
0
0
$2
0
0
,
4
5
0
$1
4
0
,
1
2
5
$2
7
2
,
6
5
0
$4
8
,
9
6
3
$2
,
85
0
$0
$1
1
,
40
0
$0
$0
$7
6
9
,
0
5
4
CS
2
14
1
8
7
8
$2
2
3
,
4
3
2
$2
4
5
,
2
0
0
$2
7
8
,
3
5
2
$1
1
8
,
4
0
0
$1
7
9
,
6
0
0
$5
8
,
4
0
0
$2
4
5
,
9
8
4
$2
8
5
,
6
6
4
$2
8
7
,
7
6
8
$2
6
6
,
0
2
4
$2
8
8
,
3
7
6
$2
9
6
,
7
3
6
$2
,
7
7
3
,
9
3
6
CS
2
14
2
3
1
4
$5
9
,
5
6
5
$9
6
,
1
0
5
$1
0
9
,
2
3
0
$4
1
,
7
4
5
$7
8
,
9
3
0
$2
7
,
3
7
5
$0
$0
$0
$0
$0
$0
$4
1
2
,
9
5
0
Mi
d

C
14
1
8
8
0
$1
9
,
2
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$3
,
6
0
0
$0
$0
$2
2
,
8
0
0
Mi
d

C
14
2
3
1
5
$6
,
0
0
8
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$6
,
0
0
8
La
n
c
16
6
0
1
9
$0
$0
$0
$8
0
0
$0
$0
$0
$0
$0
$5
,
6
0
0
$0
$0
$6
,
4
0
0
La
n
c
16
6
0
2
0
$0
$0
$0
$3
7
5
$0
$0
$0
$0
$0
$0
$0
$0
$3
7
5
To
ta
l

A
l
l

D
e
a
l
s
$3
8
6
,
6
4
5
$3
8
2
,
6
0
5
$3
9
0
,
3
8
2
$4
4
9
,
0
4
3
$4
6
1
,
1
2
4
$4
8
7
,
5
7
5
$2
9
4
,
9
4
7
$2
8
8
,
5
1
4
$2
8
7
,
7
6
8
$2
8
6
,
6
2
4
$2
8
8
,
3
7
6
$2
9
6
,
7
3
6
$4
,
3
0
0
,
3
3
9
$3
8
6
,
6
4
5
$3
8
2
,
6
0
5
$3
9
0
,
3
8
2
$4
4
9
,
0
4
3
$4
6
1
,
1
2
4
$4
8
7
,
5
7
5
$2
9
4
,
9
4
7
$2
8
8
,
5
1
4
$2
8
7
,
7
6
8
$2
8
6
,
6
2
4
$2
8
8
,
3
7
6
$2
9
6
,
7
3
6
$4
,
3
0
0
,
3
3
9
Po
w
e
r

D
e
a
l

1
4
1
8
8
8
Deferral Report Month of Dec 2013
Page 16 of 75
ICNU_DR_225 Attachment A Page 20 of 79
Deferral Report Month of Dec 2013
Page 17 of 75
ICNU_DR_225 Attachment A Page 21 of 79
Deferral Report Month of Dec 2013
Page 18 of 75
ICNU_DR_225 Attachment A Page 22 of 79
Deferral Report Month of Dec 2013
Page 19 of 75
ICNU_DR_225 Attachment A Page 23 of 79
Deferral Report Month of Dec 2013
Page 20 of 75
ICNU_DR_225 Attachment A Page 24 of 79
Deferral Report Month of Dec 2013
Page 21 of 75
ICNU_DR_225 Attachment A Page 25 of 79
Deferral Report Month of Dec 2013
Page 22 of 75
ICNU_DR_225 Attachment A Page 26 of 79
Deferral Report Month of Dec 2013
Page 23 of 75
ICNU_DR_225 Attachment A Page 27 of 79

Attachment B

Avista Corporation

Monthly Power Cost Deferral Report

Month of December 2013

REC Revenues Deferral Journal

Deferral Report Month of Dec 2013
Page 24 of 75
ICNU_DR_225 Attachment A Page 28 of 79
Deferral Report Month of Dec 2013
Page 25 of 75
ICNU_DR_225 Attachment A Page 29 of 79
Deferral Report Month of Dec 2013
Page 26 of 75
ICNU_DR_225 Attachment A Page 30 of 79
Deferral Report Month of Dec 2013
Page 27 of 75
ICNU_DR_225 Attachment A Page 31 of 79
Deferral Report Month of Dec 2013
Page 28 of 75
ICNU_DR_225 Attachment A Page 32 of 79
DJ

4
7
5

-

W
a
s
h
i
n
g
t
o
n

R
E
C

D
e
f
e
r
r
a
l
20
1
3
0
1
20
1
3
0
2
20
1
3
0
3
20
1
3
0
4
20
1
3
0
5
20
1
3
0
6
20
1
3
0
7
20
1
3
0
8
20
1
3
0
9
20
1
3
1
0
20
1
3
1
1
20
1
3
1
2
No
n

W
A

E
I
A

-

V
o
l
u
n
t
a
r
y

R
E
C

R
e
v
e
n
u
e
($
7
0
,
5
5
0
)
($
8
2
,
7
7
2
)
($
2
1
3
,
0
6
6
)
($
4
0
8
,
2
7
0
)
($
4
4
8
,
6
7
0
)
($
2
7
7
,
3
0
0
)
($
4
6
,
5
0
0
)
$0
($
3
1
,
2
5
0
)
($
4
4
0
,
0
0
0
)
($
9
6
,
4
5
0
)
($
4
9
9
,
5
7
5
)
($
2
,
6
1
4
,
4
0
4
)
WA

E
I
A
9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

P
G
E

R
e
v
e
n
u
e

$0
$0
$0
($
9
7
,
5
0
0
)
$0
$0
$0
$0
$0
($
6
5
,
0
0
0
)
$0
$0
($
1
6
2
,
5
0
0
)
Sa
c
r
a
m
e
n
t
o

M
u
n
i
c
i
p
a
l

U
t
i
l
i
t
y

D
i
s
t
r
i
c
t

(
S
M
U
D
)

-

R
E
C

R
e
v
e
n
u
e

($
3
8
6
,
6
4
5
)
($
4
1
3
,
7
7
5
)
($
3
9
2
,
7
3
4
)
($
4
4
9
,
0
3
4
)
($
4
6
1
,
1
2
4
)
($
4
8
7
,
5
7
5
)
($
2
9
4
,
9
4
7
)
($
2
8
8
,
5
1
4
)
($
2
8
7
,
7
6
8
)
($
2
8
6
,
6
2
4
)
($
2
8
8
,
3
7
6
)
($
2
9
6
,
7
3
6
)
($
4
,
3
3
3
,
8
5
2
)
No
n

W
A

E
I
A

-

V
o
l
u
n
t
a
r
y

R
E
C

R
e
v
e
n
u
e
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
1
,
4
5
8
)
($
3
7
7
,
5
0
0
)
WA

E
I
A
9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

P
G
E

R
e
v
e
n
u
e
$0
$0
$0
($
7
9
,
0
0
0
)
$0
$0
$0
$0
$0
($
7
9
,
0
0
0
)
$0
$0
($
1
5
8
,
0
0
0
)
Sa
c
r
a
m
e
n
t
o

M
u
n
i
c
i
p
a
l

U
t
i
l
i
t
y

D
i
s
t
r
i
c
t

(
S
M
U
D
)

-

R
E
C

R
e
v
e
n
u
e

($
4
7
0
,
3
9
4
)
($
4
2
4
,
8
7
2
)
($
4
6
9
,
7
6
2
)
($
4
5
5
,
2
2
0
)
($
4
7
0
,
3
9
4
)
($
4
5
5
,
2
2
0
)
($
3
1
3
,
5
9
6
)
($
3
1
3
,
5
9
6
)
($
3
0
3
,
4
8
0
)
($
3
1
3
,
5
9
6
)
($
3
0
3
,
9
0
2
)
($
3
1
3
,
5
9
6
)
($
4
,
6
0
7
,
6
2
7
)
No
n

W
A

E
I
A

-

V
o
l
u
n
t
a
r
y

R
E
C

R
e
v
e
n
u
e
($
3
9
,
0
9
2
)
($
5
1
,
3
1
4
)
($
1
8
1
,
6
0
8
)
($
3
7
6
,
8
1
2
)
($
4
1
7
,
2
1
2
)
($
2
4
5
,
8
4
2
)
($
1
5
,
0
4
2
)
$3
1
,
4
5
8
$2
0
8
($
4
0
8
,
5
4
2
)
($
6
4
,
9
9
2
)
($
4
6
8
,
1
1
7
)
($
2
,
2
3
6
,
9
0
4
)
WA

E
I
A
9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

P
G
E

R
e
v
e
n
u
e
$0
$0
$0
($
1
8
,
5
0
0
)
$0
$0
$0
$0
$0
$1
4
,
0
0
0
$0
$0
($
4
,
5
0
0
)
Sa
c
r
a
m
e
n
t
o

M
u
n
i
c
i
p
a
l

U
t
i
l
i
t
y

D
i
s
t
r
i
c
t

(
S
M
U
D
)

-

R
E
C

R
e
v
e
n
u
e

$8
3
,
7
4
9
$1
1
,
0
9
7
$7
7
,
0
2
8
$6
,
1
8
6
$9
,
2
7
0
($
3
2
,
3
5
5
)
$1
8
,
6
4
9
$2
5
,
0
8
2
$1
5
,
7
1
2
$2
6
,
9
7
2
$1
5
,
5
2
6
$1
6
,
8
6
0
$2
7
3
,
7
7
5
No
n

W
A

E
I
A

-

V
o
l
u
n
t
a
r
y

(
6
5
.
2
4
%
)
($
2
5
,
5
0
3
)
($
3
3
,
4
7
7
)
($
1
1
8
,
4
8
1
)
($
2
4
5
,
8
3
2
)
($
2
7
2
,
1
8
9
)
($
1
6
0
,
3
8
7
)
($
9
,
8
1
3
)
$2
0
,
5
2
3
$1
3
6
($
2
6
6
,
5
3
3
)
($
4
2
,
4
0
1
)
($
3
0
5
,
3
9
9
)
($
1
,
4
5
9
,
3
5
6
)
WA

E
I
A
9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

P
G
E

R
e
v
e
n
u
e

(
1
0
0
%
)
$0
$0
$0
($
1
8
,
5
0
0
)
$0
$0
$0
$0
$0
$1
4
,
0
0
0
$0
$0
($
4
,
5
0
0
)
SM
U
D

(
6
5
.
2
4
%
)
$5
4
,
6
3
8
$7
,
2
4
0
$5
0
,
2
5
3
$4
,
0
3
6
$6
,
0
4
8
($
2
1
,
1
0
8
)
$1
2
,
1
6
7
$1
6
,
3
6
3
$1
0
,
2
5
1
$1
7
,
5
9
7
$1
0
,
1
2
9
$1
0
,
9
9
9
$1
7
8
,
6
1
1
18
6
3
2
2
-
E
D
-
W
A
De
b
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
De
b
i
t
De
b
i
t
De
b
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
55
7
3
2
2
-
E
D
-
W
A
Cr
e
d
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
Deferral Report Month of Dec 2013
Page 29 of 75
ICNU_DR_225 Attachment A Page 33 of 79
Deferral Report Month of Dec 2013
Page 30 of 75
ICNU_DR_225 Attachment A Page 34 of 79
DJ

4
7
5

-

W
a
s
h
i
n
g
t
o
n

R
E
C

D
e
f
e
r
r
a
l
20
1
3
0
1
20
1
3
0
2
20
1
3
0
3
20
1
3
0
4
20
1
3
0
5
20
1
3
0
6
20
1
3
0
7
20
1
3
0
8
20
1
3
0
9
20
1
3
1
0
20
1
3
1
1
20
1
3
1
2
Ot
h
e
r

N
o
n

W
A

E
I
A

-

V
o
l
u
n
t
a
r
y

R
E
C

E
x
p
e
n
s
e
55
7
1
6
0
-
E
D
-
A
N
$7
6
,
9
6
0
$5
4
,
8
0
2
$4
9
,
4
0
0
$4
3
,
1
4
4
$2
9
,
7
6
0
$2
8
,
8
0
0
$0
$0
$0
$1
1
4
$0
$0
$2
8
2
,
9
8
0
Le
s
s

K
e
t
t
l
e

F
a
l
l
s

C
o
n
t
r
a
c
t

B
u
y
o
u
t
Ma
n
u
a
l
($
4
7
,
2
0
0
)
($
3
4
,
4
0
0
)
($
3
4
,
4
0
0
)
($
1
4
,
4
0
0
)
$0
$0
$0
$0
$0
$0
$0
$0
($
1
3
0
,
4
0
0
)
Ot
h
e
r

N
o
n

W
A

E
I
A

-

V
o
l
u
n
t
a
r
y

R
E
C

B
r
o
k
e
r

F
e
e

E
x
p
e
n
s
e
55
7
1
7
1
-
E
D
-
A
N
$0
$0
$1
1
,
9
5
2
$0
$0
$0
$0
$0
$2
,
0
0
0
$2
,
6
0
0
$0
$1
,
7
1
0
$1
8
,
2
6
2
$2
9
,
7
6
0
$2
0
,
4
0
2
$2
6
,
9
5
2
$2
8
,
7
4
4
$2
9
,
7
6
0
$2
8
,
8
0
0
$0
$0
$2
,
0
0
0
$2
,
7
1
4
$0
$1
,
7
1
0
$1
7
0
,
8
4
2
WA

E
I
A
9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

E
x
p
e
n
s
e
55
7
1
6
0
-
E
D
-
W
A
$1
8
1
,
2
5
0
$0
$7
,
0
2
5
$1
8
1
,
2
5
0
$0
$0
$2
0
5
,
2
3
3
$0
$0
$2
1
9
,
7
0
4
$0
$0
$7
9
4
,
4
6
2
To
t
a
l

W
A

E
I
A

9
3
7

R
e
q
u
i
r
e
m
e
n
t

R
E
C

E
x
p
e
n
s
e
s
$1
8
5
,
2
1
4
$3
,
9
6
4
$1
3
,
0
2
0
$1
8
5
,
2
1
4
$3
,
9
6
4
$3
,
9
6
4
$2
0
9
,
1
9
7
$3
,
9
6
4
$3
,
9
6
4
$2
2
3
,
6
6
8
$3
,
9
6
4
$3
,
9
6
4
$8
4
4
,
0
5
5
Au
t
h
o
r
i
z
e
d

-

S
y
s
t
e
m
Ot
h
e
r

N
o
n

W
A

E
I
A

-

V
o
l
u
n
t
a
r
y

R
E
C

E
x
p
e
n
s
e
$2
9
,
7
6
0
$2
6
,
8
8
0
$2
9
,
7
6
0
$2
8
,
7
6
0
$2
9
,
7
6
0
$2
8
,
8
0
0
$0
$0
$0
$0
$0
$0
$1
7
3
,
7
2
0
WA

E
I
A
9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

E
x
p
e
n
s
e
$1
8
4
,
3
5
9
$3
,
9
4
5
$3
,
9
4
5
$1
8
4
,
3
5
9
$3
,
9
4
5
$3
,
9
4
5
$1
8
4
,
3
5
9
$3
,
9
4
5
$3
,
9
4
5
$1
8
4
,
3
5
9
$3
,
9
4
5
$3
,
9
4
5
$7
6
9
,
0
0
0
To
t
a
l

A
u
t
h
o
r
i
z
e
d
$2
1
4
,
1
1
9
$3
0
,
8
2
5
$3
3
,
7
0
5
$2
1
3
,
1
1
9
$3
3
,
7
0
5
$3
2
,
7
4
5
$1
8
4
,
3
5
9
$3
,
9
4
5
$3
,
9
4
5
$1
8
4
,
3
5
9
$3
,
9
4
5
$3
,
9
4
5
$9
4
2
,
7
2
0
Di
f
f
e
r
e
n
c
e
Ot
h
e
r

N
o
n

W
A

E
I
A

-

V
o
l
u
n
t
a
r
y

R
E
C

E
x
p
e
n
s
e
$0
($
6
,
4
7
8
)
($
2
,
8
0
8
)
($
1
6
)
$0
$0
$0
$0
$2
,
0
0
0
$2
,
7
1
4
$0
$1
,
7
1
0
($
2
,
8
7
8
)
WA

E
I
A
9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

E
x
p
e
n
s
e
$8
5
4
$1
8
$9
,
0
7
4
$8
5
4
$1
8
$1
8
$2
4
,
8
3
7
$1
8
$1
8
$3
9
,
3
0
8
$1
8
$1
8
$7
5
,
0
5
5
To
t
a
l
$8
5
4
($
6
,
4
5
9
)
$6
,
2
6
6
$8
3
8
$1
8
$1
8
$2
4
,
8
3
7
$1
8
$2
,
0
1
8
$4
2
,
0
2
2
$1
8
$1
,
7
2
8
$7
2
,
1
7
7
No
n

W
A

E
I
A

-

V
o
l
u
n
t
a
r
y

(
6
5
.
2
4
%
)
$0
($
4
,
2
2
6
)
($
1
,
8
3
2
)
($
1
0
)
$0
$0
$0
$0
$1
,
3
0
5
$1
,
7
7
0
$0
$1
,
1
1
6
($
1
,
8
7
8
)
WA

E
I
A
9
3
7

R
e
q
u
i
r
e
m
e
n
t

(
E
W
E
B
)

-

(
1
0
0
%
)
$8
5
4
$1
8
$9
,
0
7
4
$8
5
4
$1
8
$1
8
$2
4
,
8
3
7
$1
8
$1
8
$3
9
,
3
0
8
$1
8
$1
8
$7
5
,
0
5
5
To
t
a
l

-

1
0
0
%

S
u
r
c
h
a
r
g
e

(
+
)

o
r

R
e
b
a
t
e

(
-
)
$8
5
4
($
4
,
2
0
8
)
$7
,
2
4
2
$8
4
4
$1
8
$1
8
$2
4
,
8
3
7
$1
8
$1
,
3
2
3
$4
1
,
0
7
8
$1
8
$1
,
1
3
4
$7
3
,
1
7
8
18
6
3
2
2
-
E
D
-
W
A
De
b
i
t
Cr
e
d
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
De
b
i
t
55
7
3
2
2
-
E
D
-
W
A
Cr
e
d
i
t
De
b
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Cr
e
d
i
t
Deferral Report Month of Dec 2013
Page 31 of 75
ICNU_DR_225 Attachment A Page 35 of 79

Attachment C

Avista Corporation

Monthly Power Cost Deferral Report

Month of December 2013

ERM Activity - Colstrip 70% Availability Journal
Recorded in December 2013

Deferral Report Month of Dec 2013
Page 32 of 75
ICNU_DR_225 Attachment A Page 36 of 79
Deferral Report Month of Dec 2013
Page 33 of 75
ICNU_DR_225 Attachment A Page 37 of 79
Deferral Report Month of Dec 2013
Page 34 of 75
ICNU_DR_225 Attachment A Page 38 of 79
Deferral Report Month of Dec 2013
Page 35 of 75
ICNU_DR_225 Attachment A Page 39 of 79
Deferral Report Month of Dec 2013
Page 36 of 75
ICNU_DR_225 Attachment A Page 40 of 79
Deferral Report Month of Dec 2013
Page 37 of 75
ICNU_DR_225 Attachment A Page 41 of 79
Deferral Report Month of Dec 2013
Page 38 of 75
ICNU_DR_225 Attachment A Page 42 of 79
Deferral Report Month of Dec 2013
Page 39 of 75
ICNU_DR_225 Attachment A Page 43 of 79
Deferral Report Month of Dec 2013
Page 40 of 75
ICNU_DR_225 Attachment A Page 44 of 79
Deferral Report Month of Dec 2013
Page 41 of 75
ICNU_DR_225 Attachment A Page 45 of 79
Deferral Report Month of Dec 2013
Page 42 of 75
ICNU_DR_225 Attachment A Page 46 of 79
Deferral Report Month of Dec 2013
Page 43 of 75
ICNU_DR_225 Attachment A Page 47 of 79
Deferral Report Month of Dec 2013
Page 44 of 75
ICNU_DR_225 Attachment A Page 48 of 79
Deferral Report Month of Dec 2013
Page 45 of 75
ICNU_DR_225 Attachment A Page 49 of 79
Deferral Report Month of Dec 2013
Page 46 of 75
ICNU_DR_225 Attachment A Page 50 of 79
Deferral Report Month of Dec 2013
Page 47 of 75
ICNU_DR_225 Attachment A Page 51 of 79
Deferral Report Month of Dec 2013
Page 48 of 75
ICNU_DR_225 Attachment A Page 52 of 79
Deferral Report Month of Dec 2013
Page 49 of 75
ICNU_DR_225 Attachment A Page 53 of 79
Deferral Report Month of Dec 2013
Page 50 of 75
ICNU_DR_225 Attachment A Page 54 of 79
Deferral Report Month of Dec 2013
Page 51 of 75
ICNU_DR_225 Attachment A Page 55 of 79
Deferral Report Month of Dec 2013
Page 52 of 75
ICNU_DR_225 Attachment A Page 56 of 79
Deferral Report Month of Dec 2013
Page 53 of 75
ICNU_DR_225 Attachment A Page 57 of 79
Deferral Report Month of Dec 2013
Page 54 of 75
ICNU_DR_225 Attachment A Page 58 of 79
Deferral Report Month of Dec 2013
Page 55 of 75
ICNU_DR_225 Attachment A Page 59 of 79
Deferral Report Month of Dec 2013
Page 56 of 75
ICNU_DR_225 Attachment A Page 60 of 79

Attachment D

Avista Corporation

Monthly Power Cost Deferral Report

Month of December 2013

ERM Activity – Natural Gas Transport Costs Allocation Journals
Recorded in December 2013

Deferral Report Month of Dec 2013
Page 57 of 75
ICNU_DR_225 Attachment A Page 61 of 79
Deferral Report Month of Dec 2013
Page 58 of 75
ICNU_DR_225 Attachment A Page 62 of 79
Deferral Report Month of Dec 2013
Page 59 of 75
ICNU_DR_225 Attachment A Page 63 of 79
Deferral Report Month of Dec 2013
Page 60 of 75
ICNU_DR_225 Attachment A Page 64 of 79
Deferral Report Month of Dec 2013
Page 61 of 75
ICNU_DR_225 Attachment A Page 65 of 79
Deferral Report Month of Dec 2013
Page 62 of 75
ICNU_DR_225 Attachment A Page 66 of 79
Deferral Report Month of Dec 2013
Page 63 of 75
ICNU_DR_225 Attachment A Page 67 of 79
Deferral Report Month of Dec 2013
Page 64 of 75
ICNU_DR_225 Attachment A Page 68 of 79
Deferral Report Month of Dec 2013
Page 65 of 75
ICNU_DR_225 Attachment A Page 69 of 79
Deferral Report Month of Dec 2013
Page 66 of 75
ICNU_DR_225 Attachment A Page 70 of 79
Deferral Report Month of Dec 2013
Page 67 of 75
ICNU_DR_225 Attachment A Page 71 of 79
Deferral Report Month of Dec 2013
Page 68 of 75
ICNU_DR_225 Attachment A Page 72 of 79
Deferral Report Month of Dec 2013
Page 69 of 75
ICNU_DR_225 Attachment A Page 73 of 79
Deferral Report Month of Dec 2013
Page 70 of 75
ICNU_DR_225 Attachment A Page 74 of 79
Deferral Report Month of Dec 2013
Page 71 of 75
ICNU_DR_225 Attachment A Page 75 of 79
Deferral Report Month of Dec 2013
Page 72 of 75
ICNU_DR_225 Attachment A Page 76 of 79
Deferral Report Month of Dec 2013
Page 73 of 75
ICNU_DR_225 Attachment A Page 77 of 79
Deferral Report Month of Dec 2013
Page 74 of 75
ICNU_DR_225 Attachment A Page 78 of 79
Deferral Report Month of Dec 2013
Page 75 of 75
ICNU_DR_225 Attachment A Page 79 of 79

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 225 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the workpaper of Jennifer S. Smith entitled “ELIMINATE WA POWER COST DEFERRAL /2) ERM - GL Transactions Detail.” Please provide an explanation for line item with the
General Ledger (“G/L”) Transaction ID of 1979189.10, titled “NSJ019 - AVA Intracompany Gas
Transfers.”

RESPONSE: Please see ICNU_DR_225 Attachment A for the monthly December 2013 Washington ERM Report. The
transaction is described on the Cover Letter (paragraph 3). In addition, a memo fully describing the detail
was included in the report beginning on page 17.

Page 1 of 1
AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015 CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 226 TELEPHONE: [phone]
EMAIL: [e-mail]
REQUEST:
Please provide a description of the purpose of each of the following G/L accounts:
a. 182350
b. 186280
c. 186290
d. 186322
e. 283280
f. 283305
g. 407320
h. 557280
i. 557290
j. 557322

RESPONSE:
The FERC Account description for each of the General Ledger accounts requested is provided below.
Please see the Company’s response to ICNU_DR_225 Attachment A for the December 2013 Monthly
ERM/REC report filed with this Commission which includes the journal and supporting work papers for
transactions pertaining to each General Ledger Account.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 227 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the workpaper of Jennifer S. Smith entitled “ELIMINATE ADDER SCHED /Eliminate Adder Schedules,” tab “E-EAS-2,” Cells “A65:G132.” Please provide an explanation of the purpose of
this table, including a description of the distinction between the amounts detailed under column “D”
versus the amounts detailed under column “C,” as labeled within the table (columns “E” and “F” in the
Excel worksheet).
RESPONSE:
The referenced table is a recap of all the Washington electric service entries to the unbilled add-on and
unbilled add-on reversal journals booked to the general ledger during the test period. Its purpose was a check that the adjustment had captured and correctly identified all the unbilled adder schedule
amortizations recorded during the test period in the table at cells “A1:F16”. It was not included in the
hard copy work papers because it was unnecessary for review of this adjustment. The values under the Dr
Cr Code D are debits recorded on these journals and the values under the Dr Cr Code C are credits
recorded on these journals.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/27/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Don Kopczynski
REQUESTER: ICNU RESPONDER: Mark Baker
TYPE: Data Request DEPT: DSM
REQUEST NO.: ICNU – 228 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a table that details, on a monthly basis, the total amount of DSM expenditures related to Washington’s electric portfolio incurred over the period January 2010 through December 2014
(inclusive). Please provide this detail broken out by “Incentives,” “Labor,” and “Non-labor / Non-
Incentive” expenditure categories.

RESPONSE:
Please see ICNU_DR_228 Attachment A for the above requested expenditure information. All expenses
associated with DSM expenditures have been excluded from the Company’s filing in the “eliminate adder
schedule” adjustments in both the Attrition and Pro Forma Studies.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/29/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 229 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a table that details, on a monthly basis, the total amount of revenues collected under schedule 91 over the period January 2010 through December 2014 (inclusive).

RESPONSE:
Please see ICNU_DR_229 Attachment A. All revenues collected under Schedule 91 are eliminated from the
Company’s filing in the “Eliminate Adders” adjustment (2.11).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 230 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please identify the adjustment where the Company removed the costs associated with its DSM program from restated or pro-forma results.

RESPONSE:
The Company’s DSM program costs are administered through a balancing account. The only
associated amounts included in Washington results of operations are the Schedule 91 revenues and
offsetting amortization expense recorded in Account 908, and credits to Account 922 for utilization of
office space and equipment by DSM program employees. All labor and other expenditures associated
with the DSM programs are charged directly to a balance sheet account that is not included in rate base. The Account 922 Administrative Expenses Transferred credit amount stays in the test year and
Schedule 91 revenues and Account 908 amortization are eliminated in the Eliminate Adder Schedule
adjustment (2.11).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jen Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State & Fed. Regulation
REQUEST NO.: ICNU – 231 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the workpaper of Jennifer S. Smith entitled “PF-TRANSMISSION REV & EXP /2015 PF Transmission Rev.Exp.” Please provide an explanation for the adjustment to transmission revenues and
expenses entitled “OASIS nf & stf Whl (Other Whl)” in the workpaper tab “E-PTR-2” (Excel Row “52”).

RESPONSE:
Please see Company witness Mr. Cox testimony starting at Exhibit No. __(BAC-1T) page 12, line 18.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jen Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State & Fed. Regulation
REQUEST NO.: ICNU – 232 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exh. No. JSS-1T at 12:9-11. Please identify the rate base dollar amount of pension and other post-retirement benefits included in rate base as working capital. Please also provide the accounting
workpapers used to develop this dollar amount.

RESPONSE:
The net pension and other post-retirement benefits included in working capital follows:

The electronic spreadsheet above is provided at ICNU_DR_232-Attachment A. The workpaper that
includes the working capital detail was provided in the original filing with Company witness Ms. Smith’s
Ferc Acct Ferc Acct Desc Sep14AMA
228300 ACCUM PROV FAS106 POST RET MED (11,264,398)$
228320 ACCUM PROV FAS87 ACCUM PEN COS 87,013,241.11
228330 HRA - RETIREE (7,244,414.65)
228335 HRA - ACTIVE EMPLOYEES (1,031,977.46)
283150 FAS 106-CURRENT 3,849,314.51
283150 FAS 106-CURRENT (21.08)
283150 FAS 106-CURRENT (17.86)
283150 FAS 106-CURRENT 20.62
283150 FAS 106-CURRENT (167,187.17)
System Pension & Post-Retirement Benefits 71,154,560.49
283152 ADFIT FAS 106 - HRA 347,395.77
283153 ADFIT FAS 106 - HRA ACTIVE EMP 284,594.97
190150 ADFIT FAS87 UNFUNDED PENSION (25,715,989.24)
190150 ADFIT FAS87 UNFUNDED PENSION (769,300.00)
System ADFIT for Pension & Post-Retirement Benefits (25,853,298.50)
System Pension & Post-Retirement Benefits, Net of ADFIT 45,301,262$
Washington Electric 21,856,470$
Washington Natural Gas 6,481,936$

Page 2 of 2
workpapers (as electric adjustment No. 1.03 and natural gas adjustment No. 1.03) for the Company’s pro
forma cross-check analysis. It has also been included as ICNU_DR_232-Attachment B.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jen Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State & Fed. Regulation
REQUEST NO.: ICNU – 233 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exh. No. JSS-1T at 12:12-15. Please identify the dollar amount of ADIT related to pension and other post-retirement benefits included in rate base as working capital. Please also provide
the accounting workpapers used to develop this dollar amount.

RESPONSE:
Please see the Company’s response to ICNU_DR_232 for the dollar amount of ADFIT related to pension
and other post-retirement benefits included in rate base as working capital.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 234 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the workpaper of Jennifer S. Smith entitled “PF-PROPERTY TAX /1) PF - Property Tax ADJ.xlsx.” Please provide workpapers used to calculate the hard-coded pro forma property tax expenses
included in tab “E-RPT,” cells “B16:G16.” At a minimum, the workpapers should detail each of the
components of the respective tax valuations, as well as the tax rates employed to estimate the expense.

RESPONSE:
The workpaper requested is included in the Company’s filing. Please refer to workpaper “PF – HPA-
1.xlsx” of the Pro Forma Property Tax Adjustment. The information identified in cells “B16:G16” can be
found in column L.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/21/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: Rates and Tariffs
REQUEST NO.: ICNU – 235 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to the workpaper of Jennifer S. Smith entitled “INJURIES & DAMAGES /1) 2014 inj & dam adj.xls.” For each amount included in the tab “C-ID-2” please provide transaction or invoice level detail
from the Company’s accounting system, detailing each of the journal entries into account 228210 over the
six-year period ending in September 2014. Please provide the detail with all available fields from the
Company’s accounting system, including description and document reference fields.
RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 235C. Please note that
Avista’s response to ICNU – 235C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205.
Please see ICNU_DR_235C Confidential Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 236 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exh. No. JSS-1T at 25:14-29:22. Please provide detail for the test period (12 months ending September 2014) that breaks out the total amount of labor and benefit expense by employee.
Please provide the data by the employees’ job titles and provide separate amounts for each G/L account to
which the labor expenses are assigned.

RESPONSE: Please see ICNU_DR_236 attachment A for test period labor for 12 months ending September 2014.
Electric and Gas are provided on individual worksheets by Service (Electric and Gas) employee, job title
and FERC General Ledger account number.
Please note the Company does not track benefits by employee number. Payroll benefits are denoted as
“PB” in the employee number column and are summarized by FERC General Ledger account number.
The payroll benefit loader includes workers compensation, health insurance, life/other insurance, 401(k),
Pension, Deferred Compensation, FAS 106 (Post Retirement Medical) and HRA Benefit.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 237 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exh. No. JSS-1T at 25:14-29:22. Please provide detail for the pro forma period that breaks out the Company’s proposed labor and benefit expense by employee. Please provide the data by the
employees’ job titles and provide separate amounts for each G/L account to which the labor expense is
booked.

RESPONSE: The labor and benefit expense included in the Company’s pro forma cross-check study is broken down by
jurisdiction, service (electric and gas) and FERC O & M general ledger accounts and is not maintained at
the employee numbers/job title level.
Please see Company adjustments 3.02 E-PLN and 3.00 G-PLN, workpaper 1) WA 2015 FLB Forecast
Labor and Benefit for the operation & maintenance pro-forma labor expense calculation broken down by
FERC account. The basis for this adjustment is labor expense for the 12 months ending September 30,
2014 increased by the anticipated increases for non-union employees and contracted increases for union
employees. Please also see the Company’s response to ICNU_DR_235.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 238 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exch. No. JSS-1T at 25:14-29:22. Please provide the total amount of capitalized labor by FERC account and department for the test period.

RESPONSE:
Please see ICNU_DR_238 Attachment A for the total amount of capitalized labor by FERC account and
department for the 12 months ending September 30, 2014.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 239 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to Exch. No. JSS-1T at 25:14-29:22. Please provide an explanation of how the Company accounted for capitalized labor in developing it pro forma labor adjustment.

RESPONSE:
Capitalized labor is included in the Company’s Planned Capital Additions adjustments 3.11, 4.01 and
4.02 for electric and 3.07, 4.01 and 4.02 for natural gas. The Pro Formal Capital adjustments include
capital additions that the Company is making from October 1, 2014 to December 31, 2016 and includes
the labor associated with those projects.

6/8/2015 9:02 AM
Flight #: AVA011411 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:January Date:14 - 14 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4 Friday January 14 Friday January 14 51 minutes
2 Pat Ehrbar GEG - Spokane OLM - Olympia, WA
4 Kelly Norwood 02800545 928000 550 R11 $3,010.00 1,2,3,4 Friday January 14 Friday January 14 35 minutes
OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 1 of 419
6/8/2015 9:02 AM
Flight #: AVA011811 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:January Date:18 - 18 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Tuesday January 18 Tuesday January 18 58 minutes
2 Pat Ehrbar 6,7,8,9 GEG - Spokane SLE - Salem
4 David Meyer 1,2,3,4,5 Tuesday January 18 Tuesday January 18 48 minutes
5 Joe Miller 6,7,8,9 SLE - Salem GEG - Spokane
7 Jeanne Pluth
8 Karen Schuh
ICNU_DR_240 Attachment A Page 2 of 419
6/8/2015 9:02 AM
Flight #: AVA011911 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:January Date:19 - 19 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Wednesday January 19 Wednesday January 19 51 minutes
2 Pat Ehrbar 6,7,8,9 GEG - Spokane SLE - Salem
4 Ronald Mckenzie 1,2,3,4,5 Wednesday January 19 Wednesday January 19 49 minutes
5 David Meyer 6,7,8,9 SLE - Salem GEG - Spokane
7 Kelly Norwood 06800545 928000 550 R11 $3,500.00
8 Karen Schuh
ICNU_DR_240 Attachment A Page 3 of 419
6/8/2015 9:03 AM
Flight #: AVA012111 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:January Date:21 - 21 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09903691 930200 550 X01 $6,055.00 1 Friday January 21 Friday January 21 39 minutes
GEG - Spokane BOI - Boise, ID
1 Friday January 21 Friday January 21 64 minutes
BOI - Boise, ID PDX - Portland, OR
1 Friday January 21 Friday January 21 33 minutes
PDX - Portland, OR BFI - Seattle, WA
1 Friday January 21 Friday January 21 37 minutes
BFI - Seattle, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 4 of 419
6/8/2015 9:03 AM
Flight #: AVA012711 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:January Date:27 - 27 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09903691 930200 550 X01 $3,500.00 1 Thursday January 27 Thursday January 27
GEG - Spokane GPI - Kalispell
1 Thursday January 27 Thursday January 27 43 minutes
GEG - Spokane BOI - Boise, ID
1 Thursday January 27 Thursday January 27 34 minutes
BOI - Boise, ID LWS - Lewiston, ID
1 Thursday January 27 Thursday January 27 23 minutes
LWS - Lewiston, ID GEG - Spokane
ICNU_DR_240 Attachment A Page 5 of 419
6/8/2015 9:03 AM
Flight #: AVA020111 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:February Date:1 - 1 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4,5 Tuesday February 1 Tuesday February 1 44 minutes
2 Renee Coelho GEG - Spokane OLM - Olympia, WA
4 Bruce Folsom 02800545 928000 550 R11 $1,487.50 1,2,3,4,5 Tuesday February 1 Tuesday February 1 41 minutes
5 Linda Gervais 02800540 928000 550 R11 $1,487.50 OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 6 of 419
6/8/2015 9:03 AM
Flight #: AVA020211 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:February Date:2 - 2 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 02800540 928000 550 R11 $393.75 1,2,3,4,5 Wednesday February 2 Wednesday February 2 42 minutes
2 Todd Bryan 09802202 557000 550 E55 $393.75 6,7,8 GEG - Spokane OLM - Olympia, WA
4 Bruce Folsom 02803400 242614 550 T52 $183.75 1,2,3,6,7 Wednesday February 2 Wednesday February 2 36 minutes
5 Linda Gervais 02800540 928000 550 R11 $183.75 8 OLM - Olympia, WA GEG - Spokane
7 Kelly Norwood 02800540 928000 550 R11 $393.75
8 Dick Storro 09802202 557000 550 E55 $393.75
ICNU_DR_240 Attachment A Page 7 of 419
6/8/2015 9:03 AM
Flight #: AVA020411 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:February Date:4 - 4 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 02800540 928000 550 R11 $485.00 1,2,3,4,5 Friday February 4 Friday February 4 43 minutes
2 Todd Bryan 09802202 557000 550 E55 $485.00 6,7 GEG - Spokane BOI - Boise, ID
4 Linda Gervais 03800540 928000 550 R11 $485.00 1,2,3,4,5 Friday February 4 Friday February 4 54 minutes
5 Bob Lafferty 09802202 557000 550 E55 $485.00 6,7 BOI - Boise, ID GEG - Spokane
7 Scott Reid 09802202 557000 550 E55 $485.00
***CATERING - Breakfast from GEG-BOI
ICNU_DR_240 Attachment A Page 8 of 419
6/8/2015 9:03 AM
Flight #: AVA020811 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:February Date:8 - 8 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4,5 Tuesday February 8 Tuesday February 8 39 minutes
2 Pat Ehrbar 03800540 928000 550 R11 $2,975.00 6 GEG - Spokane BOI - Boise, ID
4 Tara Knox 1,2,3,4,5 Tuesday February 8 Tuesday February 8 46 minutes
5 Joe Miller 6 BOI - Boise, ID GEG - Spokane
ICNU_DR_240 Attachment A Page 9 of 419
6/8/2015 9:03 AM
Flight #: AVA020911 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:February Date:9 - 9 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Craig Bertholf 06800545 928000 550 R11 $3,605.00 1,2,3,4,5 Wednesday February 9 Wednesday February 9 48 minutes
2 Annette Brandon 6,7,8 GEG - Spokane SLE - Salem
4 Cameron Dunlop 1,2,3,4,5 Wednesday February 9 Wednesday February 9 55 minutes
5 Pat Ehrbar 6,7,8 SLE - Salem GEG - Spokane
7 Kelly Irvine
8 Theresa Melvin
ICNU_DR_240 Attachment A Page 10 of 419
6/8/2015 9:03 AM
Flight #: AVA021011 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:February Date:10 - 10 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Dana Anderson 09803400 242614 550 T52 $363.13 1,2,3,4,5 Thursday February 10 Thursday February 10 45 minutes
2 Shawn Bonfield 02800540 928000 550 R11 $363.13 6,7,8 GEG - Spokane OLM - Olympia, WA
4 Joshua Diluciano 09802457 580000 550 H08 $363.12 1,2,3,4,5 Thursday February 10 Thursday February 10 39 minutes
5 Linda Gervais 02800540 928000 550 R11 $363.12 6,7,8 OLM - Olympia, WA GEG - Spokane
7 Curtis Kirkeby 09802457 580000 550 H08 $363.13
8 Clay Storey 09900181 921010 550 P09 $363.13
ICNU_DR_240 Attachment A Page 11 of 419
6/8/2015 9:03 AM
Flight #: AVA021111 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:February Date:11 - 11 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3 Friday February 11 Friday February 11 51 minutes
2 Ronald Mckenzie GEG - Spokane SLE - Salem
1,2,3 Friday February 11 Friday February 11 43 minutes
SLE - Salem GEG - Spokane
ICNU_DR_240 Attachment A Page 12 of 419
6/8/2015 9:04 AM
Flight #: AVA021811 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:February Date:18 - 18 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Karen Feltes 09900162 921000 550 E01 $5,495.00 1,2,5,6 Friday February 18 Friday February 18 13 minutes
2 Dan Kolbet GEG - Spokane PUW - Pullman, WA
4 Dick Storro 09802202 557000 550 E55 $227.50 1,2,5,6 Friday February 18 Friday February 18 19 minutes
5 Mark Thies PUW - Pullman, WA LWS - Lewiston, ID
1,2,5,6 Friday February 18 Friday February 18 62 minutes
LWS - Lewiston, ID MFR - Medford, OR
1,2,5,6 Friday February 18 Friday February 18 37 minutes
MFR - Medford, OR PDX - Portland, OR
1,2,3,4,5 Friday February 18 Friday February 18 39 minutes
6 PDX - Portland, OR GEG - Spokane
Purpose Q1 Employee Meetings
ICNU_DR_240 Attachment A Page 13 of 419
6/8/2015 9:04 AM
Flight #: AVA022311 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:February Date:23 - 23 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Ronald Mckenzie 1,2,3 Wednesday February 23 Wednesday February 23 53 minutes
2 David Meyer GEG - Spokane SLE - Salem
1,2,3 Wednesday February 23 Wednesday February 23 48 minutes
SLE - Salem GEG - Spokane
ICNU_DR_240 Attachment A Page 14 of 419
6/8/2015 9:04 AM
Flight #: AVA022411b AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:February Date:24 - 24 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Judy Cole 1,2,3,4,5 Thursday February 24 Thursday February 24 27 minutes
2 Nancy Holmes 6 GEG - Spokane LWS - Lewiston, ID
4 Patty Shea 1,2,3,4,5 Thursday February 24 Thursday February 24 19 minutes
5 Steve Trabun 6 LWS - Lewiston, ID GEG - Spokane
ICNU_DR_240 Attachment A Page 15 of 419
6/8/2015 9:04 AM
Flight #: AVA042711 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:April Date:27 - 27 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Annette Brandon 1,2,3,4,5 Wednesday April 27 Wednesday April 27
2 Kevin Christie 6 GEG - Spokane SLE - Salem
4 Pat Ehrbar 06800545 928000 550 R11 1,2,3,4,5 Wednesday April 27 Wednesday April 27
5 Kelly Irvine 6 SLE - Salem GEG - Spokane
ICNU_DR_240 Attachment A Page 16 of 419
6/8/2015 9:04 AM
Flight #: AVA022811 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Thursday Month:February Date:28 - 3 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Pat Lynch 09800731 908000 550 F52 $2,546.25 2,3,4 Monday February 28 Monday February 28 104 minutes
2 Scott Morris 09800310 930200 550 X01 $5,264.59 GEG - Spokane FAR - Fargo
4 Dennis Vermillion 09800310 930200 550 T01 $5,264.58 2,3,4 Monday February 28 Monday February 28 129 minutes
FAR - Fargo IAD - Washington, DC
1,2,3,4 Thursday March 3 Thursday March 3 157 minutes
IAD - Washington, DC FAR - Fargo
1,2,3,4 Thursday March 3 Thursday March 3 134 minutes
FAR - Fargo GEG - Spokane
***Catering - Lunch from GEG-FAR
ICNU_DR_240 Attachment A Page 17 of 419
6/8/2015 9:04 AM
Flight #: AVA030711 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Tuesday Month:March Date:7 - 8 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Michael Andrea 77705183 183000 550 U01 $1,697.50 1,2,3,4,5 Monday March 7 Monday March 7 173 minutes
2 Todd Bryan 77705183 183000 550 E55 $1,697.50 6,7,8 GEG - Spokane ADS - Addison, TX
4 Bruce Howard 77705183 183000 550 A04 $1,697.50 1,2,3,4,5 Tuesday March 8 Tuesday March 8 215 minutes
5 Tami Judge 77705183 183000 550 Y55 $1,697.50 6,7,8 ADS - Addison, TX GEG - Spokane
7 Greg Rahn 77705183 183000 550 D55 $1,697.50
8 Jason Thackston 77705183 183000 550 Y54 $1,697.50
ICNU_DR_240 Attachment A Page 18 of 419
6/8/2015 9:04 AM
Flight #: AVA030911 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:March Date:9 - 9 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Renee Coelho 02803400 242614 550 T52 $350.97 1,2,3,4,5 Wednesday March 9 Wednesday March 9 52 minutes
2 Mike Dillon 02803400 242614 550 T52 $350.97 6,7,8,9 GEG - Spokane OLM - Olympia, WA
4 Pat Ehrbar 02800545 928000 550 R11 $202.22 1,2,3,5,6 Wednesday March 9 Wednesday March 9 34 minutes
5 Bruce Folsom 02803400 242614 550 T52 $350.99 7,8,9 OLM - Olympia, WA GEG - Spokane
7 Lori Hermanson 02803400 242614 550 T52 $350.97
8 Jon Powell 02803400 242614 550 T52 $350.97
ICNU_DR_240 Attachment A Page 19 of 419
6/8/2015 9:04 AM
Flight #: AVA030911b AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:March Date:9 - 9 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09903691 930200 550 X01 $6,720.00 Wednesday March 9 Wednesday March 9 41 minutes
2 Tom Paine 09900520 921000 550 B16 $1,540.00 OLM - Olympia, WA GEG - Spokane
1,2 Wednesday March 9 Wednesday March 9 42 minutes
GEG - Spokane BOI - Boise, ID
Wednesday March 9 Wednesday March 9 65 minutes
BOI - Boise, ID OLM - Olympia, WA
Wednesday March 9 Wednesday March 9 42 minutes
GEG - Spokane BOI - Boise, ID
1,2 Wednesday March 9 Wednesday March 9 46 minutes
BOI - Boise, ID GEG - Spokane
Purpose Mtg w/ Butch Otter & NW Utility CEOs
ICNU_DR_240 Attachment A Page 20 of 419
6/8/2015 9:04 AM
Flight #: AVA031011 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:March Date:10 - 10 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Marian Durkin 77703047 186200 550 V01 $1,470.00 1,2,3 Thursday March 10 Thursday March 10 53 minutes
2 Toni Pessemier 77703047 186200 550 A01 $1,470.00 GEG - Spokane BFI - Seattle, WA
Thursday March 10 Thursday March 10 31 minutes
BFI - Seattle, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 21 of 419
6/8/2015 9:05 AM
Flight #: AVA031111 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:March Date:11 - 11 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 David Meyer 03800540 928000 550 R11 $2,436.00 1,2,3,4,5 Friday March 11 Friday March 11 43 minutes
2 Scott Morris GEG - Spokane BOI - Boise, ID
4 Mark Thies 1,2,3,4,5 Friday March 11 Friday March 11 44 minutes
5 Dennis Vermillion BOI - Boise, ID GEG - Spokane
***CATERING - Breakfast GEG-BOI
ICNU_DR_240 Attachment A Page 22 of 419
6/8/2015 9:05 AM
Flight #: AVA031611 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:March Date:16 - 16 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Joanne Babin 09802202 557000 550 E55 $587.22 1,2,3,4,5 Wednesday March 16 Wednesday March 16 68 minutes
2 Thomas Dempsey 41002100 500000 550 E55 $587.24 6,7,8,9 GEG - Spokane M46 - Colstrip, MT
4 Mike Gonnella 09802050 535010 550 E07 $587.22 1,2,3,4,5 Wednesday March 16 Wednesday March 16 16 minutes
5 Jason Graham 09802050 535010 550 E07 $587.22 6,7,8,9 M46 - Colstrip, MT BIL - Billings, MT
7 Adam Newhouse 09802815 566010 550 M08 $587.22 1,2,3,4,5 Monday March 7 Monday March 7 67 minutes
8 Karen Terpak 41002100 506000 550 M07 $587.22 6,7,8,9 BIL - Billings, MT GEG - Spokane
ICNU_DR_240 Attachment A Page 23 of 419
6/8/2015 9:05 AM
Flight #: AVA032011 AVISTA DAILY FLIGHT MANIFEST
Day:Sunday - Tuesday Month:March Date:20 - 22 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Pat Dever 09902811 926102 550 W09 $1,756.70 1,2,3,4,5 Sunday March 20 Sunday March 20 167 minutes
2 Tami Judge 09903310 921000 550 Y55 $1,756.66 6,7 GEG - Spokane ELP - El Paso, TX
4 Janna Leaf 09900710 901000 550 N50 $1,756.66 1,2,3,4,5 Tuesday March 22 Tuesday March 22 158 minutes
5 Kelly Magalsky 09900162 921000 550 H08 $1,756.66 6 ELP - El Paso, TX GEG - Spokane
7 Vicki Weber 09900710 901000 550 N50 $835.00
ICNU_DR_240 Attachment A Page 24 of 419
6/8/2015 9:05 AM
Flight #: AVA032311 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Friday Month:March Date:23 - 25 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jason Lang 09900010 921000 550 Y54 $2,788.33 1,2,3 Wednesday March 23 Wednesday March 23 129 minutes
2 Jason Thackston 09900010 921000 550 Y54 $2,788.33 GEG - Spokane LAS - Las Vegas, NV
1,2,3 Friday March 25 Wednesday March 23 110 minutes
LAS - Las Vegas, NV GEG - Spokane
ICNU_DR_240 Attachment A Page 25 of 419
6/8/2015 9:05 AM
Flight #: AVA032911 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:March Date:29 - 29 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 09905519 926105 550 R11 $5,145.00 1,2,3,4 Tuesday March 29 Tuesday March 29 63 minutes
2 Shawn Bonfield GEG - Spokane MFR - Medford, OR
4 Jennifer Smith 1,2,3,4 Tuesday March 29 Tuesday March 29 59 minutes
MFR - Medford, OR LWS - Lewiston, ID
1,2,3,4 Tuesday March 29 Tuesday March 29 25 minutes
LWS - Lewiston, ID GEG - Spokane
ICNU_DR_240 Attachment A Page 26 of 419
6/8/2015 9:05 AM
Flight #: AVA033011 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:March Date:30 - 30 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Tony Bonanzino 1,2,3,4,5 Wednesday March 30 Wednesday March 30 51 minutes
2 Betsy Cowles 6,7 GEG - Spokane OLM - Olympia, WA
4 Tom Fritz 1,2,3,4,5 Wednesday March 30 Wednesday March 30 41 minutes
5 Rich Hadley 6,7,8 OLM - Olympia, WA GEG - Spokane
7 Scott Morris 77700300 426120 550 X01 $3,220.00
8 Collin Sprague
ICNU_DR_240 Attachment A Page 27 of 419
6/8/2015 9:05 AM
Flight #: AVA033111 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:March Date:31 - 31 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 02800545 928000 550 R11 $637.00 1,2,3,4 Thursday March 31 Thursday March 31 56 minutes
2 Kelly Norwood 02800540 928000 550 R11 $2,548.00 GEG - Spokane OLM - Olympia, WA
4 Dennis Vermillion 1,2,3,4 Thursday March 31 Thursday March 31 35 minutes
OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 28 of 419
6/8/2015 9:05 AM
Flight #: AVA033111a AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:March Date:31 - 31 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Terry Bushnell 1,2,3,4,5 Thursday March 31 Thursday March 31 17 minutes
2 Karen Feltes GEG - Spokane LWS - Lewiston, ID
4 Jason Thackston 1,2,3,4,5 Thursday March 31 Thursday March 31 19 minutes
5 Dennis Vermillion 09903691 930200 550 X01 $1,260.00 LWS - Lewiston, ID GEG - Spokane
ICNU_DR_240 Attachment A Page 29 of 419
6/8/2015 9:05 AM
Flight #: AVA040611 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:April Date:6 - 6 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 David Meyer 1,2,3,4 Wednesday April 6 Wednesday April 6 55 minutes
2 Scott Morris GEG - Spokane SLE - Salem
4 Mark Thies 1,2,3,4 Wednesday April 6 Wednesday April 6 43 minutes
SLE - Salem GEG - Spokane
ICNU_DR_240 Attachment A Page 30 of 419
6/8/2015 9:06 AM
Flight #: AVA041911 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:April Date:19 - 19 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4,5 Tuesday April 19 Tuesday April 19 44 minutes
2 Tamara Carter GEG - Spokane OLM - Olympia, WA
4 Linda Gervais 02800540 928000 550 R11 $1,505.00 1,2,3,4,5 Tuesday April 19 Tuesday April 19 42 minutes
5 Janet Hadley OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 31 of 419
6/8/2015 9:06 AM
Flight #: AVA042011 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Thursday Month:April Date:20 - 21 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jason Thackston 09903691 930200 550 F54 $2,275.00 1,2 Wednesday April 20 Wednesday April 20 64 minutes
2 Mark Thies 09903691 930200 550 J01 $2,275.00 GEG - Spokane OTH - North Bend
1,2 Thursday April 21 Thursday April 21 66 minutes
OTH - North Bend GEG - Spokane
ICNU_DR_240 Attachment A Page 32 of 419
6/8/2015 9:06 AM
Flight #: AVA042711 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:April Date:27 - 27 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Annette Brandon 1,2,3,4,5 Wednesday April 27 Wednesday April 27 54 minutes
2 Kevin Christie 6 GEG - Spokane SLE - Salem
4 Carolyn Groome 1,2,3,4,5 Wednesday April 27 Wednesday April 27 41 minutes
5 Kelly Irvine 6 SLE - Salem GEG - Spokane
ICNU_DR_240 Attachment A Page 33 of 419
6/8/2015 9:06 AM
Flight #: AVA050211 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:May Date:2 - 2 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 77703050 186503 550 X01 $656.25 1,2,3,4 Monday May 2 Monday May 2 40 minutes
2 Ed Schlect 77703050 186503 550 A07 $656.25 GEG - Spokane BFI - Seattle, WA
4 Roger Woodworth 77703050 186503 550 M54 $656.25 1,2,3,4 Monday May 2 Monday May 2 36 minutes
9900111 931111 885 F54 ($10,108.00)BFI - Seattle, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 34 of 419
6/8/2015 9:06 AM
Flight #: AVA051011 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:May Date:10 - 10 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 02800540 928000 550 R11 $574.00 1,2,3,4,5 Tuesday May 10 Tuesday May 10 44 minutes
2 James Gall 02800540 928000 550 R11 $574.00 GEG - Spokane OLM - Olympia, WA
4 Scott Kinney 09802454 560000 550 D56 $574.00 1,2,3,4,5 Tuesday May 10 Tuesday May 10 38 minutes
5 Jeff Schlect 09802454 560000 550 E56 $574.00 OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 35 of 419
6/8/2015 9:06 AM
Flight #: AVA051211 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:May Date:12 - 12 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Dana Anderson 06805028 909000 550 A52 $875.00 1,2,3,4,5 Thursday May 12 Thursday May 12 71 minutes
2 Pat Lynch 06805028 909000 550 A52 $875.00 GEG - Spokane MFR - Medford, OR
4 Christine Mccabe 06805153 930200 550 H14 $875.00 1,2,3,4,5 Thursday May 12 Thursday May 12 54 minutes
5 Mary Tyrie 06805028 909000 550 A52 $875.00 MFR - Medford, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 36 of 419
6/8/2015 9:06 AM
Flight #: AVA051411 AVISTA DAILY FLIGHT MANIFEST
Day:Saturday - Tuesday Month:May Date:14 - 17 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jason Lang 09900010 921000 550 Y54 $7,175.00 1,2,3 Saturday May 14 Saturday May 14 138 minutes
2 Scott Morris 09900311 930200 550 X01 $7,175.00 GEG - Spokane SLN - Salina, KS
1,2,3 Saturday May 14 Saturday May 14 152 minutes
SLN - Salina, KS MCO - Orlando, FL
1,2,3 Tuesday May 17 Tuesday May 17 175 minutes
MCO - Orlando, FL SLN - Salina, KS
1,2,3 Tuesday May 17 Tuesday May 17 150 minutes
SLN - Salina, KS GEG - Spokane
***Breakfast - GEG-SLN
***Lunch - SLN-MCO
ICNU_DR_240 Attachment A Page 37 of 419
6/8/2015 9:06 AM
Flight #: AVA052011 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:May Date:20 - 20 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Bryan Cox 1,2,3,4 Friday May 20 Friday May 20 16 minutes
2 Dan Kolbet GEG - Spokane LWS - Lewiston, ID
4 Dennis Vermillion 09900162 921000 550 E01 $4,585.00 1,2,3,4 Friday May 20 Friday May 20 55 minutes
LWS - Lewiston, ID MFR - Medford, OR
1,2,3,4 Friday May 20 Friday May 20 60 minutes
MFR - Medford, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 38 of 419
6/8/2015 9:06 AM
Flight #: AVA052511 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:May Date:25 - 25 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Mark Baker 09803400 242614 550 T52 $299.44 1,2,3,4,5 Wednesday May 25 Wednesday May 25 40 minutes
2 Renee Coelho 09803400 242614 550 T52 $299.44 6,7,8,9 GEG - Spokane BFI - Seattle, WA
4 Bruce Folsom 09803400 242614 550 T52 $299.48 1,2,3,4,5 Wednesday May 25 Wednesday May 25 37 minutes
5 Lori Hermanson 09803400 242614 550 T52 $299.44 6,7,8,9 BFI - Seattle, WA GEG - Spokane
7 Pat Lynch 09800731 908000 550 F52 $299.44
8 Jon Powell 09803400 242614 550 T52 $299.44
ICNU_DR_240 Attachment A Page 39 of 419
6/8/2015 9:06 AM
Flight #: AVA060211 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Friday Month:June Date:2 - 3 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jim Kensok 77705072 930200 550 N09 $1,548.75 1,2,3,4 Thursday June 2 Thursday June 2 87 minutes
2 Jason Lang 77705072 930200 550 Y54 $1,548.75 GEG - Spokane UKI - Ukiah, CA
4 Mark Thies 77705072 930200 550 J01 $1,548.75 1,2,3,4 Friday June 3 Friday June 3 90 minutes
Metal FX 77703430 417100 885 F54 $23,541.00 UKI - Ukiah, CA GEG - Spokane
ICNU_DR_240 Attachment A Page 40 of 419
6/8/2015 9:07 AM
Flight #: AVA061311 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:June Date:13 - 13 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Greg Bever 1,2,3,4,5 Monday June 13 Monday June 13 185 minutes
2 Greg Bulkley 6,7,8 GEG - Spokane BLV - Belleville, IL
4 Todd Mielke 1,2,3,4,5 Monday June 13 Monday June 13 205 minutes
5 Scott Morris 77700300 426110 550 X01 $13,650.00 6,7,8 BLV - Belleville, IL GEG - Spokane
7 Bill Simer
8 Mary Verner
9900111 931111 885 F54 ($51,870.00)
ICNU_DR_240 Attachment A Page 41 of 419
6/8/2015 9:07 AM
Flight #: AVA061611 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:June Date:16 - 16 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 02800545 928000 550 R11 $1,400.00 1,2,3 Thursday June 16 Thursday June 16 41 minutes
2 David Meyer GEG - Spokane OLM - Olympia, WA
1,2,3 Thursday June 16 Thursday June 16 39 minutes
OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 42 of 419
6/8/2015 9:07 AM
Flight #: AVA062011 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:June Date:20 - 20 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Linda Gervais 03800540 928000 550 R11 $980.00 1,2,3 Monday June 20 Monday June 20 40 minutes
2 Scott Kinney 09802454 560000 550 D56 $980.00 GEG - Spokane BOI - Boise, ID
1,2,3 Monday June 20 Monday June 20 44 minutes
BOI - Boise, ID GEG - Spokane
ICNU_DR_240 Attachment A Page 43 of 419
6/8/2015 9:07 AM
Flight #: AVA062211 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Friday Month:June Date:22 - 24 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Bryan Cox 09903691 930200 550 E01 $2,085.00 1,2,3,4,5 Wednesday June 22 Wednesday June 22 109 minutes
2 Ryan Krasselt 09903370 930200 550 F54 $2,085.00 6,7 GEG - Spokane OAK - Oakland
4 Jason Thackston 09903691 930200 550 D08 $2,085.00 1,2,3,4,5 Wednesday June 22 Wednesday June 22 154 minutes
5 Mark Thies 09903691 930200 550 J01 $2,085.00 6,7 OAK - Oakland LNK - Lincoln, Nebraska
7 Dennis Vermillion 09903691 930200 550 T01 $2,085.00 1,2,3,4,5 Wednesday June 22 Wednesday June 22 154 minutes
6,7 LNK - Lincoln, Nebraska GEG - Spokane
***Catering - Breakfast GEG-OAK
ICNU_DR_240 Attachment A Page 44 of 419
6/8/2015 9:07 AM
Flight #: AVA070711 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:July Date:7 - 7 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 77700300 426120 550 X01 $2,625.00 1,2,3,5,6 Thursday July 7 Thursday July 7 41 minutes
2 Antony Chiang GEG - Spokane BFI - Seattle, WA
4 Brian Pitcher 1,2,3,4,5 Thursday July 7 Thursday July 7 34 minutes
5 Tom Quigley 6 BFI - Seattle, WA GEG - Spokane
77703430 417100 885 F54 $9,975.00
9900111 931111 885 F54 ($9,975.00)
ICNU_DR_240 Attachment A Page 45 of 419
6/8/2015 9:07 AM
Flight #: AVA071811 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:July Date:18 - 18 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Morris 1,2 Monday July 18 Monday July 18 40 minutes
2 Scott Morris 77700300 426100 885 X01 $2,765.00 GEG - Spokane BFI - Seattle, WA
9900111 931111 885 F54 ($10,507.00)1,2 Monday July 18 Monday July 18 39 minutes
BFI - Seattle, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 46 of 419
6/8/2015 9:07 AM
Flight #: AVA071911 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:July Date:19 - 19 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 02800545 928000 550 R11 $2,625.00 1,2,3,5 Tuesday July 19 Tuesday July 19 49 minutes
2 Pat Ehrbar 03800545 928000 550 R11 $2,625.00 GEG - Spokane BOI - Boise, ID
4 Kelly Norwood 1,2,3,5 Tuesday July 19 Tuesday July 19 59 minutes
5 Andrew Scull BOI - Boise, ID OLM - Olympia, WA
1,2,3,4,5 Tuesday July 19 Tuesday July 19 42 minutes
OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 47 of 419
6/8/2015 9:07 AM
Flight #: AVA080311 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:August Date:3 - 3 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4 Wednesday August 3 Wednesday August 3 47 minutes
2 Kevin Christie GEG - Spokane SLE - Salem
4 Andrew Scull 1,2,3,4 Wednesday August 3 Wednesday August 3 43 minutes
SLE - Salem GEG - Spokane
ICNU_DR_240 Attachment A Page 48 of 419
6/8/2015 9:07 AM
Flight #: AVA081711 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:August Date:17 - 17 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Wednesday August 17 Wednesday August 17 43 minutes
2 Pat Ehrbar 6,7,8,9 GEG - Spokane BOI - Boise, ID
4 Bill Johnson 1,2,3,4,5 Wednesday August 17 Wednesday August 17 41 minutes
5 Tara Knox 6,7,8,9 BOI - Boise, ID GEG - Spokane
7 Kelly Norwood 03800545 928000 550 R11 $588.00
8 Jeanne Pluth
ICNU_DR_240 Attachment A Page 49 of 419
6/8/2015 9:08 AM
Flight #: AVA081911 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:August Date:19 - 19 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Dan Kolbet 1,2,3 Friday August 19 Friday August 19 16 minutes
2 Kelly Norwood GEG - Spokane LWS - Lewiston, ID
1,2,3 Friday August 19 Friday August 19 7 minutes
LWS - Lewiston, ID PUW - Pullman, WA
1,2,3 Friday August 19 Friday August 19 59 minutes
PUW - Pullman, WA MFR - Medford, OR
1,2,3 Friday August 19 Friday August 19 58 minutes
MFR - Medford, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 50 of 419
6/8/2015 9:08 AM
Flight #: AVA082411 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:August Date:24 - 24 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Thomas Dempsey 41002100 500000 550 E55 $351.20 1,2,3,4,5 Wednesday August 24 Wednesday August 24 29 minutes
2 Mike Gonnella 61002452 546010 550 E07 $351.16 6 GEG - Spokane M50 - Boardman, OR
4 Kirk Hayfield 09902920 921208 550 G02 $351.16 1,2,4,5,6 Wednesday August 24 Wednesday August 24 26 minutes
5 Bob Lafferty 41002100 500000 550 E55 $351.16 M50 - Boardman, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 51 of 419
6/8/2015 9:08 AM
Flight #: AVA090811 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Saturday Month:September Date:8 - 10 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Mark Thies 77700300 426125 550 J01 $3,255.00 1 Thursday September 8 Thursday September 8 46 minutes
GEG - Spokane
1 Saturday September 10 Saturday September 10 47 minutes
GEG - Spokane
ICNU_DR_240 Attachment A Page 52 of 419
6/8/2015 9:08 AM
Flight #: AVA091311 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:September Date:13 - 13 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Rick Bybee 1,2,3 Tuesday September 13 Tuesday September 13 3 minutes
2 Dave Robinson 09900110 935000 550 L54 $105.00 GEG - Spokane GEG - Spokane
ICNU_DR_240 Attachment A Page 53 of 419
6/8/2015 9:08 AM
Flight #: AVA091411 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:September Date:14 - 14 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Thomas Dempsey 41002100 500000 550 E55 $1,001.00 1,2,3,4,5 70 minutes
2 Don Falkner 09903310 930200 550 C54 $1,001.00 6,7 GEG - Spokane M46 - Colstrip, MT
4 Fred Johnston 1,2,3,4,5 73 minutes
5 Kellee Quick 09903310 921000 550 A57 $1,001.00 6,7 M46 - Colstrip, MT GEG - Spokane
7 John Spanos
Karen Schuh 3800540 921000 550 R11 $500.50
ICNU_DR_240 Attachment A Page 54 of 419
6/8/2015 9:08 AM
Flight #: AVA092211 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:September Date:22 - 22 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Thursday September 22 Thursday September 22 45 minutes
2 Pat Ehrbar 6,7,8,9 GEG - Spokane OLM - Olympia, WA
4 Tara Knox 1,2,3,4,5 Thursday September 22 Thursday September 22 39 minutes
5 David Meyer 02800540 928000 550 R11 $2,352.00 6,7,8,9 OLM - Olympia, WA GEG - Spokane
7 Jeanne Pluth
8 Karen Schuh
ICNU_DR_240 Attachment A Page 55 of 419
6/8/2015 9:08 AM
Flight #: AVA092311 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:September Date:23 - 23 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Dana Anderson 09800544 928000 550 R11 $2,870.00 1,2,3,4,5 Friday September 23 Friday September 23 45 minutes
2 Joshua Diluciano GEG - Spokane OLM - Olympia, WA
4 Heather Rosentrater 1,2,3,4,5 Friday September 23 Friday September 23 37 minutes
5 Clay Storey OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 56 of 419
6/8/2015 9:08 AM
Flight #: AVA092311a AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:September Date:23 - 23 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Friday September 23 Friday September 23 46 minutes
2 Pat Ehrbar 6,7,8,9 GEG - Spokane OLM - Olympia, WA
4 Tara Knox Friday September 23 Friday September 23 38 minutes
5 David Meyer 02800540 928000 550 R11 $4,564.00 OLM - Olympia, WA GEG - Spokane
7 Jeanne Pluth 1,2,3,4,5 Friday September 23 Friday September 23 38 minutes
8 Karen Schuh 6,7,8,9 OLM - Olympia, WA GEG - Spokane
Friday September 23 Friday September 23 41 minutes
GEG - Spokane OLM - Olympia, WA
ICNU_DR_240 Attachment A Page 57 of 419
6/8/2015 9:08 AM
Flight #: AVA092911 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:September Date:29 - 29 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Dick Storro 09802202 557000 550 E55 $3,115.00 1 Thursday September 29 Thursday September 29 52 minutes
GEG - Spokane PDX - Portland, OR
1 Thursday September 29 Thursday September 29 37 minutes
PDX - Portland, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 58 of 419
6/8/2015 9:09 AM
Flight #: AVA100511 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:October Date:5 - 5 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 09902454 813000 550 D55 $1,085.00 1,2,3 Wednesday October 5 Wednesday October 5 43 minutes
2 Don Kopczynski 09903691 921000 550 D08 $1,085.00 GEG - Spokane PDX - Portland, OR
1,2,3 Wednesday October 5 Wednesday October 5 50 minutes
PDX - Portland, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 59 of 419
6/8/2015 9:09 AM
Flight #: AVA101011 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Wednesday Month:October Date:10 - 12 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Rich Hadley 1,2,3,4,5 Monday October 10 Monday October 10 162 minutes
2 Scott Morris 09903691 930200 550 X01 $9,485.00 GEG - Spokane MSN - Madison, WI
4 Tom Quigley 1,2,3,4,5 Monday October 10 Monday October 10 98 minutes
5 Bill Savitz MSN - Madison, WI IAD - Washington, DC
1,2,3,4,5 Wednesday October 12 Wednesday October 12 89 minutes
IAD - Washington, DC MSN - Madison, WI
1,2,3,4,5 Wednesday October 12 Wednesday October 12 193 minutes
MSN - Madison, WI GEG - Spokane
***CATERING - Lunch from MSN-IAD
ICNU_DR_240 Attachment A Page 60 of 419
6/8/2015 9:09 AM
Flight #: AVA101411 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:October Date:14 - 14 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Timothy Carlberg 09802050 535000 550 E07 $240.62 1,2,3,4,5 Friday October 14 Friday October 14 30 minutes
2 Bryan Cox 09903691 930200 550 E01 $240.62 6,7,8 GEG - Spokane M50 - Boardman, OR
4 Thomas Heavey 09900181 921010 550 W09 $240.62 1,2,3,4,5 Friday October 14 Friday October 14 25 minutes
5 Jim Kensok 09900181 921010 550 N09 $240.62 6,7,8 M50 - Boardman, OR GEG - Spokane
7 Vicki Weber 09905569 921010 550 N50 $240.62
8 Steve Wenke 09802050 535000 550 E07 $240.62
ICNU_DR_240 Attachment A Page 61 of 419
6/8/2015 9:09 AM
Flight #: AVA101711 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:October Date:17 - 17 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Thomas Dempsey 41002100 500000 550 E55 $532.00 1,2,3,4,5 Monday October 17 Monday October 17 41 minutes
2 Bruce Howard 09800540 537000 550 A04 $532.00 GEG - Spokane BFI - Seattle, WA
4 Dick Storro 09802202 557000 550 E55 $1,792.00 4,5 Monday October 17 Monday October 17 43 minutes
5 Dennis Vermillion 09800310 930200 550 T01 $1,792.00 BFI - Seattle, WA PDX - Portland, OR
4,5 Monday October 17 Monday October 17 29 minutes
PDX - Portland, OR BFI - Seattle, WA
1,2,3,4,5 Monday October 17 Monday October 17 35 minutes
BFI - Seattle, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 62 of 419
6/8/2015 9:09 AM
Flight #: AVA101811 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:October Date:18 - 18 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Garth Brandon 09800165 580000 550 P51 $525.00 1,2,2,3,4 Tuesday October 18 Tuesday October 18 65 minutes
2 Randy Chandler 95602455 870000 550 L50 $262.50 5,6,7,9 GEG - Spokane MFR - Medford, OR
4 Paul Good 77700242 107050 550 C53 $525.00 1,2,2,3,4 Tuesday October 18 Tuesday October 18 55 minutes
5 Tom Jannings 09902920 921208 550 G02 $525.00 5,7,8,9 MFR - Medford, OR GEG - Spokane
7 Mike Littrel 09905085 921000 550 I08 $525.00
8 John Schwendener 09900160 921000 550 G08 $240.62
Randy Chandler 77700242 107050 550 L50 $262.50
ICNU_DR_240 Attachment A Page 63 of 419
6/8/2015 9:09 AM
Flight #: AVA102511 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:October Date:25 - 25 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Marian Durkin 77703047 186200 550 P01 $2,835.00 1,2,3 Tuesday October 25 Tuesday October 25 41 minutes
2 Toni Pessemier GEG - Spokane BFI - Seattle, WA
1,2,3 Tuesday October 25 Tuesday October 25 40 minutes
BFI - Seattle, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 64 of 419
6/8/2015 9:09 AM
Flight #: AVA110511 AVISTA DAILY FLIGHT MANIFEST
Day:Saturday - Saturday Month:November Date:5 - 12 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Karen Feltes 09900020 930200 550 Y01 $3,651.68 2,3,4,5,6 Saturday November 5 Saturday November 5 146 minutes
2 Jason Lang 09900010 921000 550 Y54 $2,058.00 7 GEG - Spokane SLN - Salina, KS
4 Scott Morris 09903691 930200 550 X01 $8,194.66 2,3,4,5,6 Saturday November 5 Saturday November 5 148 minutes
5 Jason Thackston 09903691 930200 550 D08 $2,058.00 7 SLN - Salina, KS MCO - Orlando, FL
7 Diane Thoren 09903370 930200 550 F54 $2,058.00 3,4,6 Tuesday November 8 Tuesday November 8 142 minutes
MCO - Orlando, FL TEB - New York
1,4,6 Saturday November 12 Saturday November 12 171 minutes
TEB - New York FAR - Fargo
1,4,6 Saturday November 12 Saturday November 12 133 minutes
FAR - Fargo GEG - Spokane
Purpose EEI Financial Forum / Q4 Avista Corp Board Meeting
ICNU_DR_240 Attachment A Page 65 of 419
6/8/2015 9:09 AM
Flight #: AVA111511 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:November Date:15 - 15 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Bruce Folsom 09803400 242663 550 T52 $3,325.00 1,2,3,4,5 Tuesday November 15 Tuesday November 15 52 minutes
2 Lori Hermanson 6,7 GEG - Spokane PDX - Portland, OR
4 Pat Lynch 1,2,3,4,5 Tuesday November 15 Tuesday November 15 43 minutes
5 Jon Powell 6,7 PDX - Portland, OR GEG - Spokane
7 Levi Westra
ICNU_DR_240 Attachment A Page 66 of 419
6/8/2015 9:09 AM
Flight #: AVA112311 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:November Date:23 - 23 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Kinney 09802454 560000 550 D56 $761.25 1,2,3,4 51 minutes
2 Tracy Rolstad 09802454 560000 550 C56 $761.25 GEG - Spokane PDX - Portland, OR
4 Scott Waples 09802454 560000 550 C56 $761.25 1,2,3,4 36 minutes
PDX - Portland, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 67 of 419
6/8/2015 9:10 AM
Flight #: AVA112811 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Thursday Month:November Date:28 - 1 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Don Falkner 09903310 921000 550 C54 $905.00 1,2,3,4,5 Monday November 28 Monday November 28 181 minutes
2 Tami Judge 09902811 926102 550 Y55 $905.00 6,7 GEG - Spokane MDW - Chicago
4 Adam Munson 09902811 926102 550 G54 $905.00 3,5,6 Monday November 28 Monday November 28 94 minutes
5 Jason Thackston 09900010 921000 550 Y54 $5,525.00 MDW - Chicago TEB - New York
7 John Wilcox 09902811 926102 550 G54 $905.00 3,5,6 Thursday December 1 Thursday December 1 174 minutes
TEB - New York FAR - Fargo
3,5,6 Thursday December 1 Thursday December 1 128 minutes
FAR - Fargo GEG - Spokane
***CATERING - Lunch MDW-TEB
ICNU_DR_240 Attachment A Page 68 of 419
6/8/2015 9:10 AM
Flight #: AVA120211 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:December Date:2 - 2 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Linda Jones 1,2,3,4 Friday December 2 Friday December 2 16 minutes
2 Don Kopczynski GEG - Spokane LWS - Lewiston, ID
4 Dennis Vermillion 09900162 921000 550 E01 $5,110.00 1,2,3,4 Friday December 2 Friday December 2 7 minutes
LWS - Lewiston, ID PUW - Pullman, WA
1,2,3,4 Friday December 2 Friday December 2 53 minutes
PUW - Pullman, WA MFR - Medford, OR
1,2,3,4 Friday December 2 Friday December 2 70 minutes
MFR - Medford, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 69 of 419
6/8/2015 9:10 AM
Flight #: AVA120611 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Wednesday Month:December Date:6 - 7 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Marian Durkin 09903691 923000 550 P01 $20,405.00 1,2,3,4 Tuesday December 6 Tuesday December 6 173 minutes
2 Bruce Howard GEG - Spokane MSN - Madison, WI
4 Bill Schroeder 1,2,3,4 Tuesday December 6 Tuesday December 6 101 minutes
MSN - Madison, WI IAD - Washington, DC
1,2,3,4 Wednesday December 7 Wednesday December 7 100 minutes
IAD - Washington, DC MSN - Madison, WI
1,2,3,4 Wednesday December 7 Wednesday December 7 209 minutes
MSN - Madison, WI GEG - Spokane
***CATERING - Lunch GEG-MSN
ICNU_DR_240 Attachment A Page 70 of 419
6/8/2015 9:10 AM
Flight #: AVA120811 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:December Date:8 - 8 Year: 2011
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Dave Robinson 09900110 935000 550 L54 $2,730.00 1,2 Thursday December 8 Thursday December 8 78 minutes
2 Richard Stanford GEG - Spokane SMF - Sacramento, CA
ICNU_DR_240 Attachment A Page 71 of 419
6/8/2015 9:11 AM
Flight #: AVA010312 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:January Date:3 - 3 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Dave Robinson 09900110 935000 550 L54 $2,275.00 1,2 Tuesday January 3 Tuesday January 3 65 minutes
2 Richard Stanford SMF - Sacramento, CA GEG - Spokane
ICNU_DR_240 Attachment A Page 72 of 419
6/8/2015 9:11 AM
Flight #: AVA012512 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:January Date:25 - 25 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Clint Kalich 09802202 557000 550 E55 $778.75 1,2,3,4 Wednesday January 25 Wednesday January 25 53 minutes
2 Bob Lafferty 09802202 557000 550 E55 $778.75 GEG - Spokane PDX - Portland, OR
4 Dick Storro 09802202 557000 550 E55 $778.75 1,2,3,4 Wednesday January 25 Wednesday January 25 36 minutes
PDX - Portland, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 73 of 419
6/8/2015 9:11 AM
Flight #: AVA012712 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:January Date:27 - 27 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09903691 930200 550 X01 $3,080.00 1 Friday January 27 Friday January 27 46 minutes
GEG - Spokane OLM - Olympia, WA
1 Friday January 27 Friday January 27 42 minutes
OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 74 of 419
6/8/2015 9:11 AM
Flight #: AVA020612 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:February Date:6 - 6 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 David Meyer 09900540 928000 550 R11 $898.33 1,2,3 Monday February 6 Monday February 6 38 minutes
2 Scott Morris 09903691 930200 550 X01 $898.34 GEG - Spokane BFI - Seattle, WA
1,2,3 Monday February 6 Monday February 6 39 minutes
BFI - Seattle, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 75 of 419
6/8/2015 9:11 AM
Flight #: AVA021012 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:February Date:10 - 10 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jeff Heggedahl 1,2,3,4 Friday February 10 Friday February 10 13 minutes
2 Dan Kolbet GEG - Spokane PUW - Pullman, WA
4 Dennis Vermillion 1,2,3,4 Friday February 10 Friday February 10 7 minutes
PUW - Pullman, WA LWS - Lewiston, ID
1,2,3,4 Friday February 10 Friday February 10 61 minutes
LWS - Lewiston, ID MFR - Medford, OR
1,2,3,4 Friday February 10 Friday February 10 56 minutes
MFR - Medford, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 76 of 419
6/8/2015 9:11 AM
Flight #: AVA022112 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:February Date:21 - 21 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jim Corder 09900181 921010 550 P09 $810.00 1,2,3,4,5 Tuesday February 21 Tuesday February 21 68 minutes
2 Thomas Dempsey 41002100 500000 550 E55 $810.00 6,7 GEG - Spokane M46 - Colstrip, MT
4 Heather Rosentrater 9902454 813000 550 D55 $810.00 1,2,3,4,5 Tuesday February 21 Tuesday February 21 94 minutes
5 Andy Vickers 09802051 541000 550 A07 $810.00 6,7 M46 - Colstrip, MT GEG - Spokane
7 Steve Wenke 09802050 535000 550 E07 $810.00
ICNU_DR_240 Attachment A Page 77 of 419
6/8/2015 9:11 AM
Flight #: AVA022812 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Wednesday Month:February Date:28 - 29 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Timothy Carlberg 77705202 300100 550 A07 $4,716.25 1,2,3,4 Tuesday February 28 Tuesday February 28 159 minutes
2 Elvin/speed Fitzhugh 77705202 300100 550 C04 $4,716.25 GEG - Spokane MSN - Madison, WI
4 David Schwall 77705202 300100 550 A07 $4,716.25 1,2,3,4 Tuesday February 28 Tuesday February 28 86 minutes
MSN - Madison, WI IAD - Washington, DC
1,2,3,4 Wednesday February 29 Wednesday February 29 105 minutes
IAD - Washington, DC MSN - Madison, WI
1,2,3,4 Wednesday February 29 Wednesday February 29 189 minutes
MSN - Madison, WI GEG - Spokane
***CATERING - Lunch from MSN-IAD
ICNU_DR_240 Attachment A Page 78 of 419
6/8/2015 9:11 AM
Flight #: AVA030512 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:March Date:5 - 5 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 02800540 928000 550 R11 $2,380.00 1,2 Monday March 5 Monday March 5 50 minutes
2 Kelly Norwood 02800545 928000 550 R11 $595.00 GEG - Spokane OLM - Olympia, WA
1,2 Monday March 5 Monday March 5 35 minutes
OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 79 of 419
6/8/2015 9:11 AM
Flight #: AVA030612 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:March Date:6 - 6 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 03800540 928000 550 R11 $2,352.00 1,2,3 Tuesday March 6 Tuesday March 6 42 minutes
2 Kelly Norwood 03800545 928000 550 R11 $588.00 GEG - Spokane BOI - Boise, ID
1,2,3 Tuesday March 6 Tuesday March 6 42 minutes
BOI - Boise, ID GEG - Spokane
ICNU_DR_240 Attachment A Page 80 of 419
6/8/2015 9:11 AM
Flight #: AVA030712 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:March Date:7 - 7 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Justin Dorr 09902454 813000 550 D55 $484.16 1,2,3,4,5 Wednesday March 7 Wednesday March 7 44 minutes
2 Leslie Filer 09902454 813000 550 D55 $484.16 6 GEG - Spokane CLS - Chehalis, WA
4 Heather Rosentrater 09902454 813000 550 D55 $484.17 1,2,3,4,5 Wednesday March 7 Wednesday March 7 39 minutes
5 John Schwendener 09900160 921000 550 G08 $484.17 6 CLS - Chehalis, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 81 of 419
6/8/2015 9:12 AM
Flight #: AVA031912 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Friday Month:March Date:19 - 23 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Ella Gatuz 7,8 Monday March 19 Monday March 19 124 minutes
2 Jeff Hughes GEG - Spokane FAR - Fargo
4 Andre Ilano 7,8 Monday March 19 Monday March 19 163 minutes
5 Sonia Ilano FAR - Fargo TEB - New York
7 Jason Lang 09900010 921000 550 Y54 $11,865.00 1,2,3,4,5 Wednesday March 21 Wednesday March 21 167 minutes
8 Mark Thies 09903691 930200 550 J01 $11,865.00 7,8 TEB - New York SLN - Salina, KS
1,2,3,4,5 Wednesday March 21 Wednesday March 21 125 minutes
7,8 SLN - Salina, KS LAS - Las Vegas, NV
6,7,8 Friday March 23 Friday March 23 99 minutes
LAS - Las Vegas, NV GEG - Spokane
Purpose Sedoti Conference / West Coast Utilities Conference
ICNU_DR_240 Attachment A Page 82 of 419
6/8/2015 9:12 AM
Flight #: AVA032812 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Thursday Month:March Date:28 - 29 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 77703430 417120 550 G54 $1,627.50 1,2,3,4 Wednesday March 28 Wednesday March 28 100 minutes
2 Don Falkner 77703430 417120 550 C54 $1,627.50 GEG - Spokane UKI - Ukiah, CA
4 Mark Thies 77703430 417120 550 J01 $1,627.50 1,2,3,4 Thursday March 29 Thursday March 29 86 minutes
UKI - Ukiah, CA GEG - Spokane
ICNU_DR_240 Attachment A Page 83 of 419
6/8/2015 9:12 AM
Flight #: AVA040412 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:April Date:4 - 4 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Greg Bever 1,2,3,4,5 Wednesday April 4 Wednesday April 4 193 minutes
2 David Condon 6,7 GEG - Spokane BLV - Belleville, IL
4 Christine Johnson 1,2,3,4,5 Wednesday April 4 Wednesday April 4 189 minutes
5 Todd Mielke 6,7 BLV - Belleville, IL GEG - Spokane
7 Bill Savitz
ICNU_DR_240 Attachment A Page 84 of 419
6/8/2015 9:12 AM
Flight #: AVA040912 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:April Date:9 - 9 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 John Hartnett 1,2,3 Monday April 9 Monday April 9 30 minutes
2 Dave Robinson 09902811 926101 550 L54 $1,050.00 GEG - Spokane GEG - Spokane
ICNU_DR_240 Attachment A Page 85 of 419
6/8/2015 9:12 AM
Flight #: AVA041212 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:April Date:12 - 12 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Pat Ehrbar 03800545 928000 550 R11 $2,397.50 1,2,3,4,5 Thursday April 12 Thursday April 12 44 minutes
2 Steve Harper 02800545 928000 550 R11 $2,397.50 GEG - Spokane BOI - Boise, ID
4 Heather Rosentrater 1,2,3,4,5 Thursday April 12 Thursday April 12 54 minutes
5 Eric Scott BOI - Boise, ID OLM - Olympia, WA
1,2,3,4,5 Thursday April 12 Thursday April 12 39 minutes
OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 86 of 419
6/8/2015 9:12 AM
Flight #: AVA041712 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:April Date:17 - 17 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4,5 Tuesday April 17 Tuesday April 17 49 minutes
2 Pat Ehrbar 06800545 928000 550 R11 $3,045.00 6 GEG - Spokane PDX - Portland, OR
4 Kelly Irvine 1,2,3,4,5 Tuesday April 17 Tuesday April 17 38 minutes
5 Tom Pardee 6 PDX - Portland, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 87 of 419
6/8/2015 9:12 AM
Flight #: AVA041812 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Saturday Month:April Date:18 - 21 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Marian Durkin 09903691 930200 550 V01 $8,516.68 1,2,3,4 Wednesday April 18 Wednesday April 18 135 minutes
2 Terry Durkin GEG - Spokane SLN - Salina, KS
4 Patty Wood 09903691 930200 550 U01 $8,516.66 1,2,3,4 Wednesday April 18 Wednesday April 18 127 minutes
SLN - Salina, KS FHB - Fernandian Beach
1,2,4 Saturday April 21 Saturday April 21 144 minutes
FHB - Fernandian Beach SLN - Salina, KS
1,2,4 Saturday April 21 Saturday April 21 168 minutes
SLN - Salina, KS GEG - Spokane
***CATERING - Lunch SLN-FHB
ICNU_DR_240 Attachment A Page 88 of 419
6/8/2015 9:12 AM
Flight #: AVA042612 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:April Date:26 - 26 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4 Thursday April 26 Thursday April 26 46 minutes
2 Pat Ehrbar GEG - Spokane OLM - Olympia, WA
4 Kelly Norwood 02805810 928010 550 R11 $3,220.00 1,2,3,4 Thursday April 26 Thursday April 26 46 minutes
OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 89 of 419
6/8/2015 9:12 AM
Flight #: AVA043012 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:April Date:30 - 30 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 02805810 928010 550 R11 $3,080.00 1,2,3,4,5 Monday April 30 Monday April 30 49 minutes
2 Annette Brandon 6,7,8 GEG - Spokane OLM - Olympia, WA
4 Tara Knox 1,2,3,4,5 Monday April 30 Monday April 30 39 minutes
5 Joe Miller 6,7,8 OLM - Olympia, WA GEG - Spokane
7 Karen Schuh
8 Jennifer Smith
ICNU_DR_240 Attachment A Page 90 of 419
6/8/2015 9:13 AM
Flight #: AVA050112 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:May Date:1 - 1 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 09903691 930200 550 U01 $533.75 1,2,3,4,5 Tuesday May 1 Tuesday May 1 64 minutes
2 Joe Dunlap 6,7,8 GEG - Spokane MFR - Medford, OR
4 Rachelle Humphrey 09905569 921010 550 N52 $533.75 1,2,3,4,5 Tuesday May 1 Tuesday May 1 58 minutes
5 Dj Kinservik 09905569 921010 550 N52 $533.75 6,7,8 MFR - Medford, OR GEG - Spokane
7 Steve Trabun 77705205 426120 550 M53 $2,135.00
8 Jeffrey Waybright
ICNU_DR_240 Attachment A Page 91 of 419
6/8/2015 9:13 AM
Flight #: AVA050512 AVISTA DAILY FLIGHT MANIFEST
Day:Saturday - Tuesday Month:May Date:5 - 8 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jason Lang 09900010 921000 550 Y54 $2,712.50 1,4,5 Saturday May 5 Saturday May 5 132 minutes
2 Liz Morris GEG - Spokane SDL - Scottsdale, AZ
4 Jason Thackston 09903691 930200 550 D08 $2,712.50 1,2,3,4,5 Tuesday May 8 Tuesday May 8 134 minutes
5 Mark Thies 09903691 930200 550 J01 $2,712.50 SDL - Scottsdale, AZ GEG - Spokane
ICNU_DR_240 Attachment A Page 92 of 419
6/8/2015 9:13 AM
Flight #: AVA050912 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:May Date:9 - 9 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Linda Gervais 1,2,3 Wednesday May 9 Wednesday May 9 47 minutes
2 David Meyer GEG - Spokane OLM - Olympia, WA
1,2,3 Wednesday May 9 Wednesday May 9 36 minutes
OLM - Olympia, WA GEG - Spokane
ICNU_DR_240 Attachment A Page 93 of 419
6/8/2015 9:13 AM
Flight #: AVA051712 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:May Date:17 - 17 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Annette Brandon 1,2,3,4,5 Thursday May 17 Thursday May 17 51 minutes
2 Pat Ehrbar 06800545 928000 550 R11 $3,290.00 6,7 GEG - Spokane SLE - Salem
4 Kelly Irvine 1,2,3,4,5 Thursday May 17 Thursday May 17 43 minutes
5 Heather Rosentrater 6,7 SLE - Salem GEG - Spokane
7 Dick Storro
ICNU_DR_240 Attachment A Page 94 of 419
6/8/2015 9:13 AM
Flight #: AVA051812 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:May Date:18 - 18 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Linda Jones 1,2,3,4,5 Friday May 18 Friday May 18 62 minutes
2 Dan Kolbet 6 GEG - Spokane MFR - Medford, OR
4 Brandi Smith 1,2,2,3,4 Friday May 18 Friday May 18 56 minutes
5 Jason Thackston 5,6 MFR - Medford, OR PUW - Pullman, WA
1,2,3,4,5 Friday May 18 Friday May 18 7 minutes
6 PUW - Pullman, WA LWS - Lewiston, ID
1,2,3,4,5 Friday May 18 Friday May 18 16 minutes
6 LWS - Lewiston, ID GEG - Spokane
ICNU_DR_240 Attachment A Page 95 of 419
6/8/2015 9:13 AM
Flight #: AVA052412 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:May Date:24 - 24 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Timothy Carlberg 61002054 551000 550 A07 $231.88 1,2,3,4,5 Thursday May 24 Thursday May 24 27 minutes
2 Cameron Dunlop 09802810 926102 550 Y55 $231.87 6,7,8 GEG - Spokane M50 - Boardman, OR
4 Greg Rahn 09903691 930200 550 M54 $231.88 1,2,3,4,5 Thursday May 24 Thursday May 24 26 minutes
5 Heather Rosentrater 09802202 557000 550 D55 $231.88 6,7,8 M50 - Boardman, OR GEG - Spokane
7 Brandi Smith 09900330 930200 550 S54 $231.87
8 Tracy West 09802202 557000 550 T08 $231.87
ICNU_DR_240 Attachment A Page 96 of 419
6/8/2015 9:13 AM
Flight #: AVA060712 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:June Date:7 - 7 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Conrad Bell 1,2,3,4,5 Thursday June 7 Thursday June 7 36 minutes
2 Thomas Dempsey 09802202 557000 550 E55 $2,021.25 6,7,8,9 GEG - Spokane BTM - Butte, MT
4 James Gall 1,2,3,4,5 Thursday June 7 Thursday June 7 41 minutes
5 Mike Gonnella 09802050 535010 550 E07 $336.87 6,7,8,9 BTM - Butte, MT GEG - Spokane
7 Bob Lafferty
8 Steve Silkworth
ICNU_DR_240 Attachment A Page 97 of 419
6/8/2015 9:13 AM
Flight #: AVA061812 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:June Date:18 - 18 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 David Meyer 1,2,3,4 Monday June 18 Monday June 18 50 minutes
2 Scott Morris GEG - Spokane SLE - Salem
4 Mark Thies 1,2,3,4 Monday June 18 Monday June 18 48 minutes
SLE - Salem GEG - Spokane
ICNU_DR_240 Attachment A Page 98 of 419
6/8/2015 9:13 AM
Flight #: AVA062012 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:June Date:20 - 20 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09903691 930200 550 X01 $2,718.34 1,2,3 Wednesday June 20 Wednesday June 20 65 minutes
2 John Schwendener 09900160 921000 550 G08 $758.33 GEG - Spokane MFR - Medford, OR
1 Wednesday June 20 Wednesday June 20 56 minutes
MFR - Medford, OR GEG - Spokane
ICNU_DR_240 Attachment A Page 99 of 419
6/8/2015 9:14 AM
Flight #: AVA062112 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:June Date:21 - 21 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Bill Baker 09900165 870000 550 G08 $474.44 1,2,3,4,5 Thursday June 21 Thursday June 21 67 minutes
2 Bruce Cergl 77700233 163000 550 J51 $474.44 6,7,8,9 GEG - Spokane MFR - Medford, OR
4 Seth Feist 09903410 925130 550 L51 $474.48 1,2,3,4,5 Thursday June 21 Thursday June 21 55 minutes
5 Paul Good 09905085 921000 550 C53 $474.44 6,7,8,9 MFR - Medford, OR GEG - Spokane
7 Chris Schlothauer 77700200 184103 550 K51 $474.44
8 April Spacek 77700233 163000 550 J51 $474.44
ICNU_DR_240 Attachment A Page 100 of 419
6/8/2015 9:14 AM
Flight #: AVA070212 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:July Date:2 - 2 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Linda Burger 1,2,3,4 Monday July 2 Monday July 2 46 minut
2 Larry Labolle GEG - Spokane OLM - Olympia, WA
3 David Meyer 800 845
4 Kelly Norwood 02800545 928000 550 R11 $2,905.00 1,2,3,4 Monday July 2 Monday July 2 37 minut
OLM - Olympia, WA GEG - Spokane
1600 1645
Purpose WUTC Stakeholder Workshop OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Car reserved in Kelly's name. Conf# F520456
453
ICNU_DR_240 Attachment A Page 101 of 419
6/8/2015 9:14 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 102 of 419
6/8/2015 9:14 AM
Flight #: AVA070912 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Tuesday Month:July Date:9 - 10 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Marian Durkin 09903691 930200 550 V01 $2,275.00 2,3,4,6 Monday July 9 Monday July 9 156 minu
2 Ryan Krasselt 09903370 930200 550 F54 $3,640.00 GEG - Spokane MLI - Moline, IL
3 Scott Morris 09903691 930200 550 X01 $3,640.00 800 1245
4 Kelly Norwood 09900540 928000 550 R11 $3,640.00 1,2,3,4,5 Monday July 9 Monday July 9 99 minut
5 Mark Thies 09903691 930200 550 J01 $2,275.00 6 MLI - Moline, IL TEB - New York
6 Diane Thoren 09903370 930200 550 F54 $3,640.00 1315 1600
1,2,3,4,5 Tuesday July 10 Tuesday July 10 165 minu
6 TEB - New York FAR - Fargo
1500 1650
1,2,3,4,5 Tuesday July 10 Tuesday July 10 126 minu
6 FAR - Fargo GEG - Spokane
1720 1735
Purpose Rating Agency Meetings TEB - Meridian Air 201 288-5040
FAR - Fargo Jet Center 800 770-0538
Remarks Transportation - 7/9 Carey car will pick up at TEB drop off
at hotel. Conf# WA6296398-1. 7/10 carey car will pick up at MLI - Elliott Aviation 800-447-6711 hotel drop off at TEB. Conf# WA6296398-2.GEG - Avista Hangar 509 495-4139***CATERING - Lunch and snacks GEG-TEB
***CATERING - snacks TEB-GEG
ICNU_DR_240 Attachment A Page 103 of 419
6/8/2015 9:14 AM
lt Time
utes
tes
utes
utes
ICNU_DR_240 Attachment A Page 104 of 419
6/8/2015 9:14 AM
Flight #: AVA071712 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Wednesday Month:July Date:17 - 18 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Kristi Blake 1,2,4,6 Tuesday July 17 Tuesday July 17 42 minut
2 Marian Durkin 77703050 186210 550 V01 $812.00 GEG - Spokane PDX - Portland, OR
3 Karen Feltes 77703050 186210 550 Y01 $322.00 1000 1050
4 Scott Morris 77703050 186210 550 X01 $812.00 1,2,3,4,5 Wednesday July 18 Tuesday July 17 46 minut
5 Ed Schlect 77703050 186210 550 S03 $322.00 6 PDX - Portland, OR GEG - Spokane
6 Mark Thies 77703050 186210 550 J01 $812.00 1630 1715
Ecova Board Meeting 77703430 417100 885 F54 $11,352.00
9900111 931111 885 F54 ($11,352.00)
Purpose Ecova Board Meeting PDX - Atlantic 503 331-4200
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Carey car 7/17 pick up at FBD drop off at h
otel. Conf# WA6313474-1. 7/18 pick up at hotel drop off at FBO. Conf# WA6313474-2.
ICNU_DR_240 Attachment A Page 105 of 419
6/8/2015 9:14 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 106 of 419
6/8/2015 9:14 AM
Flight #: AVA072012 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:July Date:20 - 20 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Scott Morris 77705209 426500 550 E01 $5,460.00 1,2,3 Friday July 20 Friday July 20 15 minut
2 Brandi Smith GEG - Spokane PUW - Pullman, WA
3 Dennis Vermillion 645 700
1,2,3 Friday July 20 Friday July 20 6 minute
PUW - Pullman, WA LWS - Lewiston, ID
845 900
1,2,3 Friday July 20 Friday July 20 67 minut
LWS - Lewiston, ID MFR - Medford, OR
1045 1145
1,2,3 Friday July 20 Friday July 20 45 minut
MFR - Medford, OR PSC - Pasco, WA
1330 1425
1,2,3 Friday July 20 Friday July 20 23 minut
PSC - Pasco, WA GEG - Spokane
1600 1615
Purpose Branding Employee Meetings
Remarks Transportation - provided by each office.PSC - Bergstrom Aircraft 509 547-6271
PUW - Interstate Aviation 509-332-6596
***CATERING - Lunch LWS-MFR LWS - Stout Flying Service 208 743-8408
MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139
ICNU_DR_240 Attachment A Page 107 of 419
6/8/2015 9:14 AM
lt Time
tes
es
tes
tes
tes
ICNU_DR_240 Attachment A Page 108 of 419
6/8/2015 9:14 AM
Flight #: AVA072512 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:July Date:25 - 25 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Scott Morris 77705209 426500 550 E01 $1,120.00 1 Wednesday July 25 Wednesday July 25 16 minut
GEG - Spokane MWH - Moses Lake
700 720
1 Wednesday July 25 Wednesday July 25 16 minut
MWH - Moses Lake GEG - Spokane
845 905
Purpose Branding Employee Meetings MWH - Million Air 877-762-0222
GEG - Avista Hangar 509 495-4139
Remarks
ICNU_DR_240 Attachment A Page 109 of 419
6/8/2015 9:14 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 110 of 419
6/8/2015 9:14 AM
Flight #: AVA072612 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:July Date:26 - 26 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Pat Ehrbar 06800545 928000 550 R11 $3,255.00 1,2,3,4 Thursday July 26 Thursday July 26 50 minut
2 Steve Harper GEG - Spokane SLE - Salem
3 Kelly Irvine 745 835
4 Ian McLelland 1,2,3,4 Thursday July 26 Thursday July 26 43 minut
SLE - Salem GEG - Spokane
1130 1215
Purpose Natural Gas Update Meeting w/ Commissioners SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Rental car reserved in Pat's name. Conf# 39
3NFF.
ICNU_DR_240 Attachment A Page 111 of 419
6/8/2015 9:14 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 112 of 419
6/8/2015 9:14 AM
Flight #: AVA072712 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:July Date:27 - 27 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Bruce Folsom 1,2,3,4,5 Friday July 27 Friday July 27 45 minut
2 James Gall 6,7,8 GEG - Spokane OLM - Olympia, WA
3 Linda Gervais 02800540 928000 550 R11 $2,940.00 800 845
4 Lori Hermanson 1,2,3,4,5 Friday July 27 Friday July 27 39 minut
5 Clint Kalich 6,7,8 OLM - Olympia, WA GEG - Spokane
6 Jon Powell 1600 1645
7 Xin Shane
8 David Thompson
Purpose WUTC Meeting re: I-937 Filing OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Van and car reserved. Conf#
ICNU_DR_240 Attachment A Page 113 of 419
6/8/2015 9:14 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 114 of 419
6/8/2015 9:14 AM
Flight #: AVA073012 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Wednesday Month:July Date:30 - 1 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Jim Corder 77705211 186200 550 P09 $16,625.00 1,2,3,4,5 Monday July 30 Monday July 30 103 minu
2 Thomas Heavey 6 GEG - Spokane BJC - Denver, CO
3 Jason Pitts 530 815
4 William Ramshaw 1,2,3,4,5 Monday July 30 Monday July 30 114 minu
5 Jacob Reidt 6 BJC - Denver, CO MDW - Chicago
6 Graham Smith 1630 1920
1,2,3,4,5 Tuesday July 31 Tuesday July 31 81 minut
6 MDW - Chicago TUL - Tulsa, OK
1630 1750
1,2,3,4,5 Wednesday August 1 Wednesday August 1 177 minu
6 TUL - Tulsa, OK GEG - Spokane
1630 1730
Purpose Project Compass Site Visits BJC - Denver Air Center 800-525-8139
MDW - Atlantic Aviation 773-582-5720
Remarks Transportation arrangements made with Carey Car Service. Se
e itinerary for details.TUL - Biz Jet 888-388-4858
GEG - Avista Hangar 509 495-4139
ICNU_DR_240 Attachment A Page 115 of 419
6/8/2015 9:14 AM
lt Time
utes
utes
tes
utes
ICNU_DR_240 Attachment A Page 116 of 419
6/8/2015 9:15 AM
Flight #: AVA080212 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Saturday Month:August Date:2 - 4 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 JoAnne Colwell 1,2,3,4 Thursday August 2 Thursday August 2 26 minut
2 Neil Colwell 77700521 426400 550 B16 $1,855.00 GEG - Spokane GPI - Kalispell
3 Jason Thackston 1500 1620
4 Julie Thackston 1,2,3,4 Saturday August 4 Saturday August 4 27 minut
Montana Governor's Cup 77703430 417100 885 F54 $6,835.41 GPI - Kalispell GEG - Spokane
Montana Governor's Cup 09900111 931111 885 F54 ($6,835.41)1430 1350
Purpose Montana Governor's Cup GPI - Glacier Jet Center 866-353-8322
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Rental car in Neil's name. Conf# R57034
ICNU_DR_240 Attachment A Page 117 of 419
6/8/2015 9:15 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 118 of 419
6/8/2015 9:15 AM
Flight #: AVA080912 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:August Date:9 - 9 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Diane Albers 77705150 183000 550 D51 $602.28 1,2,3,5,6 Thursday August 9 Thursday August 9 65 minut
2 Kevin Booth 77705150 183000 550 E14 $602.28 9 GEG - Spokane LMT - Klamath Falls, OR
3 Bob Hooper 77705150 183000 550 B51 $602.28 700 800
4 Mike Mcmahon 77705150 183000 550 D51 $223.12 1,2,3,4,5 Thursday August 9 Thursday August 9 51 minut
5 Dave Moeller 77705150 183000 550 B51 $602.28 6,7,8,9 LMT - Klamath Falls, OR GEG - Spokane
6 Seth Samsell 77705150 183000 550 B51 $602.28 1400 1455
7 Eric Scott 77705150 183000 550 D51 $223.20
8 Jay Story
9 Jeff Webb 77705150 183000 550 B51 $602.28
Purpose Walk-thru for lateral purchase w/ seller LMT - Oceanics Aviation 541-882-4681
GEG - Avista Hangar 509 495-4139
Remarks Transportation - 1 car reserved in Jeff's name. Conf# MD0809
12WEB.
ICNU_DR_240 Attachment A Page 119 of 419
6/8/2015 9:15 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 120 of 419
6/8/2015 9:15 AM
Flight #: AVA082712 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:August Date:27 - 27 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Liz Andrews 1,2,3,4,5 Monday August 27 Monday August 27 63 minut
2 Pat Ehrbar 6,7,8,9 GEG - Spokane OLM - Olympia, WA
3 Linda Gervais 800 845
4 Bill Johnson 1,2,3,4,5 Monday August 27 Monday August 27 38 minut
5 David Meyer 6,7,8,9 OLM - Olympia, WA GEG - Spokane
6 Kelly Norwood 02805810 928010 550 R11 $3,535.00 1700 1745
7 Jeanne Pluth
8 Karen Schuh
9 Jennifer Smith
Purpose WA General Rate Case Settlement Meeting OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Transportation - 2 car's reserved in Kelly and David's name.
Conf# F5743419402 / F574000003.
ICNU_DR_240 Attachment A Page 121 of 419
6/8/2015 9:15 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 122 of 419
6/8/2015 9:15 AM
Flight #: AVA090412 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Friday Month:September Date:4 - 7 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Marian Durkin 1,2,3,4,5 Tuesday September 4 Tuesday September 4 44 minut
2 Karen Feltes 09900020 930200 550 Y01 $4,221.00 6,8,9 GEG - Spokane OLM - Olympia, WA
3 Lou Fleming 1500 1545
4 Sue Fleming 77705051 417100 550 Y01 $469.00 1,3,4,5,6 Friday September 7 Friday September 7 40 minut
5 Liz Morris 7,8 OLM - Olympia, WA GEG - Spokane
6 Scott Morris 1330 1415
7 Marc Racicot 7 Tuesday September 4 Tuesday September 4 26 minut
8 Mark Thies GEG - Spokane GPI - Kalispell
9 Mark Zakarian 1430 1500
Tuesday September 4 Tuesday September 4 24 minut
GPI - Kalispell GEG - Spokane
1525 1550
Purpose Board of Directors Meeting OLM - Glacier 360-705-3214
GPI - Glacier Jet Center 866-353-8322
Remarks Transportation - Arrangements made by Sue Fleming.
GEG - Avista Hangar 509 495-4139
ICNU_DR_240 Attachment A Page 123 of 419
6/8/2015 9:15 AM
lt Time
tes
tes
tes
tes
ICNU_DR_240 Attachment A Page 124 of 419
6/8/2015 9:15 AM
Flight #: AVA091112 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:September Date:11 - 11 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 David Condon 1,2,3,4,5 Tuesday September 11 Tuesday September 11 43 minut
2 Al French 6 GEG - Spokane BFI - Seattle, WA
3 Rich Hadley 1300 1345
4 Christine Johnson 1,2,3,4,5 Tuesday September 11 Tuesday September 11 33 minut
5 Scott Morris 07770030 426120 550 X01 $2,660.00 6 BFI - Seattle, WA GEG - Spokane
6 Robin Toth 1630 1715
Boeing Meeting 77703430 417100 885 F54 $9,801.72
Boeing Meeting 9900111 931111 885 F54 ($9,801.72)
Purpose Meeting w/ Boeing BFI - Clay Lacy Aviation 800-768-1101
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Executive van reserved with Melnik. Conf# 1
9285 / 19287
ICNU_DR_240 Attachment A Page 125 of 419
6/8/2015 9:15 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 126 of 419
6/8/2015 9:15 AM
Flight #: AVA091212 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Friday Month:September Date:12 - 14 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Liz Morris 1,2 Wednesday September 12 Wednesday September 12 111 minu
2 Scott Morris 09800310 930200 550 X01 $8,050.00 GEG - Spokane COS - Colorado Springs, CO
730 1020
1,2 Friday September 14 Friday September 14 119 minu
COS - Colorado Springs, CO GEG - Spokane
1130 1230
Purpose EEI Board of Directors Meeting COS - Colorado Jetcenter 719-591-2288
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Rental car reserved in Scott's name. Hertz
Conf# SWY4T6.
ICNU_DR_240 Attachment A Page 127 of 419
6/8/2015 9:15 AM
lt Time
utes
utes
ICNU_DR_240 Attachment A Page 128 of 419
6/8/2015 9:15 AM
Flight #: AVA091812 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:September Date:18 - 18 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Linda Jones 09800331 909000 550 S55 $822.50 1,2,3,4,5 Tuesday September 18 Tuesday September 18 66 minut
2 Bob Lafferty 09802202 557000 550 E55 $822.50 6 GEG - Spokane M46 - Colstrip, MT
3 Anna Scarlett 09800331 909000 550 S54 $822.50 715 925
4 Darrell Soyars 09900510 920000 550 E14 $822.50 1,2,3,4,5 Tuesday September 18 Tuesday September 18 75 minut
5 Dave Spannagel 41002100 501200 550 E55 $822.50 6 M46 - Colstrip, MT GEG - Spokane
6 Dick Storro 09802202 557000 550 E55 $822.50 2000 2015
Purpose Colstrip Executive Committee Meeting M46 - Colstrip Airport 406-356-2251
GEG - Avista Hangar 509 495-4139
Remarks Thomas Dempsey will arrange transportation for the passenger
s.
ICNU_DR_240 Attachment A Page 129 of 419
6/8/2015 9:15 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 130 of 419
6/8/2015 9:15 AM
Flight #: AVA092712 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:September Date:27 - 27 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Scott Morris 77700300 426120 550 X01 $2,660.00 1 Thursday September 27 Thursday September 27 43 minut
Innovate Washington BO 77703430 417100 885 F54 $9,801.72 GEG - Spokane SEA - Seattle, WA
Innovate Washington BO 9900111 931111 885 F54 ($9,801.72)1130 1215
1 Thursday September 27 Thursday September 27 33 minut
SEA - Seattle, WA GEG - Spokane
1615 1700
Purpose Innovate Washington Board Meeting SEA - Aircraft Service International G 206-433-5481
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Shuttle service provided by SeaTac FBO.
ICNU_DR_240 Attachment A Page 131 of 419
6/8/2015 9:15 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 132 of 419
6/8/2015 9:15 AM
Flight #: AVA100312 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:October Date:3 - 3 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Liz Andrews 1,2,3,4,5 Wednesday October 3 Wednesday October 3 41 minut
2 Pat Ehrbar 6,7,8,9 GEG - Spokane OLM - Olympia, WA
3 Linda Gervais 730 815
4 Bill Johnson 1,2,3,4,5 Wednesday October 3 Wednesday October 3 39 minut
5 Ronald Mckenzie 6,7,8,9 OLM - Olympia, WA GEG - Spokane
6 David Meyer 1700 1745
7 Kelly Norwood 02805810 928010 550 R11 $3,600.00
8 Karen Schuh
9 Jennifer Smith
Purpose WA General Rate Case Settlement Conference OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Transportation - 2 vehicles reserved in Kelly's and David's
name. Conf#
ICNU_DR_240 Attachment A Page 133 of 419
6/8/2015 9:15 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 134 of 419
6/8/2015 9:16 AM
Flight #: AVA100312a AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:October Date:3 - 3 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Don Kopczynski 09900311 930200 550 D08 $1,912.50 1,2 Wednesday October 3 Wednesday October 3 46 minut
2 Dennis Vermillion 09900311 930200 550 T01 $1,912.50 GEG - Spokane PDX - Portland, OR
1530 1620
1,2 Wednesday October 3 Wednesday October 3 39 minut
PDX - Portland, OR GEG - Spokane
2145 2215
Purpose NWGA CEO Summit PDX - Atlantic 503 331-4220
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Carey Car Service. Conf# WA 6541195-1/2.
ICNU_DR_240 Attachment A Page 135 of 419
6/8/2015 9:16 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 136 of 419
6/8/2015 9:16 AM
Flight #: AVA101612 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:October Date:16 - 16 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Steven Aubuchon 09802457 580000 550 P50 $604.28 1,2,3,4,5 Tuesday October 16 Tuesday October 16 51 minut
2 Bill Burger 09802457 580000 550 B50 $604.28 6,7 GEG - Spokane PDX - Portland, OR
3 Chris Fracz 09802457 580000 550 C51 $604.28 600 650
4 Tim Olson 09802457 580000 550 A50 $604.28 1,2,3,4,5 Tuesday October 16 Tuesday October 16 43 minut
5 Steve Plewman 09802457 580000 550 B50 $604.28 6,7 PDX - Portland, OR GEG - Spokane
6 Jim Rosenlund 09802457 580000 550 L53 $604.28 1700 1745
7 Mark Weiss 09802457 580000 550 C51 $604.32
Purpose BPA testing of proposed guy wire insulator PDX - Atlantic 503 331-4220
GEG - Avista Hangar 509 495-4139
Remarks Transportation - mini van and full size car reserved. Conf#
F6253635618 / F6251398679
ICNU_DR_240 Attachment A Page 137 of 419
6/8/2015 9:16 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 138 of 419
6/8/2015 9:16 AM
Flight #: AVA101712 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:October Date:17 - 17 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Bill Baker 09900546 870000 550 J08 $320.00 2,3,4,5,6 Wednesday October 17 Wednesday October 17 65 minut
2 Kristen Busko 09900165 870000 550 I08 $685.62 7,8,9 GEG - Spokane MFR - Medford, OR
3 Mike Faulkenberry 09900165 870000 550 B51 $685.62 700 805
4 Paul Good 90102455 870000 550 C53 $685.62 1,2,3,4,5 Wednesday October 17 Wednesday October 17 64 minut
5 Jeannette Proctor 09902921 921200 550 H02 $685.62 6,7,8,9 MFR - Medford, OR GEG - Spokane
6 Patty Shea 09902920 921208 550 G02 $685.66 1600 1700
7 Oona Timmons 09902921 921200 550 H02 $685.62
8 Wendy Walker 09902800 921340 550 X02 $685.62
9 Michael Whitby 06802058 300100 550 H08 $685.62
Purpose Gas Delivery Manager's Meeting MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Will be provided by Medford office.
ICNU_DR_240 Attachment A Page 139 of 419
6/8/2015 9:16 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 140 of 419
6/8/2015 9:16 AM
Flight #: AVA102512 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:October Date:25 - 25 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Karen Feltes 1,2,3,4 Thursday October 25 Thursday October 25 18 minut
2 Dan Kolbet GEG - Spokane PUW - Pullman, WA
3 Scott Morris 09900162 921000 550 E01 $7,065.00 930 945
4 Dennis Vermillion 1,2,3,4 Thursday October 25 Thursday October 25 18 minut
PUW - Pullman, WA LWS - Lewiston, ID
1145 1200
1,2,3,4 Thursday October 25 Thursday October 25 54 minut
LWS - Lewiston, ID MFR - Medford, OR
1345 1445
1,2,3,4 Thursday October 25 Thursday October 25 67 minut
MFR - Medford, OR GEG - Spokane
1615 1715
Purpose Employee Meetings PUW - Interstate Aviation 509-332-6596
LWS - Stout Flying Service 208 743-8408
Remarks Transportation provided by the outside offices.
MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139***CATERING - Lunch
ICNU_DR_240 Attachment A Page 141 of 419
6/8/2015 9:16 AM
lt Time
tes
tes
tes
tes
ICNU_DR_240 Attachment A Page 142 of 419
6/8/2015 9:16 AM
Flight #: AVA103112 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:October Date:31 - 31 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Annette Brandon 1,2,3,4 Wednesday October 31 Wednesday October 31 55 minut
2 Pat Ehrbar 06805173 928010 550 R11 $4,365.00 GEG - Spokane SLE - Salem
3 Steve Harper 745 835
4 Kelly Irvine 1,2,3,4 Wednesday October 31 Wednesday October 31 42 minut
SLE - Salem GEG - Spokane
1200 1245
Purpose Oregon PGA Commission Meeting SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Full size car reserved in Pat's name. Conf#
3XC4LC
***CATERING - Lunch SLE-GEG
ICNU_DR_240 Attachment A Page 143 of 419
6/8/2015 9:16 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 144 of 419
6/8/2015 9:16 AM
Flight #: AVA110112 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:November Date:1 - 1 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Bruce Folsom 09903691 930200 550 T52 $527.14 1,3,4,5,6 Thursday November 1 Thursday November 1 46 minut
2 Bruce Howard 09800540 537000 550 A04 $231.43 7,8 GEG - Spokane BFI - Seattle, WA
3 Linda Jones 09805377 909000 550 S54 $632.58 1630 1715
4 Collin Sprague 77700521 426400 550 B16 $295.71 1,2,3,5,6 Wednesday October 31 Wednesday October 31 36 minut
5 Jason Thackston 7,8 BFI - Seattle, WA GEG - Spokane
6 Dennis Vermillion 09903691 930200 550 T01 $527.14 2100 2145
7 Roger Woodworth
8 Jessie Wuerst 77705144 417100 550 S54 $1,476.00
Purpose Green Washington Award Event BFI - Clay Lacy Aviation 800-768-1101
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Melnick car service. Conf# 19651/19652.
***CATERING - Lunch SLE-GEG
ICNU_DR_240 Attachment A Page 145 of 419
6/8/2015 9:16 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 146 of 419
6/8/2015 9:16 AM
Flight #: AVA111012 AVISTA DAILY FLIGHT MANIFEST
Day:Saturday - Tuesday Month:November Date:10 - 13 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Ryan Krasselt 09903370 930200 550 F54 $3,303.00 1,2,3,4,5 Saturday November 10 Saturday November 10 122 minu
2 Jason Lang 09900010 921000 550 Y54 $3,303.00 6 GEG - Spokane SDL - Scottsdale, AZ
3 Scott Morris 09800310 930200 550 X01 $1,098.00 1600 1915
4 Mark Thies 09903691 930200 550 J01 $3,303.00 1,2,4 Tuesday November 13 Tuesday November 13 147 minu
5 Diane Thoren 09903370 930200 550 F54 $1,098.00 SDL - Scottsdale, AZ GEG - Spokane
6 Terry Thoren 1030 1145
Purpose EEI Financial Conference SDL - Landmark Aviation 800-995-5387
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Carey car service 11/10 p/u at FBO drop off
at hotel. Conf# WA6660416-1. 11/14 p/u at hotel drop off at FBO. Conf# WA6660416-2.
ICNU_DR_240 Attachment A Page 147 of 419
6/8/2015 9:16 AM
lt Time
utes
utes
ICNU_DR_240 Attachment A Page 148 of 419
6/8/2015 9:16 AM
Flight #: AVA111612 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:November Date:16 - 16 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Shawn Bonfield 1,2,3,4,5 Friday November 16 Friday November 16 49 minut
2 Renee Coelho 6,7 GEG - Spokane OLM - Olympia, WA
3 Pat Ehrbar 745 830
4 Bruce Folsom 1,2,3,4,5 Friday November 16 Friday November 16 45 minut
5 Linda Gervais 02800545 928000 550 R11 $4,230.00 6,7 OLM - Olympia, WA GEG - Spokane
6 Kelly Irvine 1230 1315
7 Jon Powell
Purpose Mtg w/ Commission Staff re: Natual Gas Conservation OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Rental car reserved in Linda's name. Conf#
F6593723379.
***CATERING - Lunch OLM-GEG
ICNU_DR_240 Attachment A Page 149 of 419
6/8/2015 9:16 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 150 of 419
6/8/2015 9:16 AM
Flight #: AVA112612 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:November Date:26 - 26 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Shawn Bonfield 02800540 928000 550 R11 $1,890.00 1,2,3,5,6 Monday November 26 Monday November 26 47 minut
2 Annette Brandon 02800545 928000 550 R11 $1,890.00 7,8,9 GEG - Spokane OLM - Olympia, WA
3 Jim Corder 845 930
4 Linda Gervais 1,2,3,4,5 Monday November 26 Monday November 26 37 minut
5 Steve Harper 6,7,8,9 OLM - Olympia, WA GEG - Spokane
6 Lori Hermanson 1600 1645
7 Kelly Irvine
8 Jon Powell
9 Clay Storey
Purpose Mtg w/ WUTC re: DSM OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Transportation - mini van and full size car reserved. Conf#
F66642887C4 / F66620431F1
ICNU_DR_240 Attachment A Page 151 of 419
6/8/2015 9:16 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 152 of 419
6/8/2015 9:17 AM
Flight #: AVA112812 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Thursday Month:November Date:28 - 29 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Liz Andrews 1,2,3,4,5 Wednesday November 28 Wednesday November 28 46 minut
2 Pat Ehrbar 7,8 GEG - Spokane OLM - Olympia, WA
3 Karen Feltes 1500 1545
4 Linda Gervais 1,2,3,4,5 Thursday November 29 Thursday November 29 42 minut
5 Wendy Manskey 6,7,8 OLM - Olympia, WA GEG - Spokane
6 David Meyer 1800 1845
7 Kelly Norwood 02805810 928010 550 R11 $3,960.00
8 Jeanne Pluth
Purpose WA General Rate Case Evidentaiary Hearing OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Transportation - 2 minivan's reserved. Conf# Kelly - F672244
72A8 /Pat - F67224501A1.
ICNU_DR_240 Attachment A Page 153 of 419
6/8/2015 9:17 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 154 of 419
6/8/2015 9:17 AM
Flight #: AVA113012 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:November Date:30 - 30 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Dan Kolbet 1,2,3,4,5 Friday November 30 Friday November 30 15 minut
2 Scott Morris 09900162 921000 550 E01 $6,660.00 GEG - Spokane PUW - Pullman, WA
3 Brandi Smith 645 705
4 Dick Storro 1,2,3,4,5 Friday November 30 Friday November 30 8 minute
5 Dennis Vermillion PUW - Pullman, WA LWS - Lewiston, ID
850 910
1,2,3,4,5 Friday November 30 Friday November 30 70 minut
LWS - Lewiston, ID MFR - Medford, OR
1200 1300
1,2,3,4,5 Friday November 30 Friday November 30 55 minut
MFR - Medford, OR GEG - Spokane
1430 1530
Purpose Q4 Employee Meetings PUW - Interstate Aviation 509-332-6596
LWS - Stout Flying Service 208 743-8408
Remarks Transportation provided by each office.
MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139
ICNU_DR_240 Attachment A Page 155 of 419
6/8/2015 9:17 AM
lt Time
tes
es
tes
tes
ICNU_DR_240 Attachment A Page 156 of 419
6/8/2015 9:17 AM
Flight #: AVA120412 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:December Date:4 - 4 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Shawn Bonfield 1,2,3,4,5 Tuesday December 4 Tuesday December 4 59 minut
2 Linda Gervais 02800545 928000 550 R11 $4,635.00 6 GEG - Spokane SLE - Salem
3 Steve Harper 730 820
4 Lori Hermanson 1,2,3,4,5 Tuesday December 4 Tuesday December 4 44 minut
5 Kelly Irvine 6 SLE - Salem GEG - Spokane
6 Jon Powell 1300 1345
Purpose Natural Gas IRP Presentation w/ OPUC SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks Transportation - minivan reserved in Linda's name. Conf# 43
SLT5
ICNU_DR_240 Attachment A Page 157 of 419
6/8/2015 9:17 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 158 of 419
6/8/2015 9:17 AM
Flight #: AVA121012 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:December Date:10 - 10 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 A.L. (Butch) Alford 7 Monday December 10 Monday December 10 25 minut
2 Brooke Cushman GEG - Spokane LWS - Lewiston, ID
3 Tony Fernandez 530 550
4 Gary Picone 1,2,3,4,5 Monday December 10 Monday December 10 143 minu
5 Mike Ripley 6,7 LWS - Lewiston, ID MKC - Kansas City, MO
6 Mike Tatko 77700300 426120 550 F53 $14,078.57 620 1100
7 Jason Thackston 77700300 426120 550 C52 $2,346.43 1,2,3,4,5 Monday December 10 Monday December 10 173 minu
Economic Development 77703430 417100 885 F54 $47,074.05 6,7 MKC - Kansas City, MO LWS - Lewiston, ID
Economic Development 9900111 931111 885 F54 ($47,074.05)1500 1600
7 Monday December 10 Monday December 10 24 minut
LWS - Lewiston, ID GEG - Spokane
1620 1640
Purpose NAIA World Series Bid Presentation MKC - Hanger 10 866-880-6077
LWS - Stout Flying Service 208 743-8408
Remarks No transportation needed
GEG - Avista Hangar 509 495-4139
***CATERING - Breakfast GEG-MKC
***CATERING - Snacks MKC-GEG
ICNU_DR_240 Attachment A Page 159 of 419
6/8/2015 9:17 AM
lt Time
tes
utes
utes
tes
ICNU_DR_240 Attachment A Page 160 of 419
6/8/2015 9:17 AM
Flight #: AVA121112 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:December Date:11 - 11 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 David Meyer 09903691 930200 550 S01 $2,092.50 1,2 Tuesday December 11 Tuesday December 11 56 minut
2 Scott Morris 09903691 930200 550 X01 $2,092.50 GEG - Spokane PDX - Portland, OR
1010 1100
1,2 Tuesday December 11 Tuesday December 11 37 minut
PDX - Portland, OR GEG - Spokane
1445 1530
Purpose Mtg w/ Puget Sound Energy and Pacific Power PDX - Atlantic 503 331-4220
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Carey car p/u at FBO drop off at Pacific Po
wer. 2pm p/u at Pacific Power drop off at FBO. Conf# WA6739050-1/2.
ICNU_DR_240 Attachment A Page 161 of 419
6/8/2015 9:17 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 162 of 419
6/8/2015 9:17 AM
Flight #: AVA121212 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:December Date:12 - 12 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Shawn Bonfield 1,2,3,4,5 Wednesday December 12 Wednesday December 12 46 minut
2 Pat Ehrbar GEG - Spokane SLE - Salem
3 Linda Gervais 06800545 928000 550 R11 $4,410.00 730 820
4 Kelly Irvine 1,2,3,4,5 Wednesday December 12 Wednesday December 12 52 minut
5 Jon Powell SLE - Salem GEG - Spokane
1230 1315
Purpose Oregon PUC Gas Workshop - IRP/DSM SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Minivan reserved in Shawn's name. Conf# 459
Q2B Enterprise.
***CATERING - Lunch SLE-GEG
ICNU_DR_240 Attachment A Page 163 of 419
6/8/2015 9:17 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 164 of 419
6/8/2015 9:17 AM
Flight #: AVA122112 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:December Date:21 - 21 Year: 2012
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Fl
1 Chris Drake 1,2,3,4,5 Friday December 21 Friday December 21 55 minut
2 Pat Ehrbar 02800540 928000 550 R11 $2,025.00 GEG - Spokane OLM - Olympia, WA
3 Bruce Folsom 730 815
4 Linda Gervais 02800545 928000 550 R11 $2,025.00 1,2,3,4,5 Friday December 21 Friday December 21 35 minut
5 Jon Powell OLM - Olympia, WA GEG - Spokane
1230 1315
Purpose UTC Open Meeting re: DSM OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Transportation - mini van reserved in Linda's name. Conf# F6
9304329E2.
***CATERING - Lunch OLM-GEG
ICNU_DR_240 Attachment A Page 165 of 419
6/8/2015 9:17 AM
lt Time
tes
tes
ICNU_DR_240 Attachment A Page 166 of 419
6/8/2015 9:25 AM
Flight #: AVA011413 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:January Date:14 - 14 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09903691 930200 550 X01 $2,432.42 1,2 Monday January 14 Monday January 14 43 minutes
2 Collins (Kevin) Sprague 77700521 426400 550 B16 $2,432.41 GEG - Spokane OLM - Olympia, WA
Legislative 77703430 417100 885 F54 $10,833.48 1330 1415
Legislative 9900111 931111 885 F54 ($10,833.48)1,2 Monday January 14 Monday January 14 41 minutes
OLM - Olympia, WA GEG - Spokane
1645 1730
Purpose Mtg w/ Governor's Chief of Staff OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Transportation - Governor's office is arranging transportati
on.
ICNU_DR_240 Attachment A Page 167 of 419
6/8/2015 9:25 AM
Flight #: AVA011513 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:January Date:15 - 15 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Bruce Folsom 1,2,3,4 Tuesday January 15 Tuesday January 15 44 minutes
2 Linda Gervais GEG - Spokane OLM - Olympia, WA
3 Kelly Norwood 09900540 928000 550 R11 $4,999.83 1130 1215
4 Jon Powell 1,2,3,4 Tuesday January 15 Tuesday January 15 43 minutes
OLM - Olympia, WA GEG - Spokane
1630 1715
Purpose Meetings with David Danner, Commission Jones and Chairman Go OLM - Glacier 360-705-3214ltz
GEG - Avista Hangar 509 495-4139
Remarks Rental vehicle has been reserved in Kelly Norwood's name.
***Need lunch for flight to Olympia
ICNU_DR_240 Attachment A Page 168 of 419
6/8/2015 9:25 AM
Flight #: AVA011713 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:January Date:17 - 17 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Thursday January 17 Thursday January 17 42 minutes
2 Pat Ehrbar 6,7,8,9 GEG - Spokane BOI - Boise, ID
3 Linda Gervais 715 900
4 Bill Johnson 1,2,3,4,5 Thursday January 17 Thursday January 17 49 minutes
5 Tara Knox 6,7,8,9 BOI - Boise, ID GEG - Spokane
6 Bob Lafferty 1630 1615
7 David Meyer
8 Kelly Norwood 03805343 928010 550 R11 $4,095.00
9 Jeanne Pluth
Purpose Idaho GRC Settlement Meeting BOI - Jackson Jet Center 208-383-3300
GEG - Avista Hangar 509 495-4139
Remarks Two rental vans have been reserved in Kelly Norwood's name
***Need to have breakfast on the plane
ICNU_DR_240 Attachment A Page 169 of 419
6/8/2015 9:25 AM
Flight #: AVA012313 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:January Date:23 - 23 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3 Wednesday January 23 Wednesday January 23 55 minutes
2 Ryan Krasselt GEG - Spokane SLE - Salem
3 David Meyer 06800545 928000 550 R11 $4,410.00 745 835
1,2,3 Wednesday January 23 Wednesday January 23 43 minutes
SLE - Salem GEG - Spokane
1630 1720
Purpose Investigation Into Treatment of Pension Costs in Utility Rat SLE - Salem Air Center 503 364-4158es - Workshop
GEG - Avista Hangar 509 495-4139
Remarks One Rental Vehicle reserved by Patty Hanson - confirmation #
4CX22B
ICNU_DR_240 Attachment A Page 170 of 419
6/8/2015 9:25 AM
Flight #: AVA012413 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:January Date:24 - 24 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Thursday January 24 Thursday January 24 41 minutes
2 Pat Ehrbar 6,7,8,9 GEG - Spokane BOI - Boise, ID
3 Linda Gervais 715 900
4 Bill Johnson 1,2,3,4,5 Thursday January 24 Thursday January 24 52 minutes
5 Tara Knox 6,7,8,9 BOI - Boise, ID GEG - Spokane
6 Bob Lafferty 1630 1615
7 David Meyer
8 Kelly Norwood 03805343 928010 550 R11 $4,185.00
9 Jeanne Pluth
Purpose Idaho GRC Settlement Meeting BOI - Jackson Jet Center 208-383-3300
GEG - Avista Hangar 509 495-4139
Remarks Two rental vans have been reserved in Kelly Norwood's name
***Need to have breakfast on the plane
ICNU_DR_240 Attachment A Page 171 of 419
6/8/2015 9:25 AM
Flight #: AVA012913 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:January Date:29 - 29 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Pat Lynch 1,2,3,4,5 Tuesday January 29 Tuesday January 29 64 minutes
2 Chuck Milani 6 GEG - Spokane MFR - Medford, OR
3 Jody Morehouse 1630 1735
4 Scott Morris 09903691 990200 550 X01 $6,210.00 1,2,3,4,5 Tuesday January 29 Tuesday January 29 74 minutes
5 Neil Thorson 6 MFR - Medford, OR GEG - Spokane
6 Roger Woodworth 2030 2135
Purpose Retirement Party for Several Avista Employees in Medford MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139
Remarks Sue will arrange transportation
ICNU_DR_240 Attachment A Page 172 of 419
6/8/2015 9:25 AM
Flight #: AVA013013 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:January Date:30 - 30 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 06800545 928000 550 R11 $4,455.00 1,2,3,4 Wednesday January 30 Wednesday January 30 51 minutes
2 Ryan Finesilver GEG - Spokane SLE - Salem
3 Ryan Krasselt 745 835
4 Damien Lysiak 1,2,3,4 Wednesday January 30 Wednesday January 30 48 minutes
SLE - Salem GEG - Spokane
1630 1720
Purpose Invetigation into Treatment of Pension Costs in Utility Rate SLE - Salem Air Center 503 364-4158s - Workshop
GEG - Avista Hangar 509 495-4139
Remarks One rental vehicle has been reserved by Patty Hanson - Confi
rmation#4CX526
ICNU_DR_240 Attachment A Page 173 of 419
6/8/2015 9:25 AM
Flight #: AVA020413 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Wednesday Month:February Date:4 - 6 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shane Brandon 4,5 Monday February 4 Monday February 4 151 minutes
2 Pat Ehrbar GEG - Spokane MSN - Madison, WI
3 Linda Gervais 09905328 928000 550 R11 $6,907.50 1330 1800
4 Scott Morris 09903691 930200 550 X01 $12,127.50 4,5 Monday February 4 Monday February 4 81 minutes
5 Collins (Kevin) Sprague 77700521 426400 550 B16 $5,220.00 MSN - Madison, WI IAD - Washington, DC
1830 2100
1,2,3,4 Wednesday February 6 Wednesday February 6 108 minutes
IAD - Washington, DC MSN - Madison, WI
1330 1400
1,2,3,4 Wednesday February 6 Wednesday February 6 199 minutes
MSN - Madison, WI GEG - Spokane
1430 1500
Purpose AGA Meetings MSN - Wisconsin Aviation - Madiso 608-268-5000
IAD - Landmark 703-661-0150
Remarks A Carey Sedan will pick up Scott and Collins on Feb 4.
Confirmation #WA6869814-1. A Carey SUV will pick up Pat, Linda GEG - Avista Hangar 509 495-4139and Shane from the Renaissance Hotel on Feb 6, then pick up Scott
at AGA before heading to Dulles. Confirmation #WA6869814-2
ICNU_DR_240 Attachment A Page 174 of 419
6/8/2015 9:25 AM
Flight #: AVA022713 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:February Date:27 - 27 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 9900162 921000 550 S20 1,2,3 Wednesday February 27 Wednesday February 27
2 Jason Lang 9900010 921000 550 Y54 GEG - Spokane BFI - Seattle, WA
3 Mark Thies 9903691 930200 550 J01 745 830
1,2,3 Wednesday February 27 Wednesday February 27
BFI - Seattle, WA GEG - Spokane
1500 1545
Purpose Meeting with McAdams Wright Ragen Investor Meetings BFI - Clay Lacy Aviation 800-768-1101
GEG - Avista Hangar 509-495-4139
Remarks Carey Car has been reserved - confirmation #WA6940551-001
Need breakfast from GEG to BFI
ICNU_DR_240 Attachment A Page 175 of 419
6/8/2015 9:26 AM
Flight #: AVA022813 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:February Date:28 - 28 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 David Condon 1,2,3,4,5 Thursday February 28 Thursday February 28
2 Paul Fletcher 6,7 GEG - Spokane BLV - Belleville, IL
3 Rich Hadley 530 1030
4 Todd Mielke 1,2,3,4,5 Thursday February 28 Thursday February 28
5 Scott Morris 9903691 930200 550 X01 6,7 BLV - Belleville, IL GEG - Spokane
6 Bill Savitz 1400 1600
7 Bill Simer
Purpose GSI Visit with Air Mobilty Command BLV - AVMATS Mid America 618 566-5320
GEG - Avista Hangar 509 495-4139
Remarks AMC will provide van transportation
***Will need breakfast from GEG to BLV
Bill Simer - 994-0950 cell
Rich Hadley - 953-8845
David Condon - 710-9400
Todd Mielke - 220-2200
Bill Savitz - 953-9622
Paul Fletcher - 434-4720
Scott Morris - 979-6698
ICNU_DR_240 Attachment A Page 176 of 419
6/8/2015 9:26 AM
Flight #: AVA030513 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Wednesday Month:March Date:5 - 6 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 09900162 921000 550 S20 $5,520.00 1,2,3 Tuesday March 5 Tuesday March 5 170
2 Jason Lang 09900010 921000 550 Y54 $5,520.00 GEG - Spokane DAL - Dallas, TX
3 Mark Thies 09903691 930200 550 J01 $5,520.00 800 1330
1,2,3 Wednesday March 6 Wednesday March 6 198
DAL - Dallas, TX GEG - Spokane
1500 1630
Purpose Meeting with UBS - Investor Conference DAL - Business Jet Center 888 387-7477
GEG - Avista Hangar 509 495-4139
Remarks Carey Car reserved - confirmation #WA6956199
Breakfast needed from GEG to DAL
ICNU_DR_240 Attachment A Page 177 of 419
6/8/2015 9:26 AM
Flight #: AVA030813 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:March Date:8 - 8 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Karen Feltes 1,2,3,4 Friday March 8 Friday March 8 13 minutes
2 Dan Kolbet GEG - Spokane PUW - Pullman, WA
3 Scott Morris 9903691 930200 550 X01 $6,480.00 640 700
4 Dennis Vermillion 1,2,3,4 Friday March 8 Friday March 8 8 minutes
PUW - Pullman, WA LWS - Lewiston, ID
850 910
1,2,3,4 Friday March 8 Friday March 8 59 minutes
LWS - Lewiston, ID MFR - Medford, OR
1200 1300
1,2,3,4 Friday March 8 Friday March 8 64 minutes
MFR - Medford, OR GEG - Spokane
1500 1600
Purpose Employee Meetings
Remarks Transportation provided by each office
ICNU_DR_240 Attachment A Page 178 of 419
6/8/2015 9:26 AM
Flight #: AVA031113 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:March Date:11 - 11 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Ryan Finesilver 1,2,3,4 Monday March 11 Monday March 11 54 minutes
2 Ryan Krasselt GEG - Spokane SLE - Salem
3 Damien Lysiak 1200 1250
4 David Meyer 06800545 928000 550 R11 $4,410.00 1,2,3,4 Monday March 11 Monday March 11 44 minutes
SLE - Salem GEG - Spokane
1630 1715
Purpose Investigation Into Treatment of Pension Costs in Utility Rates
UM1633 Workshop
Remarks One Rental Vehicle reserved by Patty Hanson - confirmation #4LKSH3
***Need lunch from GEG to SLE
ICNU_DR_240 Attachment A Page 179 of 419
6/8/2015 9:26 AM
Flight #: AVA031313 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:March Date:13 - 13 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4 Wednesday March 13 Wednesday March 13 49 minutes
2 Jim Corder GEG - Spokane SLE - Salem
3 Linda Gervais 06800545 928000 550 R11 $4,095.00 1200 1250
4 Clay Storey 1,2,3,4 Wednesday March 13 Wednesday March 13 42 minutes
SLE - Salem GEG - Spokane
1600 1645
Purpose Oregon Commission Cyber Security Update
Remarks Rental Car reserved in the name of Linda Gervais.
Confirmation #4APF75-S-Enterprise
***Need lunch from GEG to SLE
ICNU_DR_240 Attachment A Page 180 of 419
6/8/2015 9:26 AM
Flight #: AVA031413 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:March Date:14 - 14 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 David Meyer 1,2,3,4,5 Thursday March 14 Thursday March 14 51 minutes
2 Scott Morris GEG - Spokane SLE - Salem
3 Kelly Norwood 06800545 928000 550 R11 $4,140.00 730 815
4 Mark Thies 1,2,3,4,5 Thursday March 14 Thursday March 14 41 minutes
5 Dennis Vermillion SLE - Salem GEG - Spokane
1230 1320
Purpose Annual Update Meetings with Commissioners
Remarks One Rental vehicle reserved by Patty Hanson Confirmation # 4KTMX3
***Need lunch from SLE to GEG
ICNU_DR_240 Attachment A Page 181 of 419
6/8/2015 9:26 AM
Flight #: AVA031813 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Friday Month:March Date:18 - 22 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Dana Anderson 09900330 930200 550 S54 $1,305.00 2,3,4 Monday March 18 Monday March 18 123 minutes
2 Kevin Christie 09900162 921000 550 S20 $10,065.00 GEG - Spokane LNK - Lincoln, Nebraska
3 Jason Lang 09900010 921000 550 Y54 $10,065.00 800 1200
4 Mark Thies 09903691 930200 550 J01 $10,065.00 2,3,4 Monday March 18 Monday March 18 139 minutes
LNK - Lincoln, Nebraska TEB - New York
1230 1600
2,3,4 Wednesday March 20 Wednesday March 20 172 minutes
TEB - New York SLN - Salina, KS
1115 1315
2,3,4 Wednesday March 20 Wednesday March 20 150 minutes
SLN - Salina, KS LAS - Las Vegas, NV
1345 1400
1,2,3,4 Friday March 22 Friday March 22 116 minutes
LAS - Las Vegas, NV GEG - Spokane
1200 1400
Purpose Sidoti & Co. Forum and West Coast Seminar Investor Conference
Remarks Karen Eastwood reserved Carey Car - Confirmation No. WA6995645
***Need breakfast from GEG to LNK
***Need lunch from LNK to TEB
***Need lunch from SLN to LAS
***Need lunch from LAS to GEG
ICNU_DR_240 Attachment A Page 182 of 419
6/8/2015 9:26 AM
Flight #: AVA040413 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:April Date:4 - 4 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Lisa Brown 1,2,3,5,6 Thursday April 4 Thursday April 4 49 minutes
2 David Condon 7 GEG - Spokane OLM - Olympia, WA
3 Elaine Couture 800 845
4 Elson Floyd 2,3,4,5,6 Thursday April 4 Thursday April 4 45 minutes
5 Rich Hadley OLM - Olympia, WA PUW - Pullman, WA
6 Scott Morris 77700300 426400 550 X01 $5,500.00 1430 1530
7 Shelly OQuinn 2,3,5,6 Thursday April 4 Thursday April 4 16 minutes
PUW - Pullman, WA GEG - Spokane
1535 1550
Purpose Meetings with Governor Inslee and various legislators OLM - Glacier 360-705-3214
PUW - Interstate Aviation 509-332-6596
Remarks A Melnik Limousine van has been reserved in Scott's name
Confirmation #20982 GEG - Avista Hangar 509 495-4139
***Need breakfast from GEG to OLM
ICNU_DR_240 Attachment A Page 183 of 419
6/8/2015 9:26 AM
Flight #: AVA040413a AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Friday Month:April Date:4 - 5 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Christy Burmeister-smith 77703430 417120 550 J01 $9,200.00 1,2,3,4,5 Thursday April 4 Thursday April 4 100 minutes
2 Tom Lienhard GEG - Spokane UKI - Ukiah, CA
3 Kelly Magalsky 1615 1800
4 Mark Thies 1,2,3,4,5 Friday April 5 Friday April 5 84 minutes
5 Roger Woodworth UKI - Ukiah, CA GEG - Spokane
1300 1415
Purpose Visit AVA subsidiary, METALfx in Willits, CA UKI - Municipal Airport - City of 707-467-2817
GEG - Avista Hangar 509 495-4139
Remarks Hertz rental Suburban in Mark Thies' name waiting on flight
line. Keys with David, the fuel guy. Fuel area is open until7:30 p.m. David's cell number is 707-272-5515. Confirmation #F7924522046
***Lunch from UKI to GEG
ICNU_DR_240 Attachment A Page 184 of 419
6/8/2015 9:27 AM
Flight #: AVA040913 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:April Date:9 - 9 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 03805343 928010 550 R11 $4,200.00 1,2,3,4 Tuesday April 9 Tuesday April 9 37 minutes
2 Kevin Christie GEG - Spokane BOI - Boise, ID
3 Paul Kimball 700 845
4 Ryan Krasselt 1,2,3,4 Tuesday April 9 Tuesday April 9 47 minutes
GEG - Spokane BOI - Boise, ID
700 845
Purpose Financial Update Meeting with Staff BOI - Jackson Jet Center 208-383-3300
GEG - Avista Hangar 509-495-4139
Remarks 1 Rental vehicle reserved by Patty Hanson
Confirmation #4TG2QX
ICNU_DR_240 Attachment A Page 185 of 419
6/8/2015 9:27 AM
Flight #: AVA041613 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Wednesday Month:April Date:16 - 17 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09900311 930200 550 X01 $6,125.00 1,2 Tuesday April 16 Tuesday April 16 117 minutes
2 Jason Thackston 09802202 557000 550 E55 $6,125.00 GEG - Spokane BUR - Burbank, CA
1600 1810
1,2 Wednesday April 17 Wednesday April 17 128 minutes
BUR - Burbank, CA GEG - Spokane
1600 1805
Purpose Fuels Reduction/Biomass Energy Executive Leadership Meeting BUR - Million Air 818-843-8311
GEG - Avista Hangar 509 495-4139
Remarks Carey Car reserved for pick up at the FBO to the Hilton
Confirmation #WA7082612-001. Carey also reserved for pickup at the Convention center on Wednesday for return to the FBO
Confirmation #WA7082612-002
ICNU_DR_240 Attachment A Page 186 of 419
6/8/2015 9:27 AM
Flight #: AVA041913 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:April Date:19 - 19 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Marty Dickinson 1,2,3 Friday April 19 Friday April 19 39 minutes
2 Rich Hadley GEG - Spokane BFI - Seattle, WA
3 Scott Morris 77700300 426120 550 X01 $3,900.00 700 745
1,2,3 Friday April 19 Friday April 19 39 minutes
BFI - Seattle, WA GEG - Spokane
1030 1110
Purpose Meeting with Dr. Paul Ramsey, UW School of Medicine BFI - Clay Lacy Aviation 800-768-1101
GEG - Avista Hangar 509 495-4139
Remarks Carey Sedan has been reserved - confirmation #WA7093750.
***Need breakfast from GEG to BFI
ICNU_DR_240 Attachment A Page 187 of 419
6/8/2015 9:27 AM
Flight #: AVA042313 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:April Date:23 - 23 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4,5 Tuesday April 23 Tuesday April 23 46 minutes
2 Annette Brandon 6,7 GEG - Spokane SLE - Salem
3 Kevin Christie 745 835
4 Pat Ehrbar 06800545 928000 550 R11 $4,600.00 1,2,3,4,5 Tuesday April 23 Tuesday April 23 46 minutes
5 Steve Harper 6,7 SLE - Salem GEG - Spokane
6 Kelly Irvine 1530 1615
7 Ryan Krasselt
Purpose Financial Update Meeting with Staff, IRP/DSM Meeting with Co SLE - Salem Air Center 503 364-4158mmissioners, and PGA
GEG - Avista Hangar 509 495-4139
Remarks Patty Hanson has set up 2 rental cars: Confirmation #4TG6Y3
(Pat Ehrbar) Confirmation #4VT8Y6 (Kevin Christie)
ICNU_DR_240 Attachment A Page 188 of 419
6/8/2015 9:27 AM
Flight #: AVA042513 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:April Date:25 - 25 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 David Meyer 1,2,3 Thursday April 25 Thursday April 25 40 minutes
2 Scott Morris 02800540 928000 550 X01 $1,900.00 GEG - Spokane BFI - Seattle, WA
3 Kelly Norwood 02800540 928000 550 R11 $1,900.00 900 945
1,2,3 Thursday April 25 Thursday April 25 36 minutes
BFI - Seattle, WA BFI - Seattle, WA
1500 1540
Purpose Regulatory Meeting with PSE and Pacific Power BFI - Clay Lacy Aviation 800-768-1101
GEG - Avista Hangar 509-495-4139
Remarks Carey Car has been reserved. Confirmation #WA7107884-001
and WA7107884-002
ICNU_DR_240 Attachment A Page 189 of 419
6/8/2015 9:27 AM
Flight #: AVA042613 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:April Date:26 - 26 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09900020 930200 550 X01 $3,750.00 1 Friday April 26 Friday April 26 41 minutes
GEG - Spokane BFI - Seattle, WA
900 945
1 Friday April 26 Friday April 26 34 minutes
BFI - Seattle, WA GEG - Spokane
1430 1510
Purpose Inerview with Board Member Candidate BFI - Clay Lacy Aviation 800-768-1101
GEG - Avista Hangar 509-495-4139
Remarks Carey Car has been reserved - Confirmation #WA7107884-003
and WA7107959-001
ICNU_DR_240 Attachment A Page 190 of 419
6/8/2015 9:27 AM
Flight #: AVA050413 AVISTA DAILY FLIGHT MANIFEST
Day:Saturday - Tuesday Month:May Date:4 - 7 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 9900162 921000 550 S20 $11,602.50 1,2,3,5 Saturday May 4 Saturday May 4 149 minutes
2 Jason Lang 9900010 921000 550 Y54 $11,602.50 GEG - Spokane SLN - Salina, KS
3 Liz Morris 900 1300
4 Scott Morris 09900311 930200 550 E01 $5,037.50 1,2,3,5 Saturday May 4 Saturday May 4 154 minutes
5 Mark Thies 9903691 930200 550 J01 $11,602.50 SLN - Salina, KS APF - Naples, FL
1330 1730
1,2,3,4,5 Tuesday May 7 Tuesday May 7 168 minutes
APF - Naples, FL SLN - Salina, KS
1030 1300
1,2,3,4,5 Tuesday May 7 Tuesday May 7 142 minutes
SLN - Salina, KS GEG - Spokane
1330 1330
Purpose Annual AGA Financial Forum APF - Naples Jet Center 239-649-7900
SLN - America Jet 785-825-6261
Remarks Carey Car has been reserved. Confirmation #WA7114336-001 and
#WA7114336-002 GEG - Avista Hangar 509 495-4139
***Need breakfast from GEG to SLN
***Need lunch from SLN to GEG
ICNU_DR_240 Attachment A Page 191 of 419
6/8/2015 9:27 AM
Flight #: AVA050813 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:May Date:8 - 8 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Annette Brandon 1,2,3,4,5 Wednesday May 8 Wednesday May 8 50 minutes
2 Pat Ehrbar 06805173 928010 550 R11 $6,500.00 GEG - Spokane SLE - Salem
3 Ryan Finesilver 800 850
4 Steve Harper 1,2,3,4,5 Wednesday May 8 Wednesday May 8 50 minutes
5 Kelly Irvine SLE - Salem GEG - Spokane
1300 1345
Purpose Oregon PGA SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks A car has been reserved. Confirmation #4QMBFW
***Need Lunch from SLE to GEG
ICNU_DR_240 Attachment A Page 192 of 419
6/8/2015 9:27 AM
Flight #: AVA050913 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:May Date:9 - 9 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4 Thursday May 9 Thursday May 9 43 minutes
2 Pat Ehrbar GEG - Spokane OLM - Olympia, WA
3 David Meyer 800 845
4 Kelly Norwood 02800540 928000 550 R11 $5,265.00 1,2,3,4 Thursday May 9 Thursday May 9 38 minutes
OLM - Olympia, WA GEG - Spokane
1230 1315
Purpose BPA/Reardan Petition on WUTC Agenda OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks 1 vehicle reserved by Patty Hanson - Confirmation #F83209597A7
***Need lunch from OLM to GEG
ICNU_DR_240 Attachment A Page 193 of 419
6/8/2015 9:28 AM
Flight #: AVA051613 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:May Date:16 - 16 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Mark Baker 2,4,5,6 Thursday May 16 Thursday May 16 44 minutes
2 Chris Drake GEG - Spokane PDX - Portland, OR
3 Bruce Folsom 945 1035
4 Linda Gervais 09800544 928000 550 R11 $5,395.00 1,2,3,4,5 Thursday May 16 Thursday May 16 39 minutes
5 Lori Hermanson 6,7,8,9 PDX - Portland, OR GEG - Spokane
6 Pat Lynch 1630 1715
7 Jon Powell
8 Jason Thackston
9 David Thompson
Purpose WA/ID DSM Advisory Group Meeting PDX - Atlantic 503 331-4220
GEG - Avista Hangar 509 495-4139
Remarks Car reserved by Wendy Manskey - Confirmation #F8392866723
ICNU_DR_240 Attachment A Page 194 of 419
6/8/2015 9:28 AM
Flight #: AVA051713 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:May Date:17 - 17 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jim Kensok 1,2,3,4 Friday May 17 Friday May 17 60 minutes
2 Scott Morris 09900162 921000 550 E01 $9,100.00 GEG - Spokane MFR - Medford, OR
3 Brandi Smith 645 750
4 Dennis Vermillion 1,2,3,4,Friday May 17 Friday May 17 56 minutes
5 MFR - Medford, OR PUW - Pullman, WA
930 1030
1,2,3,4 Friday May 17 Friday May 17 7 minutes
PUW - Pullman, WA LWS - Lewiston, ID
1300 1315
1,2,3,4 Friday May 17 Friday May 17 17 minutes
LWS - Lewiston, ID GEG - Spokane
1450 1510
Purpose Q2 Employee Meetings PUW - Interstate Aviation 509-332-6596
LWS - Stout Flying Service 208 743-8408
Remarks Transportation provided by outside offices
MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139***Need breakfast from GEG to MFR
ICNU_DR_240 Attachment A Page 195 of 419
6/8/2015 9:28 AM
Flight #: AVA052913 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:May Date:29 - 29 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09900020 930200 550 E01 $5,330.00 1 Wednesday May 29 Wednesday May 29 40 minutes
GEG - Spokane BOI - Boise, ID
945 1130
1 Wednesday May 29 Wednesday May 29 42 minutes
BOI - Boise, ID GEG - Spokane
1400 1345
Purpose Interview witth Potential Board Member, Steve Hanks BOI - Jackson Jet Center 208-383-3300
GEG - Avista Hangar 509 495-4139
Remarks Steve Hanks will pick Scott up at the FBO and take him to the
Arid Club for lunch
ICNU_DR_240 Attachment A Page 196 of 419
6/8/2015 9:28 AM
Flight #: AVA053013 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:May Date:30 - 30 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09900020 930200 550 E01 $15,730.00 1 Thursday May 30 Thursday May 30 119 minutes
GEG - Spokane, WA BUR - Burbank, CA
1115 1325
1 Thursday May 30 Thursday May 30 123 minutes
BUR - Burbank, CA GEG - Spokane, WA
1630 1805
Purpose Interview with potential Board Member - Daniel Batrack BUR - Million Air 818-843-8311
GEG - Avista Hangar 509-495-4139
Remarks Carey Car reserved by Sue Fleming - Confirmation #WA7206977-001
and WA7206977-002 (Carey Car will pick Scott up at Tetra
Tech at 4:00 p.m. for the return flight.)
ICNU_DR_240 Attachment A Page 197 of 419
6/8/2015 9:28 AM
Flight #: AVA053113 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:May Date:31 - 31 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 David Meyer 02800545 928000 550 R11 $1,229.80 1,2,3,4,5 Friday May 31 Friday May 31 45 minutes
2 Scott Morris GEG - Spokane OLM - Olympia, WA
3 Kelly Norwood 02800540 928000 550 R11 $4,360.20 730 815
4 Mark Thies 1,2,3,4,5 Friday May 31 Friday May 31 41 minutes
5 Dennis Vermillion GEG - Spokane OLM - Olympia, WA
730 815
Purpose Annual Update Meeting with WUTC Commissioners OLM - Glacier 360-705-3214
GEG - Avista Hangar 509-495-4139
Remarks One Vehicle Reserved by Patty Hanson in Kelly Norwood's name
Confirmation #F8420046362
ICNU_DR_240 Attachment A Page 198 of 419
6/8/2015 9:28 AM
Flight #: AVA060813 AVISTA DAILY FLIGHT MANIFEST
Day:Saturday - Wednesday Month:June Date:8 - 12 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Marian Durkin 1,2,3,4,5 Saturday June 8 Saturday June 8 100 minutes
2 Terry Durkin 6,7 GEG - Spokane OAK - Oakland
3 Karen Feltes 1600 1745
4 Bruce Howard 1,2,3,4,7 Wednesday June 12 Wednesday June 12 82 minutes
5 Liz Morris OAK - Oakland GEG - Spokane
6 Scott Morris 9800310 930200 550 E01 $11,830.00 1100 1245
7 Mark Zakarian
Purpose EEI Annual Conference OAK - Business Jet Center 866-383-5669
GEG - Avista Hangar 509 495-4139
Remarks Carey car has been reserved in Marian's name for pickup on
both dates. Confirmation #WA7207022-001 and WA7207022-002(Carey car will be at the hotel on June 12 at 10:30 a.m. for the return to the airport.)
ICNU_DR_240 Attachment A Page 199 of 419
6/8/2015 9:28 AM
Flight #: AVA061313 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:June Date:13 - 13 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4 Thursday June 13 Thursday June 13 41 minutes
2 Pat Ehrbar GEG - Spokane OLM - Olympia, WA
3 Linda Gervais 1200 1245
4 David Meyer 09900540 928000 550 R11 $5,135.00 1,2,3,4 Thursday June 13 Thursday June 13 38 minutes
OLM - Olympia, WA GEG - Spokane
1500 1545
Purpose Interconnection Rulemaking - Adoption Hearing OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks One vehicle reserved by Patty Hanson for Linda Gervais - Con
firmation #F86702095E4
***Need lunch from GEG to OLM
ICNU_DR_240 Attachment A Page 200 of 419
6/8/2015 9:28 AM
Flight #: AVA061713 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Wednesday Month:June Date:17 - 19 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 09900162 921000 550 S20 $5,806.67 1,2,3,4,5 Monday June 17 Monday June 17 113 minutes
2 Ryan Krasselt 09903370 930200 550 F54 $5,806.67 6 GEG - Spokane FAR - Fargo
3 Scott Morris 09903691 930200 550 E01 $5,806.67 615 1009
4 Kelly Norwood 09900540 928000 550 R11 $5,806.67 1,2,3,4,5 Monday June 17 Monday June 17 136 minutes
5 Mark Thies 09903691 930200 550 J01 $5,806.66 6 FAR - Fargo TEB - New York
6 Dennis Vermillion 09903691 930200 550 T01 $5,806.66 1039 1357
1,2,3,4,5 Wednesday June 19 Wednesday June 19 162 minutes
6 TEB - New York FAR - Fargo
900 1042
1,2,3,4,5 Wednesday June 19 Wednesday June 19 125 minutes
6 FAR - Fargo GEG - Spokane
1112 1124
Purpose Rating Agency Meetings TEB - Meridian Air 201 288-5040
FAR - Fargo Jet Center 800 770-0538
Remarks Carey Car reserved in Mark's name- Confirmation #WA247032-00
1 & WA247032-002 GEG - Avista Hangar 509 495-4139
***Need Breakfast from GEG to FAR
***Need lunch from FAR to TEB
***Need lunch from FAR to GEG
ICNU_DR_240 Attachment A Page 201 of 419
6/8/2015 9:28 AM
Flight #: AVA062513 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:June Date:25 - 25 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Marian Durkin 77703430 417120 550 P01 $12,545.00 1 Tuesday June 25 Tuesday June 25 105 minutes
GEG - Spokane OAK - Oakland
530 720
1 Tuesday June 25 Tuesday June 25 88 minutes
OAK - Oakland GEG - Spokane
1700 1845
Purpose Mediation Hearing for Avista Energy OAK - Business Jet Center 866-383-5669
GEG - Avista Hangar 509 495-4139
Remarks Carey Car to pick Marian up at Landmark Aviation. Confirmat
ion #WA7301324-1
***Need breakfast from GEG to OAK
***Need dinner from OAK to GEG
ICNU_DR_240 Attachment A Page 202 of 419
6/8/2015 9:29 AM
Flight #: AVA062713 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:June Date:27 - 27 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 09900310 930200 550 S20 $2,957.50 1,2 Thursday June 27 Thursday June 27 54 minutes
2 Mark Thies 09900310 930200 550 E01 $2,957.50 GEG - Spokane PDX - Portland, OR
930 1020
1,2 Thursday June 27 Thursday June 27 37 minutes
PDX - Portland, OR PDX - Portland, OR
2100 2145
Purpose Meeting with Jim Lobdell - CFO of PGE PDX - Atlantic 503 331-4220
GEG - Avista Hangar 509 495-4139
Remarks Hertz rental car has been reserved in Mark's name
confirmation #F8622610A8.
ICNU_DR_240 Attachment A Page 203 of 419
6/8/2015 9:29 AM
Flight #: AVA070913 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:July Date:9 - 9 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jim Kensok 1,2,3,4,5 Tuesday July 9 Tuesday July 9 42 minutes
2 David Meyer 03800545 928000 550 R11 $1,131.00 6 GEG - Spokane BOI - Boise, ID
3 Scott Morris 630 815
4 Kelly Norwood 03800540 928000 550 R11 $4,524.00 1,2,3,4,5 Tuesday July 9 Tuesday July 9 45 minutes
5 Mark Thies 6 BOI - Boise, ID GEG - Spokane
6 Dennis Vermillion 1300 1245
Purpose Annual Update Meeting with IPUC Commissioners and Cyber Security BOI - Jackson Jet Center 208-383-3300Update Meeting
GEG - Avista Hangar 509 495-4139
Remarks Two full sized cars have been reserved for Kelly Confirmation
#F8484707345 & David Meyer Confirmation #F88409633A1
***Breakfast needed from GEG to BOI
***Need lunch from BOI to GEG
ICNU_DR_240 Attachment A Page 204 of 419
6/8/2015 9:29 AM
Flight #: AVA071513 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:July Date:15 - 15 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 06805169 928010 550 R11 $1,527.50 1,2,3,4 Monday July 15 Monday July 15 50 minutes
2 Annette Brandon 06800545 928010 550 R11 $1,527.50 GEG - Spokane SLE - Salem
3 Pat Ehrbar 06805169 928010 550 R11 $1,527.50 800 850
4 Jeanne Pluth 06805169 928010 550 R11 $1,527.50 1,2,3,4 Monday July 15 Monday July 15 44 minutes
SLE - Salem GEG - Spokane
1200 1250
Purpose Oregon Natural Gas update - GRC Allocation Meetings SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks Mini van reserved in Pat Ehrbar's name, Confirmation #5FCY3G
ICNU_DR_240 Attachment A Page 205 of 419
6/8/2015 9:29 AM
Flight #: AVA071613 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:July Date:16 - 16 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 77705228 426500 550 S20 $899.16 1,2,3,4,5 Tuesday July 16 Tuesday July 16 42 minutes
2 Marian Durkin 77705228 426500 550 E01 $899.17 6 GEG - Spokane BFI - Seattle, WA
3 Don Kopczynski 77705228 426500 550 E01 $899.16 645 730
4 Mark Thies 77705228 426500 550 E01 $899.17 1,2,3,4,5 Tuesday July 16 Tuesday July 16 41 minutes
5 Dennis Vermillion 77705228 426500 550 E01 $899.17 6 BFI - Seattle, WA GEG - Spokane
6 Roger Woodworth 77705228 426500 550 M54 $899.17 1500 1540
Purpose Meeting for Project Chinook BFI - Clay Lacy Aviation 800-768-1101
GEG - Avista Hangar 509 495-4139
Remarks A 10 passenger van has been reserved from Melnik. It will be
waiting at the FBO by 7:30. It is reserved under Mark Thies'name. Confirmation #22278 The same van will pick up from lunch (TBD) and return to the FBO at 2:30 pm. Confirmation #22279
***Need breakfast from GEG to BFI
ICNU_DR_240 Attachment A Page 206 of 419
6/8/2015 9:29 AM
Flight #: AVA071813 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:July Date:18 - 18 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Annette Brandon 1,2,3,4 Thursday July 18 Thursday July 18 51 minutes
2 Pat Ehrbar 06800545 928000 550 R11 $6,240.00 GEG - Spokane SLE - Salem
3 Kelly Irvine 1135 1225
4 Andrew Scull 1,2,3,4 Thursday July 18 Thursday July 18 45 minutes
SLE - Salem GEG - Spokane
1500 1545
Purpose Natural Gas Outlook Meeting for Commissioners SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks Rental vehicle in Pat's name - reserved by Patty Hanson
Confirmation #55R0DN
***Need lunch from GEG to SLE - Annette Brandon is allergic to gluten and has to eat a gluten-free diet.
Please provide her with a salad (no croutons) and viniagrette dressing on the side.
ICNU_DR_240 Attachment A Page 207 of 419
6/8/2015 9:29 AM
Flight #: AVA072313 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:July Date:23 - 23 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Britt Bachtel-Browning 09903691 930200 550 U01 $1,200.95 1,2,3,4,5 Tuesday July 23 Tuesday July 23 64 minutes
2 Terry Bushnell 09902800 921000 550 X02 $1,200.95 6,7 GEG - Spokane MFR - Medford, OR
3 Amanda Fisk 09903410 92100 550 L51 $1,200.95 700 800
4 David Howell 0990016 870000 550 G08 $594.30 1,2,3,5,6 Tuesday July 23 Tuesday July 23 56 minutes
5 Stephanie Myers 09905733 921010 550 N09 $1,200.95 7 MFR - Medford, OR GEG - Spokane
6 Andrea Pike 09905690 921000 550 W09 $1,200.95 1600 1700
7 Wendy Walker 09902800 921000 550 X02 $1,200.95
Purpose Medford Trip MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139
Remarks
ICNU_DR_240 Attachment A Page 208 of 419
6/8/2015 9:29 AM
Flight #: AVA072613 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:July Date:26 - 26 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4 Friday July 26 Friday July 26
2 James Gall GEG - Spokane OLM - Olympia, WA 41 minutes
3 Linda Gervais 02800540 928000 550 R11 745 830
4 Clint Kalich 1,2,3 Friday July 26 Friday July 26
OLM - Olympia, WA GEG - Spokane 40 minutes
1300 1345
Purpose WUTC Open Meeting Re:I937 Renewables OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Hertz Rental Car has been reserved in Linda's name
Confirmation #F90609295F3
***Need lunch from OLM to GEG
ICNU_DR_240 Attachment A Page 209 of 419
6/8/2015 9:29 AM
Flight #: AVA073013 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:July Date:30 - 30 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4 Tuesday July 30 Tuesday July 30 43 minutes
2 Kevin Christie GEG - Spokane OLM - Olympia, WA
3 Pat Ehrbar 02800540 928000 550 R11 $5,200.00 730 815
4 Ryan Krasselt 1,2,3,4 Tuesday July 30 Tuesday July 30 37 minutes
OLM - Olympia, WA GEG - Spokane
1100 1145
Purpose Finance Update Meeting to WUTC OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Rental vehicle in Pat's name reserved by Patty Hanson
Confirmation #F8903165515
ICNU_DR_240 Attachment A Page 210 of 419
6/8/2015 9:29 AM
Flight #: AVA081313 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Wednesday Month:August Date:13 - 14 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 77705228 426500 550 S20 $19,250.00 1,2,3,4,5 Tuesday August 13 Tuesday August 13 141 minutes
2 Thomas Dempsey 6,7,8,10 GEG - Spokane JNU - Juneau
3 Mike Gonnella 800 930
4 John Hamill 1,2,3,4,5 Wednesday August 14 Wednesday August 14 134 minutes
5 Bruce Howard 7,8,9,10 JNU - Juneau GEG - Spokane
6 Don Kopczynski 1200 1530
7 Darrell Soyars
8 Ken Sweigart
9 Dennis Vermillion
10 Andy Vickers
Project Chinook 77703430 417120 885 F54 $36,289.00
Project Chinook 9900111 931111 885 F54 ($36,289.00)
Purpose Project Chinook JNU - Alaska Aero Services 907-789-0055
GEG - Avista Hangar 509 495-4139
Remarks Karen Eastwood has reserved two vans for ground transportation
***Need breakfast from GEG to JNU
***Need lunch from JNU to GEG
ICNU_DR_240 Attachment A Page 211 of 419
6/8/2015 9:30 AM
Flight #: AVA082013 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:August Date:20 - 20 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4 Tuesday August 20 Tuesday August 20 42 minutes
2 Jennifer Esch GEG - Spokane OLM - Olympia, WA
3 Linda Gervais 02800540 928000 550 R11 $5,670.00 1200 1245
4 Janna Leaf 1,2,3,4 Tuesday August 20 Tuesday August 20 39 minutes
OLM - Olympia, WA GEG - Spokane
1700 1745
Purpose WUTC Consumer Meeting OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Hertz Rental Car in Linda's name - confirmation #F93412702A2
***Need lunch from GEG to OLM
ICNU_DR_240 Attachment A Page 212 of 419
6/8/2015 9:30 AM
Flight #: AVA082113 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:August Date:21 - 21 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Linda Gervais 02800540 928000 550 R11 $5,530.00 1,2,3 Wednesday August 21 Wednesday August 21 42 minutes
2 Larry Labolle GEG - Spokane OLM - Olympia, WA
3 David Meyer 800 845
1,2,3 Wednesday August 21 Wednesday August 21 37 minutes
OLM - Olympia, WA GEG - Spokane
1600 1645
Purpose Workshop Re: Procedural Rules Revisions OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Rental vehicle in Linda's name, Confirmation #F8810033840
No Catering is Required
ICNU_DR_240 Attachment A Page 213 of 419
6/8/2015 9:30 AM
Flight #: AVA082213 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:August Date:22 - 22 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Dave Robinson 9900110 935000 550 L54 $6,300.00 1 Thursday August 22 Thursday August 22 90 minutes
GEG - Spokane SMF - Sacramento, CA
730 900
Purpose Maintenance - no passengers SMF - Cessna Service Center 800-845-6317
GEG- Avista Hangar 509-495-4139
Remarks
ICNU_DR_240 Attachment A Page 214 of 419
6/8/2015 9:30 AM
Flight #: AVA090813 AVISTA DAILY FLIGHT MANIFEST
Day:Sunday - Sunday Month:September Date:8 - 8 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Dave Robinson 09900110 935000 550 L54 $6,300.00 1 Sunday September 8 Sunday September 8 90 minutes
SMF - Sacramento, CA GEG - Spokane
1030 1200
Purpose Aircraft Maintenance GEG - Avista Hangar 509 495-4139
Remarks
ICNU_DR_240 Attachment A Page 215 of 419
6/8/2015 9:30 AM
Flight #: AVA091013 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Thursday Month:September Date:10 - 12 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Morris 1,2,3,4 Tuesday September 10 Tuesday September 10 117 minutes
2 Scott Morris 09800310 930200 550 E01 $15,680.00 GEG - Spokane COS - Colorado Springs, CO
3 Jason Thackston 1030 1330
4 Julie Thackston 1,2,3,4 Thursday September 12 Thursday September 12 107 minutes
COS - Colorado Springs, CO GEG - Spokane
1230 1430
Purpose EEI Conference COS - Colorado Jetcenter 719-591-2288
GEG - Avista Hangar 509 495-4139
Remarks A Carey SUV has been reserved
Confirmation Numbers WA7483851-1 and WA7483851-2
***Need lunch from GEG to COS
ICNU_DR_240 Attachment A Page 216 of 419
6/8/2015 9:30 AM
Flight #: AVA091813 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:September Date:18 - 18 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4 Wednesday September 18 Wednesday September 18 46 minutes
2 Pat Ehrbar GEG - Spokane SLE - Salem
3 David Meyer 1145 1240
4 Kelly Norwood 06800545 928000 550 R11 $6,370.00 3,4 Wednesday September 18 Wednesday September 18 45 minutes
SLE - Salem GEG - Spokane
1700 1800
Purpose Oregon GRC Pre-hearing Conference SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks One vehichle has been rented in Pat Ehrbar's name
Confirmation #5V2K03
***Need lunch from GEG to SLE
ICNU_DR_240 Attachment A Page 217 of 419
6/8/2015 9:30 AM
Flight #: AVA092013 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:September Date:20 - 20 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09900162 921000 550 E01 $9,380.00 1,2,3,4 Friday September 20 Friday September 20 66 minutes
2 Brandi Smith GEG - Spokane MFR - Medford, OR
3 Jason Thackston 645 750
4 Dennis Vermillion 1,2,3,4 Friday September 20 Friday September 20 48 minutes
MFR - Medford, OR LWS - Lewiston, ID
930 1030
1,2,3,4 Friday September 20 Friday September 20 8 minutes
LWS - Lewiston, ID PUW - Pullman, WA
1230 1245
1,2,3,4 Friday September 20 Friday September 20 12 minutes
PUW - Pullman, WA GEG - Spokane
1545 1610
Purpose Employee Meetings LWS - Stout Flying Service 208 743-8408
PUW - Interstate Aviation 509-332-6596
Remarks Transportation provided by outside offices
MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139***Need breakfast from GEG to MFR
ICNU_DR_240 Attachment A Page 218 of 419
6/8/2015 9:30 AM
Flight #: AVA092313 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:September Date:23 - 23 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 0685169 928010 550 R11 $7,140.00 1,2,3,4,5 Monday September 23 Monday September 23 55 minutes
2 Shawn Bonfield 6 GEG - Spokane SLE - Salem
3 Pat Ehrbar 800 850
4 Lauren Pendergraft 1,2,3,4,5 Monday September 23 Monday September 23 47 minutes
5 Karen Schuh 6 SLE - Salem GEG - Spokane
6 Jennifer Smith 1600 1645
Purpose Oregon GRC Discussions SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks Van reserved in Pat Ehrbar's Name - Confirmation #F9590310841
ICNU_DR_240 Attachment A Page 219 of 419
6/8/2015 9:30 AM
Flight #: AVA092413 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:September Date:24 - 24 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Catherine Bryan 1,2,3,4,5 Tuesday September 24 Tuesday September 24 68 minutes
2 Steve Harper 6 GEG - Spokane MFR - Medford, OR
3 Kelly Irvine 930 1040
4 Marc Schaffner 1,2,3,4,5 Tuesday September 24 Tuesday September 24 56 minutes
5 Eric Scott 6 MFR - Medford, OR GEG - Spokane
6 Jason Thackston 09900311 930200 550 E55 $8,680.00 1600 1710
Purpose Oregon Utility Industrial Customer Meeting MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139
Remarks No cars or meals required
***No Car or Meals Required
ICNU_DR_240 Attachment A Page 220 of 419
6/8/2015 9:31 AM
Flight #: AVA100213 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:October Date:2 - 2 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 1,2,3 Wednesday October 2 Wednesday October 2 41 minutes
2 Jason Thackston GEG - Spokane BFI - Seattle, WA
3 Dennis Vermillion 09900311 930200 550 T01 $5,460.00 1630 1715
1,2,3 Wednesday October 2 Wednesday October 2 37 minutes
BFI - Seattle, WA GEG - Spokane
2100 2200
Purpose NWGA Fourth Annual CEO Summit - Seattle, WA BFI - Clay Lacy Aviation 800-768-1101
GEG - Avista Hangar 509 495-4139
Remarks Plane will land and park at the museum. No car service needed
ICNU_DR_240 Attachment A Page 221 of 419
6/8/2015 9:31 AM
Flight #: AVA100413 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:October Date:4 - 4 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Todd Bryan 03800545 928000 550 R11 $1,904.00 1,2,3,4,5 Friday October 4 Friday October 4 39 minutes
2 Pat Ehrbar 03800545 928000 550 R11 $1,904.00 GEG - Spokane BOI - Boise, ID
3 Steve Harper 02800545 928000 550 R11 $1,904.00 630 815
4 Kelly Irvine 02800545 928000 550 R11 $1,904.00 1,2,3,4,5 Friday October 4 Friday October 4 59 minutes
5 Lauren Pendergraft 02800545 928000 550 R11 $1,904.00 BOI - Boise, ID OLM - Olympia, WA
1200 1200
1,2,3,4,5 Friday October 4 Friday October 4 38 minutes
OLM - Olympia, WA GEG - Spokane
1530 1615
Purpose Natural Gas Procurement Planning Update Meetings BOI - Jackson Jet Center 208-383-3300
OLM - Glacier 360-705-3214
Remarks A rental van has been reserved in Pat Ehrbar's name, reserved
by Patty Hanson - Confirmation #F9624462704 (Boise) and GEG - Avista Hangar 509 495-4139#F9624866039 (Olympia)
ICNU_DR_240 Attachment A Page 222 of 419
6/8/2015 9:31 AM
Flight #: AVA101013 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:October Date:10 - 10 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Annette Brandon 1,2,3,4,5 Thursday October 10 Thursday October 10 47 minutes
2 Todd Bryan GEG - Spokane SLE - Salem
3 Pat Ehrbar 06800545 928000 550 R11 $6,720.00 1130 1220
4 Steve Harper 1,2,3,4,5 Thursday October 10 Thursday October 10 49 minutes
5 Kelly Irvine SLE - Salem GEG - Spokane
1530 1615
Purpose Oregon Quarterly Update Mtg/Procurement Plan Discussion SLE - Salem Air Center 503 364-4158Natural Gas
GEG - Avista Hangar 509 495-4139
Remarks Rental Car has been reserved in Pat Ehrbar's name. Reserved
by Patty Hanson - Confirmation #5ZB0JB
******Need lunch from GEG to SLE - Annette Brandon and Kelly Irvine both need gluten-free lunches.
Please provide them with a salad (no croutons) and viniagrette dressing on the side.
ICNU_DR_240 Attachment A Page 223 of 419
6/8/2015 9:31 AM
Flight #: AVA101313 AVISTA DAILY FLIGHT MANIFEST
Day:Sunday - Wednesday Month:October Date:13 - 16 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Mike Allen 1,2,3,4,5 Sunday October 13 Sunday October 13 130 minutes
2 Patrick Bisson 6,7,8,9 GEG - Spokane LNK - Lincoln, Nebraska
3 Jennifer DeJean 800 1130
4 Jessica Gilmore 1,2,3,4,5 Sunday October 13 Sunday October 13 128 minutes
5 Diana Osborne 6,7,8,9 LNK - Lincoln, Nebraska CLT - Charlotte
6 Larry Sullivan 1200 1500
7 Steve Trabun 77705205 426120 550 M53 $37,380.00 1,2,3,4,5 Wednesday October 16 Wednesday October 16 131 minutes
8 Jeffrey Waybright 6,7,8,9 CLT - Charlotte LNK - Lincoln, Nebraska
9 Casey Wilhelm 1300 1400
1,2,3,4,5 Wednesday October 16 Wednesday October 16 145 minutes
6,7,8,9 LNK - Lincoln, Nebraska GEG - Spokane
1430 1500
Purpose National Association for Community Colleges In Entrepreneurship LNK - Silverhawk Aviation 800-479-58512013 Annual Conference
CLT - Signature Flight Support 704 359-8415
Remarks A GroundLink 14-passenger van has been reserved for both days
Confirmation Nos. 4345716 (10/13) and 4345736 (10/16). GEG - Avista Hangar 509 495-4139If you are going to be late for the reservation on either leg of the trip, please call GroundLink at 877-227-7260 to let them know.
***Need breakfast from GEG to LNK
***Need lunch from LNK to CLT
***Need lunch from CLT to LNK
ICNU_DR_240 Attachment A Page 224 of 419
6/8/2015 9:31 AM
Flight #: AVA101713 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Friday Month:October Date:17 - 18 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Christy Burmeister-smith 77703430 417120 550 E01 $11,480.00 1,2,3,4,5 Thursday October 17 Thursday October 17 78 minutes
2 Kevin Christie 6,7 GEG - Spokane UKI - Ukiah, CA
3 Marian Durkin 930 1045
4 Don Falkner 1,2,3,4,5 Friday October 18 Friday October 18 86 minutes
5 Adam Munson 6,7 UKI - Ukiah, CA GEG - Spokane
6 Mark Thies 900 1015
7 Dennis Vermillion
Purpose Visit AVA subsidiary, METALfx in Willits, CA UKI - Municipal Airport 707-467-2817
GEG - Avista Hangar 509 495-4139
Remarks Hertz rental Suburban in Mark Thies' name waiting in parking
lot. Keys will be in the office. Confirmation #F98137651A3
ICNU_DR_240 Attachment A Page 225 of 419
6/8/2015 9:31 AM
Flight #: AVA102313 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Thursday Month:October Date:23 - 24 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Mitch Cornwell 95601100 300100 550 B50 $1,286.25 1,2,3,4,5 Wednesday October 23 Wednesday October 23 74 minutes
2 Joshua Diluciano 95601100 300100 550 Z08 $1,286.25 6,7,8 GEG - Spokane SLC - Salt Lake City, UT
3 Jennifer Esch 95601100 300100 550 F50 $1,286.25 600 830
4 David Howell 95601100 300100 550 B51 $1,286.25 1,2,3,4,5 Thursday October 24 Thursday October 24 73 minutes
5 Erika Jacobs 95601100 300100 550 C08 $1,286.25 6,7,8 SLC - Salt Lake City, UT GEG - Spokane
6 Kelly Magalsky 95601100 300100 550 B08 $1,286.25 1700 1730
7 Lamont Miles 95601100 300100 550 A50 $1,286.25
8 Eric Rosentrater 95601100 300100 550 B50 $1,286.25
Purpose Company Systems and Process Improvement SLC - Tac Air 801-359-2085
GEG - Avista Hangar 509 495-4139
Remarks Enterprise Rent-a-car - Reserved by Debbie Butler
Confirmation #786231907 & 786232075
ICNU_DR_240 Attachment A Page 226 of 419
6/8/2015 9:31 AM
Flight #: AVA102813 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:October Date:28 - 28 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Annette Brandon 06800545 928000 550 R11 $548.00 1,2,3,4,5 Monday October 28 Monday October 28 47 minutes
2 Kelly Irvine 06800545 928000 550 R11 $548.00 6 GEG - Spokane PDX - Portland, OR
3 David Meyer 02800540 928000 550 R11 $1,336.00 1030 1120
4 Scott Morris 02800540 928000 550 R11 $1,336.00 3,4,5,6 Monday October 28 Monday October 28 45 minutes
5 Kelly Norwood 02800540 928000 550 R11 $1,336.00 PDX - Portland, OR GEG - Spokane
6 Collins (Kevin) Sprague 02800540 928000 550 B16 $1,336.00 1430 1520
Purpose Regulatory Meeting PDX - Atlantic 503 331-4220
GEG - Avista Hangar 509 495-4139
Remarks Cary Car has been reserved to take David, Scott, Kelly Norwood
and Collins to the meeting - confirmation #WA7644051-1 andWA7644051-2 for the return. A rental car is being reserved for Annette and Kelly Irvine
ICNU_DR_240 Attachment A Page 227 of 419
6/8/2015 9:31 AM
Flight #: AVA110213 AVISTA DAILY FLIGHT MANIFEST
Day:Saturday - Saturday Month:November Date:2 - 2 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Pat Lynch 1,2,3,4,5 Saturday November 2 Saturday November 2
2 Chuck Milani 6,7 GEG - Spokane PSC - Pasco, WA 52 minutes
3 Marcia Milani 1045 1200
4 Jody Morehouse Intended destination was LMT - Klamath Falls, OR
5 Scott Morris 09900162 921000 550 E01 $3,640.00 Due to a Maintenance issue, the flight landed at
6 Sharmon Schmitt PSC - Pasco, WA and terminated there
7 Neil Thorson
Purpose Employee Funeral Service - Kris Ransom LMT - Oceanics Aviation 541-882-4681
GEG - Avista Hangar 509 495-4139
Remarks Steve Vincent and Victor Bautista will meet you at the Klamath
Falls airport and take your group to and from the serviceDue to a maintenance issue with the airplane, this flight landed in Pasco, WA.
The Passengers returned to Spokane in rental cars.
ICNU_DR_240 Attachment A Page 228 of 419
6/8/2015 9:31 AM
Flight #: AVA110313 AVISTA DAILY FLIGHT MANIFEST
Day:Sunday - Sunday Month:November Date:3 - 3 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Richard Stanford 9900110 935000 550 L54 $1,960.00 1 Sunday November 3 Sunday November 3 28 minutes
PSC - Pasco, WA GEG - Spokane
1600 1630
Purpose Maintenance test and reposition flight to Spokane GEG - Avista Hangar 509 495-4139
Remarks
ICNU_DR_240 Attachment A Page 229 of 419
6/8/2015 9:32 AM
Flight #: AVA110513 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:November Date:5 - 5 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Bruce Cergl 77700232 163000 550 J51 $1,268.00 1,3,5,6,7 Tuesday November 5 Tuesday November 5 29 minutes
2 Randy Daniels 77700242 107060 550 V08 $894.00 8,9 GEG - Spokane LWS - Lewiston, ID
3 Gary Knight 11005217 107610 550 H07 $1,268.00 730 745
4 Matthew Mullineaux 09905690 921000 550 A81 $591.00 1,2,3,5,6 Tuesday November 5 Tuesday November 5 58 minutes
5 Barry Pasicznyk 11005217 107610 550 H07 $1,268.00 7,8,9 LWS - Lewiston, ID MFR - Medford, OR
6 Rod Price 77700242 107060 550 V08 $1,268.00 800 915
7 Steve Rose 09905730 921010 550 E09 $1,268.00 1,2,3,4,5 Tuesday November 5 Tuesday November 5 57 minutes
8 Darrell Soyars 09902811 926102 550 E14 $1,268.00 6,7,8,9 MFR - Medford, OR LWS - Lewiston, ID
9 April Spacek 11005217 107610 550 H07 $1,268.00 1600 1715
1,3,4,5,6 Tuesday November 5 Tuesday November 5 19 minutes
7,8,9 LWS - Lewiston, ID GEG - Spokane
1730 1745
Purpose IT Site Visit/Spokane Renovation Project LWS - Stout Flying Service 208 743-8408
MFR - Jet Center 541-770-5314
Remarks April has rented a car.
GEG - Avista Hangar 509 495-4139
ICNU_DR_240 Attachment A Page 230 of 419
6/8/2015 9:32 AM
Flight #: AVA110613 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:November Date:6 - 6 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09903691 930200 550 E01 $3,115.00 1,2 Wednesday November 6 Wednesday November 6 47 minutes
2 Kelly Norwood 09900540 928000 550 R11 $3,115.00 GEG - Spokane OLM - Olympia, WA
930 1030
1,2 Wednesday November 6 Wednesday November 6 42 minutes
OLM - Olympia, WA GEG - Spokane
1230 1330
Purpose Meeting with Dave Danner - Discussion on Thermal Resources OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks One rental vehicle reserved in Kelly Norwood's name - reserved
by Patty Hanson - Confirmation # G00802280D4
***Need lunch from OLM to GEG
ICNU_DR_240 Attachment A Page 231 of 419
6/8/2015 9:32 AM
Flight #: AVA110713 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:November Date:7 - 7 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jim Corder 1,2,3,4 Thursday November 7 Thursday November 7 51 minutes
2 Pat Ehrbar 02800545 928000 550 R11 $3,220.00 GEG - Spokane OLM - Olympia, WA
3 Linda Gervais 1200 1245
4 Clay Storey 1,2,3,4 Thursday November 7 Thursday November 7 41 minutes
OLM - Olympia, WA GEG - Spokane
1630 1715
Purpose Cyber Workshop OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Hertz Rental Car in Pat's name confirmation number G0143935982
***Need lunch from GEG to OLM
ICNU_DR_240 Attachment A Page 232 of 419
6/8/2015 9:32 AM
Flight #: AVA110913 AVISTA DAILY FLIGHT MANIFEST
Day:Saturday - Wednesday Month:November Date:9 - 13 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 09900162 921000 550 S20 $8,386.00 1,2,3,4,5 Saturday November 9 Saturday November 9 129 minutes
2 Ryan Krasselt 09903370 930200 550 F54 $8,386.00 GEG - Spokane SLN - Salina, KS
3 Jason Lang 09900010 921000 550 Y54 $8,386.00 900 1330
4 Mark Thies 09903691 930200 550 J01 $8,386.00 1,2,3,4,5 Saturday November 9 Saturday November 9 138 minutes
5 Dennis Vermillion 09800310 930200 550 E01 $8,386.00 SLN - Salina, KS MCO - Orlando, FL
1400 1730
1,2,3,4,5 Wednesday November 13 Wednesday November 13 170 minutes
MCO - Orlando, FL SLN - Salina, KS
930 1100
1,2,3,4,5 Wednesday November 13 Wednesday November 13 162 minutes
SLN - Salina, KS GEG - Spokane
1130 1200
Purpose EEI Financial Conference MCO - Galaxy Aviation 800-704-4147
SLN - America Jet 785-825-6261
Remarks Carey car has been reserved by Karen Eastwood
GEG - Avista Hangar 509 495-4139
***Need lunch from SLN to MCO
***Need lunch from SLN to GEG
ICNU_DR_240 Attachment A Page 233 of 419
6/8/2015 9:32 AM
Flight #: AVA111413 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:November Date:14 - 14 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Larry Labolle 1,2,3 Thursday November 14 Thursday November 14 47 minutes
2 David Meyer GEG - Spokane OLM - Olympia, WA
3 Kelly Norwood 02800540 928000 550 R11 $6,160.00 800 845
1,2,3 Thursday November 14 Thursday November 14 41 minutes
OLM - Olympia, WA GEG - Spokane
1400 1445
Purpose Energy Rate Case and IRP Procedures Workshop OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Rental car in Kelly's Name - reserved by Patty Hanson
Confirmation #F96230709A4
ICNU_DR_240 Attachment A Page 234 of 419
6/8/2015 9:32 AM
Flight #: AVA111713 AVISTA DAILY FLIGHT MANIFEST
Day:Sunday - Tuesday Month:November Date:17 - 19 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 1,2,3 Sunday November 17 Sunday November 17 110 minutes
2 Richard Stevens 09903410 921000 550 R54 $40,180.00 GEG - Spokane FAR - Fargo
3 Mark Thies 600 1000
1,2,3 Sunday November 17 Tuesday November 19 143 minutes
FAR - Fargo TEB - New York
1030 1400
1,2,3 Tuesday November 19 Tuesday November 19 182 minutes
TEB - New York FAR - Fargo
930 1100
1,2,3 Tuesday November 19 Tuesday November 19 139 minutes
FAR - Fargo GEG - Spokane
1130 1145
Purpose D&O Insurance Meetings TEB - Meridian Air 201 288-5040
FAR - Fargo Jet Center 800 770-0538
Remarks 11/17/13 - Carey of New York pickup from Teterboro Airport.
Confirmation #WA-7703396-1, under Mark Thies. GEG - Avista Hangar 509 495-413911/19/13 - Carey car pickup from Millenium Hilton. Pickup at 8:30 am, Confirmation #WA-7703396-2, under Mark Thies.
***Need breakfast from GEG to FAR
***Need lunch from FAR to TEB
***Need lunch from FAR to GEG
ICNU_DR_240 Attachment A Page 235 of 419
6/8/2015 9:32 AM
Flight #: AVA112113 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:November Date:21 - 21 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Thursday November 21 Thursday November 21 46 minutes
2 Pat Ehrbar 6,7,8 GEG - Spokane SLE - Salem
3 Grant Forsyth 800 850
4 David Meyer 06800545 928000 550 R11 $6,650.00 1,2,3,4,5 Thursday November 21 Thursday November 21 49 minutes
5 Joe Miller 6,7,8 SLE - Salem GEG - Spokane
6 Jeanne Pluth 1700 1745
7 Karen Schuh
8 Jennifer Smith
Purpose Oregon Initial Settlement Conference SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks Two minivans have been reserved by Patty Hanson - Pat Ehrbar
Confirmation #6C3Y2L and David Meyer Confirmation #6C406C
ICNU_DR_240 Attachment A Page 236 of 419
6/8/2015 9:32 AM
Flight #: AVA112213 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:November Date:22 - 22 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Brandi Smith 1,2,3,4 Friday November 22 Friday November 22 15 minutes
2 Mark Thies GEG - Spokane LWS - Lewiston, ID
3 Dennis Vermillion 09900162 921000 550 E01 $9,590.00 640 700
4 Roger Woodworth 1,2,3,4 Friday November 22 Friday November 22 7 minutes
LWS - Lewiston, ID PUW - Pullman, WA
850 910
1,2,3,4 Friday November 22 Friday November 22 52 minutes
PUW - Pullman, WA MFR - Medford, OR
1045 1145
1,2,3,4 Friday November 22 Friday November 22 63 minutes
MFR - Medford, OR GEG - Spokane
1430 1530
Purpose Employee Meetings LWS - Stout Flying Service 208 743-8408
PUW - Interstate Aviation 509-332-6596
Remarks Transportation provided by each office
MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139***Need breakfast from GEG to LWS
ICNU_DR_240 Attachment A Page 237 of 419
6/8/2015 9:33 AM
Flight #: AVA112613 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:November Date:26 - 26 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Tuesday November 26 Tuesday November 26 60 minutes
2 Pat Ehrbar 6,7,8,8 GEG - Spokane SLE - Salem
3 David Meyer 06800545 928000 550 R11 $7,070.00 815 905
4 Joe Miller 1,2,3,4,5 Tuesday November 26 Tuesday November 26 41 minutes
5 Kelly Norwood 6,7,8,8 SLE - Salem GEG - Spokane
6 Jeanne Pluth 1700 1745
7 Karen Schuh
8 Jennifer Smith
Purpose Oregon Settlement Conference SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks Two minivans have been reserved by Patty Hanson - Pat Ehrbar
Confirmation #6C3Y5D and David Meyer Confirmation #6C41B6
ICNU_DR_240 Attachment A Page 238 of 419
6/8/2015 9:33 AM
Flight #: AVA120213 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Thursday Month:December Date:2 - 5 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Christy Burmeister-smith 09902811 926102 550 G54 $1,660.00 1,2,3,4,5 Monday December 2 Monday December 2 166 minutes
2 Don Falkner 09902811 926101 550 C54 $1,660.00 6,7,8 GEG - Spokane MDW - Chicago
3 Jason Lang 09900010 921000 550 Y54 $17,515.00 800 1300
4 Adam Munson 09902811 926101 550 D54 $1,660.00 3,5,6 Monday December 2 Monday December 2 92 minutes
5 Linda Robinson MDW - Chicago TEB - New York
6 Mark Thies 09903691 930200 550 J01 $17,515.00 1330 1600
7 Tracy Van orden 09902811 926101 550 J54 $1,660.00 3,5,6 Thursday December 5 Thursday December 5 190 minutes
8 John Wilcox 09902811 926101 550 Y55 $1,660.00 TEB - New York FAR - Fargo
1000 1200
3,5,6 Thursday December 5 Thursday December 5 171 minutes
FAR - Fargo GEG - Spokane
1230 1245
Purpose NY Utility Week TEB - Meridian Air 201 288-5040
MDW - Atlantic Aviation 773-582-5720
Remarks A Carey car has been reserved for the group in Teterboro under
Mark's name. A Carey van has been reserved for the FAR - Fargo Jet Center 800 770-0538 group in Chicago under Christy's name.GEG - Avista Hangar 509 495-4139***Need breakfast from GEG to MDW
***Need lunch from MDW to TEB
***Need lunch from FAR to GEG
ICNU_DR_240 Attachment A Page 239 of 419
6/8/2015 9:33 AM
Flight #: AVA120913 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Wednesday Month:December Date:9 - 11 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Jason Lang 09900010 921000 550 Y54 $20,860.00 1,2 Monday December 9 Monday December 9 114 minutes
2 Mark Thies 09903691 930200 550 J01 $20,860.00 GEG - Spokane FAR - Fargo
800 1145
1,2 Monday December 9 Monday December 9 163 minutes
FAR - Fargo TEB - New York
1215 1530
1,2 Wednesday December 11 Wednesday December 11 182 minutes
TEB - New York FAR - Fargo
1000 1145
1,2 Wednesday December 11 Wednesday December 11 137 minutes
FAR - Fargo GEG - Spokane
1215 1230
Purpose Annual KeyBank Conference TEB - Meridian Air 201 288-5040
FAR - Fargo Jet Center 800 770-0538
Remarks Ground transportation will be provided
GEG - Avista Hangar 509 495-4139
***Need Breakfast from GEG to FAR
***Need Lunch from FAR to TEB
***Need Lunch from FAR to GEG
ICNU_DR_240 Attachment A Page 240 of 419
6/8/2015 9:33 AM
Flight #: AVA121213 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:December Date:12 - 12 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Annette Brandon 1,2,3,4 Thursday December 12 Thursday December 12 55 minutes
2 Pat Ehrbar 06800545 928000 550 R11 $6,720.00 GEG - Spokane SLE - Salem
3 Kelly Fukai 800 850
4 Steve Harper 1,2,3,4 Thursday December 12 Thursday December 12 41 minutes
SLE - Salem GEG - Spokane
1300 1345
Purpose OPUC Natural Gas Workshop w/Commissioners 6GZG2X SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks Rental Car in Pat's name - reserved by Patty Hanson
ICNU_DR_240 Attachment A Page 241 of 419
6/8/2015 9:33 AM
Flight #: AVA121813 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:December Date:18 - 18 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Bruce Folsom 1,2,3,4,5 Wednesday December 18 Wednesday December 18 49 minutes
2 Linda Gervais 02800540 928000 550 R11 $5,950.00 GEG - Spokane OLM - Olympia, WA
3 Lori Hermanson 730 815
4 Jon Powell 1,2,3,4,5 Wednesday December 18 Wednesday December 18 36 minutes
5 David Thompson OLM - Olympia, WA GEG - Spokane
1600 1645
Purpose Meeting with WUTC I-937 Biennial Conservation Report OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Mini van in Linda's name: G0453359790
ICNU_DR_240 Attachment A Page 242 of 419
6/8/2015 9:33 AM
Flight #: AVA121913 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:December Date:19 - 19 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09900020 930200 550 E01 $19,040.00 1 Thursday December 19 Thursday December 19 115 minutes
GEG - Spokane LGB - Long Beach, CA
1145 1400
1 Thursday December 19 Thursday December 19 157 minutes
LGB - Long Beach, CA GEG - Spokane
1630 1845
Purpose Interview of Potential Board Member LGB - Mercury 562-490-2874
GEG - Avista Hangar 509 495-4139
Remarks Sue will arrange ground transportation
***Need lunch from GEG to LGB
ICNU_DR_240 Attachment A Page 243 of 419
6/8/2015 9:33 AM
Flight #: AVA122013 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:December Date:20 - 20 Year: 2013
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 09900020 930200 550 E01 $7,070.00 1 Friday December 20 Friday December 20 56 minutes
GEG - Spokane PDX - Portland, OR
915 1015
1 Friday December 20 Friday December 20 45 minutes
PDX - Portland, OR GEG - Spokane
1345 1445
Purpose Interview of Potential Board Member PDX - Atlantic 503 331-4220
GEG - Avista Hangar 509 495-4139
Remarks Ground transportation has been arranged.
ICNU_DR_240 Attachment A Page 244 of 419
6/8/2015 9:34 AM
Flight #: AVA010314 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:January Date:3 - 3 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Steve Harper 1,2,3,4,5 Friday January 3 Friday January 3 55 minutes
2 Bruce Howard 6,7,8 GEG - Spokane PDX - Portland, OR
3 Dan Johnson 745 835
4 Bob Lafferty 77705216 186200 550 M54 $4,800.00 1,2,3,4,5 Friday January 3 Friday January 3 41 minutes
5 Greg Rahn 6,7,8 PDX - Portland, OR GEG - Spokane
6 Collins (Kevin) Sprague 1245 1330
7 Jason Thackston
8 Mark Thies
PGE Meeting 77703430 417120 885 F54 $12,668.16
PGE Meeting 9900111 931111 885 F54 ($12,668.16)
Purpose PGE Meeting PDX - Atlantic 503 331-4220
GEG - Avista Hangar 509 495-4139
Remarks Group will take FBO shuttle van to the train for transportation
to PGE and return.
***Need lunch from PDX to GEG
ICNU_DR_240 Attachment A Page 245 of 419
6/8/2015 9:34 AM
Flight #: AVA010714 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:January Date:7 - 7 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Terry Bushnell 9902800 921000 550 X02 $743.75 1,2,3,4,5 Tuesday January 7 Tuesday January 7 61 minutes
2 Jeremy Gall 9902811 926408 550 I02 $743.75 6,7,8 GEG - Spokane MFR - Medford, OR
3 Daniel Gigler 98405238 300100 550 G08 $743.75 700 805
4 Darrel Haarr 98405238 300100 550 G08 $743.75 1,2,3,4,5 Tuesday January 7 Tuesday January 7 58 minutes
5 David Howell 09900165 870000 550 G08 $743.75 6,7,8 MFR - Medford, OR GEG - Spokane
6 Steven Schacher 9902811 926408 550 I02 $743.75 1630 1730
7 Wendy Walker 09902800 921000 550 X02 $743.75
8 Michael Whitby 98405238 300100 550 G08 $743.75
Purpose Trainings, Labor Negotiations and other Projects MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139
Remarks Need ground transportation
***Need breakfast from GEG to MFR
ICNU_DR_240 Attachment A Page 246 of 419
6/8/2015 9:34 AM
Flight #: AVA010914 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:January Date:9 - 9 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4,5 Thursday January 9 Thursday January 9 48 minutes
2 Thomas Dempsey 6 GEG - Spokane OLM - Olympia, WA
3 James Gall 715 815
4 Linda Gervais 02800545 928000 550 R11 $2,200.00 1,2,3,4,5 Thursday January 9 Thursday January 9 40 minutes
5 Lori Hermanson 6 OLM - Olympia, WA GEG - Spokane
6 Clint Kalich 1200 1300
Purpose Meetings with WUTC - IRP Presentation OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Lunch from Olympia to Spokane
***Hertz Rental Car in Linda G. name: Confirmation #G07705600D2
ICNU_DR_240 Attachment A Page 247 of 419
6/8/2015 9:34 AM
Flight #: AVA011514 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:January Date:15 - 15 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Paul Kimball 1,2,3 Wednesday January 15 Wednesday January 15 54 minutes
2 Larry Labolle GEG - Spokane OLM - Olympia, WA
3 David Meyer 02800540 928000 550 R11 $5,150.00 800 845
1,2,3 Wednesday January 15 Wednesday January 15 13 minutes
BFI - Seattle, WA OLM - Olympia, WA
1130 1145
1,2,3 Wednesday January 15 Wednesday January 15 36 minutes
OLM - Olympia, WA GEG - Spokane
1700 1745
Purpose Rulemaking Meeting - Possible changes/Corrections to Rules OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Rental Car in Davids name reserved by Patty Hanson #G0851979870
**** Diverted to BFI-Seattle due to weather in Olympia
ICNU_DR_240 Attachment A Page 248 of 419
6/8/2015 9:34 AM
Flight #: AVA012314 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:January Date:23 - 23 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Annette Brandon 1,2,3,4 Thursday January 23 Thursday January 23 41 minutes
2 Pat Ehrbar 02800545 928000 550 R11 $4,250.00 GEG - Spokane OLM - Olympia, WA
3 Kelly Fukai 745 830
4 Steve Harper 1,2 Thursday January 23 Thursday January 23 44 minutes
OLM - Olympia, WA GEG - Spokane
1630 1715
Purpose Natural Gas PGS Workshop OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Rental Car in Pat's name reserved by Patty Hanson #G0733595581
***Rental Car in Pat's name reserved by Patty Hanson #G0733595581
ICNU_DR_240 Attachment A Page 249 of 419
6/8/2015 9:34 AM
Flight #: AVA012414 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:January Date:24 - 24 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4,5 Friday January 24 Friday January 24
2 Terrence Browne 6,7 GEG - Spokane PDX - Portland, OR 45 Min.
3 Mike Diedesch 800 850
4 Grant Forsyth 1,2,3,4,5 Friday January 24 Friday January 24
5 Lori Hermanson 6,7 PDX - Portland, OR GEG - Spokane 48 Min.
6 Tom Pardee 1530 1620
7 Jon Powell
Purpose Natural Gas IRP Technical Advisory Committee Meeting PDX - Atlantic 503 331-4220
GEG - Avista Hangar 509 495-4139
Remarks Hertz Rental Car: Confirmation number: G0924518769 Res
erved for Shawn Bonfield
ICNU_DR_240 Attachment A Page 250 of 419
6/8/2015 9:34 AM
Flight #: AVA012714 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Monday Month:January Date:27 - 27 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Greg Hesler 1,2,3,4 Monday January 27 Monday January 27 47 minutes
2 David Meyer 06803410 925130 550 P01 $4,650.00 GEG - Spokane PDX - Portland, OR
3 Bill Schroeder 900 950
4 Marsha Ungricht 1,2,3,4 Monday January 27 Monday January 27 46 minutes
PDX - Portland, OR GEG - Spokane
1730 1815
Purpose Knife River Mediation PDX - Atlantic 503 331-4220
GEG - Avista Hangar 509 495-4139
Remarks Rental Car reserved by Marsha at Paine Hamblen
ICNU_DR_240 Attachment A Page 251 of 419
6/8/2015 9:35 AM
Flight #: AVA012814 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:January Date:28 - 28 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Terry Bushnell 9902800 921000 550 X02 $778.57 1,2,4,5,6 Tuesday January 28 Tuesday January 28 60 minutes
2 Daniel Gigler 98405238 300100 550 G08 $778.57 7,8 GEG - Spokane MFR - Medford, OR
3 David Howell 9900165 870000 550 G08 $350.00 700 805
4 Seth Samsell 98405124 300100 550 B51 $778.57 1,2,3,4,5 Tuesday January 28 Tuesday January 28 56 minutes
5 Steven Schacher 9902811 926408 550 G02 $778.57 6,7,8 MFR - Medford, OR MFR - Medford, OR
6 Wendy Walker 9902800 921000 550 X02 $778.57 1640 1740
7 Jeff Webb 9900165 980000 550 B51 $778.57
8 Michael Whitby 98405238 300100 550 G08 $778.57
Purpose Labor Negotiations and Contractor Meetings MFR - Jet Center 541-770-5314
GEG - Avista Hanger 509-495-4139
Remarks
ICNU_DR_240 Attachment A Page 252 of 419
6/8/2015 9:35 AM
Flight #: AVA012914 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Friday Month:January Date:29 - 31 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Morris 1,2,3,4 Wednesday January 29 Wednesday January 29 140 minutes
2 Scott Morris 09800310 930200 550 E01 $13,800.00 GEG - Spokane CRQ - Carlsbad, CA
3 Dennis Vermillion 1200 1400
4 Marlene Vermillion 1,2,3,4 Friday January 31 Friday January 31 136 minutes
CRQ - Carlsbad, CA GEG - Spokane
900 1130
Purpose WEI Board Meetings CRQ - Premier Jet 800-951-9557
GEG - Avista Hangar 509 495-4139
Remarks
***Need lunch from GEG to CRQ
ICNU_DR_240 Attachment A Page 253 of 419
6/8/2015 9:35 AM
Flight #: AVA020414 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:February Date:4 - 4 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Thomas Dempsey 41002100 500000 550 K07 $878.00 1,2,3,4,5 Tuesday February 4 Tuesday February 4 57 minutes
2 Mike Mecham 41002100 500000 550 K07 $878.00 6,7 GEG - Spokane BIL - Billings, MT
3 Scott Mitchell 41002100 500000 550 K07 $878.00 500 700
4 Darrell Soyars 09900510 920000 550 E14 $879.00 1,2,3,4,5 Tuesday February 4 Tuesday February 4 66 minutes
5 Jason Thackston 09802202 557000 550 E55 $879.00 6,7 BIL - Billings, MT GEG - Spokane
6 Greg Wiggins 09802202 557000 550 E55 $879.00 1700 1700
7 Jessie Wuerst 09900330 930200 550 S54 $879.00
Purpose Colstrip Mine Tour BIL - Edwards Montana Jet Ctr 406 252-0508
GEG - Avista Hangar 509 495-4139
Remarks 7 passenger suburban to drive to Colstrip Plant, returning
to Billings same day. Reporter Becky Kramer will meet plane at Billings airport at 7:30 a.m. then carpool to the Plant. Enterprise Car Rental Confirmation 6SY597 DEMPSEY; TDF74J MECHAM
***Need breakfast from GEG to BIL
ICNU_DR_240 Attachment A Page 254 of 419
6/8/2015 9:35 AM
Flight #: AVA022014 AVISTA DAILY FLIGHT MANIFEST
Day:Thursday - Thursday Month:February Date:20 - 20 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Thursday February 20 Thursday February 20 51 minutes
2 Pat Ehrbar 02805810 928010 550 R11 $4,350.00 6,7 GEG - Spokane OLM - Olympia, WA
3 Ryan Finesilver 800 845
4 Tara Knox 1,2,3,4,5 Thursday February 20 Thursday February 20 36 minutes
5 Larry Labolle 6,7 OLM - Olympia, WA GEG - Spokane
6 Karen Schuh 1600 1645
7 Jennifer Smith
Purpose Meeting with Washington Staff Regarding General Rate Case OLM - Glacier 360-705-3214
GEG - Avista Hangar 509 495-4139
Remarks Rental van in Pat and Liz's name, reserved by Wendy Manskey.
Confirmation #G1133064481 (Pat) and G1162594124 (Liz).
ICNU_DR_240 Attachment A Page 255 of 419
6/8/2015 9:35 AM
Flight #: AVA022514 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:February Date:25 - 25 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Shawn Bonfield 1,2,3,4,5 Tuesday February 25 Tuesday February 25 45 minutes
2 Annette Brandon 09900540 928000 550 R11 $4,575.00 6,7,8 GEG - Spokane OLM - Olympia, WA
3 Terrence Browne 730 815
4 Grant Forsyth 1,2,3,4,6 Tuesday February 25 Tuesday February 25 21 minutes
5 Scott Morris 09900310 930200 550 E01 $4,150.00 7 OLM - Olympia, WA PDX - Portland, OR
6 Tom Pardee 830 900
7 Lauren Pendergraft 1,2,3,4,6 Tuesday February 25 Tuesday February 25 18 minutes
8 Steve Trabun 7 PDX - Portland, OR OLM - Olympia, WA
1545 1615
1,2,3,4,5 Tuesday February 25 Tuesday February 25 38 minutes
6,7,8 OLM - Olympia, WA GEG - Spokane
1630 1715
Purpose Washington Roundtable Meeting and Natural Gas IRP TAC meetin OLM - Glacier 360-705-3214g
PDX - Atlantic 503 331-4220
Remarks
GEG - Avista Hangar 509 495-4139
***Need breakfast from GEG to OLM
ICNU_DR_240 Attachment A Page 256 of 419
6/8/2015 9:35 AM
Flight #: AVA022814 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:February Date:28 - 28 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Terry Bushnell 3,4,6,7,8 Friday February 28 Friday February 28 16 minutes
2 David Howell GEG - Spokane PUW - Pullman, WA
3 Scott Morris 09900162 921000 550 E01 $7,600.00 640 700
4 Kelly Norwood 3,4,6,7,8 Friday February 28 Friday February 28 17 minutes
5 Cindy Rogers PUW - Pullman, WA LWS - Lewiston, ID
6 Brandi Smith 850 910
7 Jason Thackston 3,4,6,7,8 Thursday February 13 Thursday February 13 58 minutes
8 Dennis Vermillion LWS - Lewiston, ID MFR - Medford, OR
1200 1300
1,2,3,4,5 Friday February 28 Friday February 28 61 minutes
6,7,8 MFR - Medford, OR GEG - Spokane
1445 1545
Purpose Employee Meetings PUW - Interstate Aviation 509-332-6596
LWS - Stout Flying Service 208 743-8408
Remarks Transportation provided by each office
MFR - Jet Center 541-770-5314
GEG - Avista Hangar 509 495-4139
ICNU_DR_240 Attachment A Page 257 of 419
6/8/2015 9:35 AM
Flight #: AVA030314 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Thursday Month:March Date:3 - 6 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 9800310 930200 E01 1,2,3 Monday March 3 Monday March 3
2 Collins (Kevin) Sprague GEG - Spokane MSN - Madison, WI 153 minutes
3 Dennis Vermillion 830 1315
1,2,3 Monday March 3 Monday March 3
MSN - Madison, WI IAD - Washington, DC 89 minutes
1345 1615
1,2,3 Thursday March 6 Thursday March 6
IAD - Washington, DC MSN - Madison, WI 96 minutes
1330 1415
1,2,3 Thursday March 6 Thursday March 6
MSN - Madison, WI GEG - Spokane 185 minutes
1445 1600
Purpose EEI Spring Conference (WA DC)MSN - Wisconsin Aviation - Madison 608-268-5000
IAD - Landmark 703-661-0150
Remarks
GEG - Avista Hangar 509 495-4139
3/3 Carey Car for Dennis, Kevin and Collins #WA7977197-001 p/u at 4:15 pm at Landmark Aviation bound for Mandarin Oriental Hotel
3/6 Carey Car for Dennis, Kevin and Collins #WA7977212-001 p/u at 12:45 pm at Mandarin Oriental Hotel bound for Landmark Aviation
3/3 Breakfast: Spokane to Madison

3/3 Lunch: Madison to DC

3/6 Lunch: From DC to Madison

3/6 Snacks Madison to Spokane
ICNU_DR_240 Attachment A Page 258 of 419
6/8/2015 9:35 AM
Flight #: AVA030314 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Thursday Month:March Date:3 - 6 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Kevin Christie 9800310 930200 E01 1,2,3 Monday March 3 Monday March 3
2 Collins (Kevin) Sprague GEG - Spokane MSN - Madison, WI 153 minutes
3 Dennis Vermillion 830 1315
1,2,3 Monday March 3 Monday March 3
MSN - Madison, WI IAD - Washington, DC 89 minutes
1345 1615
1,2,3 Thursday March 6 Thursday March 6
IAD - Washington, DC MSN - Madison, WI 96 minutes
1330 1415
1,2,3 Thursday March 6 Thursday March 6
MSN - Madison, WI GEG - Spokane 185 minutes
1445 1600
Purpose EEI Spring Conference (WA DC)MSN - Wisconsin Aviation - Madison 608-268-5000
IAD - Landmark 703-661-0150
Remarks
GEG - Avista Hangar 509 495-4139
3/3 Carey Car for Dennis, Kevin and Collins #WA7977197-001 p/u at 4:15 pm at Landmark Aviation bound for Mandarin Oriental Hotel
3/6 Carey Car for Dennis, Kevin and Collins #WA7977212-001 p/u at 12:45 pm at Mandarin Oriental Hotel bound for Landmark Aviation
3/3 Breakfast: Spokane to Madison

3/3 Lunch: Madison to DC

3/6 Lunch: From DC to Madison

3/6 Snacks Madison to Spokane
ICNU_DR_240 Attachment A Page 259 of 419
6/8/2015 9:35 AM
Flight #: AVA030714 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:March Date:7 - 7 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Friday March 7 Friday March 7
2 Pat Ehrbar 6,7,8 GEG - Spokane OLM - Olympia, WA 47 Min.
3 Linda Gervais 830 915
4 Clint Kalich 1,2,3,4,5 Friday March 7 Friday March 7
5 Bill Johnson 6,7,8 OLM - Olympia, WA GEG - Spokane 39 Min.
6 Larry La Bolle 1700 1745
7 David Meyer
8 Kelly Norwood 02805810 928010 550 R11
Purpose Pre-hearing Conference and meeting with parties after OLM - Glacier 360-705-3214pre-hearing conference GEG - Avista Hangar 509 495-4139
Remarks Two vehicles have been reserved by Patty Hanson
Minivan in Kelly's name - Confirmation #G1203792056Car in Pat's name - Confirmation #G13527125C0
ICNU_DR_240 Attachment A Page 260 of 419
6/8/2015 9:36 AM
Flight #: AVA030714 AVISTA DAILY FLIGHT MANIFEST
Day:Friday - Friday Month:March Date:7 - 7 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Liz Andrews 1,2,3,4,5 Friday March 7 Friday March 7
2 Pat Ehrbar 6,7,8 GEG - Spokane OLM - Olympia, WA 47 Min.
3 Linda Gervais 830 915
4 Clint Kalich 1,2,3,4,5 Friday March 7 Friday March 7
5 Bill Johnson 6,7,8 OLM - Olympia, WA GEG - Spokane 39 Min.
6 Larry La Bolle 1700 1745
7 David Meyer
8 Kelly Norwood 02805810 928010 550 R11
Purpose Pre-hearing Conference and meeting with parties after OLM - Glacier 360-705-3214pre-hearing conference GEG - Avista Hangar 509 495-4139
Remarks Two vehicles have been reserved by Patty Hanson
Minivan in Kelly's name - Confirmation #G1203792056Car in Pat's name - Confirmation #G13527125C0
ICNU_DR_240 Attachment A Page 261 of 419
6/8/2015 9:36 AM
Flight #: AVA031814 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:March Date:18 - 18 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Terry Bushnell 9902800 921000 550 X02 1,2,3,4,6 Tuesday March 18 Tuesday March 18
2 James Danley 8 GEG - Spokane LGD - LaGrande, OR
3 Derek Dykeman 700 730
4 David Howell 09900165 870000 550 G08 1,2,3,4,5 Tuesday March 18 Tuesday March 18
5 Donald Kellogg 77700242 107060 550 C83 6,7,8 LGD - LaGrande, OR MFR - Medford, OR
6 Razziq Khusro 745 845
7 Rob Rajkovich 9902800 921000 550 X02 1,2,3,4,5 Tuesday March 18 Tuesday March 18
8 Stuart Reed 6,7,8,9 MFR - Medford, OR LGD - LaGrande, OR
9 Harold Sheeran 77700242 107060 550 A82 1600 1700
1,2,3,4,6 Tuesday March 18 Tuesday March 18
8,9 LGD - LaGrande, OR GEG - Spokane
1715 1745
Purpose Labor Negotiations and Windows 7 Deployment LGD - Union County Airport 541-963-6615
MFR - Jet Center 541-770-5314
Remarks
GEG - Avista Hangar 509 495-4139
***Need breakfast from GEG to LGD
ICNU_DR_240 Attachment A Page 262 of 419
6/8/2015 9:36 AM
Flight #: AVA031814 AVISTA DAILY FLIGHT MANIFEST
Day:Tuesday - Tuesday Month:March Date:18 - 18 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Terry Bushnell 9902800 921000 550 X02 1,2,3,4,6 Tuesday March 18 Tuesday March 18
2 James Danley 8 GEG - Spokane LGD - LaGrande, OR
3 Derek Dykeman 700 730
4 David Howell 09900165 870000 550 G08 1,2,3,4,5 Tuesday March 18 Tuesday March 18
5 Donald Kellogg 77700242 107060 550 C83 6,7,8 LGD - LaGrande, OR MFR - Medford, OR
6 Razziq Khusro 745 845
7 Rob Rajkovich 9902800 921000 550 X02 1,2,3,4,5 Tuesday March 18 Tuesday March 18
8 Stuart Reed 6,7,8,9 MFR - Medford, OR LGD - LaGrande, OR
9 Harold Sheeran 77700242 107060 550 A82 1600 1700
1,2,3,4,6 Tuesday March 18 Tuesday March 18
8,9 LGD - LaGrande, OR GEG - Spokane
1715 1745
Purpose Labor Negotiations and Windows 7 Deployment LGD - Union County Airport 541-963-6615
MFR - Jet Center 541-770-5314
Remarks
GEG - Avista Hangar 509 495-4139
***Need breakfast from GEG to LGD
ICNU_DR_240 Attachment A Page 263 of 419
6/8/2015 9:36 AM
Flight #: AVA031914 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Thursday Month:March Date:19 - 20 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Casey Fielder 09900330 930200 550 S54 1,2,3 Wednesday March 19 Wednesday March 19
2 Jason Lang 09900010 921000 550 Y54 GEG - Spokane LAS - Las Vegas, NV 109 Min.
3 Mark Thies 09903691 930200 550 J01 700 845
1,2,3 Thursday March 20 Thursday March 20
LAS - Las Vegas, NV GEG - Spokane 116 Min.
730 855
Purpose Annual West Coast Seminar LAS - Signature Flight Support 702-739-1100
GEG - Avista Hangar 509 495-4139
Remarks Carey Car has been reseved by Karen Eastwood. Confirmation
#WA8068783-1 and WA8068783-2
***Need breakfast from GEG to LAS
***Need breakfast from LAS to GEG
ICNU_DR_240 Attachment A Page 264 of 419
6/8/2015 9:36 AM
Flight #: AVA031914 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Thursday Month:March Date:19 - 20 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Casey Fielder 09900330 930200 550 S54 1,2,3 Wednesday March 19 Wednesday March 19
2 Jason Lang 09900010 921000 550 Y54 GEG - Spokane LAS - Las Vegas, NV 109 Min.
3 Mark Thies 09903691 930200 550 J01 700 845
1,2,3 Thursday March 20 Thursday March 20
LAS - Las Vegas, NV GEG - Spokane 116 Min.
730 855
Purpose Annual West Coast Seminar LAS - Signature Flight Support 702-739-1100
GEG - Avista Hangar 509 495-4139
Remarks Carey Car has been reseved by Karen Eastwood. Confirmation
#WA8068783-1 and WA8068783-2
***Need breakfast from GEG to LAS
***Need breakfast from LAS to GEG
ICNU_DR_240 Attachment A Page 265 of 419
6/8/2015 9:36 AM
Flight #: AVA032414 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Wednesday Month:March Date:24 - 26 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 77700300 426120 550 E01 1,2 Monday March 24 Monday March 24
2 Collins (Kevin) Sprague GEG - Spokane MSN - Madison, WI 155 Min.
700 1145
1,2 Monday March 24 Monday March 24
MSN - Madison, WI IAD - Washington, DC 83 Min.
1215 1450
1,2 Wednesday March 26 Wednesday March 26
IAD - Washington, DC MSN - Madison, WI 102 Min.
900 955
1,2 Wednesday March 26 Wednesday March 26
MSN - Madison, WI GEG - Spokane 191 Min.
1025 1135
Purpose Meetings with Legislators MSN - Wisconsin Aviation - Madison 608-268-5000
IAD - Landmark 703-661-0150
Remarks A Carey car has been set up. Confirmation #WA8070107-1 and
WA8070107-2 GEG - Avista Hangar 509 495-4139
***Need breakfast from GEG to MSN
***Need lunch from MSN to IAD
ICNU_DR_240 Attachment A Page 266 of 419
6/8/2015 9:36 AM
Flight #: AVA032414 AVISTA DAILY FLIGHT MANIFEST
Day:Monday - Wednesday Month:March Date:24 - 26 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 Scott Morris 77700300 426120 550 E01 1,2 Monday March 24 Monday March 24
2 Collins (Kevin) Sprague GEG - Spokane MSN - Madison, WI 155 Min.
700 1145
1,2 Monday March 24 Monday March 24
MSN - Madison, WI IAD - Washington, DC 83 Min.
1215 1450
1,2 Wednesday March 26 Wednesday March 26
IAD - Washington, DC MSN - Madison, WI 102 Min.
900 955
1,2 Wednesday March 26 Wednesday March 26
MSN - Madison, WI GEG - Spokane 191 Min.
1025 1135
Purpose Meetings with Legislators MSN - Wisconsin Aviation - Madison 608-268-5000
IAD - Landmark 703-661-0150
Remarks A Carey car has been set up. Confirmation #WA8070107-1 and
WA8070107-2 GEG - Avista Hangar 509 495-4139
***Need breakfast from GEG to MSN
***Need lunch from MSN to IAD
ICNU_DR_240 Attachment A Page 267 of 419
6/8/2015 9:36 AM
Flight #: AVA052814 AVISTA DAILY FLIGHT MANIFEST
Day:Wednesday - Wednesday Month:May Date:28 - 28 Year: 2014
P/D Passenger Name Project Task Exp Org Charge LEG Departure Info Arrival Info Actual Flt Time
1 David Meyer 1,2,3,4,5 Wednesday May 28 Wednesday May 28
2 Scott Morris GEG - Spokane SLE - Salem
3 Kelly Norwood 06800545 928000 550 R11 1130 1210
4 Mark Thies 1,2,3,4,5 Wednesday May 28 Wednesday May 28
5 Dennis Vermillion SLE - Salem GEG - Spokane
1630 1715
Purpose Annual Update Meetings with OPUC Commisioners SLE - Salem Air Center 503 364-4158
GEG - Avista Hangar 509 495-4139
Remarks 1 rental van reserved by Patty Hanson in Kelly's name
***Need lunch from GEG to SLE
ICNU_DR_240 Attachment A Page 268 of 419
Trip ID: 1061 06/05/1 08:21 AM Page:
AIRCRAFT ROUTIN
01/06/1 - 1/08/1
RIP PURPOSE:EEI Conference
AIRCRAFT:N202AV CE-650 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 2DATE:01/06/15 TUE
TRAVEL TIME:2 Hours 6 Minute DISTANCE:1014 Nautical Mile
DEPART TIME:09:06 AM PST ARRIVE TIME:01:12 PM CST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALINA, KS - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALINA MUNICIPAL
FBO: FBO:AVFLIGHT2035 BEECHCRAFT RD
SALINA, KS 6740785-825-626785-825-6264 - fa
PASSENGERS:VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E0
THACKSTON, JASON R - 509-290-4590 / 09800310-930200-550-E0
LEG MSGS: Please provide breakfast for four on leg 1
Leg
OF PA 2DATE:01/06/1 TU
TRAVEL TIME:2 Hours 36 Minute DISTANCE:1142 Nautical Mile
DEPART TIME:01:41 PM CST ARRIVE TIME:05:17 PM EST
DEPART FROM:SALINA, KS - KSL ARRIVE AT:WEST PALM BEACH, FL - KPBI
AIRPORT NAME:SALINA MUNICIPAL AIRPORT NAME:PALM BEACH INTERNATIONAL
FBO:AVFLIGHT FBO:ATLANTIC AVIATIO2035 BEECHCRAFT RD 3800 SOUTHERN BLVD
SALINA, KS 6740 WEST PALM BEACH, FL 3340561-683-412785-825-626 561-689-1849 - fa785-825-6264 - fa
PASSENGERS:VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E01
THACKSTON, JASON R - 509-290-4590 / 09800310-930200-550-E01
LEG MSGS: Please provide a light lunch for four on leg 2.
Leg
OF PA 3DATE:01/08/1 TH
TRAVEL TIME:3 Hours 0 Minute DISTANCE:1142 Nautical Mile
DEPART TIME:11:56 AM EST ARRIVE TIME:02:00 PM CST
DEPART FROM:WEST PALM BEACH, FL - KPBI ARRIVE AT:SALINA, KS - KSL
AIRPORT NAME:PALM BEACH INTERNATIONAL AIRPORT NAME:SALINA MUNICIPAL
FBO:ATLANTIC AVIATIO FBO:AVFLIGHT3800 SOUTHERN BLVD 2035 BEECHCRAFT RD
WEST PALM BEACH, FL 3340 SALINA, KS 6740785-825-626561-683-412 785-825-6264 - fa561-689-1849 - fa
PASSENGERS:VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E0
THACKSTON, JASON R - 509-290-4590 / 09800310-930200-550-E0ANDERSON, DARREL - 09800310-930200-550-E01
LEG MSGS: Need lunch from KPBI to KSLN
Leg 4
Page 1 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 269 of 419
Trip ID: 1061 06/05/1 08:21 AM Page: 2
AIRCRAFT ROUTING
01/06/1 - 1/08/1
RIP PURPOSE:EEI Conference
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 4 continue
OF PA 3DATE:01/08/1 TH
TRAVEL TIME:2 Hours 33 Minute DISTANCE:884 Nautical Mile
DEPART TIME:02:23 PM CST ARRIVE TIME:03:56 PM MST
DEPART FROM:SALINA, KS - KSL ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SALINA MUNICIPAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO:AVFLIGHT FBO:JACKSON JET CENTE2035 BEECHCRAFT RD 3815 RICKENBACKER STREETSALINA, KS 6740 BOISE, ID 8370208-383-330785-825-626 208-336-9082 - fa785-825-6264 - fax
PASSENGERS:VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E0
THACKSTON, JASON R - 509-290-4590 / 09800310-930200-550-E01
ANDERSON, DARREL - 09800310-930200-550-E0
LEG MSGS: Please provide snacks for leg 4.
Leg
OF PA 2DATE:01/08/1 TH
TRAVEL TIME:0 Hour 48 Minute DISTANCE:249 Nautical Mile
DEPART TIME:04:18 PM MST ARRIVE TIME:04:06 PM PST
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JACKSON JET CENTE FBO:AVISTA HANGA
3815 RICKENBACKER STREET 7500 W PARK DRIVE GATE LBOISE, ID 8370 SPOKANE, W509.495.413208-383-330
208-336-9082 - fax
PASSENGERS:VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E0
THACKSTON, JASON R - 509-290-4590 / 09800310-930200-550-E0
TRIP MSGS: Provide Breakfast and Lunch on January 6.
Provide Snacks for January 8.
Page 2 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 270 of 419
Trip ID: 1131 06/05/1 08:21 AM Page: 3
AIRCRAFT ROUTING
01/13/1 - 1/13/1
RIP PURPOSE:Salem Oregon UG 284 Settlement Conference/Olympia - Commissioner Jeff Goltz Retirement
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 9DATE:01/13/1 TU
TRAVEL TIME:1 Hour 6 Minute DISTANCE:242 Nautical Mile
DEPART TIME:07:58 AM PST ARRIVE TIME:09:04 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:PORTLAND, OR - KPD
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:PORTLAND INTERNATIONAL
FBO: FBO:ATLANTIC AVIATIO7527 NE AIRPORT WAPORTLAND, OR 9721503-331-422503-331-4273 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 06805169-928010-550-R1
MEYER, DAVID J. - 509-220-7432 / 06805169-928010-550-R11
ANDREWS, ELIZABETH (LIZ) - / 06805169-928010-550-R1EHRBAR, PAT - 509-994-9074 / 06805169-928010-550-R1MILLER, JOE - 509-951-4123 / 06805169-928010-550-R1
SCHUH, KAREN - 509-995-6652 / 06805169-928010-550-R1SMITH, JENNIFER (JEN) - / 06805169-928010-550-R11
BRANDON, ANNETTE - 509-979-3214 / 06805169-928010-550-R1PLUTH, JEANNE - 509-294-9560 / 06805169-928010-550-R1
LEG MSGS: Two vehicles reserved by Patty Hanson in Kelly and Pat's names. Full size for Kelly - confirmation
#G44337483C5 and minivan for Pat - confirmation #G44302379A9.
Leg
OF PA 1DATE:01/13/1 TU
TRAVEL TIME:0 Hour 14 Minute DISTANCE:44 Nautical Mile
DEPART TIME:11:29 AM PST ARRIVE TIME:11:43 AM PST
DEPART FROM:PORTLAND, OR - KPD ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:PORTLAND INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO:ATLANTIC AVIATIO FBO:7527 NE AIRPORT WA
PORTLAND, OR 9721503-331-422503-331-4273 - fa
PASSENGERS:ROBINSON, DAVID (DAVE) - 509-280-1038 / 06805169-928010-550-R1
Leg
OF PA 9DATE:01/13/1 TU
TRAVEL TIME:0 Hour 25 Minute DISTANCE:124 Nautical Mile
DEPART TIME:05:43 PM PST ARRIVE TIME:06:08 PM PST
DEPART FROM:SALEM, OR - KSL ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:OLYMPIA REGIONAL
FBO:FBO:GLACIER JET CENTE
7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214
360-753-0083 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 09900549-426500-550-R11
Additional Passengers for this leg continue on the next page
Page 3 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 271 of 419
Trip ID: 1131 06/05/1 08:21 AM Page:
AIRCRAFT ROUTING
01/13/1 - 1/13/1
RIP PURPOSE:Salem Oregon UG 284 Settlement Conference/Olympia - Commissioner Jeff Goltz Retirement
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 3 continue
PASSENGERS:MEYER, DAVID J. - 509-220-7432 / 09900549-426500-550-R1
ANDREWS, ELIZABETH LIZ - / 09900549-426500-550-R1EHRBAR, PAT - 509-994-9074 / 09900549-426500-550-R11MILLER, JOE - 509-951-4123 / 09900549-426500-550-R1SCHUH, KAREN - 509-995-6652 / 09900549-426500-550-R1SMITH, JENNIFER JEN - / 09900549-426500-550-R1
BRANDON, ANNETTE - 509-979-3214 / 09900549-426500-550-R1PLUTH, JEANNE - 509-294-9560 / 09900549-426500-550-R11
LEG MSGS: Two vehicles reserved by Patty Hanson in Kelly and Pat's names. Full size for Kelly - confirmation#G4434462644 and minivan for Pat - confirmation #G4431208848.
Leg 4
OF PA 9DATE:01/13/1 TU
TRAVEL TIME:0 Hour 44 Minute DISTANCE:222 Nautical Mile
DEPART TIME:08:37 PM PST ARRIVE TIME:09:21 PM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE L
OLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 06805169-928010-550-R11
MEYER, DAVID J. - 509-220-7432 / 06805169-928010-550-R11ANDREWS, ELIZABETH (LIZ) - / 06805169-928010-550-R1EHRBAR, PAT - 509-994-9074 / 06805169-928010-550-R1
MILLER, JOE - 509-951-4123 / 06805169-928010-550-R1SCHUH, KAREN - 509-995-6652 / 06805169-928010-550-R1SMITH, JENNIFER (JEN) - / 06805169-928010-550-R11BRANDON, ANNETTE - 509-979-3214 / 06805169-928010-550-R1PLUTH, JEANNE - 509-294-9560 / 06805169-928010-550-R1
Page 4 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 272 of 419
Trip ID: 60614 06/05/1 08:21 AM Page: 5
AIRCRAFT ROUTING
06/06/1 - 6/06/1
RIP PURPOSE:EMPLOYEE MEETINGS
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 4DATE:06/06/14 FRI
TRAVEL TIME:1 Hour 0 Minute DISTANCE:387 Nautical Mile
DEPART TIME:06:36 AM PDT ARRIVE TIME:07:36 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO: FBO:JET CENTER MF5000 CIRRUS DMEDFORD, OR 97504800-359-029541-772-2759 - fa
PASSENGERS:MORRIS, SCOTT -
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E01
KENSOK, JAMES M(JIM) - 509-994-2892 / 09900162-921000-550-E0SMITH, BRANDI BRANDI - 509-847-8952 / 09900162-921000-550-E0
Leg
OF PA 4DATE:06/06/14 FRI
TRAVEL TIME:0 Hour 55 Minute DISTANCE:360 Nautical Mile
DEPART TIME:09:44 AM PDT ARRIVE TIME:10:39 AM PDT
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO:JET CENTER MF FBO:INTER-STATE AV
5000 CIRRUS D 2601 AIRPORT COMPLEX MEDFORD, OR 97504 PULLMAN, WA 9916509-332-659800-359-029
509-334-1751 - fa541-772-2759 - fa
PASSENGERS:MORRIS, SCOTT -
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E0KENSOK, JAMES M JIM - 509-994-2892 / 09900162-921000-550-E0
SMITH, BRANDI BRANDI - 509-847-8952 / 09900162-921000-550-E0
Leg 3
OF PA 4DATE:06/06/14 FRI
TRAVEL TIME:0 Hour 8 Minutes DISTANCE:22 Nautical Mile
DEPART TIME:01:02 PM PDT ARRIVE TIME:01:10 PM PDT
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:LEWISTON, ID - KLW
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:LEWISTON-NEZ PERCE COUNT
FBO:INTER-STATE AV FBO:STOUT FLYING SV2601 AIRPORT COMPLEX N 406 BURRELLPULLMAN, WA 9916 LEWISTON, ID 8350
208-743-840509-332-659 208-798-3284 - fa509-334-1751 - fa
PASSENGERS:MORRIS, SCOTT -
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E0
KENSOK, JAMES M JIM - 509-994-2892 / 09900162-921000-550-E0SMITH, BRANDI (BRANDI) - 509-847-8952 / 09900162-921000-550-E0
Leg 4
Page 5 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 273 of 419
Trip ID: 60614 06/05/1 08:21 AM Page: 6
AIRCRAFT ROUTING
06/06/1 - 6/06/1
RIP PURPOSE:EMPLOYEE MEETINGS
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 4 continue
OF PA 4DATE:06/06/14 FRI
TRAVEL TIME:0 Hour 20 Minute DISTANCE:78 Nautical Mile
DEPART TIME:03:07 PM PDT ARRIVE TIME:03:27 PM PDT
DEPART FROM:LEWISTON, ID - KLW ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:LEWISTON-NEZ PERCE COUNT AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:STOUT FLYING SV FBO:AVISTA HANGA406 BURRELL 7500 W PARK DRIVE GATE LLEWISTON, ID 8350 SPOKANE, W509.495.413208-743-840208-798-3284 - fax
PASSENGERS:MORRIS, SCOTT -
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E01
KENSOK, JAMES M(JIM) - 509-994-2892 / 09900162-921000-550-E0SMITH, BRANDI BRANDI - 509-847-8952 / 09900162-921000-550-E0
Page 6 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 274 of 419
Trip ID: VA01141 06/05/1 08:21 AM Page: 7
AIRCRAFT ROUTING
01/14/1 - 1/14/1
RIP PURPOSE:Meeting with ID Staff and UTC Staff in preparation of Project Compass 'Go Live'. The Butte trippurpose is for the safety team to meet with Northwestern Energy.
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE - STANFORD, RICHARD -
Leg 1
OF PA 3DATE:01/14/15 WED
TRAVEL TIME:0 Hour 43 Minute DISTANCE:249 Nautical Mile
DEPART TIME:07:31 AM PST ARRIVE TIME:09:14 AM MST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO:LANDMARK FBO:JACKSON JET CENTE
3815 RICKENBACKER STREETBOISE, ID 8370208-383-330
208-336-9082 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 03805511-928000-550-R1
BONFIELD, SHAWN (SHAWN) - 509-434-6502 / 03805511-928000-550-R1ESCH, JENNIFER - 509-435-5205 / 03805511-928000-550-R1
LEG MSGS: Hertz Rental cars in Linda's name - Boise G44133787F9
Leg
OF PA 3DATE:01/14/15 WED
TRAVEL TIME:0 Hour 57 Minute DISTANCE:348 Nautical Mile
DEPART TIME:12:42 PM MST ARRIVE TIME:12:39 PM PST
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:OLYMPIA REGIONAL
FBO:JACKSON JET CENTE FBO:GLACIER JET CENTE3815 RICKENBACKER STREET 7645 OLD HWY 99 S
BOISE, ID 8370 OLYMPIA, WA 9850360-705-3214208-383-330 360-753-0083 - fa208-336-9082 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 03805511-928000-550-R1
BONFIELD, SHAWN (SHAWN) - 509-434-6502 / 03805511-928000-550-R1
ESCH, JENNIFER - 509-435-5205 / 03805511-928000-550-R1
LEG MSGS: Hertz Rental cars in Linda's name - Olympia G4410639703
Leg
OF PA 3DATE:01/14/1 WED
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:04:54 PM PST ARRIVE TIME:05:32 PM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA
7645 OLD HWY 99 S 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 03805511-928000-550-R11
BONFIELD, SHAWN (SHAWN) - 509-434-6502 / 03805511-928000-550-R1ESCH, JENNIFER - 509-435-5205 / 03805511-928000-550-R1
Leg 4
Page 7 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 275 of 419
Trip ID: VA01141 06/05/1 08:21 AM Page: 8
AIRCRAFT ROUTING
01/14/1 - 1/14/1
RIP PURPOSE:Meeting with ID Staff and UTC Staff in preparation of Project Compass 'Go Live'. The Butte trippurpose is for the safety team to meet with Northwestern Energy.
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD - ROBINSON, DAVE -
Leg 4 continue
OF PA 9DATE:01/14/15 WED
TRAVEL TIME:0 Hour 39 Minute DISTANCE:230 Nautical Mile
DEPART TIME:06:06 PM PST ARRIVE TIME:07:45 PM MST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BUTTE, MT - KBTM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BERT MOONE
FBO:AVISTA HANGA FBO:
7500 W PARK DRIVE GATE LSPOKANE, WA509.495.413
PASSENGERS:KANE, JIM - 208-929-0166 / 95602810-588030-550-B5
OLSON, KERMIT - 509-675-5276 / 95602810-588030-550-B5SCHLOTHAUER, CHRIS - 509-999-7836 / 95602810-588030-550-B5
HENDRY, KELLEY - 208-818-3017 / 95602810-588030-550-B5SANCHEZ, JIM RODNEY(JIM) - 509-990-1857 / 95602810-588030-550-B5COX, BRYAN - 509-290-2790 / 95602810-588030-550-B5
STEINBRUECKER, KINGSLEY (CHAD) - 208-305-1039 / 95602810-588030-550-B5HYDE, DAN - 509-863-3774 / 95602810-588030-550-B5
GIBBS, ALICIA - / 95602810-588030-550-B5
Leg 5
OF PA 1DATE:01/14/1 WED
TRAVEL TIME:0 Hour 42 Minutes DISTANCE:230 Nautical Mile
DEPART TIME:08:08 PM MST ARRIVE TIME:07:50 PM PST
DEPART FROM:BUTTE, MT - KBTM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BERT MOONE AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:FBO:AVISTA HANGA7500 W PARK DRIVE GATE LSPOKANE, W
509.495.413
PASSENGERS:ROBINSON, DAVID DAVE - 509-280-1038 / 95602810-588030-550-B5
Page 8 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 276 of 419
Trip ID: VA01151 06/05/1 08:21 AM Page: 9
AIRCRAFT ROUTING
01/15/1 - 1/15/1
RIP PURPOSE:Open Meeting with UTC, DSM and Buck-a-Block. Commissioner briefings regarding EIM, powerhedging and natural gas hedging
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE - STANFORD, RICHARD -
Leg 1
OF PA 8DATE:01/15/15 THU
TRAVEL TIME:0 Hour 45 Minute DISTANCE:222 Nautical Mile
DEPART TIME:07:37 AM PST ARRIVE TIME:08:22 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:FBO:GLACIER JET CENTE
7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214
360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800540-928000-550-R1
JOHNSON, DAN (DAN) - 509-720-1028 / 02800540-928000-550-R1DRAKE, CHRIS CHRIS - 509-389-0521 / 02800540-928000-550-R1
POWELL, JON JON - / 02800540-928000-550-R1KINNEY, SCOTT (SCOTT) - 509-688-5369 / 02800540-928000-550-R1MOREHOUSE, JODY - 509-979-6674 / 02800540-928000-550-R1
BRYAN, TODD - / 02800540-928000-550-R1HOLLAND, KEVIN - 509-280-4117 / 02800540-928000-550-R1
LEG MSGS: Hertz rental car in Linda's and Pat's names - G4411900123 and G44145416E3
Leg
OF PA 8DATE:01/15/15 THU
TRAVEL TIME:0 Hour 38 Minute DISTANCE:222 Nautical Mile
DEPART TIME:02:46 PM PST ARRIVE TIME:03:24 PM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W
509.495.413360-705-3214360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800545-928000-550-R1
JOHNSON, DAN (DAN) - 509-720-1028 / 02800545-928000-550-R1
DRAKE, CHRIS CHRIS - 509-389-0521 / 02800545-928000-550-R1POWELL, JON JON - / 02800545-928000-550-R1KINNEY, SCOTT SCOTT - 509-688-5369 / 02800545-928000-550-R1
MOREHOUSE, JODY - 509-979-6674 / 02800545-928000-550-R11BRYAN, TODD - / 02800545-928000-550-R1HOLLAND, KEVIN - 509-280-4117 / 02800545-928000-550-R1
Page 9 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 277 of 419
Trip ID: VA01161 06/05/1 08:21 AM Page: 10
AIRCRAFT ROUTING
01/16/1 - 1/16/1
RIP PURPOSE:Safety Visit to Northwestern Energy
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 1DATE:01/16/1 FRI
TRAVEL TIME:0 Hour 40 Minute DISTANCE:230 Nautical Mile
DEPART TIME:09:10 AM PST ARRIVE TIME:10:50 AM MST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BUTTE, MT - KBTM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BERT MOONE
FBO:FBO:
PASSENGERS:ROBINSON, DAVID DAVE - 509-280-1038 / 95602810-588030-550-B5
Leg
OF PA 9DATE:01/16/15 FRI
TRAVEL TIME:0 Hour 49 Minute DISTANCE:230 Nautical Mile
DEPART TIME:11:38 AM MST ARRIVE TIME:11:27 AM PST
DEPART FROM:BUTTE, MT - KBTM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BERT MOONE AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA
7500 W PARK DRIVE GATE LSPOKANE, W
509.495.413
PASSENGERS:KANE, JIM - 208-929-0166 / 95602810-588030-550-B5
OLSON, KERMIT - 509-675-5276 / 95602810-588030-550-B5SCHLOTHAUER, CHRIS - 509-999-7836 / 95602810-588030-550-B5
HENDRY, KELLEY - 208-818-3017 / 95602810-588030-550-B5HYDE, DAN - 509-863-3774 / 95602810-588030-550-B5SANCHEZ, JIM RODNEY(JIM) - 509-990-1857 / 95602810-588030-550-B50COX, BRYAN - 509-290-2790 / 95602810-588030-550-B5STEINBRUECKER, KINGSLEY CHAD - 208-305-1039 / 95602810-588030-550-B5
GIBBS, ALICIA - / 95602810-588030-550-B5
Page 10 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 278 of 419
Trip ID: VA01211 06/05/1 08:21 AM Page: 11
AIRCRAFT ROUTING
01/21/1 - 1/21/1
RIP PURPOSE:Annual Update Meeting with WUTC Commissioners
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 4DATE:01/21/1 WED
TRAVEL TIME:0 Hour 45 Minute DISTANCE:222 Nautical Mile
DEPART TIME:11:34 AM PST ARRIVE TIME:12:19 PM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:AVISTA HANGA FBO:GLACIER JET CENTE7500 W PARK DRIVE GATE L 7645 OLD HWY 99 SSPOKANE, W OLYMPIA, WA 9850360-705-3214509.495.413 360-753-0083 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 02806136-928000-550-R1
MORRIS, SCOTT L - 509-979-6698 / 02806136-928000-550-R11
THIES, MARK T - 509-850-7832 / 02806136-928000-550-R1MEYER, DAVID J. - 509-220-7432 / 02806136-928000-550-R1
LEG MSGS: Need lunch from KGEG to KOLM.
Rental car reserved by Patty Hanson in Kelly's name - Confirmation #G4430741256
Leg 2
OF PA 4DATE:01/21/1 WED
TRAVEL TIME:0 Hour 36 Minutes DISTANCE:222 Nautical Mile
DEPART TIME:04:35 PM PST ARRIVE TIME:05:13 PM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA
7645 OLD HWY 99 SE 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 02806136-928000-550-R1
MORRIS, SCOTT L - 509-979-6698 / 02806136-928000-550-R1THIES, MARK T - 509-850-7832 / 02806136-928000-550-R1
MEYER, DAVID J. - 509-220-7432 / 02806136-928000-550-R1
Page 11 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 279 of 419
Trip ID: VA01261 06/05/1 08:21 AM Page: 12
AIRCRAFT ROUTING
01/26/1 - 1/26/1
RIP PURPOSE:Washington Roundtable Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 1DATE:01/26/1 MO
TRAVEL TIME:0 Hour 54 Minute DISTANCE:193 Nautical Mile
DEPART TIME:03:45 PM PST ARRIVE TIME:04:34 PM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO:LANDMARK FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900310-930200-550-E0
Leg 2
OF PA 1DATE:01/26/1 MO
TRAVEL TIME:0 Hour 33 Minute DISTANCE:193 Nautical Mile
DEPART TIME:08:53 PM PST ARRIVE TIME:09:26 PM PST
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA
8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600
206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900310-930200-550-E0
Page 1 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 280 of 419
Trip ID: VA01271 06/05/1 08:21 AM Page: 13
AIRCRAFT ROUTING
01/27/1 - 1/29/1
RIP PURPOSE:Safety Visit with APS and SRP
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 9DATE:01/27/1 TU
TRAVEL TIME:2 Hours 25 Minute DISTANCE:887 Nautical Mile
DEPART TIME:08:06 AM PST ARRIVE TIME:11:31 AM MST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:PHOENIX, AZ - KPH
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:PHOENIX SKY HARBOR INTERNATIO
FBO:LANDMARK FBO:CUTTER AVIATIO2802 E OLD TOWER ROADPHOENIX, AZ 85034602-273-123602-267-4029 - fa
PASSENGERS:COX, BRYAN - 509-290-2790 / 95602810-588030-550-B5
KANE, JIM - 208-929-0166 / 95602810-588030-550-B50
OLSON, KERMIT - 509-675-5276 / 95602810-588030-550-B5HENDRY, KELLEY - 208-818-3017 / 95602810-588030-550-B5SCHLOTHAUER, CHRIS - 509-999-7836 / 95602810-588030-550-B5
SANCHEZ, JIM RODNEY JIM - 509-990-1857 / 95602810-588030-550-B5HYDE, DAN - 509-863-3774 / 95602810-588030-550-B50
STEINBRUECKER, KINGSLEY (CHAD) - 208-305-1039 / 95602810-588030-550-B5DOTSON, HASSEL - 208-512-5688 / 95602810-588030-550-B5
Leg
OF PA 8DATE:01/29/15 THU
TRAVEL TIME:2 Hours 6 Minute DISTANCE:887 Nautical Mile
DEPART TIME:03:45 PM MST ARRIVE TIME:04:42 PM PST
DEPART FROM:PHOENIX, AZ - KPH ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:PHOENIX SKY HARBOR INTERNATIO AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CUTTER AVIATIO FBO:LANDMARK2802 E OLD TOWER ROAD
PHOENIX, AZ 85034602-273-123
602-267-4029 - fa
PASSENGERS:COX, BRYAN - 509-290-2790 / 95602810-588030-550-B5
KANE, JIM - 208-929-0166 / 95602810-588030-550-B5OLSON, KERMIT - 509-675-5276 / 95602810-588030-550-B5HENDRY, KELLEY - 208-818-3017 / 95602810-588030-550-B5
SCHLOTHAUER, CHRIS - 509-999-7836 / 95602810-588030-550-B5SANCHEZ, JIM RODNEY(JIM) - 509-990-1857 / 95602810-588030-550-B50HYDE, DAN - 509-863-3774 / 95602810-588030-550-B5STEINBRUECKER, KINGSLEY CHAD - 208-305-1039 / 95602810-588030-550-B5
Page 1 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 281 of 419
Trip ID: VA020414 06/05/1 08:21 AM Page: 1
AIRCRAFT ROUTING
02/04/1 - 2/04/1
RIP PURPOSE:
IRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 7DATE:02/04/14 TU
TRAVEL TIME:0 Hour 54 Minute DISTANCE:385 Nautical Mile
DEPART TIME:05:00 AM PST ARRIVE TIME:07:30 AM MST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BILLINGS, MT - KBIL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BILLINGS LOGAN INTERNATIONAL
FBO: FBO:EDWARDS JET CENTELOGAN FIELDBILLINGS, MT 5910406-252-050406-245-9491 - fa
PASSENGERS:DEMPSEY, TOM C -
MECHAM, MIKE -
MITCHELL, SCOTT (SCOTT) - / 41002100-5000000-550-K0SOYARS, DARRELL - THACKSTON, JASON -
WIGGINS, GREGORY - WUERST, JESSIE -
Leg
OF PA 7DATE:02/04/14 TU
TRAVEL TIME:1 Hour 6 Minute DISTANCE:385 Nautical Mile
DEPART TIME:05:05 PM MST ARRIVE TIME:06:00 PM PST
DEPART FROM:BILLINGS, MT - KBIL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BILLINGS LOGAN INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:EDWARDS JET CENTE FBO:AVISTA HANGA
LOGAN FIELD 7500 W PARK DRIVE GATE LBILLINGS, MT 5910 SPOKANE, W509.495.413406-252-050
406-245-9491 - fa
PASSENGERS:DEMPSEY, TOM C -
MECHAM, MIKE - MITCHELL, SCOTT (SCOTT) - / 41002100-5000000-550-K07
SOYARS, DARRELL - THACKSTON, JASON - WIGGINS, GREGORY -
WUERST, JESSIE -
Page 1 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 282 of 419
Trip ID: VA02051 06/05/1 08:21 AM Page: 15
AIRCRAFT ROUTING
02/05/1 - 2/05/1
RIP PURPOSE:Federal Reserve Board Meeting and WA GRC Updates to Staff and Public
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
SCOTT, BRIAN - Leg 1
OF PA 6DATE:02/05/1 TH
TRAVEL TIME:0 Hour 46 Minute DISTANCE:193 Nautical Mile
DEPART TIME:06:29 AM PST ARRIVE TIME:07:15 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO:LANDMARK FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09903691-930200-550-E0
NORWOOD, KELLY O. - 509-990-8144 / 02805810-928010-550-R11
MEYER, DAVID J. - 509-220-7432 / 02805810-928010-550-R1ANDREWS, ELIZABETH LIZ - / 02805810-928010-550-R1EHRBAR, PAT - 509-994-9074 / 02805810-928010-550-R1
MACHADO, DAVID DAVE - / 02805810-928010-550-R1
LEG MSGS: Minivan reserved by Patty Hanson in Pat's name - confirmation #G46939958B7
Leg 2
OF PA 1DATE:02/05/1 TH
TRAVEL TIME:0 Hour 35 Minutes DISTANCE:193 Nautical Mile
DEPART TIME:10:41 AM PST ARRIVE TIME:11:16 AM PST
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:LANDMARK
8285 PERIMETER RD SSEATTLE, WA 9810206-762-600
206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09903691-930200-550-E0
Leg
OF PA 1DATE:02/05/1 TH
TRAVEL TIME:0 Hour 49 Minute DISTANCE:193 Nautical Mile
DEPART TIME:12:34 PM PST ARRIVE TIME:01:23 PM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO:AVISTA HANGA FBO:CLAY LACY AVIATIO7500 W PARK DRIVE GATE L 8285 PERIMETER RD SPOKANE, W SEATTLE, WA 9810
206-762-600509.495.413 206-768-0888 - fa
PASSENGERS:ROBINSON, DAVID (DAVE) - 509-280-1038 / 02805810-928010-550-R1
Leg 4
Page 1 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 283 of 419
Trip ID: VA02051 06/05/1 08:21 AM Page: 16
AIRCRAFT ROUTING
02/05/1 - 2/05/1
RIP PURPOSE:Federal Reserve Board Meeting and WA GRC Updates to Staff and Public
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
SCOTT, BRIAN - Leg 4 continue
OF PA 5DATE:02/05/1 TH
TRAVEL TIME:0 Hour 30 Minute DISTANCE:193 Nautical Mile
DEPART TIME:03:28 PM PST ARRIVE TIME:04:01 PM PST
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600206-768-0888 - fax
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 02805810-928010-550-R1
MEYER, DAVID J. - 509-220-7432 / 02805810-928010-550-R11
ANDREWS, ELIZABETH (LIZ) - / 02805810-928010-550-R1EHRBAR, PAT - 509-994-9074 / 02805810-928010-550-R1MACHADO, DAVID DAVE - / 02805810-928010-550-R1
Page 1 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 284 of 419
Trip ID: VA02101 06/05/1 08:21 AM Page: 17
AIRCRAFT ROUTING
02/10/1 - 2/10/1
RIP PURPOSE:Meeting of Avista, Itron and Cisco smart city teams to explore possibilities
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
HARTNETT, JOHN - Leg 1
OF PA 9DATE:02/10/1 TU
TRAVEL TIME:1 Hour 39 Minute DISTANCE:645 Nautical Mile
DEPART TIME:07:31 AM PST ARRIVE TIME:09:10 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SAN JOSE, CA - KSJ
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:NORMAN Y MINETA SAN JOSE INTE
FBO:LANDMARK FBO:ATLANTIC AVIATIO1250 AVIATION AVSAN JOSE, CA 95110-112408-297-755408-280-5701 - fa
PASSENGERS:WOODWORTH, ROGER D - 509-981-2282 / 77700300-426120-550-M54
ROSENTRATER, HEATHER - 509-879-5320 / 77700300-426120-550-M54
KIRKEBY, CURT - 509-995-5099 / 77700300-426120-550-M54ZENTZ, KIM - 77700300-426120-550-M54DUQUETTE, DELORIS - 77700300-426120-550-M54
SIMMONS, SCOTT - 77700300-426120-550-M54CLAIBORN, CANDIS - 77700300-426120-550-M54
GUSTAFSON, MARK - 509-468-7910 / 77700300-426120-550-M54KENSOK, JAMES M JIM - 509-994-2892 / 77700300-426120-550-M54
LEG MSGS: Only need snacks, coffee, soda and water
Leg
OF PA 9DATE:02/10/1 TU
TRAVEL TIME:1 Hour 58 Minute DISTANCE:645 Nautical Mile
DEPART TIME:03:12 PM PST ARRIVE TIME:05:10 PM PST
DEPART FROM:SAN JOSE, CA - KSJ ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:NORMAN Y MINETA SAN JOSE INTE AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:ATLANTIC AVIATIO FBO:LANDMARK
1250 AVIATION AVSAN JOSE, CA 95110-112408-297-7552
408-280-5701 - fa
PASSENGERS:ROSENTRATER, HEATHER - 509-879-5320 / 77700300-426120-550-M54
KIRKEBY, CURT - 509-995-5099 / 77700300-426120-550-M54ZENTZ, KIM - 77700300-426120-550-M54
DUQUETTE, DELORIS - 77700300-426120-550-M54SIMMONS, SCOTT - 77700300-426120-550-M54CLAIBORN, CANDIS - 77700300-426120-550-M54
GUSTAFSON, MARK - 509-468-7910 / 77700300-426120-550-M54KENSOK, JAMES M(JIM) - 509-994-2892 / 77700300-426120-550-M54
GIBSON, JOHN - / 77700300-426120-550-M54
TRIP MSGS: LimoLink car service will take the group to and from the meeting. Reservation numbers 1979954-001and 1979954-002
Page 1 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 285 of 419
Trip ID: VA02121 06/05/1 08:21 AM Page: 18
AIRCRAFT ROUTING
02/12/1 - 2/12/1
RIP PURPOSE:Idaho Commissioner's Retirement Celebration
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
SCOTT, BRIAN - Leg 1
OF PA 7DATE:02/12/1 TH
TRAVEL TIME:0 Hour 44 Minute DISTANCE:249 Nautical Mile
DEPART TIME:02:29 PM PST ARRIVE TIME:04:13 PM MST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO:LANDMARK FBO:JACKSON JET CENTE3815 RICKENBACKER STREETBOISE, ID 8370208-383-330208-336-9082 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 09900549-426500-550-R1
MEYER, DAVID J. - 509-220-7432 / 09900549-426500-550-R11
GERVAIS, LINDA - 509-953-8057 / 09900549-426500-550-R1ANDREWS, ELIZABETH LIZ - / 09900549-426500-550-R1EHRBAR, PAT - 509-994-9074 / 09900549-426500-550-R1
MORRIS, SCOTT L - 509-979-6698 / 09900549-426500-550-R1ANDREA, MICHAEL - / 09900549-426500-550-R11
LEG MSGS: Two vehicles reserved by Patty Hanson - Minivan in Pat's name confirmation #G4732068414 and FullSize vehicle in Linda's name confirmation #G4739627F8.
Leg
OF PA 7DATE:02/12/1 TH
TRAVEL TIME:0 Hour 43 Minute DISTANCE:249 Nautical Mile
DEPART TIME:07:57 PM MST ARRIVE TIME:07:40 PM PST
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JACKSON JET CENTE FBO:LANDMARK
3815 RICKENBACKER STREETBOISE, ID 8370208-383-330
208-336-9082 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 09900549-426500-550-R1
MEYER, DAVID J. - 509-220-7432 / 09900549-426500-550-R11GERVAIS, LINDA - 509-953-8057 / 09900549-426500-550-R1
ANDREWS, ELIZABETH LIZ - / 09900549-426500-550-R1EHRBAR, PAT - 509-994-9074 / 09900549-426500-550-R1MORRIS, SCOTT L - 509-979-6698 / 09900549-426500-550-R1
ANDREA, MICHAEL - / 09900549-426500-550-R11
Page 18 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 286 of 419
Trip ID: VA02131 06/05/1 08:21 AM Page: 19
AIRCRAFT ROUTING
02/13/1 - 2/13/1
RIP PURPOSE:LIRAP Workshop #2 UE-140188 and UG-140189
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
SCOTT, BRIAN - Leg 1
OF PA 9DATE:02/13/1 FRI
TRAVEL TIME:0 Hour 42 Minute DISTANCE:193 Nautical Mile
DEPART TIME:07:17 AM PST ARRIVE TIME:07:59 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO:LANDMARK FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 09900549-426400-550-R1
DRAKE, CHRIS (CHRIS) - 509-389-0521 / 09900549-426400-550-R11
MATTHEWS, ANA (ANA) - 509-869-1688 / 09900549-426400-550-R1MANSKEY, WENDY WENDY - / 09900549-426400-550-R1HONEKAMP, JULIE - 09900549-426400-550-R1
WELTZ, CAROL - 09900549-426400-550-R1FEIN, AL - 09900549-426400-550-R11
BATTIN, DENA - 09900549-426400-550-R1FINESILVER, RYAN RYAN - / 09900549-426400-550-R1
LEG MSGS: Two minivans reserved by Wendy Manskey. Chris' confirmation #G4770356863 and Linda's
confirmation #G4710714998
Leg
OF PA 9DATE:02/13/1 FRI
TRAVEL TIME:0 Hour 30 Minute DISTANCE:193 Nautical Mile
DEPART TIME:04:37 PM PST ARRIVE TIME:05:09 PM PST
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA8285 PERIMETER RD 7500 W PARK DRIVE GATE L
SEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600206-768-0888 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 09900549-426400-550-R1
DRAKE, CHRIS CHRIS - 509-389-0521 / 09900549-426400-550-R1MATTHEWS, ANA ANA - 509-869-1688 / 09900549-426400-550-R1MANSKEY, WENDY WENDY - / 09900549-426400-550-R1
HONEKAMP, JULIE - 09900549-426400-550-R11WELTZ, CAROL - 09900549-426400-550-R1FEIN, AL - 09900549-426400-550-R1
BATTIN, DENA - 09900549-426400-550-R1FINESILVER, RYAN RYAN - / 09900549-426400-550-R1
Page 1 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 287 of 419
Trip ID: VA02191 06/05/1 08:21 AM Page: 20
AIRCRAFT ROUTING
02/19/1 - 2/19/1
RIP PURPOSE:Washington Roundtable Olympia Visit
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 2DATE:02/19/1 TH
TRAVEL TIME:0 Hour 47 Minute DISTANCE:222 Nautical Mile
DEPART TIME:06:49 AM PST ARRIVE TIME:07:36 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:LANDMARK FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900310-930200-550-E0
SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 09900310-930200-550-E01
LEG MSGS: Need breakfast from KGEG to KOLM
Leg 2
OF PA 2DATE:02/19/1 TH
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:04:24 PM PST ARRIVE TIME:05:05 PM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTER FBO:LANDMARK7645 OLD HWY 99 S
OLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900310-930200-550-E0
SPRAGUE, KEVIN COLLINS COLLINS - 360-951-4540 / 09900310-930200-550-E0
Page 20 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 288 of 419
Trip ID: VA022014 06/05/1 08:21 AM Page: 21
AIRCRAFT ROUTING
02/20/1 - 2/20/1
RIP PURPOSE:Meeting with Washington Staff Regarding General Rate Case
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 7DATE:02/20/14 TH
TRAVEL TIME:0 Hour 54 Minute DISTANCE:222 Nautical Mile
DEPART TIME:08:00 AM PST ARRIVE TIME:08:51 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:ANDREWS, ELIZABETH (LIZ) - / 02805810-928010-550-R1
EHRBAR, PAT -
FINESILVER, RYAN - KNOX, TARA - LABOLLE, LARRY -
SCHUH, KAREN - SMITH, JENNIFER -
Leg
OF PA 7DATE:02/20/14 TH
TRAVEL TIME:0 Hour 36 Minute DISTANCE:222 Nautical Mile
DEPART TIME:04:00 PM PST ARRIVE TIME:04:36 PM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA
7645 OLD HWY 99 S 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:ANDREWS, ELIZABETH LIZ - / 02805810-928010-550-R1
EHRBAR, PAT - FINESILVER, RYAN -
KNOX, TARA - LABOLLE, LARRY - SCHUH, KAREN -
SMITH, JENNIFER -
TRIP MSGS: Rental van in Pat and Liz's name, reserved by Wendy Manskey, Confirmation number
#G1133064481(Pat) and G1162594124(Liz)
Page 21 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 289 of 419
Trip ID: VA02241 06/05/1 08:21 AM Page: 22
AIRCRAFT ROUTING
02/24/1 - 2/24/1
RIP PURPOSE:Natural Gas IRP and Natural Gas Quarterly Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 5DATE:02/24/1 TU
TRAVEL TIME:0 Hour 50 Minute DISTANCE:279 Nautical Mile
DEPART TIME:07:51 AM PST ARRIVE TIME:08:41 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO:LANDMARK FBO:
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 06805169-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 06805169-928000-550-R1PARDEE, TOM - / 06805169-928000-550-R1MOREHOUSE, JODY - 509-979-6674 / 06805169-928000-550-R11
MACHADO, DAVID (DAVE) - / 06805169-928000-550-R1
LEG MSGS: Mini van reserved by Patty Hanson in Pat's name - confirmation #9CPTC9
Leg
OF PA 5DATE:02/24/1 TU
TRAVEL TIME:0 Hour 46 Minute DISTANCE:279 Nautical Mile
DEPART TIME:12:02 PM PST ARRIVE TIME:12:48 PM PST
DEPART FROM:SALEM, OR - KSL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:LANDMARK
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 06805169-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 06805169-928000-550-R1PARDEE, TOM - / 06805169-928000-550-R1
MOREHOUSE, JODY - 509-979-6674 / 06805169-928000-550-R1MACHADO, DAVID (DAVE) - / 06805169-928000-550-R1
LEG MSGS: Need lunch from KSLE to KGEG (Annette needs a gluten free meal)
Page 2 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 290 of 419
Trip ID: VA022514 06/05/1 08:21 AM Page: 23
AIRCRAFT ROUTING
02/25/1 - 2/25/1
RIP PURPOSE:Washington Roundtable meeting with Natural Gas IRP TAC.
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 8DATE:02/25/14 TU
TRAVEL TIME:0 Hour 45 Minute DISTANCE:222 Nautical Mile
DEPART TIME:07:30 AM PST ARRIVE TIME:08:15 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:BONFIELD, SHAWN -
BRANDON, ANNETTE -
BROWNE, TERRENCE - FORSYTH, GRANT - MORRIS, SCOTT -
PARDEE, TOM - PENDERGRAFT, LAUREN -
TRABUN, STEVE -
Leg
OF PA 6DATE:02/25/14 TU
TRAVEL TIME:0 Hour 21 Minute DISTANCE:84 Nautical Mile
DEPART TIME:08:30 AM PST ARRIVE TIME:08:51 AM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:PORTLAND, OR - KPD
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:PORTLAND INTERNATIONAL
FBO:GLACIER JET CENTE FBO:ATLANTIC AVIATIO7645 OLD HWY 99 S 7527 NE AIRPORT WAOLYMPIA, WA 9850 PORTLAND, OR 9721
503-331-422360-705-3214 503-331-4273 - fa360-753-0083 - fa
PASSENGERS:BONFIELD, SHAWN -
BRANDON, ANNETTE -
BROWNE, TERRENCE - FORSYTH, GRANT - PARDEE, TOM -
PENDERGRAFT, LAUREN -
Leg 3
OF PA 6DATE:02/25/14 TU
TRAVEL TIME:0 Hour 18 Minute DISTANCE:84 Nautical Mile
DEPART TIME:03:45 PM PST ARRIVE TIME:04:03 PM PST
DEPART FROM:PORTLAND, OR - KPD ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:PORTLAND INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:ATLANTIC AVIATION FBO:GLACIER JET CENTE7527 NE AIRPORT WA 7645 OLD HWY 99 S
PORTLAND, OR 9721 OLYMPIA, WA 9850360-705-3214503-331-422 360-753-0083 - fa503-331-4273 - fa
This le continues on the next pa e
Page 2 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 291 of 419
Trip ID: VA022514 06/05/1 08:21 AM Page: 2
AIRCRAFT ROUTING
02/25/1 - 2/25/1
RIP PURPOSE:Washington Roundtable meeting with Natural Gas IRP TAC.
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 3 continue
PASSENGERS:BONFIELD, SHAWN -
BRANDON, ANNETTE - BROWNE, TERRENCE -
FORSYTH, GRANT - PARDEE, TOM - PENDERGRAFT, LAUREN -
Leg 4
OF PA 8DATE:02/25/14 TU
TRAVEL TIME:0 Hour 42 Minutes DISTANCE:222 Nautical Mile
DEPART TIME:04:30 PM PST ARRIVE TIME:05:08 PM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA
7645 OLD HWY 99 SE 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:BONFIELD, SHAWN -
BRANDON, ANNETTE - BROWNE, TERRENCE -
FORSYTH, GRANT - MORRIS, SCOTT - PARDEE, TOM -
PENDERGRAFT, LAUREN - TRABUN, STEVE -
TRIP MSGS: Need breakfast from GEG to OLM
Page 2 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 292 of 419
Trip ID: VA02251 06/05/1 08:21 AM Page: 25
AIRCRAFT ROUTING
02/25/1 - 2/25/1
RIP PURPOSE:Colstrip Fuel Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
SCOTT, BRIAN - Leg 1
OF PA 2DATE:02/25/1 WED
TRAVEL TIME:0 Hour 57 Minute DISTANCE:385 Nautical Mile
DEPART TIME:05:33 AM PST ARRIVE TIME:07:30 AM MST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BILLINGS, MT - KBIL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BILLINGS LOGAN INTERNATIONAL
FBO:LANDMARK FBO:
PASSENGERS:THACKSTON, JASON R - 509-290-4590 / 09902811-926102-550-E14
SOYARS, DARRELL DARRELL - 509-435-6464 / 09902811-926102-550-E14
Leg
OF PA 3DATE:02/25/1 WED
TRAVEL TIME:1 Hour 7 Minute DISTANCE:385 Nautical Mile
DEPART TIME:02:15 PM MST ARRIVE TIME:02:22 PM PST
DEPART FROM:BILLINGS, MT - KBIL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BILLINGS LOGAN INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:EDWARDS JET CENTE FBO:LANDMARKLOGAN FIELD
BILLINGS, MT 5910406-252-050406-245-9491 - fa
PASSENGERS:THACKSTON, JASON R - 509-290-4590 / 09902811-926102-550-E14
DEMPSEY, TOM C TOM - 509-688-9716 / 09902811-926102-550-E14
SOYARS, DARRELL DARRELL - 509-435-6464 / 09902811-926102-550-E14
Page 2 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 293 of 419
Trip ID: VA02271 06/05/1 08:21 AM Page: 26
AIRCRAFT ROUTING
02/27/1 - 2/27/1
RIP PURPOSE:Employee Meetings
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 4DATE:02/27/1 FRI
TRAVEL TIME:0 Hour 14 Minute DISTANCE:55 Nautical Mile
DEPART TIME:06:49 AM PST ARRIVE TIME:07:03 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO:LANDMARK FBO:INTER-STATE AV2601 AIRPORT COMPLEX PULLMAN, WA 9916509-332-659509-334-1751 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900162-921000-550-E0
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E01
FELTES, KAREN S - 509-290-2612 / 09900162-921000-550-E0KOLBET, DAN - 509-434-8621 / 09900162-921000-550-E0
Leg
OF PA 4DATE:02/27/15 FRI
TRAVEL TIME:0 Hour 7 Minute DISTANCE:22 Nautical Mile
DEPART TIME:08:59 AM PST ARRIVE TIME:09:06 AM PST
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:LEWISTON, ID - KLW
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:LEWISTON-NEZ PERCE COUNT
FBO:INTER-STATE AV FBO:STOUT FLYING SV
2601 AIRPORT COMPLEX 406 BURRELLPULLMAN, WA 9916 LEWISTON, ID 8350208-743-840509-332-659
208-798-3284 - fa509-334-1751 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900162-921000-550-E0
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E0FELTES, KAREN S - 509-290-2612 / 09900162-921000-550-E0
KOLBET, DAN - 509-434-8621 / 09900162-921000-550-E0
Leg 3
OF PA 4DATE:02/27/1 FRI
TRAVEL TIME:0 Hour 56 Minutes DISTANCE:347 Nautical Mile
DEPART TIME:11:57 AM PST ARRIVE TIME:12:53 PM PST
DEPART FROM:LEWISTON, ID - KLW ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:LEWISTON-NEZ PERCE COUNT AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO:STOUT FLYING SV FBO:JET CENTER MF406 BURRELL 5000 CIRRUS DLEWISTON, ID 8350 MEDFORD, OR 97504
800-359-029208-743-840 541-772-2759 - fa208-798-3284 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900162-921000-550-E0
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E0
FELTES, KAREN S - 509-290-2612 / 09900162-921000-550-E0KOLBET, DAN - 509-434-8621 / 09900162-921000-550-E0
Leg 4
Page 2 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 294 of 419
Trip ID: VA02271 06/05/1 08:21 AM Page: 27
AIRCRAFT ROUTING
02/27/1 - 2/27/1
RIP PURPOSE:Employee Meetings
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 4 continue
OF PA 5DATE:02/27/1 FRI
TRAVEL TIME:1 Hour 0 Minute DISTANCE:387 Nautical Mile
DEPART TIME:02:48 PM PST ARRIVE TIME:03:48 PM PST
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JET CENTER MF FBO:LANDMARK5000 CIRRUS DMEDFORD, OR 97504800-359-029541-772-2759 - fax
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900162-921000-550-E0
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E01
FELTES, KAREN S - 509-290-2612 / 09900162-921000-550-E0JOHNSON, DAN DAN - 509-720-1028 / 09900162-921000-550-E0KOLBET, DAN - 509-434-8621 / 09900162-921000-550-E0
Page 2 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 295 of 419
Trip ID: VA022814 06/05/1 08:21 AM Page: 28
AIRCRAFT ROUTING
02/28/1 - 2/28/1
RIP PURPOSE:Employee Meetings.
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 5DATE:02/28/14 FRI
TRAVEL TIME:0 Hour 18 Minute DISTANCE:55 Nautical Mile
DEPART TIME:06:00 AM PST ARRIVE TIME:08:00 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO: FBO:INTER-STATE AV2601 AIRPORT COMPLEX PULLMAN, WA 9916509-332-659509-334-1751 - fa
PASSENGERS:MORRIS, SCOTT -
NORWOOD, KELLY -
SMITH, BRANDI - THACKSTON, JASON - VERMILLION, DENNIS -
Leg
OF PA 5DATE:02/28/14 FRI
TRAVEL TIME:0 Hour 18 Minute DISTANCE:22 Nautical Mile
DEPART TIME:10:00 AM PST ARRIVE TIME:10:30 AM PST
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:LEWISTON, ID - KLW
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:LEWISTON-NEZ PERCE COUNT
FBO:INTER-STATE AV FBO:STOUT FLYING SV2601 AIRPORT COMPLEX 406 BURRELLPULLMAN, WA 9916 LEWISTON, ID 8350
208-743-840509-332-659 208-798-3284 - fa509-334-1751 - fa
PASSENGERS:MORRIS, SCOTT -
NORWOOD, KELLY -
SMITH, BRANDI - THACKSTON, JASON - VERMILLION, DENNIS -
Leg
OF PA 5DATE:02/28/14 FRI
TRAVEL TIME:1 Hour 0 Minute DISTANCE:347 Nautical Mile
DEPART TIME:12:00 PM PST ARRIVE TIME:01:30 PM PST
DEPART FROM:LEWISTON, ID - KLW ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:LEWISTON-NEZ PERCE COUNT AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO:STOUT FLYING SV FBO:JET CENTER MF
406 BURRELL 5000 CIRRUS DLEWISTON, ID 8350 MEDFORD, OR 97504
800-359-029208-743-840 541-772-2759 - fa208-798-3284 - fax
PASSENGERS:MORRIS, SCOTT -
NORWOOD, KELLY - SMITH, BRANDI -
Additional Passengers for this leg continue on the next page
Page 28 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 296 of 419
Trip ID: VA022814 06/05/1 08:21 AM Page: 29
AIRCRAFT ROUTING
02/28/1 - 2/28/1
RIP PURPOSE:Employee Meetings.
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 3 continue
PASSENGERS:THACKSTON, JASON -
VERMILLION, DENNIS -
Leg 4
OF PA 8DATE:02/28/14 FRI
TRAVEL TIME:1 Hour 0 Minute DISTANCE:387 Nautical Mile
DEPART TIME:03:00 PM PST ARRIVE TIME:04:30 PM PST
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JET CENTER MFR FBO:AVISTA HANGA5000 CIRRUS D 7500 W PARK DRIVE GATE L
MEDFORD, OR 97504 SPOKANE, W509.495.413800-359-029541-772-2759 - fa
PASSENGERS:BUSHNELL, TERRY -
HOWELL, DAVID - MORRIS, SCOTT - NORWOOD, KELLY -
ROGERS, CINDY - SMITH, BRANDI - THACKSTON, JASON -
VERMILLION, DENNIS -
TRIP MSGS: Transportation provided by each office.
Page 2 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 297 of 419
Trip ID: VA030314 06/05/1 08:21 AM Page: 30
AIRCRAFT ROUTING
03/03/1 - 3/06/1
RIP PURPOSE:EEI Spring Conference
AIRCRAFT:N202AV CE-65 PILOTS:
Leg 1
OF PA 3DATE:03/03/14 MO
TRAVEL TIME:2 Hours 33 Minute DISTANCE:1211 Nautical Mile
DEPART TIME:08:30 AM PST ARRIVE TIME:01:03 PM CST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:MADISON, WI - KMS
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO
FBO:FBO:WISCONSIN AV3606 CORBEN CT DANE CO REGLMADISON, WI 53704608-268-500
608-268-5037 - fa
PASSENGERS:CHRISTIE, KEVIN J. - 509-714-3587 / 09800310-930200-550-E0
VERMILLION, DENNIS - SPRAGUE, COLLINS -
LEG MSGS: Need breakfast from KGEG to KMSN; Need lunch from KMSN to KIAD; Need lunch from KIAD toKMSN; Need snacks from KMSN to KGEG
Leg
OF PA 3DATE:03/03/14 MO
TRAVEL TIME:1 Hour 29 Minute DISTANCE:593 Nautical Mile
DEPART TIME:01:45 PM CST ARRIVE TIME:04:14 PM EST
DEPART FROM:MADISON, WI - KMS ARRIVE AT:WASHINGTON, VA - KIAD
AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO AIRPORT NAME:WASHINGTON DULLES INTERNATION
FBO:WISCONSIN AV FBO:LANDMARK AVIATIO
3606 CORBEN CT DANE CO REGL 23411 AUTO PILOT DMADISON, WI 53704 DULLES, VA 2016703-661-015608-268-500
703-661-0152 - fa608-268-5037 - fax
PASSENGERS:CHRISTIE, KEVIN J. - 509-714-3587 / 09800310-930200-550-E0
VERMILLION, DENNIS - SPRAGUE, COLLINS -
Leg
OF PA 3DATE:03/06/14 TH
TRAVEL TIME:1 Hour 37 Minute DISTANCE:593 Nautical Mile
DEPART TIME:01:30 PM EST ARRIVE TIME:02:07 PM CST
DEPART FROM:WASHINGTON, VA - KIAD ARRIVE AT:MADISON, WI - KMS
AIRPORT NAME:WASHINGTON DULLES INTERNATION AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO
FBO:LANDMARK AVIATIO FBO:WISCONSIN AV
23411 AUTO PILOT D 3606 CORBEN CT DANE CO REGLDULLES, VA 2016 MADISON, WI 53704608-268-500703-661-015
608-268-5037 - fa703-661-0152 - fa
PASSENGERS:CHRISTIE, KEVIN J. - 509-714-3587 / 09800310-930200-550-E0
VERMILLION, DENNIS - SPRAGUE, COLLINS -
Leg 4
Page 30 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 298 of 419
Trip ID: VA030314 06/05/1 08:21 AM Page: 31
AIRCRAFT ROUTING
03/03/1 - 3/06/1
RIP PURPOSE:EEI Spring Conference
AIRCRAFT:N202AV CE-65 PILOTS:
Leg 4 continued
OF PA 3DATE:03/06/14 TH
TRAVEL TIME:3 Hours 7 Minute DISTANCE:1211 Nautical Mile
DEPART TIME:02:45 PM CST ARRIVE TIME:03:52 PM PST
DEPART FROM:MADISON, WI - KMS ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGION AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:WISCONSIN AV FBO:AVISTA HANGA3606 CORBEN CT DANE CO REGL 7500 W PARK DRIVE GATE L
MADISON, WI 53704 SPOKANE, W509.495.413608-268-500
608-268-5037 - fa
PASSENGERS:CHRISTIE, KEVIN J. - 509-714-3587 / 09800310-930200-550-E0
VERMILLION, DENNIS - SPRAGUE, COLLINS -
TRIP MSGS: 3/3 - Carey car has been reserved by Linda Williams - confirmation #WA7977197-01 - pickup atLandmark Aviation with drop off at Mandarin Oriental Hotel.
3/6 - Carey car has been reserved by Linda Williams - confirmation #WA7977212-01 - pickup atMandarin Oriental Hotel with drop off at Landmark Aviation.
Page 31 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 299 of 419
Trip ID: VA03031 06/05/1 08:21 AM Page: 32
AIRCRAFT ROUTING
03/03/1 - 3/04/1
RIP PURPOSE:UBS Conference
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
SCOTT, BRIAN - Leg 1
OF PA 2DATE:03/03/1 TU
TRAVEL TIME:1 Hour 58 Minute DISTANCE:842 Nautical Mile
DEPART TIME:08:14 AM PST ARRIVE TIME:12:12 PM CST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:LANDMARK FBO:FARGO JET CENTE3801 20TH ST FARGO, ND 5810701-235-360701-237-6887 - fa
PASSENGERS:THIES, MARK T - 509-850-7832 / 09903691-930200-550-E0
LANG, JASON - 509-995-8248 / 09903691-930200-550-E01
LEG MSGS: Need breakfast from KGEG to KFAR
Leg 2
OF PA 2DATE:03/03/1 TU
TRAVEL TIME:2 Hours 11 Minute DISTANCE:1116 Nautical Mile
DEPART TIME:12:44 PM CST ARRIVE TIME:03:55 PM EST
DEPART FROM:FARGO, ND - KFA ARRIVE AT:BEDFORD, MA - KBED
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:LAURENCE G HANSCOM FIELD
FBO:FARGO JET CENTER FBO:JET AVIATIO3801 20TH ST 380 HANSCOM DR HANSCOM FLD
FARGO, ND 5810 BEDFORD, MA 0173781-274-003701-235-360 781-274-6573 - fa701-237-6887 - fa
PASSENGERS:THIES, MARK T - 509-850-7832 / 09903691-930200-550-E0
LANG, JASON - 509-995-8248 / 09903691-930200-550-E0
LEG MSGS: Need lunch from KFAR to KBED
Leg 3
OF PA 2DATE:03/04/1 WED
TRAVEL TIME:3 Hours 41 Minute DISTANCE:1116 Nautical Mile
DEPART TIME:06:12 PM EST ARRIVE TIME:08:53 PM CST
DEPART FROM:BEDFORD, MA - KBED ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:LAURENCE G HANSCOM FIELD AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:JET AVIATIO FBO:FARGO JET CENTE380 HANSCOM DR HANSCOM FLD 3801 20TH ST
BEDFORD, MA 0173 FARGO, ND 5810701-235-360781-274-003 701-237-6887 - fa781-274-6573 - fa
PASSENGERS:THIES, MARK T - 509-850-7832 / 09903691-930200-550-E0
LANG, JASON - 509-995-8248 / 09903691-930200-550-E0
LEG MSGS: Need dinner from KBED to KFAR
Leg 4
Page 3 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 300 of 419
Trip ID: VA03031 06/05/1 08:21 AM Page: 33
AIRCRAFT ROUTING
03/03/1 - 3/04/1
RIP PURPOSE:UBS Conference
AIRCRAFT:N202AV CE-65 PILOTS:SCOTT, BRIAN -
ROBINSON, DAVE - Leg 4 continue
OF PA 2DATE:03/04/1 WED
TRAVEL TIME:2 Hours 9 Minute DISTANCE:842 Nautical Mile
DEPART TIME:09:18 PM CST ARRIVE TIME:09:27 PM PST
DEPART FROM:FARGO, ND - KFA ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:FARGO JET CENTE FBO:LANDMARK3801 20TH ST FARGO, ND 5810701-235-360701-237-6887 - fax
PASSENGERS:THIES, MARK T - 509-850-7832 / 09903691-930200-550-E0
LANG, JASON - 509-995-8248 / 09903691-930200-550-E01
Page 3 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 301 of 419
Trip ID: VA03051 06/05/1 08:21 AM Page: 3
AIRCRAFT ROUTING
03/05/1 - 3/06/1
RIP PURPOSE:Meeting in Scottsdale
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 1DATE:03/05/1 TH
TRAVEL TIME:0 Hour 41 Minute DISTANCE:193 Nautical Mile
DEPART TIME:01:40 PM PST ARRIVE TIME:02:21 PM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO:LANDMARK AVIATIO FBO:CLAY LACY AVIATIO8136 W PILOT D 8285 PERIMETER RD SPOKANE, WA 99224 SEATTLE, WA 9810206-762-600509-455-5204 206-768-0888 - fa509-455-5272 - fax
PASSENGERS:THIES, MARK T - 509-850-7832 / 09903691-930200-550-E0
Leg 2
OF PA 2DATE:03/05/1 TH
TRAVEL TIME:2 Hours 18 Minute DISTANCE:957 Nautical Mile
DEPART TIME:02:40 PM PST ARRIVE TIME:05:55 PM MST
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SCOTTSDALE, AZ - KSDL
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SCOTTSDAL
FBO:CLAY LACY AVIATIO FBO:LANDMARK AVIATIO
8285 PERIMETER RD 14600 N AIRPORT DSEATTLE, WA 9810 SCOTTSDALE, AZ 8526480-443-729206-762-600
480-443-7227 - fa206-768-0888 - fa
PASSENGERS:THIES, MARK T - 509-850-7832 / 09903691-930200-550-E0
MORRIS, SCOTT L - 509-979-6698 / 09903691-930200-550-E0
Leg 3
OF PA 1DATE:03/06/1 FRI
TRAVEL TIME:2 Hours 12 Minutes DISTANCE:877 Nautical Mile
DEPART TIME:12:50 PM MST ARRIVE TIME:02:00 PM PST
DEPART FROM:SCOTTSDALE, AZ - KSDL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SCOTTSDAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:LANDMARK AVIATIO FBO:AVISTA HANGA14600 N AIRPORT DR 7500 W PARK DRIVE GATE L
SCOTTSDALE, AZ 8526 SPOKANE, W509.495.413480-443-729480-443-7227 - fa
PASSENGERS:THIES, MARK T - 509-850-7832 / 09903691-930200-550-E0
TRIP MSGS: Scott will fly to Seattle in the morning for a Federal Reserve Board Meeting. Mark will fly on theCompany plane to Seattle in the afternoon to get Scott and then the plane will head to Scottsdale.
Page 3 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 302 of 419
Trip ID: VA030714 06/05/1 08:21 AM Page: 35
AIRCRAFT ROUTING
03/07/1 - 3/07/1
RIP PURPOSE:
IRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 8DATE:03/07/14 FRI
TRAVEL TIME:0 Hour 48 Minute DISTANCE:222 Nautical Mile
DEPART TIME:08:30 AM PST ARRIVE TIME:09:18 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:ANDREWS, ELIZABETH (LIZ) - / 02805810-928010-550-R1
EHRBAR, PAT -
GERVAIS, LINDA - KALICH, CLINT - JOHNSON, BILL -
LA BOLLE, LARRY - MEYER, DAVID -
NORWOOD, KELLY -
Leg
OF PA 8DATE:03/07/14 FRI
TRAVEL TIME:0 Hour 39 Minute DISTANCE:222 Nautical Mile
DEPART TIME:12:30 PM PST ARRIVE TIME:01:09 PM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W
509.495.413360-705-3214360-753-0083 - fa
PASSENGERS:ANDREWS, ELIZABETH (LIZ) - / 02805810-928010-550-R11
EHRBAR, PAT -
GERVAIS, LINDA - KALICH, CLINT - JOHNSON, BILL -
LA BOLLE, LARRY - MEYER, DAVID -
NORWOOD, KELLY -
Page 3 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 303 of 419
Trip ID: VA03091 06/05/1 08:21 AM Page: 36
AIRCRAFT ROUTING
03/09/1 - 3/09/1
RIP PURPOSE:Visit to Sacramento Municipal Utility District
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 8DATE:03/09/1 MO
TRAVEL TIME:1 Hour 24 Minute DISTANCE:564 Nautical Mile
DEPART TIME:06:34 AM PDT ARRIVE TIME:08:00 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SACRAMENTO, CA - KSMF
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SACRAMENTO INTERNATIONAL
FBO:LANDMARK AVIATIO FBO:SACRAMENTO INTL JET8136 W PILOT D 5885 FLIGHTLINE CIRCLSPOKANE, WA 99224 SACRAMENTO, CA 9583916-428-829509-455-5204 916-646-6747 - fa509-455-5272 - fax
PASSENGERS:ROSENTRATER, HEATHER - 509-879-5320 / 02806160-588000-550-Z0
KIRKEBY, CURT - 509-995-5099 / 02806160-588000-550-Z08
MALENSKY, VERN - 208-582-0694 / 02806160-588000-550-Z0CHAMBERS, SEAN - 509-981-4272 / 02806160-588000-550-Z0DIEDESCH, MICHAEL MIKE - 509-990-2934 / 02806160-588000-550-Z0
GUSTAFSON, MARK - 509-468-7910 / 02806160-588000-550-Z0BROEMELING, MIKE (MIKE) - 509-939-0357 / 02806160-588000-550-Z08
PITTS, JASON - 509-979-2667 / 02806160-588000-550-Z0
Leg
OF PA 6DATE:03/09/1 MO
TRAVEL TIME:1 Hour 28 Minute DISTANCE:564 Nautical Mile
DEPART TIME:04:39 PM PDT ARRIVE TIME:06:07 PM PDT
DEPART FROM:SACRAMENTO, CA - KSMF ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SACRAMENTO INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:SACRAMENTO INTL JET FBO:AVISTA HANGA5885 FLIGHTLINE CIRCL 7500 W PARK DRIVE GATE LSACRAMENTO, CA 9583 SPOKANE, W
509.495.413916-428-829916-646-6747 - fa
PASSENGERS:ROSENTRATER, HEATHER - 509-879-5320 / 02806160-588000-550-Z08
KIRKEBY, CURT - 509-995-5099 / 02806160-588000-550-Z08
DIEDESCH, MICHAEL (MIKE) - 509-990-2934 / 02806160-588000-550-Z0GUSTAFSON, MARK - 509-468-7910 / 02806160-588000-550-Z0BROEMELING, MIKE MIKE - 509-939-0357 / 02806160-588000-550-Z0
PITTS, JASON - 509-979-2667 / 02806160-588000-550-Z0
Page 3 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 304 of 419
Trip ID: VA03101 06/05/1 08:21 AM Page: 37
AIRCRAFT ROUTING
03/10/1 - 3/10/1
RIP PURPOSE:WA GRC meeting. Steve Trabun is going to Olympia for a legislative meeting.
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
SCOTT, BRIAN - Leg 1
OF PA 5DATE:03/10/1 TU
TRAVEL TIME:0 Hour 46 Minute DISTANCE:222 Nautical Mile
DEPART TIME:07:58 AM PDT ARRIVE TIME:08:44 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:LANDMARK AVIATIO FBO:GLACIER JET CENTE8136 W PILOT D 7645 OLD HWY 99 SSPOKANE, WA 99224 OLYMPIA, WA 9850360-705-3214509-455-5204 360-753-0083 - fa509-455-5272 - fax
PASSENGERS:ANDREWS, ELIZABETH (LIZ) - / 02805810-928010-550-R1
KNOX, TARA - / 02805810-928010-550-R11
SCHUH, KAREN - 509-995-6652 / 02805810-928010-550-R1FINESILVER, RYAN RYAN - / 02805810-928010-550-R1TRABUN, STEVE - 509-995-4077 / 77700521-426400-550-J5
LEG MSGS: One full-size vehicle reserved by Patty Hanson in Liz's name - confirmation #G4911944170
Leg
OF PA 5DATE:03/10/15 TUE
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:04:17 PM PDT ARRIVE TIME:05:00 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE L
OLYMPIA, WA 98501 SPOKANE, W509.495.413360-705-3214360-753-0083 - fa
PASSENGERS:ANDREWS, ELIZABETH (LIZ) - / 02805810-928010-550-R1
KNOX, TARA - / 02805810-928010-550-R1SCHUH, KAREN - 509-995-6652 / 02805810-928010-550-R1FINESILVER, RYAN RYAN - / 02805810-928010-550-R1
TRABUN, STEVE - 509-995-4077 / 77700521-426400-550-J5
Page 3 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 305 of 419
Trip ID: VA03161 06/05/1 08:21 AM Page: 38
AIRCRAFT ROUTING
03/16/1 - 3/18/1
RIP PURPOSE:EEI Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 3DATE:03/16/1 MO
TRAVEL TIME:2 Hours 25 Minute DISTANCE:1211 Nautical Mile
DEPART TIME:09:22 AM PDT ARRIVE TIME:01:47 PM CDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:MADISON, WI - KMS
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO
FBO:LANDMARK FBO:WISCONSIN AV3606 CORBEN CT DANE CO REGL
MADISON, WI 53704608-268-500608-268-5037 - fa
PASSENGERS:THACKSTON, JASON R - 509-290-4590 / 09800310-930200-550-E0
SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 09800310-930200-550-E01
VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E0
LEG MSGS: Need breakfast from KGEG to KMSN
Leg
OF PA 3DATE:03/16/1 MO
TRAVEL TIME:1 Hour 24 Minute DISTANCE:593 Nautical Mile
DEPART TIME:02:21 PM CDT ARRIVE TIME:04:45 PM EDT
DEPART FROM:MADISON, WI - KMS ARRIVE AT:WASHINGTON, VA - KIAD
AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO AIRPORT NAME:WASHINGTON DULLES INTERNATION
FBO:WISCONSIN AV FBO:LANDMARK AVIATIO
3606 CORBEN CT DANE CO REGL 23411 AUTO PILOT DMADISON, WI 53704 DULLES, VA 2016703-661-015608-268-500
703-661-0152 - fa608-268-5037 - fax
PASSENGERS:THACKSTON, JASON R - 509-290-4590 / 09800310-930200-550-E0
SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 09800310-930200-550-E0VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E0
LEG MSGS: Need lunch from KMSN to KIAD
Leg
OF PA 3DATE:03/18/1 WED
TRAVEL TIME:1 Hour 54 Minute DISTANCE:593 Nautical Mile
DEPART TIME:11:52 AM EDT ARRIVE TIME:12:46 PM CDT
DEPART FROM:WASHINGTON, VA - KIAD ARRIVE AT:MADISON, WI - KMS
AIRPORT NAME:WASHINGTON DULLES INTERNATION AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO
FBO:LANDMARK AVIATIO FBO:WISCONSIN AV23411 AUTO PILOT D 3606 CORBEN CT DANE CO REGLDULLES, VA 2016 MADISON, WI 53704
608-268-500703-661-015 608-268-5037 - fa703-661-0152 - fax
PASSENGERS:THACKSTON, JASON R - 509-290-4590 / 09800310-930200-550-E0
SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 09800310-930200-550-E0
VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E0
LEG MSGS: Additional Messages for this leg continue on the next page
Page 38 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 306 of 419
Trip ID: VA03161 06/05/1 08:21 AM Page: 39
AIRCRAFT ROUTING
03/16/1 - 3/18/1
RIP PURPOSE:EEI Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 3 continue
LEG MSGS: Need lunch from KIAD to KMSN
Leg 4
OF PA 3DATE:03/18/1 WED
TRAVEL TIME:3 Hours 16 Minutes DISTANCE:1211 Nautical Mile
DEPART TIME:01:21 PM CDT ARRIVE TIME:02:37 PM PDT
DEPART FROM:MADISON, WI - KMS ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:WISCONSIN AV FBO:AVISTA HANGA3606 CORBEN CT DANE CO REGL 7500 W PARK DRIVE GATE LMADISON, WI 53704 SPOKANE, W
509.495.413608-268-500608-268-5037 - fa
PASSENGERS:THACKSTON, JASON R - 509-290-4590 / 09800310-930200-550-E0
SPRAGUE, KEVIN COLLINS COLLINS - 360-951-4540 / 09800310-930200-550-E0
VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E0
Page 3 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 307 of 419
Trip ID: VA031615 06/05/1 08:21 AM Page: 40
AIRCRAFT ROUTING
04/16/1 - 4/16/1
RIP PURPOSE:
IRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
MUELHEIM, MARKMARK - Leg 1
OF PA 1DATE:04/16/1 TH
TRAVEL TIME:0 Hour 14 Minute DISTANCE:0 Nautical Mile
DEPART TIME:06:40 PM PDT ARRIVE TIME:06:54 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:LANDMARK AVIATIO FBO:AVISTA HANGA8136 W PILOT D 7500 W PARK DRIVE GATE LSPOKANE, WA 99224 SPOKANE, W509.495.413509-455-5204509-455-5272 - fax
PASSENGERS:PETE BROWN -
Page 40 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 308 of 419
Trip ID: VA031814 06/05/1 08:21 AM Page: 41
AIRCRAFT ROUTING
03/18/1 - 3/18/1
RIP PURPOSE:Labor Negotiations
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 2DATE:03/18/14 TU
TRAVEL TIME:0 Hour 24 Minute DISTANCE:141 Nautical Mile
DEPART TIME:07:00 AM PDT ARRIVE TIME:08:01 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:LA GRANDE, OR - KLGD
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:LA GRANDE/UNION COUNT
FBO:AVISTA HANGA FBO:UNION CO ARPT7500 W PARK DRIVE GATE L 60175 PIERCE RD
SPOKANE, W LA GRANDE, OR 9785541-963-661509.495.413 541-963-9098 - fa
PASSENGERS:BUSHNELL, TERRY (TERRY) - 509-991-5021 / 9902800-921320-550-X0
HOWELL, DAVID (DAVID) - 509-990-8732 / 09900165-870000-550-G08
LEG MSGS: Need breakfast from KGEG to KLGD
Leg 2
OF PA 4DATE:03/18/14 TU
TRAVEL TIME:0 Hour 45 Minute DISTANCE:274 Nautical Mile
DEPART TIME:08:05 AM PDT ARRIVE TIME:08:50 AM PDT
DEPART FROM:LA GRANDE, OR - KLGD ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:LA GRANDE/UNION COUNT AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO:UNION CO ARPT FBO:JET CENTER MF60175 PIERCE RD 5000 CIRRUS D
LA GRANDE, OR 9785 MEDFORD, OR 97504800-359-029541-963-661 541-772-2759 - fa541-963-9098 - fa
PASSENGERS:BUSHNELL, TERRY TERRY - 509-991-5021 / 9902800-921320-550-X0
HOWELL, DAVID DAVID - 509-990-8732 / 09900165-870000-550-G0
KELLOGG, DONALD (DON) - 541-786-0280 / 77700242-107060-550-A8RAJKOVICH, THOMAS (ROB) - 541-786-0514 / 9902800-921000-550-X0
Leg
OF PA 5DATE:03/18/14 TU
TRAVEL TIME:0 Hour 48 Minute DISTANCE:274 Nautical Mile
DEPART TIME:04:00 PM PDT ARRIVE TIME:04:47 PM PDT
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:LA GRANDE, OR - KLGD
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:LA GRANDE/UNION COUNT
FBO:JET CENTER MF FBO:UNION CO ARPT
5000 CIRRUS D 60175 PIERCE RDMEDFORD, OR 97504 LA GRANDE, OR 9785541-963-661800-359-029
541-963-9098 - fa541-772-2759 - fa
PASSENGERS:BUSHNELL, TERRY (TERRY) - 509-991-5021 / 9902800-921320-550-X0
HOWELL, DAVID (DAVID) - 509-990-8732 / 09900165-870000-550-G08KELLOGG, DONALD (DON) - 541-786-0280 / 77700242-107060-550-A8
RAJKOVICH, THOMAS ROB - 541-786-0514 / 9902800-921000-550-X0SHEERAN, HAROLD - 541-580-2940 / 77700242-107060-550-A8
Leg 4
Page 41 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 309 of 419
Trip ID: VA031814 06/05/1 08:21 AM Page: 42
AIRCRAFT ROUTING
03/18/1 - 3/18/1
RIP PURPOSE:Labor Negotiations
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 4 continue
OF PA 4DATE:03/18/14 TU
TRAVEL TIME:0 Hour 24 Minute DISTANCE:141 Nautical Mile
DEPART TIME:05:00 PM PDT ARRIVE TIME:05:28 PM PDT
DEPART FROM:LA GRANDE, OR - KLGD ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:LA GRANDE/UNION COUNT AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:UNION CO ARPT FBO:AVISTA HANGA60175 PIERCE RD 7500 W PARK DRIVE GATE LLA GRANDE, OR 9785 SPOKANE, W509.495.413541-963-661541-963-9098 - fax
PASSENGERS:BUSHNELL, TERRY (TERRY) - 509-991-5021 / 9902800-921320-550-X0
HOWELL, DAVID (DAVID) - 509-990-8732 / 09900165-870000-550-G08
KELLOGG, DONALD (DON) - 541-786-0280 / 77700242-107060-550-A8SHEERAN, HAROLD - 541-580-2940 / 77700242-107060-550-A8
Page 4 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 310 of 419
Trip ID: VA03181 06/05/1 08:21 AM Page: 43
AIRCRAFT ROUTING
03/18/1 - 3/20/1
RIP PURPOSE:Williams West Coast Conference
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 3DATE:03/18/1 WED
TRAVEL TIME:1 Hour 54 Minute DISTANCE:700 Nautical Mile
DEPART TIME:03:26 PM PDT ARRIVE TIME:05:20 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:LAS VEGAS, NV - KLA
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:MCCARRAN INTERNATIONAL
FBO:LANDMARK FBO:SIGNATURE FLIGHT SU6005 LAS VEGAS BLVD LAS VEGAS, NV 8911702-739-110702-739-1241 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09903691-930200-550-E0
THIES, MARK T - 509-850-7832 / 09903691-930200-550-E01
FIELDER, CASEY (CASEY) - 509-703-2209 / 09903691-930200-550-E0
Leg
OF PA 3DATE:03/20/1 FRI
TRAVEL TIME:1 Hour 51 Minute DISTANCE:700 Nautical Mile
DEPART TIME:02:18 PM PDT ARRIVE TIME:04:09 PM PDT
DEPART FROM:LAS VEGAS, NV - KLA ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:MCCARRAN INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:SIGNATURE FLIGHT SU FBO:LANDMARK6005 LAS VEGAS BLVD
LAS VEGAS, NV 8911702-739-110702-739-1241 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09903691-930200-550-E01
THIES, MARK T - 509-850-7832 / 09903691-930200-550-E01FIELDER, CASEY (CASEY) - 509-703-2209 / 09903691-930200-550-E0
Page 4 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 311 of 419
Trip ID: VA031914 06/05/1 08:21 AM Page: 4
AIRCRAFT ROUTING
03/19/1 - 3/20/1
RIP PURPOSE:Annual West Coast Seminar
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 3DATE:03/19/14 WED
TRAVEL TIME:1 Hour 49 Minute DISTANCE:700 Nautical Mile
DEPART TIME:07:06 AM PDT ARRIVE TIME:08:55 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:LAS VEGAS, NV - KLA
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:MCCARRAN INTERNATIONAL
FBO:AVISTA HANGA FBO:SIGNATURE FLIGHT SU7500 W PARK DRIVE GATE L 6005 LAS VEGAS BLVD SPOKANE, W LAS VEGAS, NV 8911702-739-110509.495.413 702-739-1241 - fa
PASSENGERS:THIES, MARK -
LANG, JASON -
FIELDER, CASEY -
LEG MSGS: Need breakfast from KGEG to KLAS.
Need breakfast from KLAS to KGEG
Leg
OF PA 3DATE:03/20/14 THU
TRAVEL TIME:1 Hour 57 Minute DISTANCE:700 Nautical Mile
DEPART TIME:07:30 AM PDT ARRIVE TIME:09:27 AM PDT
DEPART FROM:LAS VEGAS, NV - KLA ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:MCCARRAN INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:SIGNATURE FLIGHT SU FBO:AVISTA HANGA6005 LAS VEGAS BLVD 7500 W PARK DRIVE GATE L
LAS VEGAS, NV 89119 SPOKANE, W509.495.413702-739-110702-739-1241 - fa
PASSENGERS:THIES, MARK -
LANG, JASON - FIELDER, CASEY -
TRIP MSGS: 3/19 - Carey Car has been reserved by Karen Eastwood - Confirmation #WA8068783-1. Pick up at
Signature Flight Support with drop off at THEhotel @ Mandalay Bay.
3/20 - Carey Car has been reserved by Karen Eastwood - Confirmation # WA8068783-2. Pick up atTHEhotel @ Mandalay Bay with drop off at Signature Flight Support.
Page 4 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 312 of 419
Trip ID: VA03231 06/05/1 08:21 AM Page: 45
AIRCRAFT ROUTING
03/23/1 - 3/23/1
RIP PURPOSE:These are co-pilot test flights
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 1DATE:03/23/1 MO
TRAVEL TIME:0 Hour 53 Minute DISTANCE:0 Nautical Mile
DEPART TIME:10:20 AM PDT ARRIVE TIME:11:13 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:LANDMARK AVIATIO FBO:AVISTA HANGA8136 W PILOT D 7500 W PARK DRIVE GATE LSPOKANE, WA 99224 SPOKANE, W509.495.413509-455-5204509-455-5272 - fax
PASSENGERS:MARSHALL, ADAM - 09902811-926101-550-L54
Leg 2
OF PA 1DATE:03/23/1 MO
TRAVEL TIME:0 Hour 41 Minute DISTANCE:0 Nautical Mile
DEPART TIME:12:52 PM PDT ARRIVE TIME:01:33 PM PDT
DEPART FROM:SPOKANE, WA - KGEG ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:AVISTA HANGA FBO:AVISTA HANGA
7500 W PARK DRIVE GATE L 7500 W PARK DRIVE GATE LSPOKANE, W SPOKANE, W509.495.413509.495.413
PASSENGERS:MUELHEIM, MARK - 09902811-926101-550-L54
Page 4 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 313 of 419
Trip ID: VA032414 06/05/1 08:21 AM Page: 46
AIRCRAFT ROUTING
03/24/1 - 3/26/1
RIP PURPOSE:Meetings with Legislators
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 2DATE:03/24/14 MO
TRAVEL TIME:2 Hours 36 Minute DISTANCE:1211 Nautical Mile
DEPART TIME:06:52 AM PDT ARRIVE TIME:11:28 AM CDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:MADISON, WI - KMS
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO
FBO:FBO:WISCONSIN AV3606 CORBEN CT DANE CO REGL
MADISON, WI 53704608-268-500608-268-5037 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 77700300-426120-550-E0
SPRAGUE, COLLINS -
LEG MSGS: Need lunch from KMSN to KIAD
Leg 2
OF PA 2DATE:03/24/14 MO
TRAVEL TIME:1 Hour 24 Minute DISTANCE:593 Nautical Mile
DEPART TIME:11:54 AM CDT ARRIVE TIME:02:18 PM EDT
DEPART FROM:MADISON, WI - KMS ARRIVE AT:WASHINGTON, VA - KIAD
AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO AIRPORT NAME:WASHINGTON DULLES INTERNATION
FBO:WISCONSIN AV FBO:LANDMARK AVIATIO3606 CORBEN CT DANE CO REGL 23411 AUTO PILOT D
MADISON, WI 53704 DULLES, VA 2016703-661-015608-268-500 703-661-0152 - fa608-268-5037 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 77700300-426120-550-E0
SPRAGUE, COLLINS -
Leg 3
OF PA 2DATE:03/26/14 WED
TRAVEL TIME:1 Hour 43 Minutes DISTANCE:593 Nautical Mile
DEPART TIME:09:18 AM EDT ARRIVE TIME:10:01 AM CDT
DEPART FROM:WASHINGTON, VA - KIAD ARRIVE AT:MADISON, WI - KMS
AIRPORT NAME:WASHINGTON DULLES INTERNATION AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO
FBO:LANDMARK AVIATIO FBO:WISCONSIN AV23411 AUTO PILOT D 3606 CORBEN CT DANE CO REGLDULLES, VA 2016 MADISON, WI 53704
608-268-500703-661-015 608-268-5037 - fa703-661-0152 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 77700300-426120-550-E0
SPRAGUE, COLLINS -
Leg 4
Page 4 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 314 of 419
Trip ID: VA032414 06/05/1 08:21 AM Page: 47
AIRCRAFT ROUTING
03/24/1 - 3/26/1
RIP PURPOSE:Meetings with Legislators
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 4 continue
OF PA 2DATE:03/26/14 WED
TRAVEL TIME:3 Hours 11 Minute DISTANCE:1211 Nautical Mile
DEPART TIME:10:27 AM CDT ARRIVE TIME:11:38 AM PDT
DEPART FROM:MADISON, WI - KMS ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:WISCONSIN AV FBO:AVISTA HANGA3606 CORBEN CT DANE CO REGL 7500 W PARK DRIVE GATE LMADISON, WI 53704 SPOKANE, W509.495.413608-268-500608-268-5037 - fax
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 77700300-426120-550-E0
SPRAGUE, COLLINS -
TRIP MSGS: A Carey car has been set up. Confirmation #WA8070107-2 and WA8070107-2
Page 4 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 315 of 419
Trip ID: VA03241 06/05/1 08:21 AM Page: 48
AIRCRAFT ROUTING
03/24/1 - 3/24/1
RIP PURPOSE:Meeting with Community Solar Vendor
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 8DATE:03/24/1 TU
TRAVEL TIME:1 Hour 38 Minute DISTANCE:708 Nautical Mile
DEPART TIME:06:28 AM PDT ARRIVE TIME:09:06 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:DENVER, CO - KBJ
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:ROCKY MOUNTAIN METROPOLITAN/J
FBO:LANDMARK AVIATIO FBO:LANDMARK AVIATIO8136 W PILOT D 11705 AIRPORT WASPOKANE, WA 99224 BROOMFIELD, CO 8002303-466-233509-455-5204 303-466-1524 - fa509-455-5272 - fax
PASSENGERS:CHRISTIE, KEVIN J. - 509-714-3587 / 77705270-186200-550-A54
MAGALSKY, KELLY - 509-863-4586 / 77705270-186200-550-A54
DRAKE, CHRIS (CHRIS) - 509-389-0521 / 77705270-186200-550-A54BACHTEL-BROWNING, BRITT - 503-740-9946 / 77705270-186200-550-A54DORNQUAST, TYLER - / 77705270-186200-550-A54
TYRIE, MARY - 509-216-9900 / 77705270-186200-550-A54THACKSTON, JASON R - 509-290-4590 / 77705270-186200-550-A54
HUMPHREY, RACHELLE - 509-714-2731 / 77705270-186200-550-A54
LEG MSGS: Need breakfast from GEG to BJC
Leg
OF PA 8DATE:03/24/1 TU
TRAVEL TIME:1 Hour 54 Minute DISTANCE:708 Nautical Mile
DEPART TIME:04:13 PM MDT ARRIVE TIME:05:11 PM PDT
DEPART FROM:DENVER, CO - KBJ ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:ROCKY MOUNTAIN METROPOLITAN/J AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:LANDMARK AVIATIO FBO:AVISTA HANGA11705 AIRPORT WA 7500 W PARK DRIVE GATE L
BROOMFIELD, CO 8002 SPOKANE, W509.495.413303-466-233303-466-1524 - fax
PASSENGERS:CHRISTIE, KEVIN J. - 509-714-3587 / 77705270-186200-550-A54
MAGALSKY, KELLY - 509-863-4586 / 77705270-186200-550-A54DRAKE, CHRIS (CHRIS) - 509-389-0521 / 77705270-186200-550-A54BACHTEL-BROWNING, BRITT - 503-740-9946 / 77705270-186200-550-A54
DORNQUAST, TYLER - / 77705270-186200-550-A54TYRIE, MARY - 509-216-9900 / 77705270-186200-550-A54THACKSTON, JASON R - 509-290-4590 / 77705270-186200-550-A54
HUMPHREY, RACHELLE - 509-714-2731 / 77705270-186200-550-A54
TRIP MSGS: Meeting location is at 361 Centennial Parkway, Louisville, CO - approximately 6.6 miles from the airport
Page 48 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 316 of 419
Trip ID: VA03311 06/05/1 08:21 AM Page: 49
AIRCRAFT ROUTING
03/31/1 - 3/31/1
RIP PURPOSE:LIRAP Workshop #4 - UE-140188 and UG-140189
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 9DATE:03/31/1 TU
TRAVEL TIME:0 Hour 48 Minute DISTANCE:193 Nautical Mile
DEPART TIME:07:16 AM PDT ARRIVE TIME:08:00 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO:LANDMARK AVIATIO FBO:CLAY LACY AVIATIO8136 W PILOT D 8285 PERIMETER RD SPOKANE, WA 99224 SEATTLE, WA 9810206-762-600509-455-5204 206-768-0888 - fa509-455-5272 - fax
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 09900549-426400-550-R1
EHRBAR, PAT - 509-994-9074 / 09900549-426400-550-R11
FINESILVER, RYAN (RYAN) - / 09900549-426400-550-R1MATTHEWS, ANA ANA - 509-869-1688 / 09900549-426400-550-R1BATTIN, DENA - 09900549-426400-550-R1
HONEKAMP, JULIE - 09900549-426400-550-R1WELTZ, CAROL - 09900549-426400-550-R11
FEIN, AL - 09900549-426400-550-R1LEPINSKI, LUCY - 09900549-426400-550-R1
LEG MSGS: A 12-passenger van has been reserved by Wendy Manskey in Pat's name. Confirmation
#G52147196D1
Leg
OF PA 9DATE:03/31/1 TU
TRAVEL TIME:0 Hour 34 Minute DISTANCE:193 Nautical Mile
DEPART TIME:06:20 PM PDT ARRIVE TIME:06:54 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA8285 PERIMETER RD 7500 W PARK DRIVE GATE L
SEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600206-768-0888 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 09900549-426400-550-R1
EHRBAR, PAT - 509-994-9074 / 09900549-426400-550-R1FINESILVER, RYAN RYAN - / 09900549-426400-550-R1MATTHEWS, ANA ANA - 509-869-1688 / 09900549-426400-550-R1
BATTIN, DENA - 09900549-426400-550-R11HONEKAMP, JULIE - 09900549-426400-550-R1WELTZ, CAROL - 09900549-426400-550-R1
FEIN, AL - 09900549-426400-550-R1LEPINSKI, LUCY - 09900549-426400-550-R1
Page 4 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 317 of 419
Trip ID: VA040114 06/05/1 08:21 AM Page: 50
AIRCRAFT ROUTING
04/01/1 - 4/01/1
RIP PURPOSE:OPUC PUBLIC MEETING REGARDING AELP
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 4DATE:04/01/14 TU
TRAVEL TIME:0 Hour 48 Minute DISTANCE:279 Nautical Mile
DEPART TIME:08:00 AM PDT ARRIVE TIME:09:00 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO: FBO:
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 77705228-426500-550-R1
MEYER, DAVID J. - 509-220-7432 / 77705228-426500-550-R1KRASSELT, RYAN L RYAN - 509-590-8363 / 77705228-426500-550-R1HOWARD, BRUCE - 509-990-0984 / 77705228-426500-550-R11
Leg
OF PA 4DATE:04/01/14 TU
TRAVEL TIME:0 Hour 48 Minute DISTANCE:279 Nautical Mile
DEPART TIME:11:00 AM PDT ARRIVE TIME:11:54 AM PDT
DEPART FROM:SALEM, OR - KSL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA7500 W PARK DRIVE GATE LSPOKANE, W
509.495.413
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 77705228-426500-550-R1
MEYER, DAVID J. - 509-220-7432 / 77705228-426500-550-R1KRASSELT, RYAN L(RYAN) - 509-590-8363 / 77705228-426500-550-R11HOWARD, BRUCE - 509-990-0984 / 77705228-426500-550-R1
TRIP MSGS: ONE CAR RESERVED IN KELLY'S NAME, RESERVED BY PATTY HANSON. CONFIRMATION
#TGB3XK
Page 50 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 318 of 419
Trip ID: VA040314 06/05/1 08:21 AM Page: 51
AIRCRAFT ROUTING
04/03/1 - 4/03/1
RIP PURPOSE:Annual Update Meetings with IPUC Commissioners
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
HARTNETT, JOHN - Leg 1
OF PA 5DATE:04/03/14 TH
TRAVEL TIME:0 Hour 48 Minute DISTANCE:249 Nautical Mile
DEPART TIME:06:30 AM PDT ARRIVE TIME:08:18 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO: FBO:JACKSON JET CENTE3815 RICKENBACKER STREETBOISE, ID 8370208-383-330208-336-9082 - fa
PASSENGERS:MEYER, DAVID -
NORWOOD, KELLY -
MORRIS, SCOTT - THIES, MARK - VERMILLION, DENNIS -
LEG MSGS: Need breakfast snack from KGEG to KBOI
Need lunch from KBOI to KGEG
Leg 2
OF PA 5DATE:04/03/14 TH
TRAVEL TIME:0 Hour 48 Minutes DISTANCE:249 Nautical Mile
DEPART TIME:12:30 PM MDT ARRIVE TIME:12:18 PM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JACKSON JET CENTE FBO:AVISTA HANGA
3815 RICKENBACKER STREET 7500 W PARK DRIVE GATE LBOISE, ID 8370 SPOKANE, W509.495.413208-383-330
208-336-9082 - fa
PASSENGERS:MEYER, DAVID -
NORWOOD, KELLY - MORRIS, SCOTT -
THIES, MARK - VERMILLION, DENNIS -
TRIP MSGS: One Rental minivan reserved by Patty Hanson in Kelly's Name - Confirmation #G1140039534
Page 51 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 319 of 419
Trip ID: VA040714 06/05/1 08:21 AM Page: 52
AIRCRAFT ROUTING
04/07/1 - 4/07/1
RIP PURPOSE:Regulatory Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 4DATE:04/07/14 MO
TRAVEL TIME:0 Hour 48 Minute DISTANCE:193 Nautical Mile
DEPART TIME:11:15 AM PDT ARRIVE TIME:12:03 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO:AVISTA HANGA FBO:CLAY LACY AVIATIO7500 W PARK DRIVE GATE L 8285 PERIMETER RD SPOKANE, W SEATTLE, WA 9810206-762-600509.495.413 206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 77700300-426120-550-E0
NORWOOD, KELLY -
SPRAGUE, COLLINS - VERMILLION, DENNIS -
LEG MSGS: Need lunch from KGEG to KBFI
Leg
OF PA 4DATE:04/07/14 MO
TRAVEL TIME:0 Hour 42 Minute DISTANCE:193 Nautical Mile
DEPART TIME:03:30 PM PDT ARRIVE TIME:04:12 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W
509.495.413206-762-6000206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 77700300-426120-550-E01
NORWOOD, KELLY -
SPRAGUE, COLLINS - VERMILLION, DENNIS -
TRIP MSGS: Melnik Car Service will meet passengers at Clay Lacy Aviation and take them to and from the meeting
in Bellevue. Confirmations #26033 and 26034
Page 5 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 320 of 419
Trip ID: VA04091 06/05/1 08:21 AM Page: 53
AIRCRAFT ROUTING
04/09/1 - 4/09/1
RIP PURPOSE:Smart City Workshop with Verizon Wireless
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 7DATE:04/09/1 TH
TRAVEL TIME:1 Hour 38 Minute DISTANCE:628 Nautical Mile
DEPART TIME:05:58 AM PDT ARRIVE TIME:07:36 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OAKLAND, CA - KOAK
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:METROPOLITAN OAKLAND INTERNATI
FBO:LANDMARK AVIATIO FBO:KAISERAIR JET CT8136 W PILOT D 8735 EARHART RDSPOKANE, WA 99224 OAKLAND, CA 9462510-569-962509-455-5204 510-255-5017 - fa509-455-5272 - fax
PASSENGERS:KENSOK, JAMES M(JIM) - 509-994-2892 / 77700300-426120-550-M54
ROSENTRATER, HEATHER - 509-879-5320 / 77700300-426120-550-M54
GIBSON, JOHN - / 77700300-426120-550-M54KIRKEBY, CURT - 509-995-5099 / 77700300-426120-550-M54DUQUETTE, DELORIS - 77700300-426120-550-M54
ZENTZ, KIM - 77700300-426120-550-M54SIMMONS, SCOTT - 77700300-426120-550-M54
Leg
OF PA 7DATE:04/09/1 TH
TRAVEL TIME:1 Hour 30 Minute DISTANCE:628 Nautical Mile
DEPART TIME:03:46 PM PDT ARRIVE TIME:05:18 PM PDT
DEPART FROM:OAKLAND, CA - KOAK ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:METROPOLITAN OAKLAND INTERNATIAIRPORT NAME:SPOKANE INTERNATIONAL
FBO:KAISERAIR JET CT FBO:AVISTA HANGA
8735 EARHART RD 7500 W PARK DRIVE GATE LOAKLAND, CA 9462 SPOKANE, W509.495.413510-569-962
510-255-5017 - fa
PASSENGERS:KENSOK, JAMES M JIM - 509-994-2892 / 77700300-426120-550-M54
ROSENTRATER, HEATHER - 509-879-5320 / 77700300-426120-550-M54GIBSON, JOHN - / 77700300-426120-550-M54
KIRKEBY, CURT - 509-995-5099 / 77700300-426120-550-M54DUQUETTE, DELORIS - 77700300-426120-550-M54ZENTZ, KIM - 77700300-426120-550-M54
SIMMONS, SCOTT - 77700300-426120-550-M54
Page 5 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 321 of 419
Trip ID: VA04131 06/05/1 08:21 AM Page: 5
AIRCRAFT ROUTING
04/13/1 - 4/14/1
RIP PURPOSE:Colstrip Litigation Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
HARTNETT, JOHN - Leg 1
OF PA 4DATE:04/13/1 MO
TRAVEL TIME:2 Hours 38 Minute DISTANCE:1211 Nautical Mile
DEPART TIME:08:11 AM PDT ARRIVE TIME:12:49 PM CDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:MADISON, WI - KMS
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO
FBO:LANDMARK AVIATIO FBO:WISCONSIN AV8136 W PILOT D 3606 CORBEN CT DANE CO REGLSPOKANE, WA 99224 MADISON, WI 53704608-268-500509-455-5204 608-268-5037 - fa509-455-5272 - fax
PASSENGERS:DURKIN, MARIAN M - 708-917-4982 / 09903691-930200-550-E0
HOWARD, BRUCE - 509-990-0984 / 09903691-930200-550-E01
SCHROEDER, BILL - 09903691-930200-550-E0SPRAGUE, KEVIN COLLINS COLLINS - 360-951-4540 / 09903691-930200-550-E0
Leg
OF PA 4DATE:04/13/15 MON
TRAVEL TIME:1 Hour 30 Minute DISTANCE:593 Nautical Mile
DEPART TIME:01:18 PM CDT ARRIVE TIME:03:48 PM EDT
DEPART FROM:MADISON, WI - KMS ARRIVE AT:WASHINGTON, VA - KIAD
AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO AIRPORT NAME:WASHINGTON DULLES INTERNATION
FBO:WISCONSIN AV FBO:LANDMARK AVIATIO
3606 CORBEN CT DANE CO REGL 23411 AUTO PILOT DMADISON, WI 53704 DULLES, VA 2016703-661-015608-268-500
703-661-0152 - fa608-268-5037 - fa
PASSENGERS:DURKIN, MARIAN M - 708-917-4982 / 09903691-930200-550-E0
HOWARD, BRUCE - 509-990-0984 / 09903691-930200-550-E0SCHROEDER, BILL - 09903691-930200-550-E0
SPRAGUE, KEVIN COLLINS COLLINS - 360-951-4540 / 09903691-930200-550-E0
LEG MSGS: Need lunch from KMSM to KIAD. Limolink will pick up the passengers at the airport for transportationto the hotel - Confirmation #2005824-001
Leg 3
OF PA 3DATE:04/14/1 TU
TRAVEL TIME:1 Hour 35 Minute DISTANCE:593 Nautical Mile
DEPART TIME:03:01 PM EDT ARRIVE TIME:03:36 PM CDT
DEPART FROM:WASHINGTON, VA - KIAD ARRIVE AT:MADISON, WI - KMS
AIRPORT NAME:WASHINGTON DULLES INTERNATION AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO
FBO:LANDMARK AVIATION FBO:WISCONSIN AV23411 AUTO PILOT D 3606 CORBEN CT DANE CO REGLDULLES, VA 2016 MADISON, WI 53704
608-268-500703-661-015 608-268-5037 - fa703-661-0152 - fa
PASSENGERS:DURKIN, MARIAN M - 708-917-4982 / 09903691-930200-550-E0
HOWARD, BRUCE - 509-990-0984 / 09903691-930200-550-E0
SCHROEDER, BILL - 09903691-930200-550-E0
LEG MSGS: Additional Messa es for this le continue on the next pa e
Page 5 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 322 of 419
Trip ID: VA04131 06/05/1 08:21 AM Page: 55
AIRCRAFT ROUTING
04/13/1 - 4/14/1
RIP PURPOSE:Colstrip Litigation Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
HARTNETT, JOHN - Leg 3 continue
LEG MSGS: Limolink will pick up the passengers at the hotel and take them to the airport - Confirmation #2005824-002
Leg 4
OF PA 3DATE:04/14/1 TU
TRAVEL TIME:3 Hours 0 Minute DISTANCE:1211 Nautical Mile
DEPART TIME:04:01 PM CDT ARRIVE TIME:05:01 PM PDT
DEPART FROM:MADISON, WI - KMS ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:TRUAX FIELD/DANE COUNTY REGIO AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:WISCONSIN AV FBO:AVISTA HANGA
3606 CORBEN CT DANE CO REGL 7500 W PARK DRIVE GATE LMADISON, WI 53704 SPOKANE, W509.495.413608-268-500
608-268-5037 - fa
PASSENGERS:DURKIN, MARIAN M - 708-917-4982 / 09903691-930200-550-E0
HOWARD, BRUCE - 509-990-0984 / 09903691-930200-550-E0SCHROEDER, BILL - 09903691-930200-550-E01
Page 5 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 323 of 419
Trip ID: VA041414 06/05/1 08:21 AM Page: 56
AIRCRAFT ROUTING
04/14/1 - 4/14/1
RIP PURPOSE:WUTC OPEN MEETING RE: INVESTIGATION OF THE COSTS AND BENEFITS OFDISTRIBUTED GENERATION AND THE EFFECT OF DISTRIBUTED GENERATION ON UTILITYPROVISION OF ELECTRIC SERVICE - DOCKET UE-131883
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 4DATE:04/14/14 MO
TRAVEL TIME:0 Hour 43 Minute DISTANCE:222 Nautical Mile
DEPART TIME:10:37 AM PDT ARRIVE TIME:11:20 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850
360-705-3214360-753-0083 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 09900540-928000-550-R1
GERVAIS, LINDA - 509-953-8057 / 09900540-928000-550-R1
KALICH, CLINT CLINT - 509-230-3923 / 09900540-928000-550-R1THACKSTON, JASON R - 509-290-4590 / 09900540-928000-550-R1
Leg 2
OF PA 3DATE:04/14/14 MO
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:04:55 PM PDT ARRIVE TIME:05:36 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTER FBO:AVISTA HANGA
7645 OLD HWY 99 S 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 09900540-928000-550-R1
GERVAIS, LINDA - 509-953-8057 / 09900540-928000-550-R1THACKSTON, JASON R - 509-290-4590 / 09900540-928000-550-R11
TRIP MSGS: ONE CAR RESERVED IN PAT'S NAME BY PATTY HANSON - CONFIRMATION #G1624230427
Page 5 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 324 of 419
Trip ID: VA041514 06/05/1 08:21 AM Page: 57
AIRCRAFT ROUTING
04/15/1 - 4/15/1
RIP PURPOSE:Colstrip Executive Communication Workshop
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 3DATE:04/15/14 TU
TRAVEL TIME:1 Hour 12 Minute DISTANCE:457 Nautical Mile
DEPART TIME:09:30 AM PDT ARRIVE TIME:11:42 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:COLSTRIP, MT - M4
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:RICK'S COLSTRI
FBO:AVISTA HANGA FBO:7500 W PARK DRIVE GATE L
SPOKANE, W509.495.413
PASSENGERS:DEMPSEY, TOM C(TOM) - 509-688-9716 / 41002100-500000-550-K0
THACKSTON, JASON R - 509-290-4590 / 09802202-557000-550-E55
WUERST, JESSIE (JESSIE) - 509-879-2114 / 09900330-930200-550-S54
LEG MSGS: Light Snack from KGEG to M46
Leg
OF PA 3DATE:04/15/14 TU
TRAVEL TIME:1 Hour 12 Minute DISTANCE:457 Nautical Mile
DEPART TIME:04:00 PM MDT ARRIVE TIME:04:18 PM PDT
DEPART FROM:COLSTRIP, MT - M4 ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:RICK'S COLSTRI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA
7500 W PARK DRIVE GATE LSPOKANE, W509.495.413
PASSENGERS:DEMPSEY, TOM C TOM - 509-688-9716 / 41002100-500000-550-K0
THACKSTON, JASON R - 509-290-4590 / 09802202-557000-550-E5WUERST, JESSIE (JESSIE) - 509-879-2114 / 09900330-930200-550-S54
TRIP MSGS: Debra Beartuck Dove will make arrangements for two company cars at airstrip upon arrival: (1) forpassengers, (1) for pilots. PPL Montana-Colstrip - Office: [phone] Fax: (406) [e-mail]
Page 5 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 325 of 419
Trip ID: VA041714 06/05/1 08:21 AM Page: 58
AIRCRAFT ROUTING
04/17/1 - 4/17/1
RIP PURPOSE:Oregon Quarterly Update Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 6DATE:04/17/14 TH
TRAVEL TIME:1 Hour 0 Minute DISTANCE:279 Nautical Mile
DEPART TIME:07:45 AM PDT ARRIVE TIME:08:45 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO: FBO:
PASSENGERS:BRANDON, ANNETTE - 509-979-3214 / 06805169-928000-550-R1
EHRBAR, PAT - 509-994-9074 / 06805169-928000-550-R1FORSYTH, GRANT GRANT - / 06805169-928000-550-R1FUKAI, KELLY (KELLY) - / 06805169-928000-550-R11
HARPER, STEVE (STEVE) - / 06805169-928000-550-R1BONFIELD, SHAWN SHAWN - 509-434-6502 / ---
LEG MSGS: Need lunch from SLE to LMT. Need chef salads for Annette and Kelly - gluten free
Leg
OF PA 6DATE:04/17/14 TH
TRAVEL TIME:0 Hour 42 Minute DISTANCE:174 Nautical Mile
DEPART TIME:12:30 PM PDT ARRIVE TIME:01:12 PM PDT
DEPART FROM:SALEM, OR - KSL ARRIVE AT:KLAMATH FALLS, OR - KLMT
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:KLAMATH FALLS REGIONAL
FBO: FBO:
PASSENGERS:BRANDON, ANNETTE - 509-979-3214 / 06805169-928000-550-R1
EHRBAR, PAT - 509-994-9074 / 06805169-928000-550-R1
FORSYTH, GRANT (GRANT) - / 06805169-928000-550-R1FUKAI, KELLY (KELLY) - / 06805169-928000-550-R1
HARPER, STEVE (STEVE) - / 06805169-928000-550-R1BONFIELD, SHAWN SHAWN - 509-434-6502 / ---
Leg
OF PA 8DATE:04/17/14 TH
TRAVEL TIME:1 Hour 6 Minute DISTANCE:373 Nautical Mile
DEPART TIME:01:15 PM PDT ARRIVE TIME:02:21 PM PDT
DEPART FROM:KLAMATH FALLS, OR - KLMT ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KLAMATH FALLS REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA7500 W PARK DRIVE GATE L
SPOKANE, W509.495.413
PASSENGERS:BRANDON, ANNETTE - 509-979-3214 / 06805169-928000-550-R1
EHRBAR, PAT - 509-994-9074 / 06805169-928000-550-R1FORSYTH, GRANT GRANT - / 06805169-928000-550-R1FUKAI, KELLY KELLY - / 06805169-928000-550-R1
Additional Passengers for this leg continue on the next page.
Page 58 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 326 of 419
Trip ID: VA041714 06/05/1 08:21 AM Page: 59
AIRCRAFT ROUTING
04/17/1 - 4/17/1
RIP PURPOSE:Oregon Quarterly Update Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 3 continue
PASSENGERS:HARPER, STEVE STEVE - / 06805169-928000-550-R1
BONFIELD, SHAWN SHAWN - 509-434-6502 / ---VERMILLION, DENNIS -
KOPCZYNSKI, DON M - 509-990-8885 / 09903691-930200-550-E0
TRIP MSGS: One minivan reserved in Pat's name by Patty Hanson - Confirmation #G13436560F8
Page 5 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 327 of 419
Trip ID: VA04201 06/05/1 08:21 AM Page: 60
AIRCRAFT ROUTING
04/20/1 - 4/20/1
RIP PURPOSE:East Medford Reinforcement Project; Meford Construction Tech Interviews.
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 5DATE:04/20/1 MO
TRAVEL TIME:0 Hour 13 Minute DISTANCE:55 Nautical Mile
DEPART TIME:06:08 AM PDT ARRIVE TIME:06:21 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO:LANDMARK AVIATIO FBO:INTER-STATE AV8136 W PILOT D 2601 AIRPORT COMPLEX SPOKANE, WA 99224 PULLMAN, WA 9916509-332-659509-455-5204 509-334-1751 - fa509-455-5272 - fax
PASSENGERS:SAMSELL, SETH - 509-951-5459 / 98405247-300100-550-B5
GIGLER, DAN - 509-979-6755 / 98405254-300100-550-G08
WHITBY, MICHAEL (MIKE) - 509-991-1278 / 98405254-300100-550-G0KOLBET, DAN - 509-434-8621 / 09902800-930200-550-X0MAURO, CHRISTOPHER CHRIS - 541-891-9915 / 06802451-874030-550-G0
LEG MSGS: Need breakfast from KGEG to KPUW
Leg
OF PA 6DATE:04/20/15 MON
TRAVEL TIME:0 Hour 57 Minute DISTANCE:360 Nautical Mile
DEPART TIME:06:44 AM PDT ARRIVE TIME:07:41 AM PDT
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO:INTER-STATE AV FBO:JET CENTER MF2601 AIRPORT COMPLEX 5000 CIRRUS D
PULLMAN, WA 99163 MEDFORD, OR 97504800-359-029509-332-659 541-772-2759 - fa509-334-1751 - fa
PASSENGERS:DANIELS, RANDY - 509-553-9907 / 98405247-300100-550-V0
SAMSELL, SETH - 509-951-5459 / 98405247-300100-550-B5GIGLER, DAN - 509-979-6755 / 98405254-300100-550-G0WHITBY, MICHAEL MIKE - 509-991-1278 / 98405254-300100-550-G0
KOLBET, DAN - 509-434-8621 / 09902800-930200-550-X0MAURO, CHRISTOPHER (CHRIS) - 541-891-9915 / 06802451-874030-550-G0
Leg
OF PA 5DATE:04/20/1 MO
TRAVEL TIME:0 Hour 55 Minute DISTANCE:360 Nautical Mile
DEPART TIME:03:09 PM PDT ARRIVE TIME:04:04 PM PDT
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO:JET CENTER MF FBO:INTER-STATE AV
5000 CIRRUS D 2601 AIRPORT COMPLEX MEDFORD, OR 97504 PULLMAN, WA 9916509-332-659800-359-029
509-334-1751 - fa541-772-2759 - fa
PASSENGERS:DANIELS, RANDY - 509-553-9907 / 98405247-300100-550-V0
Additional Passengers for this leg continue on the next page.
Page 60 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 328 of 419
Trip ID: VA04201 06/05/1 08:21 AM Page: 61
AIRCRAFT ROUTING
04/20/1 - 4/20/1
RIP PURPOSE:East Medford Reinforcement Project; Meford Construction Tech Interviews.
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 3 continue
PASSENGERS:SAMSELL, SETH - 509-951-5459 / 98405247-300100-550-B5
GIGLER, DAN - 509-979-6755 / 98405254-300100-550-G0WHITBY, MICHAEL (MIKE) - 509-991-1278 / 98405254-300100-550-G08KOLBET, DAN - 509-434-8621 / 09902800-930200-550-X0
Leg 4
OF PA 4DATE:04/20/1 MO
TRAVEL TIME:0 Hour 12 Minute DISTANCE:55 Nautical Mile
DEPART TIME:04:12 PM PDT ARRIVE TIME:04:24 PM PDT
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:INTER-STATE AV FBO:AVISTA HANGA2601 AIRPORT COMPLEX 7500 W PARK DRIVE GATE LPULLMAN, WA 9916 SPOKANE, W
509.495.413509-332-6596509-334-1751 - fa
PASSENGERS:SAMSELL, SETH - 509-951-5459 / 98405247-300100-550-B51
GIGLER, DAN - 509-979-6755 / 98405254-300100-550-G0
WHITBY, MICHAEL (MIKE) - 509-991-1278 / 98405254-300100-550-G0KOLBET, DAN - 509-434-8621 / 09902800-930200-550-X0
Page 61 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 329 of 419
Trip ID: VA042214 06/05/1 08:21 AM Page: 62
AIRCRAFT ROUTING
04/22/1 - 4/23/1
RIP PURPOSE:Gas Manager Meeting and Local 659 Labor Management Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
SCOTT, BRIAN - Leg 1
OF PA 7DATE:04/22/14 TU
TRAVEL TIME:0 Hour 30 Minute DISTANCE:127 Nautical Mile
DEPART TIME:07:00 AM PDT ARRIVE TIME:07:30 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:PENDLETON, OR - KPDT
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:EASTERN OREGON REGIONAL PENDL
FBO:AVISTA HANGA FBO:7500 W PARK DRIVE GATE L
SPOKANE, W509.495.413
PASSENGERS:HOWELL, DAVID (DAVID) - 509-990-8732 / 09900165-870000-550-G0
BUSHNELL, TERRY (TERRY) - 509-991-5021 / 9902800-921000-550-X02
GIGLER, DAN - 509-979-6755 / 98405238-107500-550-G0WHITBY, MICHAEL MIKE - 509-991-1278 / 98405239-300100-550-G0MAIR, TIM TIM - 509-995-6112 / 77700242-107050-550-L5
GOOD, PAUL PAUL - 208-929-1132 / 77700242-107050-550-C5PIKE, ANDREA (ANDREA) - 509-220-6188 / 09905690-921000-550-W09
LEG MSGS: Need breakfast from KGEG to KLGD
Leg 2
OF PA 9DATE:04/22/14 TU
TRAVEL TIME:0 Hour 54 Minute DISTANCE:264 Nautical Mile
DEPART TIME:07:45 AM PDT ARRIVE TIME:08:39 AM PDT
DEPART FROM:PENDLETON, OR - KPDT ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:EASTERN OREGON REGIONAL PENDLAIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO: FBO:JET CENTER MF5000 CIRRUS DMEDFORD, OR 97504
800-359-029541-772-2759 - fa
PASSENGERS:HOWELL, DAVID DAVID - 509-990-8732 / 09900165-870000-550-G0
BUSHNELL, TERRY TERRY - 509-991-5021 / 9902800-921000-550-X0
KELLOGG, DONALD (DON) - 541-786-0280 / 77700242-107060-550-C8RAJKOVICH, THOMAS (ROB) - 541-786-0514 / 9902800-921000-550-X0GIGLER, DAN - 509-979-6755 / 98405238-107500-550-G0
WHITBY, MICHAEL MIKE - 509-991-1278 / 98405239-300100-550-G0MAIR, TIM TIM - 509-995-6112 / 77700242-107050-550-L5GOOD, PAUL (PAUL) - 208-929-1132 / 77700242-107050-550-C5
PIKE, ANDREA (ANDREA) - 509-220-6188 / 09905690-921000-550-W0
Leg
Page 6 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 330 of 419
Trip ID: VA042214 06/05/1 08:21 AM Page: 63
AIRCRAFT ROUTING
04/22/1 - 4/23/1
RIP PURPOSE:Gas Manager Meeting and Local 659 Labor Management Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
SCOTT, BRIAN - Leg 3 continue
OF PA 7DATE:04/23/14 WED
TRAVEL TIME:0 Hour 48 Minute DISTANCE:264 Nautical Mile
DEPART TIME:04:30 PM PDT ARRIVE TIME:05:24 PM PDT
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:PENDLETON, OR - KPDT
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:EASTERN OREGON REGIONAL PENDL
FBO:JET CENTER MF FBO:5000 CIRRUS DMEDFORD, OR 97504800-359-029541-772-2759 - fax
PASSENGERS:HOWELL, DAVID (DAVID) - 509-990-8732 / 09900165-870000-550-G0
BUSHNELL, TERRY (TERRY) - 509-991-5021 / 9902800-921000-550-X02
KELLOGG, DONALD (DON) - 541-786-0280 / 77700242-107060-550-C8RAJKOVICH, THOMAS ROB - 541-786-0514 / 9902800-921000-550-X0GIGLER, DAN - 509-979-6755 / 98405238-107500-550-G0
WHITBY, MICHAEL MIKE - 509-991-1278 / 98405239-300100-550-G0PIKE, ANDREA (ANDREA) - 509-220-6188 / 09905690-921000-550-W09
Leg 4
OF PA 5DATE:04/23/14 WED
TRAVEL TIME:0 Hour 24 Minute DISTANCE:127 Nautical Mile
DEPART TIME:05:40 PM PDT ARRIVE TIME:06:10 PM PDT
DEPART FROM:PENDLETON, OR - KPDT ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:EASTERN OREGON REGIONAL PENDLAIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA
7500 W PARK DRIVE GATE LSPOKANE, W509.495.413
PASSENGERS:HOWELL, DAVID DAVID - 509-990-8732 / 09900165-870000-550-G0
BUSHNELL, TERRY TERRY - 509-991-5021 / 9902800-921000-550-X0GIGLER, DAN - 509-979-6755 / 98405238-107500-550-G08
WHITBY, MICHAEL (MIKE) - 509-991-1278 / 98405239-300100-550-G0PIKE, ANDREA ANDREA - 509-220-6188 / 09905690-921000-550-W0
Page 6 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 331 of 419
Trip ID: VA042514 06/05/1 08:21 AM Page: 6
AIRCRAFT ROUTING
04/25/1 - 4/25/1
RIP PURPOSE:CNG Workshop at WUTC
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
SCOTT, BRIAN - Leg 1
OF PA 3DATE:04/25/14 FRI
TRAVEL TIME:0 Hour 48 Minute DISTANCE:222 Nautical Mile
DEPART TIME:07:45 AM PDT ARRIVE TIME:08:33 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:AVISTA HANGA FBO:GLACIER JET CENTE7500 W PARK DRIVE GATE L 7645 OLD HWY 99 SSPOKANE, W OLYMPIA, WA 9850360-705-3214509.495.413 360-753-0083 - fa
PASSENGERS:NORWOOD, KELLY -
EHRBAR, PAT - 509-994-9074 / 02800545-928000-550-R11
SCHAFFNER, MARC - 208-659-7864 / 02800545-928000-550-R1
LEG MSGS: Need lunch from Olympia to Spokane
Leg
OF PA 3DATE:04/25/14 FRI
TRAVEL TIME:0 Hour 36 Minute DISTANCE:222 Nautical Mile
DEPART TIME:12:00 PM PDT ARRIVE TIME:12:42 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA
7645 OLD HWY 99 S 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fax
PASSENGERS:NORWOOD, KELLY -
EHRBAR, PAT - 509-994-9074 / 02800545-928000-550-R1SCHAFFNER, MARC - 208-659-7864 / 02800545-928000-550-R1
TRIP MSGS: Hertz Rental car in Pat's name, reserved by Wendy Manskey - Confirmation #G17913645B6
Page 6 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 332 of 419
Trip ID: VA042914 06/05/1 08:21 AM Page: 65
AIRCRAFT ROUTING
04/29/1 - 4/29/1
RIP PURPOSE:Natural Gas Procurement Planning Update Meetings
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 6DATE:04/29/14 TU
TRAVEL TIME:0 Hour 37 Minute DISTANCE:249 Nautical Mile
DEPART TIME:06:57 AM PDT ARRIVE TIME:08:34 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO: FBO:JACKSON JET CENTE3815 RICKENBACKER STREETBOISE, ID 8370208-383-330208-336-9082 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03800545-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 03800545-928000-550-R11
FUKAI, KELLY (KELLY) - / 03800545-928000-550-R1HARPER, STEVE STEVE - / 03800545-928000-550-R1KRASSELT, RYAN L RYAN - 509-590-8363 / 03800545-928000-550-R1
ANDREWS, ELIZABETH LIZ - / 03800545-928000-550-R1
Leg 2
OF PA 6DATE:04/29/14 TU
TRAVEL TIME:1 Hour 0 Minute DISTANCE:348 Nautical Mile
DEPART TIME:11:42 AM MDT ARRIVE TIME:11:42 AM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:OLYMPIA REGIONAL
FBO:JACKSON JET CENTE FBO:GLACIER JET CENTE3815 RICKENBACKER STREET 7645 OLD HWY 99 S
BOISE, ID 8370 OLYMPIA, WA 9850360-705-3214208-383-330 360-753-0083 - fa208-336-9082 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03800545-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 03800545-928000-550-R1FUKAI, KELLY KELLY - / 03800545-928000-550-R1HARPER, STEVE (STEVE) - / 03800545-928000-550-R11
KRASSELT, RYAN L(RYAN) - 509-590-8363 / 03800545-928000-550-R1ANDREWS, ELIZABETH LIZ - / 03800545-928000-550-R1
LEG MSGS: Need lunch from KBOI to KOLM
(Annette Brandon and Kelly Fukai would like turkey sandwich with lettuce, tomato, no cheese -condiments on the side and fruit salad or chips
Leg 3
Page 6 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 333 of 419
Trip ID: VA042914 06/05/1 08:21 AM Page: 66
AIRCRAFT ROUTING
04/29/1 - 4/29/1
RIP PURPOSE:Natural Gas Procurement Planning Update Meetings
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 3 continue
OF PA 4DATE:04/29/14 TU
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:04:51 PM PDT ARRIVE TIME:05:29 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214360-753-0083 - fax
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03800545-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 03800545-928000-550-R11
KRASSELT, RYAN L(RYAN) - 509-590-8363 / 03800545-928000-550-R1ANDREWS, ELIZABETH LIZ - / 03800545-928000-550-R1
TRIP MSGS: Rental cars have been reserved by Patty Hanson
Boise - Confirmation #G18429782B3 (Minivan in Pat's name)
Olympia - Confirmation #G1853899724 4 (Minivan in Steve's name)
Page 6 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 334 of 419
Trip ID: VA04301 06/05/1 08:21 AM Page: 67
AIRCRAFT ROUTING
04/30/1 - 4/30/1
RIP PURPOSE:Meetings with Oregon Commissioners
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 3DATE:04/30/1 TH
TRAVEL TIME:0 Hour 49 Minute DISTANCE:279 Nautical Mile
DEPART TIME:07:58 AM PDT ARRIVE TIME:08:47 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO:LANDMARK AVIATIO FBO:8136 W PILOT DSPOKANE, WA 99224509-455-5204509-455-5272 - fax
PASSENGERS:MEYER, DAVID J. - 509-220-7432 / 06800545-928010-550-R1
EHRBAR, PAT - 509-994-9074 / 06800545-928010-550-R11
MORRIS, SCOTT L - 509-979-6698 / 06800545-928010-550-R1
Leg
OF PA 3DATE:04/30/1 TH
TRAVEL TIME:0 Hour 46 Minute DISTANCE:279 Nautical Mile
DEPART TIME:11:49 AM PDT ARRIVE TIME:12:35 PM PDT
DEPART FROM:SALEM, OR - KSL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:SALEM AVIATION FUEL FBO:AVISTA HANGA3300 25TH ST S 7500 W PARK DRIVE GATE L
SALEM, OR 9730 SPOKANE, W509.495.413503-364-415503-763-8722 - fa
PASSENGERS:MEYER, DAVID J. - 509-220-7432 / 06800545-928010-550-R11
EHRBAR, PAT - 509-994-9074 / 06800545-928010-550-R11MORRIS, SCOTT L - 509-979-6698 / 06800545-928010-550-R1
LEG MSGS: Need lunch from SLE to GEG
TRIP MSGS: A full size vehicle has been rented under Kelly Norwood's name, confirmation # G5532513342
Page 6 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 335 of 419
Trip ID: VA05051 06/05/1 08:21 AM Page: 68
AIRCRAFT ROUTING
05/05/1 - 5/05/1
RIP PURPOSE:Visit with senators
AIRCRAFT:N202AV CE-65 PILOTS:SCOTT, BRIAN -
ROBINSON, DAVE - Leg 1
OF PA 3DATE:05/05/1 TU
TRAVEL TIME:0 Hour 51 Minute DISTANCE:222 Nautical Mile
DEPART TIME:09:01 AM PDT ARRIVE TIME:09:52 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:LANDMARK AVIATIO FBO:GLACIER JET CENTE8136 W PILOT D 7645 OLD HWY 99 SSPOKANE, WA 99224 OLYMPIA, WA 9850360-705-3214509-455-5204 360-753-0083 - fa509-455-5272 - fax
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 77700300-426400-550-E0
SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 77700300-426400-550-E01
MCCULLOH, THAYNE - 77700300-426400-550-E0
LEG MSGS: John Rothlin will pick up passengers at the airport and take them to and from the meeting.
Leg
OF PA 3DATE:05/05/1 TU
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:01:00 PM PDT ARRIVE TIME:01:41 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA
7645 OLD HWY 99 S 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fax
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 77700300-426400-550-E0
SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 77700300-426400-550-E0MCCULLOH, THAYNE - 77700300-426400-550-E0
Page 68 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 336 of 419
Trip ID: VA05111 06/05/1 08:21 AM Page: 69
AIRCRAFT ROUTING
05/11/1 - 5/11/1
RIP PURPOSE:Annual Update Meetings with IPUC Commissioners
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 4DATE:05/11/1 MO
TRAVEL TIME:0 Hour 42 Minute DISTANCE:249 Nautical Mile
DEPART TIME:06:32 AM PDT ARRIVE TIME:08:14 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO:LANDMARK FBO:JACKSON JET CENTE3815 RICKENBACKER STREETBOISE, ID 8370208-383-330208-336-9082 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 03805511-928000-550-R1
MEYER, DAVID J. - 509-220-7432 / 03805511-928000-550-R11
MORRIS, SCOTT L - 509-979-6698 / 03805511-928000-550-R1VERMILLION, DENNIS P - 509-990-8233 / 03805511-928000-550-R1
Leg
OF PA 4DATE:05/11/15 MON
TRAVEL TIME:0 Hour 41 Minute DISTANCE:249 Nautical Mile
DEPART TIME:12:32 PM MDT ARRIVE TIME:12:13 PM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JACKSON JET CENTE FBO:AVISTA HANGA
3815 RICKENBACKER STREET 7500 W PARK DRIVE GATE LBOISE, ID 8370 SPOKANE, W509.495.413208-383-330
208-336-9082 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 03805511-928000-550-R1
MEYER, DAVID J. - 509-220-7432 / 03805511-928000-550-R1MORRIS, SCOTT L - 509-979-6698 / 03805511-928000-550-R1
VERMILLION, DENNIS P - 509-990-8233 / 03805511-928000-550-R1
LEG MSGS: Need lunch from KBOI to KGEG
TRIP MSGS: One rental vehicle reserved by Patty Hanson in Kelly's name - confirmation #G56005963DN3
Page 6 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 337 of 419
Trip ID: VA05131 06/05/1 08:21 AM Page: 70
AIRCRAFT ROUTING
05/13/1 - 5/13/1
RIP PURPOSE:Natual Gas Semi-Annual Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 5DATE:05/13/1 WED
TRAVEL TIME:0 Hour 53 Minute DISTANCE:249 Nautical Mile
DEPART TIME:06:55 AM PDT ARRIVE TIME:08:48 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO:LANDMARK AVIATIO FBO:JACKSON JET CENTE8136 W PILOT D 3815 RICKENBACKER STREETSPOKANE, WA 99224 BOISE, ID 8370208-383-330509-455-5204 208-336-9082 - fa509-455-5272 - fax
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03800545-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 03800545-928000-550-R11
FINESILVER, RYAN (RYAN) - / 02800545-928000-550-R1PARDEE, TOM - / 02800545-928000-550-R1MOREHOUSE, JODY - 509-979-6674 / 02800545-928000-550-R1
LEG MSGS: Car rental in Boise reserved by Patty Hanson in Pat's name - Confirmation #G5364186615
Leg
OF PA 5DATE:05/13/15 WED
TRAVEL TIME:1 Hour 3 Minute DISTANCE:348 Nautical Mile
DEPART TIME:10:53 AM MDT ARRIVE TIME:10:56 AM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:OLYMPIA REGIONAL
FBO:JACKSON JET CENTE FBO:GLACIER JET CENTE3815 RICKENBACKER STREET 7645 OLD HWY 99 S
BOISE, ID 83705 OLYMPIA, WA 9850360-705-3214208-383-330 360-753-0083 - fa208-336-9082 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03800545-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 03800545-928000-550-R1FINESILVER, RYAN RYAN - / 02800545-928000-550-R1PARDEE, TOM - / 02800545-928000-550-R1
MOREHOUSE, JODY - 509-979-6674 / 02800545-928000-550-R1
LEG MSGS: Car rental in Olympia reserved by Patty Hanson in Pat's name - Confirmation #G53638206B7
Leg 3
OF PA 5DATE:05/13/1 WED
TRAVEL TIME:0 Hour 47 Minute DISTANCE:222 Nautical Mile
DEPART TIME:02:39 PM PDT ARRIVE TIME:03:26 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTER FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE L
OLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03800545-928000-550-R1
Page 70 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 338 of 419
Trip ID: VA05131 06/05/1 08:21 AM Page: 71
AIRCRAFT ROUTING
05/13/1 - 5/13/1
RIP PURPOSE:Natual Gas Semi-Annual Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 3 continue
PASSENGERS:BRANDON, ANNETTE - 509-979-3214 / 03800545-928000-550-R1
FINESILVER, RYAN RYAN - / 02800545-928000-550-R1PARDEE, TOM - / 02800545-928000-550-R11MOREHOUSE, JODY - 509-979-6674 / 02800545-928000-550-R1
Page 71 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 339 of 419
Trip ID: VA05141 06/05/1 08:21 AM Page: 72
AIRCRAFT ROUTING
05/14/1 - 5/14/1
RIP PURPOSE:Meeting with Legislators
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 9DATE:05/14/1 TH
TRAVEL TIME:0 Hour 44 Minute DISTANCE:222 Nautical Mile
DEPART TIME:07:09 AM PDT ARRIVE TIME:07:53 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:LANDMARK AVIATIO FBO:GLACIER JET CENTE8136 W PILOT D 7645 OLD HWY 99 SSPOKANE, WA 99224 OLYMPIA, WA 9850360-705-3214509-455-5204 360-753-0083 - fa509-455-5272 - fax
PASSENGERS:VERMILLION, DENNIS P - 509-990-8233 / 77700300-426400-550-E0
SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 77700300-426400-550-E01
STEVENS, STEVE - 859-393-7014 / 77700300-426400-550-E0PHILIPPS, JEFF - 77700300-426400-550-E0ECKHARDT, EZRA - 77700300-426400-550-E0
SENSKE, MICHAEL - 509-979-6702 / 77700300-426400-550-E0ELKIN, LINDA - 77700300-426400-550-E01
COWLES, STACEY - 77700300-426400-550-E0COUTURE, ELAINE - 77700300-426400-550-E0
LEG MSGS: Need breakfast from GEG to OLM
Two Hertz rental cars have been reserved by Sue Fleming. One in Collins' name and one in Dennis'name. Collins Confirmation #G5641940868
Dennis Confirmation #G5643209934
Leg
OF PA 8DATE:05/14/1 TH
TRAVEL TIME:0 Hour 40 Minute DISTANCE:222 Nautical Mile
DEPART TIME:01:46 PM PDT ARRIVE TIME:02:26 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE L
OLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214360-753-0083 - fax
PASSENGERS:VERMILLION, DENNIS P - 509-990-8233 / 77700300-426400-550-E0
SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 77700300-426400-550-E0
STEVENS, STEVE - 859-393-7014 / 77700300-426400-550-E0PHILIPPS, JEFF - 77700300-426400-550-E0
ECKHARDT, EZRA - 77700300-426400-550-E0SENSKE, MICHAEL - 509-979-6702 / 77700300-426400-550-E0ELKIN, LINDA - 77700300-426400-550-E0
COWLES, STACEY - 77700300-426400-550-E0
Page 7 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 340 of 419
Trip ID: VA051514 06/05/1 08:21 AM Page: 73
AIRCRAFT ROUTING
05/15/1 - 5/15/1
RIP PURPOSE:WUTC for UE-131723 I-937 Rulemaking Workshop
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 6DATE:05/15/14 TH
TRAVEL TIME:0 Hour 48 Minute DISTANCE:222 Nautical Mile
DEPART TIME:07:45 AM PDT ARRIVE TIME:08:33 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800540-928000-550-R1
BONFIELD, SHAWN (SHAWN) - 509-434-6502 / 02800540-928000-550-R11
GALL, JAMES (JAMES) - / 02800540-928000-550-R1KALICH, CLINT CLINT - 509-230-3923 / 02800540-928000-550-R1FOLSOM, BRUCE - 509-990-8428 / 02800540-928000-550-R1
BELL, GRIFFIN GRIFFIN - 02800540-928000-550-R1
LEG MSGS: Need lunch from Olympia to Spokane
Leg 2
OF PA 6DATE:05/15/14 TH
TRAVEL TIME:0 Hour 36 Minutes DISTANCE:222 Nautical Mile
DEPART TIME:12:00 PM PDT ARRIVE TIME:12:42 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA
7645 OLD HWY 99 SE 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800540-928000-550-R1
BONFIELD, SHAWN SHAWN - 509-434-6502 / 02800540-928000-550-R1GALL, JAMES JAMES - / 02800540-928000-550-R1
KALICH, CLINT (CLINT) - 509-230-3923 / 02800540-928000-550-R1FOLSOM, BRUCE - 509-990-8428 / 02800540-928000-550-R1BELL, GRIFFIN (GRIFFIN) - 02800540-928000-550-R1
TRIP MSGS: Hertz Rental Car in Linda's name - Confirmation #G1793295310
Page 7 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 341 of 419
Trip ID: VA05161 06/05/1 08:21 AM Page: 7
AIRCRAFT ROUTING
05/16/1 - 5/19/1
RIP PURPOSE:AGA Financial Conference
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
MUELHEIM, MARKMARK - Leg 1
OF PA 2DATE:05/16/1 SAT
TRAVEL TIME:2 Hours 6 Minute DISTANCE:829 Nautical Mile
DEPART TIME:03:02 PM PDT ARRIVE TIME:05:07 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:PALM SPRINGS, CA - KPS
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:PALM SPRINGS INTERNATIONAL
FBO:LANDMARK FBO:SIGNATURE FLIGHT SU250 N EL CIELO RDPALM SPRINGS, CA 9226760-327-120760-327-5081 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09903691-930200-550-E0
THIES, MARK T - 509-850-7832 / 09903691-930200-550-E01
Leg
OF PA 2DATE:05/19/1 TU
TRAVEL TIME:2 Hours 8 Minute DISTANCE:829 Nautical Mile
DEPART TIME:10:15 AM PDT ARRIVE TIME:12:23 PM PDT
DEPART FROM:PALM SPRINGS, CA - KPS ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:PALM SPRINGS INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:SIGNATURE FLIGHT SU FBO:LANDMARK250 N EL CIELO RDPALM SPRINGS, CA 9226
760-327-120760-327-5081 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09903691-930200-550-E0
THIES, MARK T - 509-850-7832 / 09903691-930200-550-E0
Page 7 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 342 of 419
Trip ID: VA051714 06/05/1 08:21 AM Page: 75
AIRCRAFT ROUTING
05/17/1 - 5/20/1
RIP PURPOSE:AGA FINANCIAL FORUM AND BOARD MEETING
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
HARTNETT, JOHN - Leg 1
OF PA 2DATE:05/17/14 SAT
TRAVEL TIME:2 Hours 8 Minute DISTANCE:1014 Nautical Mile
DEPART TIME:10:10 AM PDT ARRIVE TIME:02:18 PM CDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALINA, KS - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALINA MUNICIPAL
FBO: FBO:
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
LEG MSGS: Need yogurt and granola from KGEG to KSLN
Leg
OF PA 2DATE:05/17/14 SAT
TRAVEL TIME:2 Hours 35 Minute DISTANCE:1168 Nautical Mile
DEPART TIME:02:51 PM CDT ARRIVE TIME:06:26 PM EDT
DEPART FROM:SALINA, KS - KSL ARRIVE AT:MIAMI, FL - KOPF
AIRPORT NAME:SALINA MUNICIPAL AIRPORT NAME:OPA-LOCKA EXECUTIV
FBO:AVFLIGHT FBO:2035 BEECHCRAFT RDSALINA, KS 67401785-825-626
785-825-6264 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
LEG MSGS: Need lunch from SLN to OPF
Leg
OF PA 3DATE:05/20/14 TU
TRAVEL TIME:3 Hours 6 Minute DISTANCE:1168 Nautical Mile
DEPART TIME:10:30 AM EDT ARRIVE TIME:12:36 PM CDT
DEPART FROM:MIAMI, FL - KOPF ARRIVE AT:SALINA, KS - KSL
AIRPORT NAME:OPA-LOCKA EXECUTIV AIRPORT NAME:SALINA MUNICIPAL
FBO: FBO:
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK - MORRIS, SCOTT -
Leg 4
Page 7 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 343 of 419
Trip ID: VA051714 06/05/1 08:21 AM Page: 76
AIRCRAFT ROUTING
05/17/1 - 5/20/1
RIP PURPOSE:AGA FINANCIAL FORUM AND BOARD MEETING
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
HARTNETT, JOHN - Leg 4 continue
OF PA 3DATE:05/20/14 TU
TRAVEL TIME:3 Hours 36 Minute DISTANCE:1014 Nautical Mile
DEPART TIME:01:00 PM CDT ARRIVE TIME:01:36 PM PDT
DEPART FROM:SALINA, KS - KSL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SALINA MUNICIPAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:AVFLIGHT FBO:AVISTA HANGA2035 BEECHCRAFT RD 7500 W PARK DRIVE GATE LSALINA, KS 6740 SPOKANE, W509.495.413785-825-626785-825-6264 - fax
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
MORRIS, SCOTT -
LEG MSGS: Need lunch from SLN to GEG
TRIP MSGS: Carey Car has been reserved by Karen Eastwood
Page 7 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 344 of 419
Trip ID: VA05201 06/05/1 08:21 AM Page: 77
AIRCRAFT ROUTING
05/20/1 - 5/20/1
RIP PURPOSE:Colstrip Mine and Plant Tour; Ownership and Operation Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 7DATE:05/20/1 WED
TRAVEL TIME:1 Hour 10 Minute DISTANCE:457 Nautical Mile
DEPART TIME:06:34 AM PDT ARRIVE TIME:08:44 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:COLSTRIP, MT - M4
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:RICK'S COLSTRI
FBO:LANDMARK FBO:
PASSENGERS:DURKIN, MARIAN M - 708-917-4982 / 09903691-930200-550-E0
GRAHAM, JASON - / 41005004-500000-550-T0FLETCHER, NATHAN - 509-496-3277 / 41005004-500000-550-E0SIMOCK, DEBBIE - 509-981-2357 / 09805377-909000-550-S54
SOYARS, DARRELL (DARRELL) - 509-435-6464 / 09902811-926102-550-E14MECHAM, MIKE MIKE - 509-590-5084 / 41005004-500000-550-T0WIGGINS, GREGORY GREG - 509-690-2731 / 21202810-506020-550-K0
LEG MSGS: Need breakfast from Spokane to Colstrip.
PPL Montana will arrange for a vehicle for the passengers as well as a vehicle for the pilots to use.
Leg 2
OF PA 8DATE:05/20/1 WED
TRAVEL TIME:1 Hour 19 Minute DISTANCE:457 Nautical Mile
DEPART TIME:03:32 PM MDT ARRIVE TIME:03:51 PM PDT
DEPART FROM:COLSTRIP, MT - M4 ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:RICK'S COLSTRI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:LANDMARK
PASSENGERS:DURKIN, MARIAN M - 708-917-4982 / 09903691-930200-550-E0
GRAHAM, JASON - / 41005004-500000-550-T0FLETCHER, NATHAN - 509-496-3277 / 41005004-500000-550-E0SIMOCK, DEBBIE - 509-981-2357 / 09805377-909000-550-S54
SOYARS, DARRELL (DARRELL) - 509-435-6464 / 09902811-926102-550-E14MECHAM, MIKE (MIKE) - 509-590-5084 / 41005004-500000-550-T0WIGGINS, GREGORY GREG - 509-690-2731 / 21202810-506020-550-K0
DEMPSEY, TOM C TOM - 509-688-9716 / 41002100-500000-550-N0
Page 7 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 345 of 419
Trip ID: VA05211 06/05/1 08:21 AM Page: 78
AIRCRAFT ROUTING
05/21/1 - 5/21/1
RIP PURPOSE:EMPLOYEE MEETINGS
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 3DATE:05/21/1 TH
TRAVEL TIME:1 Hour 5 Minute DISTANCE:387 Nautical Mile
DEPART TIME:06:38 AM PDT ARRIVE TIME:07:43 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO:LANDMARK FBO:JET CENTER MF5000 CIRRUS DMEDFORD, OR 97504800-359-029541-772-2759 - fa
PASSENGERS:CHRISTIE, KEVIN J. - 509-714-3587 / 09900162-921000-550-E0
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E01
KENSOK, JAMES M(JIM) - 509-994-2892 / 09900162-921000-550-E0
Leg
OF PA 3DATE:05/21/1 TH
TRAVEL TIME:0 Hour 57 Minute DISTANCE:360 Nautical Mile
DEPART TIME:09:38 AM PDT ARRIVE TIME:10:35 AM PDT
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO:JET CENTER MF FBO:INTER-STATE AV5000 CIRRUS D 2601 AIRPORT COMPLEX
MEDFORD, OR 97504 PULLMAN, WA 9916509-332-659800-359-029 509-334-1751 - fa541-772-2759 - fa
PASSENGERS:CHRISTIE, KEVIN J. - 509-714-3587 / 09900162-921000-550-E01
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E01KENSOK, JAMES M(JIM) - 509-994-2892 / 09900162-921000-550-E0
Leg
OF PA 3DATE:05/21/1 TH
TRAVEL TIME:0 Hour 7 Minute DISTANCE:22 Nautical Mile
DEPART TIME:01:10 PM PDT ARRIVE TIME:01:17 PM PDT
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:LEWISTON, ID - KLW
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:LEWISTON-NEZ PERCE COUNT
FBO:INTER-STATE AV FBO:STOUT FLYING SV2601 AIRPORT COMPLEX 406 BURRELL
PULLMAN, WA 9916 LEWISTON, ID 8350208-743-840509-332-6596 208-798-3284 - fa509-334-1751 - fa
PASSENGERS:CHRISTIE, KEVIN J. - 509-714-3587 / 09900162-921000-550-E01
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E0KENSOK, JAMES M(JIM) - 509-994-2892 / 09900162-921000-550-E0
Leg 4
Page 78 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 346 of 419
Trip ID: VA05211 06/05/1 08:21 AM Page: 79
AIRCRAFT ROUTING
05/21/1 - 5/21/1
RIP PURPOSE:EMPLOYEE MEETINGS
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 4 continue
OF PA 3DATE:05/21/1 TH
TRAVEL TIME:0 Hour 21 Minute DISTANCE:78 Nautical Mile
DEPART TIME:03:02 PM PDT ARRIVE TIME:03:23 PM PDT
DEPART FROM:LEWISTON, ID - KLW ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:LEWISTON-NEZ PERCE COUNT AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:STOUT FLYING SV FBO:LANDMARK406 BURRELL
LEWISTON, ID 8350208-743-840208-798-3284 - fax
PASSENGERS:CHRISTIE, KEVIN J. - 509-714-3587 / 09900162-921000-550-E0
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E01
KENSOK, JAMES M(JIM) - 509-994-2892 / 09900162-921000-550-E0
Page 7 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 347 of 419
Trip ID: VA052214 06/05/1 08:21 AM Page: 80
AIRCRAFT ROUTING
05/22/1 - 5/22/1
RIP PURPOSE:Update Meeting with Idaho Staff in Boise and UW Advisory Council on Medical Education Visit forPasco Group
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE - STANFORD, RICHARD -
Leg 1
OF PA 7DATE:05/22/14 THU
TRAVEL TIME:0 Hour 43 Minute DISTANCE:249 Nautical Mile
DEPART TIME:07:24 AM PDT ARRIVE TIME:09:07 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO:FBO:JACKSON JET CENTE
3815 RICKENBACKER STREETBOISE, ID 8370208-383-330
208-336-9082 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 02805810-928010-550-R1
MEYER, DAVID J. - 509-220-7432 / 02805810-928010-550-R1EHRBAR, PAT - 509-994-9074 / 02805810-928010-550-R1
CLACK, DAVID DAVE - ---CLACK, MARI - ---MORRIS, SCOTT -
BLAKE, KRISTIANNE (KRISTI) - 509-370-2935 / ---
LEG MSGS: Need breakfast from KGEG to KBOI
Leg
OF PA 4DATE:05/22/14 TH
TRAVEL TIME:0 Hour 35 Minute DISTANCE:203 Nautical Mile
DEPART TIME:09:18 AM MDT ARRIVE TIME:08:53 AM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:PASCO, WA - KPS
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:TRI-CITIE
FBO:JACKSON JET CENTE FBO:SULLINAIR JET CT
3815 RICKENBACKER STREET 3702 STEARMAN AVBOISE, ID 8370 PASCO, WA 9930509-545-6524208-383-330
877-858-3770 - fa208-336-9082 - fa
PASSENGERS:CLACK, DAVID (DAVE) - ---
CLACK, MARI - ---MORRIS, SCOTT -
BLAKE, KRISTIANNE KRISTI - 509-370-2935 / ---
Leg
OF PA 3DATE:05/22/14 THU
TRAVEL TIME:0 Hour 39 Minute DISTANCE:203 Nautical Mile
DEPART TIME:02:42 PM PDT ARRIVE TIME:04:21 PM MDT
DEPART FROM:PASCO, WA - KPS ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:TRI-CITIE AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO:SULLINAIR JET CT FBO:JACKSON JET CENTE3702 STEARMAN AV 3815 RICKENBACKER STREETPASCO, WA 99301 BOISE, ID 8370208-383-330509-545-6524 208-336-9082 - fa877-858-3770 - fa
This le continues on the next a e
Page 80 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 348 of 419
Trip ID: VA052214 06/05/1 08:21 AM Page: 81
AIRCRAFT ROUTING
05/22/1 - 5/22/1
RIP PURPOSE:Update Meeting with Idaho Staff in Boise and UW Advisory Council on Medical Education Visit forPasco Group
AIRCRAFT:N202AV CE-65 PILOTS:
Leg 3 continue
PASSENGERS:CLACK, DAVID DAVE - ---
CLACK, MARI - ---MORRIS, SCOTT -
Leg 4
OF PA 6DATE:05/22/14 TH
TRAVEL TIME:0 Hour 42 Minute DISTANCE:249 Nautical Mile
DEPART TIME:04:32 PM MDT ARRIVE TIME:04:14 PM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JACKSON JET CENTE FBO:AVISTA HANGA
3815 RICKENBACKER STREET 7500 W PARK DRIVE GATE LBOISE, ID 8370 SPOKANE, W509.495.413208-383-330
208-336-9082 - fax
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 02805810-928010-550-R1
MEYER, DAVID J. - 509-220-7432 / 02805810-928010-550-R1EHRBAR, PAT - 509-994-9074 / 02805810-928010-550-R1
CLACK, DAVID (DAVE) - ---CLACK, MARI - ---MORRIS, SCOTT -
TRIP MSGS: Rental car reserved by Patty Hanson in Pat Erbar's name for the Boise Group. Rental car reserved bySue Fleming in Scott Morris' name for the Pasco group.
Page 81 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 349 of 419
Trip ID: VA052714 06/05/1 08:21 AM Page: 82
AIRCRAFT ROUTING
05/27/1 - 5/27/1
RIP PURPOSE:ID General Rate Case Discussions
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 4DATE:05/27/14 TU
TRAVEL TIME:0 Hour 46 Minute DISTANCE:249 Nautical Mile
DEPART TIME:08:29 AM PDT ARRIVE TIME:10:15 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO: FBO:JACKSON JET CENTE3815 RICKENBACKER STREETBOISE, ID 8370208-383-330208-336-9082 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03805343-928010-550-R1
GERVAIS, LINDA - 509-953-8057 / 03805343-928010-550-R11
NORWOOD, KELLY O. - 509-990-8144 / 03805343-928010-550-R1MEYER, DAVID J. - 509-220-7432 / 03805343-928010-550-R1
Leg
OF PA 4DATE:05/27/14 TUE
TRAVEL TIME:0 Hour 39 Minute DISTANCE:249 Nautical Mile
DEPART TIME:04:25 PM MDT ARRIVE TIME:04:04 PM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JACKSON JET CENTE FBO:AVISTA HANGA
3815 RICKENBACKER STREET 7500 W PARK DRIVE GATE LBOISE, ID 8370 SPOKANE, W509.495.413208-383-330
208-336-9082 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03805343-928010-550-R1
GERVAIS, LINDA - 509-953-8057 / 03805343-928010-550-R1NORWOOD, KELLY O. - 509-990-8144 / 03805343-928010-550-R1
MEYER, DAVID J. - 509-220-7432 / 03805343-928010-550-R1
TRIP MSGS: Rental Car reserved by Wendy Manskey in Pat's name - confirmation #G21422309A6
Page 8 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 350 of 419
Trip ID: VA052814 06/05/1 08:21 AM Page: 83
AIRCRAFT ROUTING
05/28/1 - 5/28/1
RIP PURPOSE:NW Utility General Counsel's Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 1DATE:05/28/14 WED
TRAVEL TIME:0 Hour 51 Minute DISTANCE:249 Nautical Mile
DEPART TIME:07:36 AM PDT ARRIVE TIME:09:27 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO:AVISTA HANGA FBO:JACKSON JET CENTE7500 W PARK DRIVE GATE L 3815 RICKENBACKER STREETSPOKANE, W BOISE, ID 8370208-383-330509.495.413 208-336-9082 - fa
PASSENGERS:DURKIN, MARIAN M - 708-917-4982 / 09903691-930200-550-E0
LEG MSGS: Need breakfast from KGEG to KBOI
Marian will need a taxi from the airport to her meeting at Idaho Power Corporate Headquarters, 1221W. Idaho Street, Boise, ID
Leg
OF PA 1DATE:05/28/14 WED
TRAVEL TIME:0 Hour 37 Minute DISTANCE:249 Nautical Mile
DEPART TIME:03:32 PM MDT ARRIVE TIME:03:09 PM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JACKSON JET CENTE FBO:AVISTA HANGA3815 RICKENBACKER STREET 7500 W PARK DRIVE GATE LBOISE, ID 8370 SPOKANE, W
509.495.413208-383-3300208-336-9082 - fa
PASSENGERS:DURKIN, MARIAN M - 708-917-4982 / 09903691-930200-550-E01
TRIP MSGS: Marian will need a taxi from the airport to her meeting at Idaho Power Corporate Headquarters, 1221
W. Idaho Street, Boise, ID
Page 8 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 351 of 419
Trip ID: VA05281 06/05/1 08:21 AM Page: 8
AIRCRAFT ROUTING
05/28/1 - 5/28/1
RIP PURPOSE:Washington Roundtable Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 1DATE:05/28/1 TH
TRAVEL TIME:0 Hour 41 Minute DISTANCE:193 Nautical Mile
DEPART TIME:10:36 AM PDT ARRIVE TIME:11:17 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO:LANDMARK AVIATIO FBO:CLAY LACY AVIATIO8136 W PILOT D 8285 PERIMETER RD SPOKANE, WA 99224 SEATTLE, WA 9810206-762-600509-455-5204 206-768-0888 - fa509-455-5272 - fax
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900310-930200-550-E0
Leg 2
OF PA 1DATE:05/28/1 TH
TRAVEL TIME:0 Hour 43 Minute DISTANCE:193 Nautical Mile
DEPART TIME:02:18 PM PDT ARRIVE TIME:03:01 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA
8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600
206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900310-930200-550-E0
Page 8 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 352 of 419
Trip ID: VA052914 06/05/1 08:21 AM Page: 85
AIRCRAFT ROUTING
05/29/1 - 5/29/1
RIP PURPOSE:WUTC Workshop - U140632 Low Income Electric and Gas
AIRCRAFT:N202AV CE-65 PILOTS:
Leg 1
OF PA 5DATE:05/29/14 TH
TRAVEL TIME:0 Hour 43 Minute DISTANCE:222 Nautical Mile
DEPART TIME:11:28 AM PDT ARRIVE TIME:12:11 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:FBO:GLACIER JET CENTE7645 OLD HWY 99 S
OLYMPIA, WA 9850360-705-3214
360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800540-928000-550-R1
EHRBAR, PAT - 509-994-9074 / 02800540-928000-550-R1DRAKE, CHRIS (CHRIS) - 509-389-0521 / 02800540-928000-550-R1COELHO, RENEE (RENEE) - 509-981-9528 / 02800540-928000-550-R1
FIELDER, CASEY (CASEY) - 509-703-2209 / 02800540-928000-550-R1
LEG MSGS: Need lunch from KGEG to KOLM
Leg
OF PA 5DATE:05/29/14 TH
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:05:15 PM PDT ARRIVE TIME:05:57 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA
7645 OLD HWY 99 S 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800545-928000-550-R1
EHRBAR, PAT - 509-994-9074 / 02800545-928000-550-R1DRAKE, CHRIS (CHRIS) - 509-389-0521 / 02800545-928000-550-R1
COELHO, RENEE RENEE - 509-981-9528 / 02800545-928000-550-R1FIELDER, CASEY CASEY - 509-703-2209 / 02800545-928000-550-R1
TRIP MSGS: Rental Van in Pat's name - confirmation #G1962590828
Page 8 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 353 of 419
Trip ID: VA05291 06/05/1 08:21 AM Page: 86
AIRCRAFT ROUTING
05/29/1 - 5/29/1
RIP PURPOSE:Group of Spokane Leaders/stakeholders to meet with leaders of Bend's successful startupcommunity - entrepreneurship and economic development.
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD - ROBINSON, DAVE -
Leg 1
OF PA 8DATE:05/29/15 FRI
TRAVEL TIME:0 Hour 45 Minute DISTANCE:261 Nautical Mile
DEPART TIME:07:31 AM PDT ARRIVE TIME:08:16 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BEND, OR - KBD
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BEND MUNICIPAL
FBO:LANDMARK AVIATIO FBO:PROFESSIONAL AI
8136 W PILOT D 63132 POWELL BUTTE RDSPOKANE, WA 99224 BEND, OR 9770541-388-001509-455-5204
541-385-8459 - fa509-455-5272 - fa
PASSENGERS:TRABUN, STEVE - 509-995-4077 / 77700300-426120-550-J5
ELKIN, LINDA - 77700300-426120-550-J5ARNOLD, RYAN - 77700300-426120-550-J5
ALLEN, MICHAEL MIKE - 77700300-426120-550-J5LAFFERTY, TYLER - 77700300-426120-550-J5SAVITZ, BILL - 509-953-9622 / 77700300-426120-550-J5
STEVENS, STEVE - 859-393-7014 / 77700300-426120-550-J5LANE, TED - 77700300-426120-550-J5
LEG MSGS: Steve has rented a van.
Leg
OF PA 8DATE:05/29/15 FRI
TRAVEL TIME:0 Hour 42 Minute DISTANCE:261 Nautical Mile
DEPART TIME:04:55 PM PDT ARRIVE TIME:05:38 PM PDT
DEPART FROM:BEND, OR - KBD ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BEND MUNICIPAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:PROFESSIONAL AI FBO:AVISTA HANGA63132 POWELL BUTTE RD 7500 W PARK DRIVE GATE LBEND, OR 9770 SPOKANE, W
509.495.413541-388-001541-385-8459 - fa
PASSENGERS:TRABUN, STEVE - 509-995-4077 / 77700300-426120-550-J5
ELKIN, LINDA - 77700300-426120-550-J5
ARNOLD, RYAN - 77700300-426120-550-J5ALLEN, MICHAEL MIKE - 77700300-426120-550-J5LAFFERTY, TYLER - 77700300-426120-550-J5
SAVITZ, BILL - 509-953-9622 / 77700300-426120-550-J50STEVENS, STEVE - 859-393-7014 / 77700300-426120-550-J5LANE, TED - 77700300-426120-550-J5
Page 8 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 354 of 419
Trip ID: VA060214 06/05/1 08:21 AM Page: 87
AIRCRAFT ROUTING
06/02/1 - 6/02/1
RIP PURPOSE:WESTERN ENERGY CONFERENCE - PANEL MEMBER
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 1DATE:06/02/14 MO
TRAVEL TIME:0 Hour 48 Minute DISTANCE:193 Nautical Mile
DEPART TIME:05:45 AM PDT ARRIVE TIME:06:33 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO: FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900310-930200-550-E0
Leg 2
OF PA 1DATE:06/02/14 MO
TRAVEL TIME:0 Hour 36 Minute DISTANCE:193 Nautical Mile
DEPART TIME:11:00 AM PDT ARRIVE TIME:11:42 AM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA
8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600
206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900310-930200-550-E0
Page 8 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 355 of 419
Trip ID: VA060314 06/05/1 08:21 AM Page: 88
AIRCRAFT ROUTING
06/03/1 - 6/03/1
RIP PURPOSE:WASHINGTON ROUNDTABLE MEETING
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 1DATE:06/03/14 TU
TRAVEL TIME:0 Hour 48 Minute DISTANCE:193 Nautical Mile
DEPART TIME:10:30 AM PDT ARRIVE TIME:11:18 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO: FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900310-930200-550-E0
Leg 2
OF PA 1DATE:06/03/14 TU
TRAVEL TIME:0 Hour 36 Minute DISTANCE:193 Nautical Mile
DEPART TIME:02:00 PM PDT ARRIVE TIME:02:42 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA
8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600
206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09900310-930200-550-E0
Page 88 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 356 of 419
Trip ID: VA060814 06/05/1 08:21 AM Page: 89
AIRCRAFT ROUTING
06/08/1 - 6/11/1
RIP PURPOSE:EEI Conference
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 7DATE:06/08/14 SU
TRAVEL TIME:1 Hour 48 Minute DISTANCE:700 Nautical Mile
DEPART TIME:08:30 AM PDT ARRIVE TIME:10:18 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:LAS VEGAS, NV - KLA
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:MCCARRAN INTERNATIONAL
FBO: FBO:SIGNATURE FLIGHT SU6005 LAS VEGAS BLVD LAS VEGAS, NV 8911702-739-110702-739-1241 - fa
PASSENGERS:DURKIN, MARIAN M - 708-917-4982 / 09800310-930200-550-E0
CHRISTIE, KEVIN J. - 509-714-3587 / 09800310-930200-550-E01
THACKSTON, JASON R - 509-290-4590 / 09800310-930200-550-E0LANG, JASON - 509-995-8248 / 09800310-930200-550-E0HOWARD, BRUCE - 509-990-0984 / 09800310-930200-550-E0
MORRIS, SCOTT - MORRIS, LIZBETH ANN(LIZ) - 09800310-930200-550-E01
LEG MSGS: Need breakfast from KGEG to KLAS
A Cary Van (operated by Executive Las Vegas) has been reserved by Sue Fleming - Confirmation
#WA8316102-1. The van will pick the group up at Signature Flight Support and drop off at Aria.
Leg
OF PA 3DATE:06/11/14 WED
TRAVEL TIME:1 Hour 54 Minute DISTANCE:700 Nautical Mile
DEPART TIME:02:00 PM PDT ARRIVE TIME:03:48 PM PDT
DEPART FROM:LAS VEGAS, NV - KLA ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:MCCARRAN INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:SIGNATURE FLIGHT SU FBO:AVISTA HANGA6005 LAS VEGAS BLVD 7500 W PARK DRIVE GATE LLAS VEGAS, NV 89119 SPOKANE, W509.495.413702-739-110702-739-1241 - fa
PASSENGERS:FELTES, KAREN S - 509-290-2612 / 09800310-930200-550-E0
DURKIN, MARIAN M - 708-917-4982 / 09800310-930200-550-E0
LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
Page 8 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 357 of 419
Trip ID: VA061714 06/05/1 08:21 AM Page: 90
AIRCRAFT ROUTING
06/17/1 - 6/17/1
RIP PURPOSE:Visit with OPUC Commissioners
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 4DATE:06/17/14 TU
TRAVEL TIME:0 Hour 46 Minute DISTANCE:279 Nautical Mile
DEPART TIME:07:35 AM PDT ARRIVE TIME:08:21 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO: FBO:
PASSENGERS:NORWOOD, KELLY -
THIES, MARK - VERMILLION, DENNIS - MEYER, DAVID -
Leg
OF PA 4DATE:06/17/14 TU
TRAVEL TIME:0 Hour 56 Minute DISTANCE:279 Nautical Mile
DEPART TIME:11:26 AM PDT ARRIVE TIME:12:22 PM PDT
DEPART FROM:SALEM, OR - KSL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA7500 W PARK DRIVE GATE LSPOKANE, W
509.495.413
PASSENGERS:NORWOOD, KELLY -
THIES, MARK - VERMILLION, DENNIS - MEYER, DAVID -
LEG MSGS: Need lunch from KSLE to KGEG
TRIP MSGS: 1 rental minivan reserved in Kelly's name by Patty Hanson
Page 90 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 358 of 419
Trip ID: VA061814 06/05/1 08:21 AM Page: 91
AIRCRAFT ROUTING
06/18/1 - 6/18/1
RIP PURPOSE:BNSF Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 5DATE:06/18/14 WED
TRAVEL TIME:3 Hours 0 Minute DISTANCE:1274 Nautical Mile
DEPART TIME:06:20 AM PDT ARRIVE TIME:11:20 AM CDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:FORT WORTH, TX - KFTW
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:FORT WORTH MEACHAM INTERNATIO
FBO: FBO:TEXAS JET INC200 TEXAS WAFT WORTH, TX 7610817-624-843817-624-1320 - fa
PASSENGERS:LAFFERTY, BOB (BOB) - 509-994-6625 / 77705248-930290-550-S0
RAHN, GREG (GREG) - 509-435-8887 / 77705248-930290-550-S05
THACKSTON, JASON R - 509-290-4590 / 77705248-930290-550-S0STEWART, OLIVIA - 77705248-930290-550-S0TOTH, ROBIN - 509-994-6602 / 77705248-930290-550-S0
LEG MSGS: Need breakfast from Spokane to Fort Worth
Leg
OF PA 5DATE:06/18/14 WED
TRAVEL TIME:3 Hours 6 Minute DISTANCE:1274 Nautical Mile
DEPART TIME:04:00 PM CDT ARRIVE TIME:05:12 PM PDT
DEPART FROM:FORT WORTH, TX - KFTW ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:FORT WORTH MEACHAM INTERNATIOAIRPORT NAME:SPOKANE INTERNATIONAL
FBO:TEXAS JET INC FBO:AVISTA HANGA200 TEXAS WA 7500 W PARK DRIVE GATE L
FT WORTH, TX 76106 SPOKANE, W509.495.413817-624-843817-624-1320 - fa
PASSENGERS:LAFFERTY, BOB (BOB) - 509-994-6625 / 77705248-930290-550-S0
RAHN, GREG (GREG) - 509-435-8887 / 77705248-930290-550-S0THACKSTON, JASON R - 509-290-4590 / 77705248-930290-550-S0STEWART, OLIVIA - 77705248-930290-550-S0
TOTH, ROBIN - 509-994-6602 / 77705248-930290-550-S0
TRIP MSGS: Shirley Wolf has set up a car service with Fernando Limo - 917-434-5795 for transportation to and from
the airport.
Page 91 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 359 of 419
Trip ID: VA062414 06/05/1 08:21 AM Page: 92
AIRCRAFT ROUTING
06/24/1 - 6/24/1
RIP PURPOSE:Meeting with Bob Grimm - Alaska Power & Telephone
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 4DATE:06/24/14 TU
TRAVEL TIME:0 Hour 41 Minute DISTANCE:193 Nautical Mile
DEPART TIME:10:08 AM PDT ARRIVE TIME:10:49 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO: FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:VERMILLION, DENNIS P - 509-990-8233 / 77705228-426500-550-S2
STEINER, NOLAN - 509-279-5190 / 77705228-426500-550-S20
CHRISTIE, KEVIN J. - 509-714-3587 / 77705228-426500-550-S2SCHAFFNER, MARC - 208-659-7864 / 77705228-426500-550-S2
Leg
OF PA 4DATE:06/24/14 TUE
TRAVEL TIME:0 Hour 34 Minute DISTANCE:193 Nautical Mile
DEPART TIME:01:59 PM PDT ARRIVE TIME:02:33 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA
8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600
206-768-0888 - fa
PASSENGERS:VERMILLION, DENNIS P - 509-990-8233 / 77705228-426500-550-S2
STEINER, NOLAN - 509-279-5190 / 77705228-426500-550-S2CHRISTIE, KEVIN J. - 509-714-3587 / 77705228-426500-550-S2
SCHAFFNER, MARC - 208-659-7864 / 77705228-426500-550-S2
TRIP MSGS: Linda will set up ground transportation
Page 9 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 360 of 419
Trip ID: VA062414 06/05/1 08:21 AM Page: 93
AIRCRAFT ROUTING
06/24/1 - 6/24/1
RIP PURPOSE:Valley Vision Presentation in Lewiston
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 1DATE:06/24/14 TU
TRAVEL TIME:0 Hour 18 Minute DISTANCE:78 Nautical Mile
DEPART TIME:03:47 PM PDT ARRIVE TIME:04:05 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:LEWISTON, ID - KLW
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:LEWISTON-NEZ PERCE COUNT
FBO:AVISTA HANGA FBO:STOUT FLYING SV7500 W PARK DRIVE GATE L 406 BURRELLSPOKANE, W LEWISTON, ID 8350208-743-840509.495.413 208-798-3284 - fa
PASSENGERS:MORRIS, SCOTT -
LEG MSGS: Mike Tatko will provide transportation
Leg 2
OF PA 1DATE:06/24/14 TU
TRAVEL TIME:0 Hour 16 Minutes DISTANCE:78 Nautical Mile
DEPART TIME:07:40 PM PDT ARRIVE TIME:07:56 PM PDT
DEPART FROM:LEWISTON, ID - KLW ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:LEWISTON-NEZ PERCE COUNT AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:STOUT FLYING SV FBO:AVISTA HANGA
406 BURRELL 7500 W PARK DRIVE GATE LLEWISTON, ID 8350 SPOKANE, W
509.495.413208-743-840208-798-3284 - fa
PASSENGERS:MORRIS, SCOTT -
LEG MSGS: Mike Tatko will provide transportation
Page 9 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 361 of 419
Trip ID: VA062514 06/05/1 08:21 AM Page: 9
AIRCRAFT ROUTING
06/25/1 - 6/25/1
RIP PURPOSE:Settlement Conference
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 8DATE:06/25/14 WED
TRAVEL TIME:0 Hour 42 Minute DISTANCE:249 Nautical Mile
DEPART TIME:06:59 AM PDT ARRIVE TIME:08:41 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO: FBO:JACKSON JET CENTE3815 RICKENBACKER STREETBOISE, ID 8370208-383-330208-336-9082 - fa
PASSENGERS:MEYER, DAVID -
NORWOOD, KELLY -
EHRBAR, PAT - 509-994-9074 / 03805343-928010-550-R1ANDREWS, ELIZABETH LIZ - / 03805343-928010-550-R1GERVAIS, LINDA - 509-953-8057 / 03805343-928010-550-R1
PLUTH, JEANNE - 509-294-9560 / 03805343-928010-550-R1LA BOLLE, LARRY - 208-659-2428 / 03805343-928010-550-R11
JOHNSON, BILL (BILL) - / 03805343-928010-550-R1
Leg
OF PA 8DATE:06/25/14 WED
TRAVEL TIME:0 Hour 43 Minute DISTANCE:249 Nautical Mile
DEPART TIME:01:16 PM MDT ARRIVE TIME:12:59 PM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JACKSON JET CENTE FBO:AVISTA HANGA3815 RICKENBACKER STREET 7500 W PARK DRIVE GATE LBOISE, ID 8370 SPOKANE, W
509.495.413208-383-330208-336-9082 - fa
PASSENGERS:MEYER, DAVID -
NORWOOD, KELLY -
EHRBAR, PAT - 509-994-9074 / 03805343-928010-550-R1ANDREWS, ELIZABETH LIZ - / 03805343-928010-550-R1GERVAIS, LINDA - 509-953-8057 / 03805343-928010-550-R1
PLUTH, JEANNE - 509-294-9560 / 03805343-928010-550-R1LA BOLLE, LARRY - 208-659-2428 / 03805343-928010-550-R11JOHNSON, BILL (BILL) - / 03805343-928010-550-R1
TRIP MSGS: Two rental vehicles have been reserved by Patty Hanson in Kelly and Pat's names (Confirmation#G2401942651 (Klly) and #G24027433B3 (Pat)
Page 9 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 362 of 419
Trip ID: VA062614 06/05/1 08:21 AM Page: 95
AIRCRAFT ROUTING
06/26/1 - 6/26/1
RIP PURPOSE:Colstrip CEO Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 3DATE:06/26/14 TH
TRAVEL TIME:0 Hour 48 Minute DISTANCE:193 Nautical Mile
DEPART TIME:11:30 AM PDT ARRIVE TIME:12:18 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO: FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09903691-930200-550-E0
DURKIN, MARIAN M - 708-917-4982 / 09903691-930200-550-E01
SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 09903691-930200-550-E0
LEG MSGS: Need lunch from KGEG to KBFI
Leg
OF PA 3DATE:06/26/14 TH
TRAVEL TIME:0 Hour 36 Minute DISTANCE:193 Nautical Mile
DEPART TIME:04:30 PM PDT ARRIVE TIME:05:12 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA
8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600
206-768-0888 - fax
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09903691-930200-550-E0
DURKIN, MARIAN M - 708-917-4982 / 09903691-930200-550-E0SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 09903691-930200-550-E0
TRIP MSGS: Melnik will provide transportation to and from the meeting. Confirmation #
Page 9 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 363 of 419
Trip ID: VA062614 06/05/1 08:21 AM Page: 96
AIRCRAFT ROUTING
06/26/1 - 6/26/1
RIP PURPOSE:Retirement Party for Harold Sheeran
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 5DATE:06/26/14 TH
TRAVEL TIME:1 Hour 6 Minute DISTANCE:359 Nautical Mile
DEPART TIME:05:15 PM PDT ARRIVE TIME:06:27 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:ROSEBURG, OR - KRB
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:ROSEBURG REGIONAL
FBO: FBO:WESTERN OR FLYING S2251 NW AVIATION DROSEBURG, OR 9747541-673-472541-673-5586 - fa
PASSENGERS:KOPCZYNSKI, DON M - 509-990-8885 / 09900162-921000-550-E0
FAULKENBERRY, MIKE - 509-990-2386 / 09900162-921000-550-E01
THORSON, NEIL - 509-499-7673 / 09900162-921000-550-E0MILANI, CHUCK - 509-990-4188 / 09900162-921000-550-E0WEBB, RENEE - 509-280-7541 / 09900162-921000-550-E0
Leg
OF PA 6DATE:06/26/14 TH
TRAVEL TIME:1 Hour 6 Minute DISTANCE:359 Nautical Mile
DEPART TIME:08:30 PM PDT ARRIVE TIME:09:36 PM PDT
DEPART FROM:ROSEBURG, OR - KRB ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:ROSEBURG REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:WESTERN OR FLYING S FBO:AVISTA HANGA2251 NW AVIATION D 7500 W PARK DRIVE GATE LROSEBURG, OR 9747 SPOKANE, W
509.495.413541-673-472541-673-5586 - fa
PASSENGERS:KOPCZYNSKI, DON M - 509-990-8885 / 09900162-921000-550-E0
FAULKENBERRY, MIKE - 509-990-2386 / 09900162-921000-550-E0
HOWELL, DAVID DAVID - 509-990-8732 / 09900162-921000-550-E0THORSON, NEIL - 509-499-7673 / 09900162-921000-550-E0MILANI, CHUCK - 509-990-4188 / 09900162-921000-550-E01
WEBB, RENEE - 509-280-7541 / 09900162-921000-550-E0
TRIP MSGS: Rental Car from Clint Newell Auto Group will be waiting at FBO for the group - 7 passenger van rented
to Don Kopczynski
Page 9 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 364 of 419
Trip ID: VA070714 06/05/1 08:21 AM Page: 97
AIRCRAFT ROUTING
07/07/1 - 7/07/1
RIP PURPOSE:WA GRC Settlement Conference
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 9DATE:07/07/14 MO
TRAVEL TIME:0 Hour 54 Minute DISTANCE:222 Nautical Mile
DEPART TIME:08:00 AM PDT ARRIVE TIME:08:48 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:MEYER, DAVID -
NORWOOD, KELLY -
EHRBAR, PAT - 509-994-9074 / 02805810-928010-550-R1ANDREWS, ELIZABETH LIZ - / 02805810-928010-550-R1GERVAIS, LINDA - 509-953-8057 / 02805810-928010-550-R1
JOHNSON, BILL BILL - / 02805810-928010-550-R1PLUTH, JEANNE - 509-294-9560 / 02805810-928010-550-R11
SCHUH, KAREN - 509-995-6652 / 02805810-928010-550-R1KNOX, TARA - / 02805810-928010-550-R1
Leg
OF PA 9DATE:07/07/14 MON
TRAVEL TIME:0 Hour 36 Minute DISTANCE:222 Nautical Mile
DEPART TIME:05:00 PM PDT ARRIVE TIME:05:42 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE L
OLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:MEYER, DAVID -
NORWOOD, KELLY - EHRBAR, PAT - 509-994-9074 / 02805810-928010-550-R1ANDREWS, ELIZABETH LIZ - / 02805810-928010-550-R1
GERVAIS, LINDA - 509-953-8057 / 02805810-928010-550-R1JOHNSON, BILL (BILL) - / 02805810-928010-550-R11PLUTH, JEANNE - 509-294-9560 / 02805810-928010-550-R1SCHUH, KAREN - 509-995-6652 / 02805810-928010-550-R1KNOX, TARA - / 02805810-928010-550-R1
TRIP MSGS: Rental vehicles reserved by Patty Hanson in Kelly and Pat's names - Confirmation #G24008051D3(Kelly) and #G24048605E4 (Pat).
Page 9 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 365 of 419
Trip ID: VA070814 06/05/1 08:21 AM Page: 98
AIRCRAFT ROUTING
07/08/1 - 7/08/1
RIP PURPOSE:Oregon Natual Gas Outlook Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 4DATE:07/08/14 TU
TRAVEL TIME:0 Hour 51 Minute DISTANCE:279 Nautical Mile
DEPART TIME:07:46 AM PDT ARRIVE TIME:08:37 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO: FBO:
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 06800545-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 06800545-928000-550-R1PARDEE, TOM - / 06800545-928000-550-R1FILER, LESLIE - / 06800545-928000-550-R11
Leg
OF PA 4DATE:07/08/14 TU
TRAVEL TIME:0 Hour 44 Minute DISTANCE:279 Nautical Mile
DEPART TIME:11:06 AM PDT ARRIVE TIME:11:50 AM PDT
DEPART FROM:SALEM, OR - KSL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA7500 W PARK DRIVE GATE LSPOKANE, W
509.495.413
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 06800545-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 06800545-928000-550-R1PARDEE, TOM - / 06800545-928000-550-R11FILER, LESLIE - / 06800545-928000-550-R1
TRIP MSGS: Rental car reserved by Wendy Manskey in Pat Ehrbar's name - confirmation #G2143510049
Page 98 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 366 of 419
Trip ID: VA070914 06/05/1 08:21 AM Page: 99
AIRCRAFT ROUTING
07/09/1 - 7/09/1
RIP PURPOSE:Meeting with University Presidents Regarding Medical School
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 4DATE:07/09/14 WED
TRAVEL TIME:0 Hour 48 Minute DISTANCE:193 Nautical Mile
DEPART TIME:10:15 AM PDT ARRIVE TIME:11:03 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO: FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09903691-930200-550-E0
WOODWORTH, ROGER D - 509-981-2282 / 09903691-930200-550-E01
WILSON, MICHAEL (MIKE) - 09903691-930200-550-E0AXWORTHY, ANNE MARIE - 09903691-930200-550-E0
Leg
OF PA 5DATE:07/09/14 WED
TRAVEL TIME:0 Hour 42 Minute DISTANCE:217 Nautical Mile
DEPART TIME:04:45 PM PDT ARRIVE TIME:05:33 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO:CLAY LACY AVIATIO FBO:INTER-STATE AV
8285 PERIMETER RD 2601 AIRPORT COMPLEX SEATTLE, WA 9810 PULLMAN, WA 9916509-332-659206-762-600
509-334-1751 - fa206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09903691-930200-550-E0
WOODWORTH, ROGER D - 509-981-2282 / 09903691-930200-550-E0WILSON, MICHAEL MIKE - 09903691-930200-550-E0
AXWORTHY, ANNE MARIE - 09903691-930200-550-E0FLOYD, ELSON - 09903691-930200-550-E0
Leg 3
OF PA 4DATE:07/09/14 WED
TRAVEL TIME:0 Hour 12 Minute DISTANCE:55 Nautical Mile
DEPART TIME:05:45 PM PDT ARRIVE TIME:06:03 PM PDT
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:INTER-STATE AV FBO:AVISTA HANGA2601 AIRPORT COMPLEX 7500 W PARK DRIVE GATE L
PULLMAN, WA 9916 SPOKANE, W509.495.413509-332-659
509-334-1751 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09903691-930200-550-E0
WOODWORTH, ROGER D - 509-981-2282 / 09903691-930200-550-E0WILSON, MICHAEL (MIKE) - 09903691-930200-550-E0AXWORTHY, ANNE MARIE - 09903691-930200-550-E0
TRIP MSGS: Additional Messages for this leg continue on the next page
Page 9 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 367 of 419
Trip ID: VA070914 06/05/1 08:21 AM Page: 100
AIRCRAFT ROUTING
07/09/1 - 7/09/1
RIP PURPOSE:Meeting with University Presidents Regarding Medical School
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 3 continue
RIP MSGS: Melnik will provide transportation to and from the airport
Page 100 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 368 of 419
Trip ID: VA071014 06/05/1 08:21 AM Page: 101
AIRCRAFT ROUTING
07/10/1 - 7/10/1
RIP PURPOSE:UM 1633 Pension Investigation Workshop with Commissioners and Prehearing Conference
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 2DATE:07/10/14 TH
TRAVEL TIME:0 Hour 48 Minute DISTANCE:279 Nautical Mile
DEPART TIME:08:00 AM PDT ARRIVE TIME:09:00 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO: FBO:
PASSENGERS:ANDREWS, ELIZABETH LIZ - / 06805169-928000-550-R1
KRASSELT, RYAN L RYAN - 509-590-8363 / 06805169-928000-550-R1
Leg
OF PA 2DATE:07/10/14 TH
TRAVEL TIME:0 Hour 48 Minute DISTANCE:279 Nautical Mile
DEPART TIME:03:00 PM PDT ARRIVE TIME:03:54 PM PDT
DEPART FROM:SALEM, OR - KSL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA7500 W PARK DRIVE GATE L
SPOKANE, W509.495.413
PASSENGERS:ANDREWS, ELIZABETH (LIZ) - / 06805169-928000-550-R1
KRASSELT, RYAN L RYAN - 509-590-8363 / 06805169-928000-550-R1
TRIP MSGS: Car reserved by Patty Hanson in Liz's name - Confirmation #7CY7R0
Page 101 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 369 of 419
Trip ID: VA071014 06/05/1 08:21 AM Page: 102
AIRCRAFT ROUTING
07/10/1 - 7/11/1
RIP PURPOSE:Visit with MetalFx Management
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 4DATE:07/10/14 TH
TRAVEL TIME:1 Hour 36 Minute DISTANCE:566 Nautical Mile
DEPART TIME:04:30 PM PDT ARRIVE TIME:06:06 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:UKIAH, CA - KUKI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:UKIAH MUNICIPAL
FBO:AVISTA HANGA FBO:7500 W PARK DRIVE GATE L
SPOKANE, W509.495.413
PASSENGERS:BURMEISTER-SMITH, CHRISTY M. - 509-981-3470 / 77703430-417120-550-E0
THIES, MARK -
VAN ORDEN, TRACY - 509-954-3875 / 77703430-417120-550-E0FALKNER, DON M DON - 509-953-7895 / 77703430-417120-550-E0
Leg
OF PA 4DATE:07/11/14 FRI
TRAVEL TIME:1 Hour 18 Minute DISTANCE:566 Nautical Mile
DEPART TIME:01:00 PM PDT ARRIVE TIME:02:30 PM PDT
DEPART FROM:UKIAH, CA - KUKI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:UKIAH MUNICIPAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CITY OF UKIAH ARPT FBO:AVISTA HANGA
1403 S STATE ST 7500 W PARK DRIVE GATE LUKIAH, CA 9548 SPOKANE, W509.495.413707-467-281
707-467-2853 - fa
PASSENGERS:BURMEISTER-SMITH, CHRISTY M. - 509-981-3470 / 77703430-417120-550-E0
THIES, MARK - VAN ORDEN, TRACY - 509-954-3875 / 77703430-417120-550-E0
FALKNER, DON M DON - 509-953-7895 / 77703430-417120-550-E0
Page 10 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 370 of 419
Trip ID: VA071614 06/05/1 08:21 AM Page: 103
AIRCRAFT ROUTING
07/16/1 - 7/16/1
RIP PURPOSE:Visit to Scott AFB - Air Mobility Command
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 7DATE:07/16/14 WED
TRAVEL TIME:3 Hours 2 Minute DISTANCE:1321 Nautical Mile
DEPART TIME:04:57 AM PDT ARRIVE TIME:09:59 AM CDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BELLEVILLE, IL - KBLV
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:MIDAMERICA ST LOUIS SCOTT AFB
FBO: FBO:AVMATS-MIDAMERIC8885 AVMATS DRIVMASCOUTAH, IL 6225636-812-152618-566-5326 - fa
PASSENGERS:CONDON, DAVID - 509-710-9400 / 77700300-426120-550-E0
HADLEY, RICH (RICH) - 509-953-8845 / 77700300-426120-550-E01
MIELKE, TODD - 509-220-2200 / 77700300-426120-550-E0SAVITZ, BILL - 509-953-9622 / 77700300-426120-550-E0SENSKE, MICHAEL - 509-979-6702 / 77700300-426120-550-E0
STEVENS, STEVE - 859-393-7014 / 77700300-426120-550-E0VERMILLION, DENNIS P - 509-990-8233 / 77700300-426120-550-E01
LEG MSGS: Need breakfast from KGEG to KBLV
Leg 2
OF PA 7DATE:07/16/14 WED
TRAVEL TIME:3 Hours 20 Minute DISTANCE:1321 Nautical Mile
DEPART TIME:01:52 PM CDT ARRIVE TIME:03:12 PM PDT
DEPART FROM:BELLEVILLE, IL - KBLV ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:MIDAMERICA ST LOUIS SCOTT AFB AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:AVMATS-MIDAMERICA FBO:AVISTA HANGA8885 AVMATS DRIV 7500 W PARK DRIVE GATE LMASCOUTAH, IL 6225 SPOKANE, W
509.495.413636-812-152618-566-5326 - fa
PASSENGERS:CONDON, DAVID - 509-710-9400 / 77700300-426120-550-E0
HADLEY, RICH RICH - 509-953-8845 / 77700300-426120-550-E0
MIELKE, TODD - 509-220-2200 / 77700300-426120-550-E0SAVITZ, BILL - 509-953-9622 / 77700300-426120-550-E0SENSKE, MICHAEL - 509-979-6702 / 77700300-426120-550-E0
STEVENS, STEVE - 859-393-7014 / 77700300-426120-550-E0VERMILLION, DENNIS P - 509-990-8233 / 77700300-426120-550-E0
TRIP MSGS: Sue will set up ground transportation
Page 10 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 371 of 419
Trip ID: VA072514 06/05/1 08:21 AM Page: 10
AIRCRAFT ROUTING
07/25/1 - 7/25/1
RIP PURPOSE:I-937 Biennial Conservation Report Hearing
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 6DATE:07/25/14 FRI
TRAVEL TIME:0 Hour 48 Minute DISTANCE:222 Nautical Mile
DEPART TIME:08:00 AM PDT ARRIVE TIME:08:48 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800540-928000-205-R1
FOLSOM, BRUCE - 509-990-8428 / 02800540-928000-205-R11
JOHNSON, DAN (DAN) - 509-720-1028 / 02800540-928000-205-R1POWELL, JON JON - / 02800540-928000-205-R1THOMPSON, DAVID - 509-979-9147 / 02800540-928000-205-R1
DRAKE, CHRIS CHRIS - 509-389-0521 / 02800540-928000-205-R1
Leg 2
OF PA 6DATE:07/25/14 FRI
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:01:00 PM PDT ARRIVE TIME:01:42 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE L
OLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800540-928000-205-R1
FOLSOM, BRUCE - 509-990-8428 / 02800540-928000-205-R1JOHNSON, DAN DAN - 509-720-1028 / 02800540-928000-205-R1POWELL, JON (JON) - / 02800540-928000-205-R11
THOMPSON, DAVID - 509-979-9147 / 02800540-928000-205-R1DRAKE, CHRIS CHRIS - 509-389-0521 / 02800540-928000-205-R1
Page 10 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 372 of 419
Trip ID: VA072814 06/05/1 08:21 AM Page: 105
AIRCRAFT ROUTING
07/28/1 - 7/30/1
RIP PURPOSE:Meetings with Moody's and S&P
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
SCOTT, BRIAN - Leg 1
OF PA 5DATE:07/28/14 MO
TRAVEL TIME:1 Hour 50 Minute DISTANCE:842 Nautical Mile
DEPART TIME:07:05 AM PDT ARRIVE TIME:10:55 AM CDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:FBO:FARGO JET CENTE3801 20TH ST FARGO, ND 5810701-235-360701-237-6887 - fa
PASSENGERS:MORRIS, SCOTT -
THIES, MARK -
STEVENS, RICH - 509-990-6072 / 09903370-930200-550-F54NORWOOD, KELLY - PENDERGRAFT, LAUREN - / 09903370-930200-550-F54
LEG MSGS: Need breakfast from KGEG to KFAR
Leg
OF PA 5DATE:07/28/14 MON
TRAVEL TIME:2 Hours 29 Minute DISTANCE:1045 Nautical Mile
DEPART TIME:11:22 AM CDT ARRIVE TIME:02:51 PM EDT
DEPART FROM:FARGO, ND - KFA ARRIVE AT:TETERBORO, NJ - KTEB
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:TETERBOR
FBO:FARGO JET CENTE FBO:MERIDIAN TETERBOR3801 20TH ST 485 INDUSTRIAL AV
FARGO, ND 58102 TETERBORO, NJ 0760201-288-504701-235-360 201-288-4430 - fa701-237-6887 - fa
PASSENGERS:MORRIS, SCOTT -
THIES, MARK - STEVENS, RICH - 509-990-6072 / 09903370-930200-550-F54NORWOOD, KELLY -
PENDERGRAFT, LAUREN - / 09903370-930200-550-F54
LEG MSGS: Need lunch from KFAR to KTEB
Leg 3
OF PA 5DATE:07/30/14 WED
TRAVEL TIME:2 Hours 44 Minute DISTANCE:1045 Nautical Mile
DEPART TIME:01:12 PM EDT ARRIVE TIME:02:56 PM CDT
DEPART FROM:TETERBORO, NJ - KTEB ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:TETERBORO AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:MERIDIAN TETERBORO FBO:FARGO JET CENTE485 INDUSTRIAL AV 3801 20TH ST
TETERBORO, NJ 0760 FARGO, ND 5810701-235-360201-288-504
701-237-6887 - fa201-288-4430 - fa
PASSENGERS:MORRIS, SCOTT -
Page 10 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 373 of 419
Trip ID: VA072814 06/05/1 08:21 AM Page: 106
AIRCRAFT ROUTING
07/28/1 - 7/30/1
RIP PURPOSE:Meetings with Moody's and S&P
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
SCOTT, BRIAN - Leg 3 continue
PASSENGERS:THIES, MARK -
STEVENS, RICH - 509-990-6072 / 09903370-930200-550-F54NORWOOD, KELLY -
PENDERGRAFT, LAUREN - / 09903370-930200-550-F54
LEG MSGS: Need lunch from KTEB to KFAR
Leg 4
OF PA 5DATE:07/30/14 WED
TRAVEL TIME:2 Hours 11 Minute DISTANCE:842 Nautical Mile
DEPART TIME:03:25 PM CDT ARRIVE TIME:03:36 PM PDT
DEPART FROM:FARGO, ND - KFA ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:FARGO JET CENTE FBO:AVISTA HANGA3801 20TH ST 7500 W PARK DRIVE GATE L
FARGO, ND 5810 SPOKANE, W509.495.413701-235-360701-237-6887 - fa
PASSENGERS:MORRIS, SCOTT -
THIES, MARK - STEVENS, RICH - 509-990-6072 / 09903370-930200-550-F54NORWOOD, KELLY -
PENDERGRAFT, LAUREN - / 09903370-930200-550-F54
TRIP MSGS: Carey Cars have been reserved for the trip
Page 10 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 374 of 419
Trip ID: VA073114 06/05/1 08:21 AM Page: 107
AIRCRAFT ROUTING
07/31/1 - 8/02/1
RIP PURPOSE:Montana Governor's Cup
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
HARTNETT, JOHN - Leg 1
OF PA 3DATE:07/31/14 TH
TRAVEL TIME:0 Hour 27 Minute DISTANCE:138 Nautical Mile
DEPART TIME:03:41 PM PDT ARRIVE TIME:05:08 PM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:KALISPELL, MT - KGPI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:GLACIER PARK INTERNATIONAL
FBO: FBO:GLACIER JET CENTE4170 HWY 2 E INTL AIRPORTKALISPELL, MT 5990406-755-536406-755-5900 - fa
PASSENGERS:COLWELL, NEIL - 208-890-2731 / 77700521-426400-550-B1
THACKSTON, JASON R - 509-290-4590 / 77700521-426400-550-E01
THACKSTON, JULIE - 77700521-426400-550-B1
Leg
OF PA 3DATE:08/02/14 SAT
TRAVEL TIME:0 Hour 30 Minute DISTANCE:138 Nautical Mile
DEPART TIME:02:16 PM MDT ARRIVE TIME:01:46 PM PDT
DEPART FROM:KALISPELL, MT - KGPI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:GLACIER PARK INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA4170 HWY 2 E INTL AIRPORT 7500 W PARK DRIVE GATE L
KALISPELL, MT 5990 SPOKANE, W509.495.413406-755-536406-755-5900 - fa
PASSENGERS:COLWELL, NEIL - 208-890-2731 / 77700521-426400-550-B16
THACKSTON, JASON R - 509-290-4590 / 77700521-426400-550-E01THACKSTON, JULIE - 77700521-426400-550-B1
Page 10 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 375 of 419
Trip ID: VA080414 06/05/1 08:21 AM Page: 108
AIRCRAFT ROUTING
08/04/1 - 8/04/1
RIP PURPOSE:WA GRC Settlement Conference
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
HARTNETT, JOHN - Leg 1
OF PA 9DATE:08/04/14 MO
TRAVEL TIME:0 Hour 48 Minute DISTANCE:222 Nautical Mile
DEPART TIME:08:00 AM PDT ARRIVE TIME:08:48 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:MEYER, DAVID -
NORWOOD, KELLY -
EHRBAR, PAT - 509-994-9074 / 02805810-928010-550-R1ANDREWS, ELIZABETH LIZ - / 02805810-928010-550-R1GERVAIS, LINDA - 509-953-8057 / 02805810-928010-550-R1
JOHNSON, BILL BILL - / 02805810-928010-550-R1FORSYTH, GRANT (GRANT) - / 02805810-928010-550-R11
SCHUH, KAREN - 509-995-6652 / 02805810-928010-550-R1KNOX, TARA - / 02805810-928010-550-R1
Leg
OF PA 9DATE:08/04/14 MON
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:05:00 PM PDT ARRIVE TIME:05:42 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE L
OLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:MEYER, DAVID -
NORWOOD, KELLY - EHRBAR, PAT - 509-994-9074 / 02805810-928010-550-R1ANDREWS, ELIZABETH LIZ - / 02805810-928010-550-R1
GERVAIS, LINDA - 509-953-8057 / 02805810-928010-550-R1JOHNSON, BILL (BILL) - / 02805810-928010-550-R11FORSYTH, GRANT (GRANT) - / 02805810-928010-550-R1SCHUH, KAREN - 509-995-6652 / 02805810-928010-550-R1KNOX, TARA - / 02805810-928010-550-R1
TRIP MSGS: Rental Vehicles in Kelly (#G2813815246), Pat (G2813839806) and Linda's (#G2813683087) names.
Page 108 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 376 of 419
Trip ID: VA081114 06/05/1 08:21 AM Page: 109
AIRCRAFT ROUTING
08/11/1 - 8/12/1
RIP PURPOSE:AGA Executive Committee Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
HARTNETT, JOHN - Leg 1
OF PA 1DATE:08/11/14 MO
TRAVEL TIME:0 Hour 48 Minute DISTANCE:242 Nautical Mile
DEPART TIME:03:54 PM PDT ARRIVE TIME:04:42 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:PORTLAND, OR - KPD
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:PORTLAND INTERNATIONAL
FBO: FBO:ATLANTIC AVIATIO7527 NE AIRPORT WAPORTLAND, OR 9721503-331-422503-331-4273 - fa
PASSENGERS:MORRIS, SCOTT -
LEG MSGS: LimoLink has been reserved to pick up Scott at the FBO and take him to the hotel - confirmation#Q1913259-001
Leg
OF PA 1DATE:08/12/14 TU
TRAVEL TIME:0 Hour 43 Minute DISTANCE:242 Nautical Mile
DEPART TIME:12:52 PM PDT ARRIVE TIME:01:35 PM PDT
DEPART FROM:PORTLAND, OR - KPD ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:PORTLAND INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:ATLANTIC AVIATIO FBO:AVISTA HANGA7527 NE AIRPORT WA 7500 W PARK DRIVE GATE L
PORTLAND, OR 9721 SPOKANE, W509.495.413503-331-422
503-331-4273 - fa
PASSENGERS:MORRIS, SCOTT -
LEG MSGS: LimoLink has been reserved to pick up Scott at the hotel and take him to the FBO - confirmation#Q1913259-002
Page 10 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 377 of 419
Trip ID: VA081814 06/05/1 08:21 AM Page: 110
AIRCRAFT ROUTING
08/18/1 - 8/18/1
RIP PURPOSE:Ecova Closing Celebration
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 4DATE:08/18/14 MO
TRAVEL TIME:0 Hour 42 Minute DISTANCE:193 Nautical Mile
DEPART TIME:01:18 PM PDT ARRIVE TIME:02:00 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO: FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT -
FELTES, KAREN S - 509-290-2612 / 77703430-417120-550-E01
DURKIN, MARIAN M - 708-917-4982 / 77703430-417120-550-E0FLEMING, SUSAN Y SUE - 509-939-6550 / 77703430-417120-550-E0
Leg
OF PA 4DATE:08/18/14 MON
TRAVEL TIME:0 Hour 40 Minute DISTANCE:193 Nautical Mile
DEPART TIME:09:54 PM PDT ARRIVE TIME:10:34 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA
8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600
206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT -
FELTES, KAREN S - 509-290-2612 / 77703430-417120-550-E0DURKIN, MARIAN M - 708-917-4982 / 77703430-417120-550-E0
FLEMING, SUSAN Y SUE - 509-939-6550 / 77703430-417120-550-E0
TRIP MSGS: Sue will set up ground transportation
Page 110 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 378 of 419
Trip ID: VA081914 06/05/1 08:21 AM Page: 111
AIRCRAFT ROUTING
08/19/1 - 8/19/1
RIP PURPOSE:Oregon PGA Workshop
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 6DATE:08/19/14 TU
TRAVEL TIME:0 Hour 50 Minute DISTANCE:279 Nautical Mile
DEPART TIME:07:25 AM PDT ARRIVE TIME:08:15 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO: FBO:
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 06805173-928010-550-R1
BRANDON, ANNETTE - 509-979-3214 / 06805173-928010-550-R1PARDEE, TOM - / 06805173-928010-550-R1FILER, LESLIE - / 06805173-928010-550-R11
FINESILVER, RYAN (RYAN) - / 06805173-928010-550-R1STANFORD, HARLEY - 06805173-928010-550-R1
LEG MSGS: One vehicle reserved by Patty Hanson in Pat Ehrbar's name - confirmation #857JHN
Leg
OF PA 6DATE:08/19/14 TU
TRAVEL TIME:0 Hour 48 Minute DISTANCE:279 Nautical Mile
DEPART TIME:11:00 AM PDT ARRIVE TIME:11:47 AM PDT
DEPART FROM:SALEM, OR - KSL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA7500 W PARK DRIVE GATE LSPOKANE, W
509.495.413
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 06805173-928010-550-R11
BRANDON, ANNETTE - 509-979-3214 / 06805173-928010-550-R1
PARDEE, TOM - / 06805173-928010-550-R1FILER, LESLIE - / 06805173-928010-550-R1FINESILVER, RYAN RYAN - / 06805173-928010-550-R1
STANFORD, HARLEY - 06805173-928010-550-R1
LEG MSGS: Need lunch from KSLE to KGEG - salad for Annette (no cheese)
Page 111 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 379 of 419
Trip ID: VA082014 06/05/1 08:21 AM Page: 112
AIRCRAFT ROUTING
08/20/1 - 8/20/1
RIP PURPOSE:Oregon Gas Manager Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 7DATE:08/20/14 WED
TRAVEL TIME:0 Hour 24 Minute DISTANCE:141 Nautical Mile
DEPART TIME:07:00 AM PDT ARRIVE TIME:07:36 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:LA GRANDE, OR - KLGD
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:LA GRANDE/UNION COUNT
FBO:FBO:UNION CO ARPT60175 PIERCE RD
LA GRANDE, OR 9785541-963-661541-963-9098 - fa
PASSENGERS:BUSHNELL, TERRY (TERRY) - 509-991-5021 / 09902800-921000-550-X0
HOWELL, DAVID (DAVID) - 509-990-8732 / 09900165-870000-550-G08
BEELER, KEN - / 09902800-921000-550-X0GIGLER, DAN - 509-979-6755 / 98405238-300100-550-G0MOREHOUSE, JODY - 509-979-6674 / 098405239-300100-550-G0
WEBB, JEFF - 509-714-4674 / 098405239-300100-550-G0MOSS, DEREK - 509-842-0726 / 09902800-921000-550-X02
LEG MSGS: Need Breakfast from KGEG to KLGD
Leg 2
OF PA 9DATE:08/20/14 WED
TRAVEL TIME:1 Hour 0 Minute DISTANCE:274 Nautical Mile
DEPART TIME:07:45 AM PDT ARRIVE TIME:08:45 AM PDT
DEPART FROM:LA GRANDE, OR - KLGD ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:LA GRANDE/UNION COUNT AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO:UNION CO ARPT FBO:JET CENTER MF60175 PIERCE RD 5000 CIRRUS DLA GRANDE, OR 9785 MEDFORD, OR 97504
800-359-029541-963-661 541-772-2759 - fa541-963-9098 - fa
PASSENGERS:BUSHNELL, TERRY TERRY - 509-991-5021 / 09902800-921000-550-X0
HOWELL, DAVID DAVID - 509-990-8732 / 09900165-870000-550-G0
BEELER, KEN - / 09902800-921000-550-X0GIGLER, DAN - 509-979-6755 / 98405238-300100-550-G0MOREHOUSE, JODY - 509-979-6674 / 098405239-300100-550-G0
WEBB, JEFF - 509-714-4674 / 098405239-300100-550-G0RAJKOVICH, THOMAS ROB - 541-786-0514 / 09902800-921000-550-X0KELLOGG, DONALD (DON) - 541-786-0280 / 77700242-107060-550-G0
MOSS, DEREK - 509-842-0726 / 09902800-921000-550-X0
Leg
Page 11 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 380 of 419
Trip ID: VA082014 06/05/1 08:21 AM Page: 113
AIRCRAFT ROUTING
08/20/1 - 8/20/1
RIP PURPOSE:Oregon Gas Manager Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 3 continue
OF PA 8DATE:08/20/14 WED
TRAVEL TIME:0 Hour 42 Minute DISTANCE:274 Nautical Mile
DEPART TIME:04:30 PM PDT ARRIVE TIME:05:24 PM PDT
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:LA GRANDE, OR - KLGD
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:LA GRANDE/UNION COUNT
FBO:JET CENTER MF FBO:UNION CO ARPT5000 CIRRUS D 60175 PIERCE RDMEDFORD, OR 97504 LA GRANDE, OR 9785541-963-661800-359-029 541-963-9098 - fa541-772-2759 - fax
PASSENGERS:BUSHNELL, TERRY (TERRY) - 509-991-5021 / 09902800-921000-550-X0
BEELER, KEN - / 09902800-921000-550-X02
GIGLER, DAN - 509-979-6755 / 98405238-300100-550-G0WHITBY, MICHAEL MIKE - 509-991-1278 / 09902800-921000-550-X0MOREHOUSE, JODY - 509-979-6674 / 098405239-300100-550-G0
WEBB, JEFF - 509-714-4674 / 098405239-300100-550-G0RAJKOVICH, THOMAS (ROB) - 541-786-0514 / 09902800-921000-550-X02
MOSS, DEREK - 509-842-0726 / 09902800-921000-550-X0
Leg 4
OF PA 7DATE:08/20/14 WED
TRAVEL TIME:0 Hour 30 Minute DISTANCE:141 Nautical Mile
DEPART TIME:06:00 PM PDT ARRIVE TIME:06:36 PM PDT
DEPART FROM:LA GRANDE, OR - KLGD ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:LA GRANDE/UNION COUNT AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:UNION CO ARPT FBO:AVISTA HANGA60175 PIERCE RD 7500 W PARK DRIVE GATE LLA GRANDE, OR 9785 SPOKANE, W
509.495.413541-963-661541-963-9098 - fa
PASSENGERS:BUSHNELL, TERRY (TERRY) - 509-991-5021 / 09902800-921000-550-X02
BEELER, KEN - / 09902800-921000-550-X02
GIGLER, DAN - 509-979-6755 / 98405238-300100-550-G0WHITBY, MICHAEL MIKE - 509-991-1278 / 09902800-921000-550-X0MOREHOUSE, JODY - 509-979-6674 / 098405239-300100-550-G0
WEBB, JEFF - 509-714-4674 / 098405239-300100-550-G0MOSS, DEREK - 509-842-0726 / 09902800-921000-550-X02
Page 11 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 381 of 419
Trip ID: VA082114 06/05/1 08:21 AM Page: 11
AIRCRAFT ROUTING
08/21/1 - 8/21/1
RIP PURPOSE:Meetings with WUTC and IPUC Staffs
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 3DATE:08/21/14 TH
TRAVEL TIME:0 Hour 44 Minute DISTANCE:222 Nautical Mile
DEPART TIME:08:37 AM PDT ARRIVE TIME:09:21 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800540-928000-550-R1
CHRISTIE, KEVIN J. - 509-714-3587 / 02800540-928000-550-R11
JOHNSON, DAN (DAN) - 509-720-1028 / 02800540-928000-550-R1
LEG MSGS: Rental Car in Olympia Confirmation #G28311646A3
Leg
OF PA 3DATE:08/21/14 TH
TRAVEL TIME:0 Hour 51 Minute DISTANCE:348 Nautical Mile
DEPART TIME:11:53 AM PDT ARRIVE TIME:01:44 PM MDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO:GLACIER JET CENTE FBO:JACKSON JET CENTE
7645 OLD HWY 99 S 3815 RICKENBACKER STREETOLYMPIA, WA 9850 BOISE, ID 8370208-383-330360-705-3214
208-336-9082 - fa360-753-0083 - fax
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 03800540-928000-550-R1
CHRISTIE, KEVIN J. - 509-714-3587 / 03800540-928000-550-R1JOHNSON, DAN (DAN) - 509-720-1028 / 03800540-928000-550-R1
LEG MSGS: Need lunch from KOLM to KBOI
Rental Car in Boise Confirmation #G28312528C0D
Leg
OF PA 3DATE:08/21/14 THU
TRAVEL TIME:0 Hour 42 Minute DISTANCE:249 Nautical Mile
DEPART TIME:05:37 PM MDT ARRIVE TIME:05:18 PM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JACKSON JET CENTE FBO:AVISTA HANGA
3815 RICKENBACKER STREET 7500 W PARK DRIVE GATE LBOISE, ID 83705 SPOKANE, W509.495.413208-383-330
208-336-9082 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 03800540-928000-550-R1
CHRISTIE, KEVIN J. - 509-714-3587 / 03800540-928000-550-R1Additional Passen ers for this le continue on the next a e
Page 11 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 382 of 419
Trip ID: VA082114 06/05/1 08:21 AM Page: 115
AIRCRAFT ROUTING
08/21/1 - 8/21/1
RIP PURPOSE:Meetings with WUTC and IPUC Staffs
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 3 continue
PASSENGERS:JOHNSON, DAN DAN - 509-720-1028 / 03800540-928000-550-R1
Page 11 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 383 of 419
Trip ID: VA082514 06/05/1 08:21 AM Page: 116
AIRCRAFT ROUTING
08/25/1 - 8/25/1
RIP PURPOSE:Physical survey of Gas Pipeline from Medford to Grants Pass for vegetation mgmt project / Nancywill be delivering training presentation to CPC's on Real Estate Job Requests and Exhibits.
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD - ROBINSON, DAVE -
Leg 1
OF PA 4DATE:08/25/14 MON
TRAVEL TIME:0 Hour 18 Minute DISTANCE:55 Nautical Mile
DEPART TIME:07:30 AM PDT ARRIVE TIME:07:48 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO:FBO:INTER-STATE AV
2601 AIRPORT COMPLEX PULLMAN, WA 9916509-332-659
509-334-1751 - fa
PASSENGERS:PRICE, ROD - 509-991-2877 / 77700242-107060-550-V0
ATHERTON, DAVE - / 77700242-107060-550-V0LEE, LARRY - 509-990-8309 / 77700242-107060-550-V0
SOYARS, DARRELL DARRELL - 509-435-6464 / 77700242-107060-550-V0
LEG MSGS: Breakfast will be provided
Leg
OF PA 5DATE:08/25/14 MO
TRAVEL TIME:0 Hour 54 Minute DISTANCE:360 Nautical Mile
DEPART TIME:08:00 AM PDT ARRIVE TIME:09:12 AM PDT
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO:INTER-STATE AV FBO:JET CENTER MF
2601 AIRPORT COMPLEX 5000 CIRRUS DPULLMAN, WA 9916 MEDFORD, OR 97504800-359-029509-332-659
541-772-2759 - fa509-334-1751 - fa
PASSENGERS:PRICE, ROD - 509-991-2877 / 77700242-107060-550-V0
DANIELS, RANDY - 509-553-9907 / 77700240-107060-550-V0ATHERTON, DAVE - / 77700242-107060-550-V0LEE, LARRY - 509-990-8309 / 77700242-107060-550-V0SOYARS, DARRELL (DARRELL) - 509-435-6464 / 77700242-107060-550-V08
Leg
OF PA 5DATE:08/25/14 MO
TRAVEL TIME:1 Hour 0 Minute DISTANCE:360 Nautical Mile
DEPART TIME:04:00 PM PDT ARRIVE TIME:05:06 PM PDT
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO:JET CENTER MF FBO:INTER-STATE AV5000 CIRRUS D 2601 AIRPORT COMPLEX
MEDFORD, OR 97504 PULLMAN, WA 9916509-332-659800-359-029 509-334-1751 - fa541-772-2759 - fax
PASSENGERS:PRICE, ROD - 509-991-2877 / 77700242-107060-550-V0
DANIELS, RANDY - 509-553-9907 / 77700240-107060-550-V0Additional Passengers for this leg continue on the next page
Page 11 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 384 of 419
Trip ID: VA082514 06/05/1 08:21 AM Page: 117
AIRCRAFT ROUTING
08/25/1 - 8/25/1
RIP PURPOSE:Physical survey of Gas Pipeline from Medford to Grants Pass for vegetation mgmt project / Nancywill be delivering training presentation to CPC's on Real Estate Job Requests and Exhibits.
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE - STANFORD, RICHARD -
Leg 3 continue
PASSENGERS:ATHERTON, DAVE - / 77700242-107060-550-V08
LEE, LARRY - 509-990-8309 / 77700242-107060-550-V0
SOYARS, DARRELL (DARRELL) - 509-435-6464 / 77700242-107060-550-V0
Leg 4
OF PA 4DATE:08/25/14 MO
TRAVEL TIME:0 Hour 12 Minute DISTANCE:55 Nautical Mile
DEPART TIME:05:15 PM PDT ARRIVE TIME:05:33 PM PDT
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:INTER-STATE AV FBO:AVISTA HANGA2601 AIRPORT COMPLEX 7500 W PARK DRIVE GATE L
PULLMAN, WA 9916 SPOKANE, W509.495.413509-332-6596509-334-1751 - fa
PASSENGERS:PRICE, ROD - 509-991-2877 / 77700242-107060-550-V0
ATHERTON, DAVE - / 77700242-107060-550-V0LEE, LARRY - 509-990-8309 / 77700242-107060-550-V0SOYARS, DARRELL DARRELL - 509-435-6464 / 77700242-107060-550-V0
TRIP MSGS: Rental Car
Page 11 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 385 of 419
Trip ID: VA082714 06/05/1 08:21 AM Page: 118
AIRCRAFT ROUTING
08/27/1 - 8/27/1
RIP PURPOSE:Washington Roundtable Executive Committee Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 1DATE:08/27/14 WED
TRAVEL TIME:0 Hour 46 Minute DISTANCE:193 Nautical Mile
DEPART TIME:09:31 AM PDT ARRIVE TIME:10:17 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO: FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT -
LEG MSGS: Melnik Limousine will pick up Scott at Clay Lacy Aviation
Leg 2
OF PA 1DATE:08/27/14 WED
TRAVEL TIME:0 Hour 33 Minutes DISTANCE:193 Nautical Mile
DEPART TIME:02:09 PM PDT ARRIVE TIME:02:42 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA
8285 PERIMETER RD S 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W
509.495.413206-762-600206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT -
LEG MSGS: Melnik Limousine will return Scott to Clay Lacy Aviation
Page 118 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 386 of 419
Trip ID: VA090214 06/05/1 08:21 AM Page: 119
AIRCRAFT ROUTING
09/02/1 - 9/03/1
RIP PURPOSE:Avista Board Retreat
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 8DATE:09/02/14 TU
TRAVEL TIME:0 Hour 45 Minute DISTANCE:193 Nautical Mile
DEPART TIME:04:03 PM PDT ARRIVE TIME:04:48 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO:AVISTA HANGA FBO:CLAY LACY AVIATIO7500 W PARK DRIVE GATE L 8285 PERIMETER RD SPOKANE, W SEATTLE, WA 9810206-762-600509.495.413 206-768-0888 - fa
PASSENGERS:FELTES, KAREN S - 509-290-2612 / 09900020-930200-550-E0
ZAKARIAN, MARK - 09900020-930200-550-E01
MORRIS, SCOTT - MORRIS, LIZBETH ANN LIZ - 09900020-930200-550-E0VERMILLION, DENNIS -
VERMILLION, MARLENE - 09900020-930200-550-E0FLEMING, SUSAN Y(SUE) - 509-939-6550 / 09900020-930200-550-E01
WOODWORTH, ROGER D - 509-981-2282 / 09900020-930200-550-E0
Leg
OF PA 8DATE:09/03/14 WED
TRAVEL TIME:0 Hour 36 Minute DISTANCE:193 Nautical Mile
DEPART TIME:03:16 PM PDT ARRIVE TIME:03:52 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W
509.495.413206-762-600206-768-0888 - fa
PASSENGERS:BURMEISTER-SMITH, CHRISTY M. - 509-981-3470 / 09900020-930200-550-E01
MEYER, DAVID -
KOPCZYNSKI, DON M - 509-990-8885 / 09900020-930200-550-E0KENSOK, JAMES M JIM - 509-994-2892 / 09900020-930200-550-E0WOODWORTH, ROGER D - 509-981-2282 / 09900020-930200-550-E0
ROSENTRATER, HEATHER - 509-879-5320 / 09900020-930200-550-E0CHRISTIE, KEVIN J. - 509-714-3587 / 09900020-930200-550-E01LAFFERTY, BOB (BOB) - 509-994-6625 / 09900020-930200-550-E0
Page 11 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 387 of 419
Trip ID: VA090214 06/05/1 08:21 AM Page: 120
AIRCRAFT ROUTING
09/02/1 - 9/02/1
RIP PURPOSE:Meeting with Public Counsel 11:00 am downtown Seattle to discuss DSM re-organization
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 3DATE:09/02/14 TU
TRAVEL TIME:0 Hour 48 Minute DISTANCE:193 Nautical Mile
DEPART TIME:09:00 AM PDT ARRIVE TIME:09:48 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO: FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800540-928000-550-R1
CHRISTIE, KEVIN J. - 509-714-3587 / 02800540-928000-550-R11
JOHNSON, DAN (DAN) - 509-720-1028 / 02800540-928000-550-R1
LEG MSGS: Car in Linda's name - Conf#G2882956631
Leg
OF PA 2DATE:09/02/14 TU
TRAVEL TIME:0 Hour 42 Minute DISTANCE:193 Nautical Mile
DEPART TIME:12:45 PM PDT ARRIVE TIME:01:27 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA
8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600
206-768-0888 - fax
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800540-928000-550-R1
JOHNSON, DAN (DAN) - 509-720-1028 / 02800540-928000-550-R1
Page 120 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 388 of 419
Trip ID: VA090714 06/05/1 08:21 AM Page: 121
AIRCRAFT ROUTING
09/07/1 - 9/09/1
RIP PURPOSE:WEI Annual Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 6DATE:09/07/14 SU
TRAVEL TIME:0 Hour 36 Minute DISTANCE:158 Nautical Mile
DEPART TIME:12:30 PM PDT ARRIVE TIME:01:06 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:KELOWNA, BC - CYLW
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KELOWNA INTERNATIONAL
FBO: FBO:KELOWNA SHELL AER104 6197 AIRPORT WAKELOWNA, BC V1V 2S250-765-815250-765-0814 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09800310-930200-550-E0
MORRIS, LIZBETH ANN(LIZ) - 09800310-930200-550-E01
FELTES, KAREN S - 509-290-2612 / 09800310-930200-550-E0ZAKARIAN, MARK - 09800310-930200-550-E0ROSENTRATER, HEATHER - 509-879-5320 / 09800310-930200-550-E0
VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E0
Leg 2
OF PA 6DATE:09/09/14 TU
TRAVEL TIME:0 Hour 30 Minute DISTANCE:158 Nautical Mile
DEPART TIME:05:30 PM PDT ARRIVE TIME:06:06 PM PDT
DEPART FROM:KELOWNA, BC - CYLW ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KELOWNA INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:KELOWNA SHELL AER FBO:AVISTA HANGA 104 6197 AIRPORT WA 7500 W PARK DRIVE GATE L
KELOWNA, BC V1V 2S SPOKANE, W509.495.413250-765-815250-765-0814 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 09800310-930200-550-E0
MORRIS, LIZBETH ANN LIZ - 09800310-930200-550-E0FELTES, KAREN S - 509-290-2612 / 09800310-930200-550-E0ZAKARIAN, MARK - 09800310-930200-550-E01
ROSENTRATER, HEATHER - 509-879-5320 / 09800310-930200-550-E0VERMILLION, DENNIS P - 509-990-8233 / 09800310-930200-550-E0
TRIP MSGS: Let's Go Transportation will pick up 6 passengers from the airport and transport to hotel - They willreverse the trip on 9/9.
Robert778-821-0101Let's Go Transportation, Kelowna
Page 121 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 389 of 419
Trip ID: VA091114 06/05/1 08:21 AM Page: 122
AIRCRAFT ROUTING
09/11/1 - 9/11/1
RIP PURPOSE:Oregon Costs Allocation Workshop for UG-246
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 4DATE:09/11/14 TH
TRAVEL TIME:1 Hour 0 Minute DISTANCE:279 Nautical Mile
DEPART TIME:08:15 AM PDT ARRIVE TIME:09:15 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO: FBO:
PASSENGERS:ANDREWS, ELIZABETH LIZ - / 06805169-928010-550-R1
PLUTH, JEANNE - 509-294-9560 / 06805169-928010-550-R1KNOX, TARA - / 06805169-928010-550-R1SMITH, JENNIFER (JEN) - / 06805169-928010-550-R11
LEG MSGS: One vehicle reserved by Patty Hanson in Liz's name - Confirmation #857H2S
Leg 2
OF PA 4DATE:09/11/14 TH
TRAVEL TIME:0 Hour 42 Minute DISTANCE:279 Nautical Mile
DEPART TIME:12:00 PM PDT ARRIVE TIME:12:54 PM PDT
DEPART FROM:SALEM, OR - KSL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA7500 W PARK DRIVE GATE L
SPOKANE, W509.495.413
PASSENGERS:ANDREWS, ELIZABETH LIZ - / 06805169-928010-550-R1
PLUTH, JEANNE - 509-294-9560 / 06805169-928010-550-R1
KNOX, TARA - / 06805169-928010-550-R1SMITH, JENNIFER (JEN) - / 06805169-928010-550-R1
LEG MSGS: Need lunch from KSLE to KGEG
Page 12 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 390 of 419
Trip ID: VA091114 06/05/1 08:21 AM Page: 123
AIRCRAFT ROUTING
09/11/1 - 9/11/1
RIP PURPOSE:Open Meeting/Work Session to present progress in implementing the policy statement of naturalgas conservation program in Docket UG-121207
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE - STANFORD, RICHARD -
Leg 1
OF PA 4DATE:09/11/14 THU
TRAVEL TIME:0 Hour 48 Minute DISTANCE:222 Nautical Mile
DEPART TIME:01:30 PM PDT ARRIVE TIME:02:18 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO:FBO:GLACIER JET CENTE
7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214
360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800545-928000-550-R1
JOHNSON, DAN (DAN) - 509-720-1028 / 02800545-928000-550-R1POWELL, JON JON - / 02800545-928000-550-R1
DRAKE, CHRIS CHRIS - 509-389-0521 / 02800545-928000-550-R1
Leg 2
OF PA 4DATE:09/11/14 TH
TRAVEL TIME:0 Hour 36 Minutes DISTANCE:222 Nautical Mile
DEPART TIME:05:30 PM PDT ARRIVE TIME:06:12 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA7645 OLD HWY 99 SE 7500 W PARK DRIVE GATE L
OLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800545-928000-550-R1
JOHNSON, DAN DAN - 509-720-1028 / 02800545-928000-550-R1
POWELL, JON JON - / 02800545-928000-550-R1DRAKE, CHRIS (CHRIS) - 509-389-0521 / 02800545-928000-550-R11
TRIP MSGS: One vehicle reserved in Linda's name by Patty Hanson 495-4126
Page 12 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 391 of 419
Trip ID: VA091214 06/05/1 08:21 AM Page: 12
AIRCRAFT ROUTING
09/12/1 - 9/12/1
RIP PURPOSE:Travel to Offices of Northwest Hydraulic Consultants in North Vancouver, BC to inspect Nine MileSediment Model, part of the Nine Mile Redevelopment Project.
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD - ROBINSON, DAVE -
Leg 1
OF PA 5DATE:09/12/14 FRI
TRAVEL TIME:0 Hour 50 Minute DISTANCE:244 Nautical Mile
DEPART TIME:07:32 AM PDT ARRIVE TIME:08:22 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:VANCOUVER, BC - CYV
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:VANCOUVER INTERNATIONAL
FBO:FBO:LANDMARK AVIATIO
4360 AGAR DRIVRICHMOND, BC V7B 1A604-279-992
604-279-9942 - fa
PASSENGERS:THACKSTON, JASON R - 509-290-4590 / 20505040-300100-550-E0
WENKE, STEVEN EUGENE(STEVE) - 509-995-9373 / 20505040-300100-550-E0VICKERS, ANDY EUGENE - 509-990-8234 / 20505040-300100-550-E0
BACHTEL-BROWNING, BRITT - 503-740-9946 / 20505040-300100-550-E0FARMER, GLEN - 509-290-3936 / 20505040-300100-550-E0
LEG MSGS: No Catering Required on either leg
Leg 2
OF PA 5DATE:09/12/14 FRI
TRAVEL TIME:0 Hour 42 Minute DISTANCE:244 Nautical Mile
DEPART TIME:02:06 PM PDT ARRIVE TIME:02:48 PM PDT
DEPART FROM:VANCOUVER, BC - CYVR ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:VANCOUVER INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:LANDMARK AVIATIO FBO:AVISTA HANGA4360 AGAR DRIV 7500 W PARK DRIVE GATE LRICHMOND, BC V7B 1A SPOKANE, W
509.495.413604-279-992604-279-9942 - fa
PASSENGERS:THACKSTON, JASON R - 509-290-4590 / 20505040-300100-550-E0
WENKE, STEVEN EUGENE STEVE - 509-995-9373 / 20505040-300100-550-E0VICKERS, ANDY EUGENE - 509-990-8234 / 20505040-300100-550-E0BACHTEL-BROWNING, BRITT - 503-740-9946 / 20505040-300100-550-E07FARMER, GLEN - 509-290-3936 / 20505040-300100-550-E0
TRIP MSGS: Steve Wenke will arrange taxis
Page 12 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 392 of 419
Trip ID: VA091614 06/05/1 08:21 AM Page: 125
AIRCRAFT ROUTING
09/16/1 - 9/18/1
RIP PURPOSE:Investor Visits in New York and Boston
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 2DATE:09/16/14 TU
TRAVEL TIME:1 Hour 49 Minute DISTANCE:842 Nautical Mile
DEPART TIME:08:16 AM PDT ARRIVE TIME:12:05 PM CDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:FBO:FARGO JET CENTE3801 20TH ST FARGO, ND 5810701-235-360701-237-6887 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
LEG MSGS: Need breakfast from KGEG to KFAR
Leg 2
OF PA 2DATE:09/16/14 TU
TRAVEL TIME:2 Hours 22 Minute DISTANCE:1045 Nautical Mile
DEPART TIME:12:35 PM CDT ARRIVE TIME:03:57 PM EDT
DEPART FROM:FARGO, ND - KFA ARRIVE AT:TETERBORO, NJ - KTEB
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:TETERBOR
FBO:FARGO JET CENTER FBO:MERIDIAN TETERBOR3801 20TH ST 485 INDUSTRIAL AV
FARGO, ND 5810 TETERBORO, NJ 0760201-288-504701-235-360 201-288-4430 - fa701-237-6887 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
LEG MSGS: Need lunch from KFAR to KTEB
Leg 3
OF PA 3DATE:09/17/14 WED
TRAVEL TIME:0 Hour 37 Minute DISTANCE:158 Nautical Mile
DEPART TIME:09:07 AM EDT ARRIVE TIME:09:44 AM EDT
DEPART FROM:TETERBORO, NJ - KTEB ARRIVE AT:BEDFORD, MA - KBED
AIRPORT NAME:TETERBOR AIRPORT NAME:LAURENCE G HANSCOM FIELD
FBO:MERIDIAN TETERBOR FBO:JET AVIATIO485 INDUSTRIAL AVE 380 HANSCOM DR HANSCOM FLD
TETERBORO, NJ 0760 BEDFORD, MA 0173781-274-003201-288-504 781-274-6573 - fa201-288-4430 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK - WEINSTIEN, MIKE -
LEG MSGS: There will be an additional passenger from Teterboro to Boston, Mike Weinstien (a non Avista
employee)Need breakfast from KTEB to KBOS
Leg 4
Page 12 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 393 of 419
Trip ID: VA091614 06/05/1 08:21 AM Page: 126
AIRCRAFT ROUTING
09/16/1 - 9/18/1
RIP PURPOSE:Investor Visits in New York and Boston
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 4 continue
OF PA 3DATE:09/18/14 TH
TRAVEL TIME:3 Hours 6 Minute DISTANCE:1116 Nautical Mile
DEPART TIME:03:54 PM EDT ARRIVE TIME:06:00 PM CDT
DEPART FROM:BEDFORD, MA - KBED ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:LAURENCE G HANSCOM FIELD AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:JET AVIATIO FBO:FARGO JET CENTE380 HANSCOM DR HANSCOM FLD 3801 20TH ST BEDFORD, MA 0173 FARGO, ND 5810701-235-360781-274-003 701-237-6887 - fa781-274-6573 - fax
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
WEINSTIEN, MIKE -
LEG MSGS: Need breakfast from KBOS to KFAR
Leg
OF PA 2DATE:09/18/14 TH
TRAVEL TIME:2 Hours 19 Minute DISTANCE:842 Nautical Mile
DEPART TIME:06:24 PM CDT ARRIVE TIME:06:43 PM PDT
DEPART FROM:FARGO, ND - KFA ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:FARGO JET CENTE FBO:AVISTA HANGA
3801 20TH ST 7500 W PARK DRIVE GATE LFARGO, ND 5810 SPOKANE, W509.495.413701-235-360
701-237-6887 - fax
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
LEG MSGS: Need lunch from KFAR to KGEG
TRIP MSGS: Ground transportation provided by UBS and arranged by Jason Lang.
Page 12 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 394 of 419
Trip ID: VA092314 06/05/1 08:21 AM Page: 127
AIRCRAFT ROUTING
09/23/1 - 9/23/1
RIP PURPOSE:WA GRC Hearing on Settlement Proposal and UW Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 7DATE:09/23/14 TU
TRAVEL TIME:0 Hour 46 Minute DISTANCE:222 Nautical Mile
DEPART TIME:07:55 AM PDT ARRIVE TIME:08:41 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:MEYER, DAVID -
NORWOOD, KELLY -
EHRBAR, PAT - 509-994-9074 / 02805810-928010-550-R1ANDREWS, ELIZABETH LIZ - / 02805810-928010-550-R1GERVAIS, LINDA - 509-953-8057 / 02805810-928010-550-R1
JOHNSON, BILL BILL - / 02805810-928010-550-R1MANSKEY, WENDY (WENDY) - / 02805810-928010-550-R11
LEG MSGS: Rental Vehicles reserved by Wendy Manskey in Pat's name (Confirmation #G33204068A4) and inLinda's name (Confirmation #G33211474B2)
Leg
OF PA 7DATE:09/23/14 TU
TRAVEL TIME:0 Hour 36 Minute DISTANCE:222 Nautical Mile
DEPART TIME:01:05 PM PDT ARRIVE TIME:01:41 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA
7645 OLD HWY 99 S 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:MEYER, DAVID -
NORWOOD, KELLY - EHRBAR, PAT - 509-994-9074 / 02805810-928010-550-R1
ANDREWS, ELIZABETH LIZ - / 02805810-928010-550-R1GERVAIS, LINDA - 509-953-8057 / 02805810-928010-550-R1JOHNSON, BILL BILL - / 02805810-928010-550-R1
MANSKEY, WENDY (WENDY) - / 02805810-928010-550-R11
LEG MSGS: Need lunch from KOLM to KGEG
Leg
Page 12 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 395 of 419
Trip ID: VA092314 06/05/1 08:21 AM Page: 128
AIRCRAFT ROUTING
09/23/1 - 9/23/1
RIP PURPOSE:WA GRC Hearing on Settlement Proposal and UW Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 3 continue
OF PA 4DATE:09/23/14 TU
TRAVEL TIME:0 Hour 46 Minute DISTANCE:193 Nautical Mile
DEPART TIME:02:05 PM PDT ARRIVE TIME:02:51 PM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO:AVISTA HANGA FBO:CLAY LACY AVIATIO7500 W PARK DRIVE GATE L 8285 PERIMETER RD SPOKANE, W SEATTLE, WA 9810206-762-600509.495.413 206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT -
STEVENS, STEVE - 859-393-7014 / 02800300-930220-550-E01
SENSKE, MICHAEL - 509-979-6702 / 02800300-930220-550-E0SPRAGUE, KEVIN COLLINS COLLINS - 360-951-4540 / 02800300-930220-550-E0
Leg 4
OF PA 4DATE:09/23/14 TUE
TRAVEL TIME:0 Hour 36 Minute DISTANCE:193 Nautical Mile
DEPART TIME:05:58 PM PDT ARRIVE TIME:06:33 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA
8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600
206-768-0888 - fa
PASSENGERS:MORRIS, SCOTT -
STEVENS, STEVE - 859-393-7014 / 02800300-930220-550-E0SENSKE, MICHAEL - 509-979-6702 / 02800300-930220-550-E0
SPRAGUE, KEVIN COLLINS COLLINS - 360-951-4540 / 02800300-930220-550-E0
LEG MSGS: Need dinner from KBFI to KGEG
Page 128 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 396 of 419
Trip ID: VA092414 06/05/1 08:21 AM Page: 129
AIRCRAFT ROUTING
09/24/1 - 9/24/1
RIP PURPOSE:Oregon GRC Prehearing Conference and UW/WSU Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 4DATE:09/24/14 WED
TRAVEL TIME:0 Hour 48 Minute DISTANCE:193 Nautical Mile
DEPART TIME:08:30 AM PDT ARRIVE TIME:09:18 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO: FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810206-762-600206-768-0888 - fa
PASSENGERS:MEYER, DAVID -
ANDREWS, ELIZABETH (LIZ) - / 06805169-928010-550-R11
MORRIS, SCOTT - WILSON, MICHAEL MIKE - 02800300-930220-550-E0
LEG MSGS: Melnik car service will take Scott and Mike to their meeting from Boeing Field.
Leg
OF PA 2DATE:09/24/14 WED
TRAVEL TIME:0 Hour 48 Minute DISTANCE:160 Nautical Mile
DEPART TIME:09:30 AM PDT ARRIVE TIME:10:18 AM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO:CLAY LACY AVIATIO FBO:8285 PERIMETER RD SEATTLE, WA 9810
206-762-6000206-768-0888 - fa
PASSENGERS:MEYER, DAVID -
ANDREWS, ELIZABETH (LIZ) - / 06805169-928010-550-R1
LEG MSGS: One Vehicle reserved by Patty Hanson in Davids name - Confirmation #TNZ64H
Leg
OF PA 2DATE:09/24/14 WED
TRAVEL TIME:0 Hour 30 Minute DISTANCE:160 Nautical Mile
DEPART TIME:01:00 PM PDT ARRIVE TIME:01:42 PM PDT
DEPART FROM:SALEM, OR - KSL ARRIVE AT:SEATTLE, WA - KBFI
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI
FBO: FBO:CLAY LACY AVIATIO8285 PERIMETER RD SEATTLE, WA 9810
206-762-600206-768-0888 - fa
PASSENGERS:MEYER, DAVID -
ANDREWS, ELIZABETH (LIZ) - / 06805169-928010-550-R1
LEG MSGS: Need lunch from KSLE to KBFI
Leg 4
Page 12 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 397 of 419
Trip ID: VA092414 06/05/1 08:21 AM Page: 130
AIRCRAFT ROUTING
09/24/1 - 9/24/1
RIP PURPOSE:Oregon GRC Prehearing Conference and UW/WSU Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 4 continue
OF PA 4DATE:09/24/14 WED
TRAVEL TIME:0 Hour 42 Minute DISTANCE:193 Nautical Mile
DEPART TIME:02:30 PM PDT ARRIVE TIME:03:12 PM PDT
DEPART FROM:SEATTLE, WA - KBFI ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:KING COUNTY INTERNATIONAL BOEI AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:CLAY LACY AVIATIO FBO:AVISTA HANGA8285 PERIMETER RD 7500 W PARK DRIVE GATE LSEATTLE, WA 9810 SPOKANE, W509.495.413206-762-600206-768-0888 - fax
PASSENGERS:MEYER, DAVID -
ANDREWS, ELIZABETH (LIZ) - / 06805169-928010-550-R11
MORRIS, SCOTT - WILSON, MICHAEL MIKE - 02800300-930220-550-E0
LEG MSGS: Melnik car service will return Scott and Mike to Boeing Field.
Page 130 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 398 of 419
Trip ID: VA092514 06/05/1 08:21 AM Page: 131
AIRCRAFT ROUTING
09/25/1 - 9/25/1
RIP PURPOSE:Employee Meetings
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 5DATE:09/25/14 TH
TRAVEL TIME:1 Hour 12 Minute DISTANCE:387 Nautical Mile
DEPART TIME:06:30 AM PDT ARRIVE TIME:07:42 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO:AVISTA HANGA FBO:JET CENTER MF7500 W PARK DRIVE GATE L 5000 CIRRUS DSPOKANE, W MEDFORD, OR 97504800-359-029509.495.413 541-772-2759 - fa
PASSENGERS:MORRIS, SCOTT -
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E01
KOLBET, DAN - 509-434-8621 / 09900162-921000-550-E0BLAYLOCK, JENNY - 509-339-3070 / 09900162-921000-550-E0MCLEOD, TIM - 907-723-6317 / 09900162-921000-550-E0
Leg
OF PA 5DATE:09/25/14 TH
TRAVEL TIME:1 Hour 0 Minute DISTANCE:347 Nautical Mile
DEPART TIME:09:30 AM PDT ARRIVE TIME:10:30 AM PDT
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:LEWISTON, ID - KLW
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:LEWISTON-NEZ PERCE COUNT
FBO:JET CENTER MF FBO:STOUT FLYING SV5000 CIRRUS D 406 BURRELLMEDFORD, OR 97504 LEWISTON, ID 8350
208-743-840800-359-029 208-798-3284 - fa541-772-2759 - fa
PASSENGERS:MORRIS, SCOTT -
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E0
KOLBET, DAN - 509-434-8621 / 09900162-921000-550-E0BLAYLOCK, JENNY - 509-339-3070 / 09900162-921000-550-E0MCLEOD, TIM - 907-723-6317 / 09900162-921000-550-E01
Leg
OF PA 5DATE:09/25/14 TH
TRAVEL TIME:0 Hour 12 Minute DISTANCE:22 Nautical Mile
DEPART TIME:12:40 PM PDT ARRIVE TIME:12:52 PM PDT
DEPART FROM:LEWISTON, ID - KLW ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:LEWISTON-NEZ PERCE COUNT AIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO:STOUT FLYING SV FBO:INTER-STATE AV
406 BURRELL 2601 AIRPORT COMPLEX LEWISTON, ID 8350 PULLMAN, WA 9916
509-332-659208-743-840 509-334-1751 - fa208-798-3284 - fax
PASSENGERS:MORRIS, SCOTT -
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E0KOLBET, DAN - 509-434-8621 / 09900162-921000-550-E0
Additional Passengers for this leg continue on the next page
Page 131 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 399 of 419
Trip ID: VA092514 06/05/1 08:21 AM Page: 132
AIRCRAFT ROUTING
09/25/1 - 9/25/1
RIP PURPOSE:Employee Meetings
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 3 continue
PASSENGERS:BLAYLOCK, JENNY - 509-339-3070 / 09900162-921000-550-E0
MCLEOD, TIM - 907-723-6317 / 09900162-921000-550-E0
Leg 4
OF PA 5DATE:09/25/14 TH
TRAVEL TIME:0 Hour 12 Minute DISTANCE:55 Nautical Mile
DEPART TIME:03:00 PM PDT ARRIVE TIME:03:18 PM PDT
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:INTER-STATE AV FBO:AVISTA HANGA2601 AIRPORT COMPLEX 7500 W PARK DRIVE GATE L
PULLMAN, WA 9916 SPOKANE, W509.495.413509-332-659509-334-1751 - fa
PASSENGERS:MORRIS, SCOTT -
VERMILLION, DENNIS P - 509-990-8233 / 09900162-921000-550-E0KOLBET, DAN - 509-434-8621 / 09900162-921000-550-E0BLAYLOCK, JENNY - 509-339-3070 / 09900162-921000-550-E0
MCLEOD, TIM - 907-723-6317 / 09900162-921000-550-E0
Page 13 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 400 of 419
Trip ID: VA092714 06/05/1 08:21 AM Page: 133
AIRCRAFT ROUTING
09/27/1 - 9/30/1
RIP PURPOSE:AGA Board and Executive Conference
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 2DATE:09/27/14 SAT
TRAVEL TIME:2 Hours 12 Minute DISTANCE:837 Nautical Mile
DEPART TIME:09:30 AM PDT ARRIVE TIME:11:42 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SANTA ANA, CA - KSN
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:JOHN WAYNE/ORANGE COUNT
FBO:FBO:SIGNATURE FLIGHT SU19301 CAMPUS DRIVE SUITE 10SANTA ANA, CA 9270949-263-580949-263-5809 - fa
PASSENGERS:MORRIS, SCOTT -
MORRIS, LIZBETH ANN(LIZ) - 09900311-930200-550-E01
Leg
OF PA 2DATE:09/30/14 TU
TRAVEL TIME:2 Hours 6 Minute DISTANCE:837 Nautical Mile
DEPART TIME:02:30 PM PDT ARRIVE TIME:04:36 PM PDT
DEPART FROM:SANTA ANA, CA - KSN ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:JOHN WAYNE/ORANGE COUNT AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:SIGNATURE FLIGHT SU FBO:AVISTA HANGA19301 CAMPUS DRIVE SUITE 10 7500 W PARK DRIVE GATE LSANTA ANA, CA 9270 SPOKANE, W
509.495.413949-263-580949-263-5809 - fa
PASSENGERS:MORRIS, SCOTT -
MORRIS, LIZBETH ANN LIZ - 09900311-930200-550-E0
TRIP MSGS: LimoLink will provide car service to and from the hotel. Confirmation #1928898-001 and 1928898-002.
Page 13 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 401 of 419
Trip ID: VA100714 06/05/1 08:21 AM Page: 13
AIRCRAFT ROUTING
10/07/1 - 10/07/1
RIP PURPOSE:Semi-Annual Meeting/Procurement Plan Update in Boise and PGA Quarterly Meeting in Olympia
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
SCOTT, BRIAN - Leg 1
OF PA 5DATE:10/07/14 TU
TRAVEL TIME:0 Hour 42 Minute DISTANCE:249 Nautical Mile
DEPART TIME:06:00 AM PDT ARRIVE TIME:07:48 AM MDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:BOISE, ID - KBOI
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD
FBO: FBO:JACKSON JET CENTE3815 RICKENBACKER STREETBOISE, ID 8370208-383-330208-336-9082 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03800545-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 03800545-928000-550-R11
PARDEE, TOM - / 02800545-928000-550-R1FINESILVER, RYAN RYAN - / 02800545-928000-550-R1MOREHOUSE, JODY - 509-979-6674 / 03800545-928000-550-R1
LEG MSGS: Rental minivan reserved by Patty Hanson in Pat's name - Confirmation #G3382330698
Leg
OF PA 5DATE:10/07/14 TUE
TRAVEL TIME:1 Hour 6 Minute DISTANCE:348 Nautical Mile
DEPART TIME:11:00 AM MDT ARRIVE TIME:11:06 AM PDT
DEPART FROM:BOISE, ID - KBOI ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:BOISE AIR TERMINAL GOWEN FIELD AIRPORT NAME:OLYMPIA REGIONAL
FBO:JACKSON JET CENTE FBO:GLACIER JET CENTE3815 RICKENBACKER STREET 7645 OLD HWY 99 S
BOISE, ID 83705 OLYMPIA, WA 9850360-705-3214208-383-330 360-753-0083 - fa208-336-9082 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03800545-928000-550-R1
BRANDON, ANNETTE - 509-979-3214 / 03800545-928000-550-R1PARDEE, TOM - / 02800545-928000-550-R1FINESILVER, RYAN RYAN - / 02800545-928000-550-R1
MOREHOUSE, JODY - 509-979-6674 / 02800545-928000-550-R1
LEG MSGS: Rental minivan reserved by Patty Hanson in Pat's name - Confirmation #G33804708E9
Leg 3
OF PA 5DATE:10/07/14 TU
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:03:30 PM PDT ARRIVE TIME:04:12 PM PDT
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTER FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE L
OLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:EHRBAR, PAT - 509-994-9074 / 03800545-928000-550-R1
Page 13 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 402 of 419
Trip ID: VA100714 06/05/1 08:21 AM Page: 135
AIRCRAFT ROUTING
10/07/1 - 10/07/1
RIP PURPOSE:Semi-Annual Meeting/Procurement Plan Update in Boise and PGA Quarterly Meeting in Olympia
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
SCOTT, BRIAN - Leg 3 continue
PASSENGERS:BRANDON, ANNETTE - 509-979-3214 / 03800545-928000-550-R1
PARDEE, TOM - / 02800545-928000-550-R1FINESILVER, RYAN (RYAN) - / 02800545-928000-550-R11MOREHOUSE, JODY - 509-979-6674 / 02800545-928000-550-R1
Page 13 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 403 of 419
Trip ID: VA101314 06/05/1 08:21 AM Page: 136
AIRCRAFT ROUTING
10/13/1 - 10/13/1
RIP PURPOSE:
IRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 1DATE:10/13/14 MO
TRAVEL TIME:1 Hour 30 Minute DISTANCE:564 Nautical Mile
DEPART TIME:07:42 AM PDT ARRIVE TIME:09:12 AM PDT
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SACRAMENTO, CA - KSMF
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SACRAMENTO INTERNATIONAL
FBO: FBO:SACRAMENTO INTL JET5885 FLIGHTLINE CIRCLSACRAMENTO, CA 9583916-428-829916-646-6747 - fa
PASSENGERS:ROBINSON, DAVID (DAVE) - 509-280-1038 / 09900110-935000-550-L54
Page 13 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 404 of 419
Trip ID: VA110914 06/05/1 08:21 AM Page: 137
AIRCRAFT ROUTING
11/10/1 - 11/10/1
RIP PURPOSE:Aircraft Maintenance
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 1DATE:11/10/14 MO
TRAVEL TIME:1 Hour 43 Minute DISTANCE:564 Nautical Mile
DEPART TIME:08:47 AM PST ARRIVE TIME:10:30 AM PST
DEPART FROM:SACRAMENTO, CA - KSMF ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SACRAMENTO INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO: FBO:AVISTA HANGA7500 W PARK DRIVE GATE LSPOKANE, W509.495.413
PASSENGERS:ROBINSON, DAVID (DAVE) - 509-280-1038 / 09900110-935000-550-L54
Page 13 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 405 of 419
Trip ID: VA111014 06/05/1 08:21 AM Page: 138
AIRCRAFT ROUTING
11/10/1 - 11/12/1
RIP PURPOSE:EEI Financial Conference
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
HARTNETT, JOHN - Leg 1
OF PA 3DATE:11/10/14 MO
TRAVEL TIME:2 Hours 48 Minute DISTANCE:1290 Nautical Mile
DEPART TIME:02:00 PM PST ARRIVE TIME:06:54 PM CST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:DALLAS, TX - KDAL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:DALLAS LOVE FIELD
FBO: FBO:BUSINESS JET CNT8611 LEMMON AVDALLAS, TX 7520214-654-160214-654-1656 - fa
PASSENGERS:THIES, MARK -
LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
MORRIS, SCOTT -
LEG MSGS: Limolink to transport from FBO to hotel. Chauffeur will request tarmac meet. 214-654-1600
Leg
OF PA 5DATE:11/12/14 WED
TRAVEL TIME:3 Hours 30 Minute DISTANCE:1290 Nautical Mile
DEPART TIME:02:30 PM CST ARRIVE TIME:04:00 PM PST
DEPART FROM:DALLAS, TX - KDAL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:DALLAS LOVE FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:BUSINESS JET CNT FBO:AVISTA HANGA
8611 LEMMON AV 7500 W PARK DRIVE GATE LDALLAS, TX 7520 SPOKANE, W509.495.413214-654-160
214-654-1656 - fax
PASSENGERS:THIES, MARK -
LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54MORRIS, SCOTT -
HULBERT, CONNIE - 907-321-5338 / 09900010-921000-550-Y54STEVENS, RICH - 509-990-6072 / 09900010-921000-550-Y54
Page 138 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 406 of 419
Trip ID: VA111414 06/05/1 08:21 AM Page: 139
AIRCRAFT ROUTING
11/14/1 - 11/14/1
RIP PURPOSE:WA Natural Gas IRP presentation to the Commission
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
HARTNETT, JOHN - Leg 1
OF PA 4DATE:11/14/14 FRI
TRAVEL TIME:0 Hour 42 Minute DISTANCE:222 Nautical Mile
DEPART TIME:12:00 PM PST ARRIVE TIME:12:48 PM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800545-928000-550-R1
PARDEE, TOM - / 02800545-928000-550-R11
MOREHOUSE, JODY - 509-979-6674 / 02800545-928000-550-R1EHRBAR, PAT - 509-994-9074 / 02800545-928000-550-R1
LEG MSGS: Need lunch from KGEG to KOLM
Hertz rental car reserved by Wendy Manskey in Pat's name. Confirmation #G385536263F6
Leg 2
OF PA 4DATE:11/14/14 FRI
TRAVEL TIME:0 Hour 42 Minutes DISTANCE:222 Nautical Mile
DEPART TIME:04:00 PM PST ARRIVE TIME:04:42 PM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTE FBO:AVISTA HANGA
7645 OLD HWY 99 SE 7500 W PARK DRIVE GATE LOLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214
360-753-0083 - fa
PASSENGERS:GERVAIS, LINDA - 509-953-8057 / 02800545-928000-550-R1
PARDEE, TOM - / 02800545-928000-550-R1MOREHOUSE, JODY - 509-979-6674 / 02800545-928000-550-R1
EHRBAR, PAT - 509-994-9074 / 02800545-928000-550-R1
Page 13 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 407 of 419
Trip ID: VA111714 06/05/1 08:21 AM Page: 140
AIRCRAFT ROUTING
11/17/1 - 11/18/1
RIP PURPOSE:2014 Underwriting Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
HARTNETT, JOHN - Leg 1
OF PA 3DATE:11/17/14 MO
TRAVEL TIME:1 Hour 30 Minute DISTANCE:842 Nautical Mile
DEPART TIME:08:00 AM PST ARRIVE TIME:11:54 AM CST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:FBO:FARGO JET CENTE3801 20TH ST FARGO, ND 5810701-235-360701-237-6887 - fa
PASSENGERS:THIES, MARK -
KRASSELT, RYAN L(RYAN) - 509-590-8363 / 09903410-930200-550-R54
BRANDKAMP, BOB - / 09903410-930200-550-R54
LEG MSGS: Need breakfast from GEG to FAR.
Leg
OF PA 3DATE:11/17/14 MO
TRAVEL TIME:2 Hours 24 Minute DISTANCE:1045 Nautical Mile
DEPART TIME:12:30 PM CST ARRIVE TIME:03:54 PM EST
DEPART FROM:FARGO, ND - KFA ARRIVE AT:TETERBORO, NJ - KTEB
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:TETERBOR
FBO:FARGO JET CENTE FBO:MERIDIAN TETERBOR
3801 20TH ST 485 INDUSTRIAL AVFARGO, ND 5810 TETERBORO, NJ 0760201-288-504701-235-360
201-288-4430 - fa701-237-6887 - fax
PASSENGERS:THIES, MARK -
KRASSELT, RYAN L(RYAN) - 509-590-8363 / 09903410-930200-550-R54BRANDKAMP, BOB - / 09903410-930200-550-R54
LEG MSGS: Please provide lunch from FAR to TEB.
Carey Car set up by Debbie Deubel to pick up from FBO and deliver to hotel.
Leg
OF PA 3DATE:11/18/14 TUE
TRAVEL TIME:2 Hours 42 Minute DISTANCE:1045 Nautical Mile
DEPART TIME:01:00 PM EST ARRIVE TIME:02:54 PM CST
DEPART FROM:TETERBORO, NJ - KTEB ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:TETERBOR AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:MERIDIAN TETERBOR FBO:FARGO JET CENTE
485 INDUSTRIAL AV 3801 20TH ST TETERBORO, NJ 07608 FARGO, ND 5810701-235-360201-288-504
701-237-6887 - fa201-288-4430 - fa
PASSENGERS:THIES, MARK -
KRASSELT, RYAN L(RYAN) - 509-590-8363 / 09903410-930200-550-R54Additional Passen ers for this le continue on the next a e
Page 140 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 408 of 419
Trip ID: VA111714 06/05/1 08:21 AM Page: 141
AIRCRAFT ROUTING
11/17/1 - 11/18/1
RIP PURPOSE:2014 Underwriting Meeting
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
HARTNETT, JOHN - Leg 3 continue
PASSENGERS:BRANDKAMP, BOB - / 09903410-930200-550-R54
LEG MSGS: Please provide lunch from TEB to FAR.
Carey Car to deliver from meeting place to FBO.
Leg 4
OF PA 3DATE:11/18/14 TU
TRAVEL TIME:2 Hours 18 Minute DISTANCE:842 Nautical Mile
DEPART TIME:03:30 PM CST ARRIVE TIME:03:48 PM PST
DEPART FROM:FARGO, ND - KFA ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:FARGO JET CENTE FBO:AVISTA HANGA3801 20TH ST 7500 W PARK DRIVE GATE LFARGO, ND 5810 SPOKANE, W
509.495.413701-235-360701-237-6887 - fa
PASSENGERS:THIES, MARK -
KRASSELT, RYAN L RYAN - 509-590-8363 / 09903410-930200-550-R54
BRANDKAMP, BOB - / 09903410-930200-550-R54
Page 141 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 409 of 419
Trip ID: VA112114 06/05/1 08:21 AM Page: 142
AIRCRAFT ROUTING
11/21/1 - 11/21/1
RIP PURPOSE:Employee Meetings
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 3DATE:11/21/14 FRI
TRAVEL TIME:0 Hour 20 Minute DISTANCE:78 Nautical Mile
DEPART TIME:06:37 AM PST ARRIVE TIME:06:57 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:LEWISTON, ID - KLW
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:LEWISTON-NEZ PERCE COUNT
FBO:FBO:STOUT FLYING SV406 BURRELLLEWISTON, ID 8350208-743-840208-798-3284 - fa
PASSENGERS:THIES, MARK -
NORWOOD, KELLY -
SMITH, BRANDI (BRANDI) - 509-847-8952 / 09900162-921000-5550-E0
Leg
OF PA 3DATE:11/21/14 FRI
TRAVEL TIME:0 Hour 8 Minute DISTANCE:22 Nautical Mile
DEPART TIME:08:56 AM PST ARRIVE TIME:09:04 AM PST
DEPART FROM:LEWISTON, ID - KLW ARRIVE AT:PULLMAN, WA - KPUW
AIRPORT NAME:LEWISTON-NEZ PERCE COUNT AIRPORT NAME:PULLMAN/MOSCOW REGIONAL
FBO:STOUT FLYING SV FBO:INTER-STATE AV406 BURRELL 2601 AIRPORT COMPLEX
LEWISTON, ID 8350 PULLMAN, WA 9916509-332-659208-743-840 509-334-1751 - fa208-798-3284 - fa
PASSENGERS:THIES, MARK -
NORWOOD, KELLY - SMITH, BRANDI (BRANDI) - 509-847-8952 / 09900162-921000-5550-E0
Leg
OF PA 3DATE:11/21/14 FRI
TRAVEL TIME:1 Hour 4 Minute DISTANCE:360 Nautical Mile
DEPART TIME:11:18 AM PST ARRIVE TIME:12:22 PM PST
DEPART FROM:PULLMAN, WA - KPUW ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:PULLMAN/MOSCOW REGIONAL AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO:INTER-STATE AV FBO:JET CENTER MF2601 AIRPORT COMPLEX 5000 CIRRUS D
PULLMAN, WA 9916 MEDFORD, OR 97504800-359-029509-332-6596 541-772-2759 - fa509-334-1751 - fa
PASSENGERS:THIES, MARK -
NORWOOD, KELLY - SMITH, BRANDI (BRANDI) - 509-847-8952 / 09900162-921000-5550-E0
Leg 4
Page 14 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 410 of 419
Trip ID: VA112114 06/05/1 08:21 AM Page: 143
AIRCRAFT ROUTING
11/21/1 - 11/21/1
RIP PURPOSE:Employee Meetings
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 4 continue
OF PA 3DATE:11/21/14 FRI
TRAVEL TIME:0 Hour 56 Minute DISTANCE:387 Nautical Mile
DEPART TIME:02:36 PM PST ARRIVE TIME:03:32 PM PST
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JET CENTER MF FBO:AVISTA HANGA5000 CIRRUS D 7500 W PARK DRIVE GATE LMEDFORD, OR 97504 SPOKANE, W509.495.413800-359-029541-772-2759 - fax
PASSENGERS:THIES, MARK -
NORWOOD, KELLY -
SMITH, BRANDI (BRANDI) - 509-847-8952 / 09900162-921000-5550-E0
Page 14 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 411 of 419
Trip ID: VA112414 06/05/1 08:21 AM Page: 14
AIRCRAFT ROUTING
11/24/1 - 11/24/1
RIP PURPOSE:Dispatchable Generation Meeting/Tour at Portland General Electric
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 8DATE:11/24/14 MO
TRAVEL TIME:0 Hour 50 Minute DISTANCE:242 Nautical Mile
DEPART TIME:07:22 AM PST ARRIVE TIME:08:12 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:PORTLAND, OR - KPD
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:PORTLAND INTERNATIONAL
FBO: FBO:ATLANTIC AVIATIO7527 NE AIRPORT WAPORTLAND, OR 9721503-331-422503-331-4273 - fa
PASSENGERS:SCHAFFNER, MARC - 208-659-7864 / 09905544-930200-550-A54
LENTINI, STEVE - 509-991-1621 / 09905544-930200-550-A54
GALL, JAMES (JAMES) - / 09905544-930200-550-A54LIENHARD, TOM - 509-389-2629 / 09905544-930200-550-A54SOYARS, DARRELL DARRELL - 509-435-6464 / 09905544-930200-550-A54
JOHNSON, GREGORY - 509-280-0795 / 09905544-930200-550-A54JAMES, DAVE - 509-953-4694 / 09905544-930200-550-A54
SPACEK, RANDY - 509-768-4337 / 09905544-930200-550-A54
LEG MSGS: Need breakfast from KGEG to KPDX
Ground transportation has been set up by Shirley Wolf
Leg
OF PA 8DATE:11/24/14 MON
TRAVEL TIME:0 Hour 42 Minute DISTANCE:242 Nautical Mile
DEPART TIME:03:22 PM PST ARRIVE TIME:04:04 PM PST
DEPART FROM:PORTLAND, OR - KPD ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:PORTLAND INTERNATIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:ATLANTIC AVIATIO FBO:AVISTA HANGA7527 NE AIRPORT WA 7500 W PARK DRIVE GATE LPORTLAND, OR 97218 SPOKANE, W509.495.413503-331-422503-331-4273 - fa
PASSENGERS:SCHAFFNER, MARC - 208-659-7864 / 09905544-930200-550-A54
LENTINI, STEVE - 509-991-1621 / 09905544-930200-550-A54
GALL, JAMES JAMES - / 09905544-930200-550-A54LIENHARD, TOM - 509-389-2629 / 09905544-930200-550-A54SOYARS, DARRELL (DARRELL) - 509-435-6464 / 09905544-930200-550-A54
JOHNSON, GREGORY - 509-280-0795 / 09905544-930200-550-A54JAMES, DAVE - 509-953-4694 / 09905544-930200-550-A54
SPACEK, RANDY - 509-768-4337 / 09905544-930200-550-A54
Page 14 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 412 of 419
Trip ID: VA120114 06/05/1 08:21 AM Page: 145
AIRCRAFT ROUTING
12/01/1 - 12/04/1
RIP PURPOSE:Analyst Meetings
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 8DATE:12/01/14 MO
TRAVEL TIME:2 Hours 53 Minute DISTANCE:1308 Nautical Mile
DEPART TIME:08:05 AM PST ARRIVE TIME:12:58 PM CST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:CHICAGO, IL - KMDW
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:CHICAGO MIDWAY INTERNATIONAL
FBO: FBO:ATLANTIC AVIATIO6150 S LARAMIE AVCHICAGO, IL 6063773-582-572773-582-1047 - fa
PASSENGERS:BURMEISTER-SMITH, CHRISTY M. - 509-981-3470 / 09902811-926102-550-G54
VAN ORDEN, TRACY - 509-954-3875 / 09902811-926102-550-G54
MUNSON, ADAM (ADAM) - 509-290-0265 / 09902811-926102-550-G54WILCOX, JOHN JOHN - / 09902811-926102-550-G54FALKNER, DON M DON - 509-953-7895 / 09902811-926102-550-G54
LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54THIES, MARK -
STANFORD, KIM - 09903691-930200-550-J0
LEG MSGS: A Carey Car has been reserved by Karen Lorenz for the Chicago group.
Drop off will be at Hyatt Regency O'Hare Hotel at 9300 Bryn Mawr Road, Rosemont, IL.
Breakfast is needed from Spokane to Chicago.
Leg 2
OF PA 3DATE:12/01/14 MO
TRAVEL TIME:1 Hour 29 Minutes DISTANCE:619 Nautical Mile
DEPART TIME:01:24 PM CST ARRIVE TIME:03:53 PM EST
DEPART FROM:CHICAGO, IL - KMDW ARRIVE AT:TETERBORO, NJ - KTEB
AIRPORT NAME:CHICAGO MIDWAY INTERNATIONAL AIRPORT NAME:TETERBOR
FBO:ATLANTIC AVIATIO FBO:MERIDIAN TETERBOR6150 S LARAMIE AVE 485 INDUSTRIAL AV
CHICAGO, IL 6063 TETERBORO, NJ 0760201-288-504773-582-572
201-288-4430 - fa773-582-1047 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK - STANFORD, KIM - 09903691-930200-550-J0
LEG MSGS: Need lunch from KMDW to KTEB
A Limolink car has been reserved by Debbie Deubel for Mark and Jason at Teterboro. Car willtransport to Grand Hyatt.
Leg
Page 14 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 413 of 419
Trip ID: VA120114 06/05/1 08:21 AM Page: 146
AIRCRAFT ROUTING
12/01/1 - 12/04/1
RIP PURPOSE:Analyst Meetings
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 3 continue
OF PA 3DATE:12/04/14 TH
TRAVEL TIME:2 Hours 55 Minute DISTANCE:1045 Nautical Mile
DEPART TIME:10:43 AM EST ARRIVE TIME:12:38 PM CST
DEPART FROM:TETERBORO, NJ - KTEB ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:TETERBOR AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:MERIDIAN TETERBOR FBO:FARGO JET CENTE485 INDUSTRIAL AV 3801 20TH ST TETERBORO, NJ 0760 FARGO, ND 5810701-235-360201-288-504 701-237-6887 - fa201-288-4430 - fax
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
STANFORD, KIM - 09903691-930200-550-J0
Leg 4
OF PA 3DATE:12/04/14 TH
TRAVEL TIME:2 Hours 19 Minute DISTANCE:842 Nautical Mile
DEPART TIME:01:18 PM CST ARRIVE TIME:01:37 PM PST
DEPART FROM:FARGO, ND - KFA ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:FARGO JET CENTE FBO:AVISTA HANGA3801 20TH ST 7500 W PARK DRIVE GATE L
FARGO, ND 5810 SPOKANE, W509.495.413701-235-360701-237-6887 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK - STANFORD, KIM - 09903691-930200-550-J0
LEG MSGS: Need lunch from KFAR to KGEG
Page 14 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 414 of 419
Trip ID: VA120814 06/05/1 08:21 AM Page: 147
AIRCRAFT ROUTING
12/08/1 - 12/10/1
RIP PURPOSE:Analyst Meetings
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 2DATE:12/08/14 MO
TRAVEL TIME:2 Hours 0 Minute DISTANCE:842 Nautical Mile
DEPART TIME:08:05 AM PST ARRIVE TIME:12:05 PM CST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:FBO:FARGO JET CENTE3801 20TH ST FARGO, ND 5810701-235-360701-237-6887 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
LEG MSGS: Need breakfast from KGEG to KFAR
Leg 2
OF PA 2DATE:12/08/14 MO
TRAVEL TIME:2 Hours 38 Minute DISTANCE:1045 Nautical Mile
DEPART TIME:12:34 PM CST ARRIVE TIME:04:12 PM EST
DEPART FROM:FARGO, ND - KFA ARRIVE AT:TETERBORO, NJ - KTEB
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:TETERBOR
FBO:FARGO JET CENTER FBO:MERIDIAN TETERBOR3801 20TH ST 485 INDUSTRIAL AV
FARGO, ND 5810 TETERBORO, NJ 0760201-288-504701-235-360 201-288-4430 - fa701-237-6887 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
LEG MSGS: Need lunch from KFAR to KTEB
A Limolink car has been reserved by Debbie Deubel to transport from FBO to Crowne Plaza Time
Square Manhattan
Leg
OF PA 2DATE:12/10/14 WED
TRAVEL TIME:2 Hours 33 Minute DISTANCE:1045 Nautical Mile
DEPART TIME:10:13 AM EST ARRIVE TIME:11:46 AM CST
DEPART FROM:TETERBORO, NJ - KTEB ARRIVE AT:FARGO, ND - KFA
AIRPORT NAME:TETERBOR AIRPORT NAME:HECTOR INTERNATIONAL FARG
FBO:MERIDIAN TETERBOR FBO:FARGO JET CENTE485 INDUSTRIAL AV 3801 20TH ST
TETERBORO, NJ 0760 FARGO, ND 5810701-235-360201-288-5040 701-237-6887 - fa201-288-4430 - fa
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
Leg 4
Page 14 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 415 of 419
Trip ID: VA120814 06/05/1 08:21 AM Page: 148
AIRCRAFT ROUTING
12/08/1 - 12/10/1
RIP PURPOSE:Analyst Meetings
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 4 continue
OF PA 2DATE:12/10/14 WED
TRAVEL TIME:2 Hours 13 Minute DISTANCE:842 Nautical Mile
DEPART TIME:01:16 PM CST ARRIVE TIME:01:29 PM PST
DEPART FROM:FARGO, ND - KFA ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:HECTOR INTERNATIONAL FARG AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:FARGO JET CENTE FBO:AVISTA HANGA3801 20TH ST 7500 W PARK DRIVE GATE LFARGO, ND 5810 SPOKANE, W509.495.413701-235-360701-237-6887 - fax
PASSENGERS:LANG, JASON - 509-995-8248 / 09900010-921000-550-Y54
THIES, MARK -
LEG MSGS: Need lunch from KFAR to KGEG
Page 148 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 416 of 419
Trip ID: VA121114 06/05/1 08:21 AM Page: 149
AIRCRAFT ROUTING
12/11/1 - 12/11/1
RIP PURPOSE:OR UG 284 Public Meeting
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 7DATE:12/11/14 TH
TRAVEL TIME:1 Hour 24 Minute DISTANCE:387 Nautical Mile
DEPART TIME:03:10 PM PST ARRIVE TIME:04:34 PM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:MEDFORD, OR - KMF
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATI
FBO: FBO:JET CENTER MF5000 CIRRUS DMEDFORD, OR 97504800-359-029541-772-2759 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 06805169-928010-550-R1
MEYER, DAVID J. - 509-220-7432 / 06805169-928010-550-R11
ANDREWS, ELIZABETH (LIZ) - / 06805169-928010-550-R1EHRBAR, PAT - 509-994-9074 / 06805169-928010-550-R1GERVAIS, LINDA - 509-953-8057 / 06805169-928010-550-R1
VINCENT, STEVE - 541-944-8992 / 06805169-928010-550-R1FIELDER, CASEY (CASEY) - 509-703-2209 / 06805169-928010-550-R11
LEG MSGS: Two vehicles have been reserved by Patty Hanson in Linda and Pat's names - Confirmation #90QMDIand 90QP70
Leg
OF PA 7DATE:12/11/14 TH
TRAVEL TIME:0 Hour 55 Minute DISTANCE:387 Nautical Mile
DEPART TIME:07:44 PM PST ARRIVE TIME:08:39 PM PST
DEPART FROM:MEDFORD, OR - KMF ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:MEDFORD/ROGUE VALLEY INTERNATIAIRPORT NAME:SPOKANE INTERNATIONAL
FBO:JET CENTER MF FBO:AVISTA HANGA
5000 CIRRUS D 7500 W PARK DRIVE GATE LMEDFORD, OR 97504 SPOKANE, W509.495.413800-359-029
541-772-2759 - fa
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 06805169-928010-550-R1
MEYER, DAVID J. - 509-220-7432 / 06805169-928010-550-R11ANDREWS, ELIZABETH (LIZ) - / 06805169-928010-550-R1
EHRBAR, PAT - 509-994-9074 / 06805169-928010-550-R1GERVAIS, LINDA - 509-953-8057 / 06805169-928010-550-R1VINCENT, STEVE - 541-944-8992 / 06805169-928010-550-R1
FIELDER, CASEY (CASEY) - 509-703-2209 / 06805169-928010-550-R11
Page 14 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 417 of 419
Trip ID: VA121214 06/05/1 08:21 AM Page: 150
AIRCRAFT ROUTING
12/12/1 - 12/12/1
RIP PURPOSE:Meetings with Commissioner Danner and Governor Inslee
AIRCRAFT:N202AV CE-65 PILOTS:STANFORD, RICHARD -
ROBINSON, DAVE - Leg 1
OF PA 2DATE:12/12/14 FRI
TRAVEL TIME:0 Hour 45 Minute DISTANCE:222 Nautical Mile
DEPART TIME:09:22 AM PST ARRIVE TIME:10:07 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:OLYMPIA, WA - KOLM
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:OLYMPIA REGIONAL
FBO: FBO:GLACIER JET CENTE7645 OLD HWY 99 SOLYMPIA, WA 9850360-705-3214360-753-0083 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 77700300-426120-550-E0
SPRAGUE, KEVIN COLLINS(COLLINS) - 360-951-4540 / 77700300-426120-550-E01
LEG MSGS: John Rothlin will pick Scott and Collins up at the airport
Leg 2
OF PA 2DATE:12/12/14 FRI
TRAVEL TIME:0 Hour 41 Minute DISTANCE:222 Nautical Mile
DEPART TIME:02:31 PM PST ARRIVE TIME:03:12 PM PST
DEPART FROM:OLYMPIA, WA - KOLM ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:OLYMPIA REGIONAL AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:GLACIER JET CENTER FBO:AVISTA HANGA7645 OLD HWY 99 S 7500 W PARK DRIVE GATE L
OLYMPIA, WA 9850 SPOKANE, W509.495.413360-705-3214360-753-0083 - fa
PASSENGERS:MORRIS, SCOTT L - 509-979-6698 / 77700300-426120-550-E0
SPRAGUE, KEVIN COLLINS COLLINS - 360-951-4540 / 77700300-426120-550-E0
Page 150 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 418 of 419
Trip ID: VA121514 06/05/1 08:21 AM Page: 151
AIRCRAFT ROUTING
12/15/1 - 12/15/1
RIP PURPOSE:Oregon UG 284 Settlement Conference
AIRCRAFT:N202AV CE-65 PILOTS:ROBINSON, DAVE -
STANFORD, RICHARD - Leg 1
OF PA 9DATE:12/15/14 MO
TRAVEL TIME:0 Hour 50 Minute DISTANCE:279 Nautical Mile
DEPART TIME:07:57 AM PST ARRIVE TIME:08:47 AM PST
DEPART FROM:SPOKANE, WA - KGE ARRIVE AT:SALEM, OR - KSL
AIRPORT NAME:SPOKANE INTERNATIONAL AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD
FBO: FBO:
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 06805169-928010-550-R1
MEYER, DAVID J. - 509-220-7432 / 06805169-928010-550-R1ANDREWS, ELIZABETH LIZ - / 06805169-928010-550-R1EHRBAR, PAT - 509-994-9074 / 06805169-928010-550-R11
MILLER, JOE - 509-951-4123 / 06805169-928010-550-R1SCHUH, KAREN - 509-995-6652 / 06805169-928010-550-R1LA BOLLE, LARRY - 208-659-2428 / 06805169-928010-550-R1
BRANDON, ANNETTE - 509-979-3214 / 06805169-928010-550-R1PLUTH, JEANNE - 509-294-9560 / 06805169-928010-550-R11
LEG MSGS: Two vehicles reserved by Patty Hanson in Kelly and Pat's names - Confirmation #G4133533068 and#G4134471316
Leg
OF PA 9DATE:12/15/14 MO
TRAVEL TIME:0 Hour 43 Minute DISTANCE:279 Nautical Mile
DEPART TIME:02:11 PM PST ARRIVE TIME:02:54 PM PST
DEPART FROM:SALEM, OR - KSL ARRIVE AT:SPOKANE, WA - KGE
AIRPORT NAME:SALEM MUNICIPAL/MCNARY FIELD AIRPORT NAME:SPOKANE INTERNATIONAL
FBO:FBO:AVISTA HANGA
7500 W PARK DRIVE GATE LSPOKANE, W509.495.413
PASSENGERS:NORWOOD, KELLY O. - 509-990-8144 / 06805169-928010-550-R1
MEYER, DAVID J. - 509-220-7432 / 06805169-928010-550-R11ANDREWS, ELIZABETH (LIZ) - / 06805169-928010-550-R1
EHRBAR, PAT - 509-994-9074 / 06805169-928010-550-R1MILLER, JOE - 509-951-4123 / 06805169-928010-550-R1SCHUH, KAREN - 509-995-6652 / 06805169-928010-550-R1
LA BOLLE, LARRY - 208-659-2428 / 06805169-928010-550-R11BRANDON, ANNETTE - 509-979-3214 / 06805169-928010-550-R1PLUTH, JEANNE - 509-294-9560 / 06805169-928010-550-R1
Page 151 of 151
6 5 201file:///C:/Users/Rff9457/AppData/Local/Microsoft/Windows/Temporary%20Internet%20Fi ...
ICNU_DR_240 Attachment A Page 419 of 419

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/12/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 240 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference the Company’s Response to ICNU Data Request (“DR”) 230. Please provide a log of corporate jet flights that occurred between January 1, 2011 and April 2015, including the date of
the flight, the list of passengers, the purpose of the flight, the departure and destination airports,
and any other fields stored by the Company related to these flights otherwise available in the
Corporate Aircraft Request & Approval Form.
RESPONSE:
Please see ICNU_DR_240 Attachment A for Company flight manifests from January 1, 2011 through
April, 30, 2015 which is being provided in electronic format only due to its voluminous nature. ICNU_DR_230 refers to costs associated with the Company’s DSM program and the Company
assumes that ICNU intended to reference ICNU Data Request (“DR”) 224 which is a request of
corporate aircraft expenses.

As a regional company, we have utilized a small business aircraft for over 50 years, as the Company serves in many areas with limited or no commercial airline service throughout the Northwest. The
majority of the Company flights are for direct support of commission-related business. It is important
to note that the aircraft is used for business purposes only, and any non-utility business use is charged
to shareholders. The flight manifests provided in ICNU_DR_240 Attachment A do not necessarily reflect the total
costs included in each rate case filing. Company Aircraft expenses are further adjusted to exclude
from Utility operations any non-utility uses prior to filing.
As it pertains to certain flights with non-employee passengers, non-employees are allowed to fly on the Company aircraft when that travel is business-related and no additional charges are
incurred, e.g, an employee spouse participates as a guest at a conference. If a spouse is
participating in a sanctioned business conference or event, then such travel is allowed as business
travel. No additional costs were incurred for any trips in which a non-employee was a passenger on the plane.

NEW YORK CITY: Dec. 2-5, 2013
Utility Week
Mark Thies, Kevin Christie & Jason Lang

MONDAY, DECEMBER 2

FLIGHT TO NYC Corporate Jet: Breakfast & Lunch
8:00 a.m. Depart Geiger Field Mark, Kevin & Jason
4:00p.m. Arrive Teterboro

TRANSPORTATION: Carey Car 4:00 p.m. pick up 3 passengers at Teterboro and transport to hotel. Dismiss.
Reservation under “Thies”; confirmation #____

HOTEL NYC: 1N @ $415 (BMO room block), 2N @ $459
Grand Hyatt New York Thies 327BJVS4 29246779
109 East 42nd Street Christie 327BJVSL 29246831
Park Avenue at Grand Central Lang 327BJZ7P 29246886

4:00-6:00 p.m. ???? Dinner: BAML
Jason Satsky, Dan Lonergan & Ray Wood (GCIB)
TBD
TUESDAY, DECEMBER 3
TBD IR Lunch: Ladenburg Thalman
Brian Russo
5:30 Cocktails BMO Pre-Conference Event: Aretsky’s Patroon
6:30 Dinner 160 East 46th St (between Lexington & 3rd Avenues)

WEDNESDAY, DECEMBER 4

BMO Capital Markets Utilities & Pipelines Day
Crowne Plaza Times Square

One-on-One Meetings:
9:30:10:15 a.m.
10:15-11:00 a.m.
11:00-11:45 a.m.
1:30-2:15 p.m.
2:15-2:45 p.m.
3:00-3:45 p.m.

June 9, 2015 DRAFT
ICNU_DR_241 Attachment A Page 1 of 18
Save the Date; Invitation to Follow 35th Annual JP Morgan Power & Utilities Dinner
??? The Metropolitan Club

WEDNESDAY, DECEMBER 4

6:00-9:00 p.m. Pillsbury Reception
?? 1540 Broadway, 22nd fl.
(entrance on 45th between 6th & 7th Avenues)

THURSDAY, DECEMBER 5

TRANSPORTATION: Carey Car 9:15 a.m. pick up 3 passengers at hotel and transport to Teterboro. Dismiss. Reservation confirmation #________

FLIGHT TO SPOKANE: Corporate Jet: Lunch
10:00 a.m. Depart Teterboro
12:50 p.m. Arrive Spokane

NAMES WORK # CELL # HOME # CHARGE CODES (ET 550)

FBOs

CAREY CARS:

PILOTS:

June 9, 2015 DRAFT
ICNU_DR_241 Attachment A Page 2 of 18
ICNU_DR_241 Attachment A Page 3 of 18
ICNU_DR_241 Attachment A Page 4 of 18
1
Finesilver, Ryan
From:Hanson, Patty
Sent:Tuesday, December 10, 2013 8:03 AM
To:Fleming, SueCc:Deubel, Debbie; Williams, LindaSubject:FW: December 16 - Cancelled
Good Morning Sue,  

Please cancel the corporate plane for the trip to Olympia on Monday, December 16th – the workshop has been 
cancelled.  Thank you,  

Patty Hanson | Avista Corporation 
Executive Assistant to Rates Department 
1411 E. Mission Ave MSC‐13 | Spokane, WA 99202 
phone: (509) 495‐4126 | fax: (509) 495‐8851  
[e-mail]  

_____________________________________________ From: Ehrbar, Pat Sent: Monday, December 09, 2013 4:14 PM To: Hanson, Patty
Subject: December 16 - Cancelled

Patty – we are NOT going to Olympia on Monday – the workshop has been cancelled. 

Thanks! 

Patrick Ehrbar | Manager, Rates & Tariffs | Avista Utilities
D 509.495.8620 | F 509.777.5259 | C 509.994.9074
1411 E. Mission Avenue | Spokane WA 99220
[e-mail]

ICNU_DR_241 Attachment A Page 5 of 18
ICNU_DR_241 Attachment A Page 6 of 18
ICNU_DR_241 Attachment A Page 7 of 18
ICNU_DR_241 Attachment A Page 8 of 18
June 5, 2015 FINAL

LAS VEGAS: March 19-20, 2014
Annual West Coast Seminar
Attire: Business Casual
Mark Thies, Jason Lang & Casey Fielder

WEDNESDAY, MARCH 19
FLIGHT TO LAS VEGAS: Corporate Jet
7:00 a.m. Depart Spokane Mark, Jason & Casey
8:45 a.m. Arrive Las Vegas Breakfast

GROUND TRANSPORTATION:
Carey sedan pick up 3 passengers @ 8:45 a.m from FBO and transport to hotel. Dismiss. Confirmation #WA8068783-001, Thies.
HOTEL: 2N, K, $275++ (WillCap making room res)
THEhotel @ Mandalay Bay Thies 699035870
3950 Las Vegas Blvd South, Las Vegas Lang 699035888
Fielder 699546540

11:00-12:00 AVA Presentation
Marble F & G, Level 6

One-on One Meetings
Marble D/E, Level 6
4:30 p.m. Chris Ellinghaus & Eric Beaumont, WillCap
5:00 p.m. Andrew Gay, Carlson Capital
TBD Ed Tirello, Tudor Capital

6:00 p.m. Dinner hosted by WillCap
Foundation Room

THURSDAY, MARCH 20

TRANSPORTATION: Carey sedan pick up 3 passengers @ 7:00 a.m. from hotel and transport to FBO. Dismiss. Confirmation # WA8068783-002, Thies.
Check in w/bell desk @ hotel for chauffer; cannot park in front of hotel
FLIGHT TO SPOKANE: Mark, Jason & Casey
7:30 a.m. Depart Las Vegas Breakfast
8:55 a.m. Arrive Spokane

ICNU_DR_241 Attachment A Page 9 of 18
June 5, 2015 FINAL

TRAVELER WORK # CELL# CHARGE #
Thies, Mark 509-495-4639 509-368-4503 09903691-930200-J01
Lang, Jason 509-495-2930 509-995-8248 09900010-921000-Y54
Fielder, Casey 509-495-4916 509-703-2209 09900330-930200-S54
CAREY CAR Avista Account #070056
Executive Star Limo, Las Vegas 702-646-4661

FBOs
Geiger Field (GEG), Spokane 509-495-4139
Signature Flight Support (LAS), Las Vegas 702-739-1100

PILOTS
Robinson, Dave 509-280-1038 509-251-3495 Stanford, Richard 509-495-4139 509-570-6033
ICNU_DR_241 Attachment A Page 10 of 18
1
Finesilver, Ryan
From:Hanson, Patty
Sent:Thursday, March 13, 2014 3:06 PM
To:Fleming, SueCc:Deubel, Debbie; Williams, LindaSubject:3/14/2014 Flight to Salem Cancelled
Hi Sue,  

The flight to Salem has been cancelled as it will take place via conference call.   

Patty Hanson
Executive Assistant Rates Department
PO Box 3727 MSC-27 Spokane, WA 99220 1411 E Mission Ave. MSC-27 Spokane, WA 99202 P 509-495-4126 http://www.avistautilities.com
This email (including any attachments) may contain confidential and privileged information, and unauthorized disclosure or use is prohibited. If you are not an intended recipient, please notify the sender and delete this email from your system. Thank you.

ICNU_DR_241 Attachment A Page 11 of 18
1
Finesilver, Ryan
From:Manskey, Wendy
Sent:Tuesday, May 06, 2014 9:47 AM
To:Fleming, SueSubject:Please cancel plane for June 2
Hi,
We will not need the plane that day. Thank you so much!

jxÇwç

Wendy D. Manskey
Rates Coordinator
PO Box 3727 MSC-27
Spokane, WA 99220 1411 E Mission MSC-27 P 509.495.4565 [e-mail] http://www.avistautilities.com

ICNU_DR_241 Attachment A Page 12 of 18
ICNU_DR_241 Attachment A Page 13 of 18
ICNU_DR_241 Attachment A Page 14 of 18
Colstrip CEO Meeting Seattle, Washington
SeaTac Conference Room
June 26, 2014
Scott Morris, Dennis Vermillion, Marian Durkin, Collins Sprague

Thursday, June 26

Depart
11:30 a.m. Spokane, WA Company Plane
(Lunch will be available) Arrive
12:15 p.m. Seattle

Transportation: 12:15 p.m. Melnik will pick you up at Clay Lacy Aviation and take you to SeaTac

Meeting:
1:00 p.m. – 4:00 p.m. Colstrip CEO Meeting SeaTac Conference Center
Bejing Room (located pre-security on the mezzanine level
above checkpoint one at the south end of the airport.)
Transportation: 4:00 p.m. Melnik will pick you up at SeaTac and return you
to Clay Lacy Aviation

Depart 4:30 p.m. Seattle, WA Company Plane

5:15 p.m. Spokane, WA
ICNU_DR_241 Attachment A Page 15 of 18
ICNU_DR_241 Attachment A Page 16 of 18
ICNU_DR_241 Attachment A Page 17 of 18
ICNU_DR_241 Attachment A Page 18 of 18

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 241 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference the Company’s Response to ICNU DR 2301. Please provide each approved Corporate Aircraft Request & Approval Form for corporate jet flights that occurred in the months of
December 2013, March 2014, June 2014, and September 2014.

RESPONSE:
Please see ICNU_DR_241 Attachment A for copies of approval forms for the given months. When
the aircraft is requested by executive level employees, an authorization form is not required.

All aircraft travel is reviewed to ensure only utility related expenses are included in the Company’s filing. Please see adjustment 2.12 Miscellaneous Restating Adjustment for flights that have been
recategorized or removed from utility operations.

1 The Company assumes ICNU intended to reference ICNU_DR_224.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 242 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference the Company’s Response to ICNU DR 2301. Please provide all Corporate Aircraft Request & Approval Forms that were submitted but not approved in the months of December 2013,
March 2014, June 2014, and September 2014.

RESPONSE:
There are no Aircraft Request & Approval Forms that were submitted but not approved during these
months.

Company use of the Corporate Aircraft is typically first approved at the departmental level before the
Corporate Aircraft Request & Approval form is prepared. If a request, verbal or written, is outside of the company guidelines, or if the plane is unavailable, the request is denied and no Approval Form is
submitted.

1 The Company assumes ICNU intended to reference ICNU_DR_224.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/09/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 243 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference the Company’s Response to ICNU DR 2301. Please state the total revenue requirement included in this proceeding associated with the corporate jet.
RESPONSE:

The total cost to operate the aircraft was $1,754,850.96 during the test period (See Avista’s response to ICNU_DR_244.) Total cost allocated to Washington electric service was $849,713.31
($861,777.70 – $12,064.392) and Washington Natural gas service was $267,597.96 ($268,878.17 -
$1,280.213)

The total revenue requirement for Washington Electric is $890,828 and $280,483 for Washington Gas. These balances are consistent with amounts reflected in current rates. No incremental amount has been requested in this case.

1 The Company assumes ICNU intended to reference ICNU_DR_224. 2 Represents expenses that were removed from revenue requirements in the company’s Miscellaneous Restating Expenses
Adjustment. See. 2.12 E-MR for details. 3 Represents expenses that were removed from revenue requirements in the company’s Miscellaneous Restating Expenses
Adjustment. See. 2.12 G-MR for details.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 244 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference the Company’s Response to ICNU DR 2301. Please provide detail of the total rate base, accumulated depreciation, accumulated deferred income taxes, operations, maintenance and
administrative expense associated with the corporate jet in the test period.

RESPONSE:
The Company leases its aircraft from PNC Aviation Finance and does not include costs in rate base,
accumulated depreciation or accumulated deferred income taxes.

Please see ICNU_DR_244 Attachment A for total utility fixed costs related to the corporate aircraft
and ICNU_DR_244 Attachment B for variable costs.

1 The Company assumes ICNU intended to reference ICNU_DR_224.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/12/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 245 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the total compensation for each of the Company’s employees, manager level and above, identified solely by job title, over the 12 month period ending December 31, 2014. Please provide a
separate column for each category of the employees’ compensation, including columns for wages, payroll
taxes, incentives, pensions, defined contribution plans, and any other aspects of the employees’
compensation.
RESPONSE: Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 245C. Please note that
Avista’s response to ICNU – 245C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205. Please see ICNU_DR_245 Attachment A for all employees, including manager level and above, for all
labor expenditure types. The Company’s general ledger system does not provide a field designating
employees as “manager” or “non-manager”. For this reason, all positions have been included. Please
note payroll tax and payroll benefits are not tracked at the employee level but are part of an overall burden rate applied to the FERC account where the direct labor was charged. Incentive payments represent cash
payment during 2014 which is based on the 2013 Short Term Incentive Plan.

Data has been provided in electronic format due to the voluminous nature.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/12/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 246 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the total compensation for each of the Company’s employees, manager level and above, identified solely by job title, over the 12 month period ending December 31, 2013. Please provide a
separate column for each category of the employees’ compensation, including columns for wages, payroll
taxes, incentives, pensions, defined contribution plans, and any other aspects of the employees’
compensation.
RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 246C. Please note that
Avista’s response to ICNU – 246C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205. Please see ICNU_DR_246C Confidential Attachment A for all employees, including manager level and
above, for all labor expenditure types. The Company’s general ledger system does not provide a field
designating employees as “manager” or “non-manager”. For this reason, all positions have been included.
Please note payroll tax and payroll benefits are not tracked at the employee level but are part of an overall burden rate applied to the FERC account where the direct labor was charged. Incentive payments
represent cash payment during 2013 which is based on the 2012 Short Term Incentive Plan.

Data has been provided in electronic format due to the voluminous nature.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/12/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 247 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the total compensation for each of the Company’s employees, manager level and above, identified solely by job title, over the 12 month period ending December 31, 2012. Please provide a
separate column for each category of the employees’ compensation, including columns for wages, payroll
taxes, incentives, pensions, defined contribution plans, and any other aspects of the employees’
compensation.
RESPONSE: Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 247C. Please note that
Avista’s response to ICNU – 247C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205. Please see ICNU_DR_247C Confidential Attachment A for all employees, including manager level and
above, for all labor expenditure types. The Company’s general ledger system does not provide a field
designating employees as “manager” or “non-manager”. For this reason, all positions have been included.
Please note payroll tax and payroll benefits are not tracked at the employee level but are part of an overall burden rate applied to the FERC account where the direct labor was charged. Incentive payments
represent cash payment during 2012 which is based on the 2011 Short Term Incentive Plan.

Data has been provided in electronic format due to the voluminous nature.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/10/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 248 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference the Company’s Response to ICNU DR 66. For each of the present members of the Financial Planning & Analysis (“FP&A”) group, please indicate the year in which that member began serving on
the FP&A group.

RESPONSE:
Below is the year in which each employee joined the FP&A department:
• Margie Stevens, Director Financial Planning and Analysis, 2004
• Jeremiah Webster, Financial Analyst, 2013
• Rosemary Coulson, Sr. Financial Analyst, 2006
• Dave DeFelice, Sr. Business Analyst, 2011
• Frank Johnson, Financial Analyst, 2010
• Grant Forsyth, Chief Economist, 2012
• Neil Thorson, Temporary assignment Manager, Operations Analytics, 2011
• Julie Lee, Operations Analyst, 2006
• Stephen Carrozzo, Operations Analyst, 2010
• Laura Vickers, Temporary assignment in Operations, 2000

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/17/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Don Kopczynski
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 249 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference the Company’s Response to ICNU DR 205. Please provide copies of the deliverables from the contract with Boreas Group, LLC, when completed.

RESPONSE:
None of the subject deliverables have been completed at this time, but they will be provided when
finished.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 06/12/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 250 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference the Company’s Responses to ICNU DRs 30 and 208. Corresponding to each bullet point in the Company’s Response to ICNU DR 30 stating changes resulting from the 2013 benefit plan review, please
identify the actual reduction in expenses relative to Avista’s current executive officers, from
implementation of the changes to the present.

RESPONSE:
As noted in the Company’s response to ICNU_DR_208, the actuarial analysis performed in relation to
each bullet point referenced in the Company’s response to ICNU_DR_030 included assumptions for all
employees, and were not specific to the executive officer vs. non-executive officer. Therefore, the actual
reduction in expenses specifically related to Avista’s current executive officers is not available.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: William Johnson/Clint Kalich
REQUESTER: INCU RESPONDER: William Johnson/Liz Andrews
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: INCU - 251 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide an update of the Company’s net power supply cost calculations based on the most recent
forward price curves available and all known power and transmission contracts. Please indicate the total Washington-allocated revenue requirement impact of the update, relative to the amount included in the
May 1, 2015 Multiparty Stipulation.

RESPONSE:
Per the Multiparty Settlement Stipulation filed with the Washington UTC on May 1, 2015, the Parties agreed that Avista shall file with the Commission an updated Power Supply adjustment two months before new electric retail rates from this electric Docket go into effect1 (see page 3, Section III. 5. a).
Therefore, the requested information reflects only a point in time and is simply illustrative of the impact
of the change in the net power supply expense as of the date of this response (07/08/2015).
Please see ICNU_DR_251-Attachment A and B for the requested information. The total Washington-allocated impact of updated powers supply as of July 8, 2015, relative to the amount included in the May
1, 2015 Multiparty Stipulation, reduces net Washington power supply expense by approximately $11.9
million ($12.5 million reduction in revenue requirement).
The reduction in net power supply expense is mainly due to the following updates from that agreed to per the Multiparty Settlement Stipulation:
• Gas Prices are down $.99/dth
• Power Prices are down $6.15/MWh
• Gas-fired Generation is up 29.8 aMW
• Natural Gas Fuel Expense is down $15.6 million

Per the Multiparty Settlement (see page 4, Section III. 5. b) (iv.)), the Parties also agreed to the following:

Colstrip and CS2 Thermal O&M: O&M costs related to Coyote Springs II and Colstrip will be
removed from the base Power Supply costs. The effect of this adjustment is an estimated reduction in power supply expense of $3.6 million (Washington basis). The revenue requirement
related to these costs will be addressed during the remainder of the case.

This removal of Colstrip and CS2 thermal O&M, as agreed to per the Multiparty Settlement, is reflected
in both the 7/8/2015 updated power supply expense and that agreed to per the Settlement as shown in ICNU_DR_251-Attachment A and B. As described in Avista’s response to Staff_DR_130-Attachment A,

1 As in past proceedings, the purpose of this power supply update would be to: 1) update the three-month average of natural gas and electricity market prices; 2) include new short-term contracts for gas and electric; and 3) update or correct power and
transmission service contracts for the 2016 rate year.

Page 2 of 2
the Company has updated its Electric Attrition Study to reflect the Multiparty Settlement, including
removal of CS2 and Colstrip maintenance expense from power supply expense (see column [I] pages 4-5
of Staff_DR_130-Attachment B), and including the incremental expense in Column [AA] "After Attrition Adjustment CS2/Colstrip Incremental O&M Exp" to address the incremental CS2/Colstrip operating and
maintenance (O&M) expense planned in 2016 for major maintenance projects at these plants (see column
[AA] pages 4-5 of Staff_DR_130-Attachment B). (Note, with the removal of the CS2/Colstrip O&M from
base power supply expense in (column [I], and addition of the amount included in column [AA], there is no net increase in these costs from the Company's direct filed Electric Attrition Study.)
In addition, as noted in Avista’s response to Staff_DR_131-Attachment A, the Company has updated its
Electric Pro Forma Study to reflect the Multiparty Settlement, including removal of CS2 and Colstrip
maintenance expense from power supply expense (Adjustment 3.00), and including the incremental expense in Pro Forma Major Maintenance-Hydro Thermal, and Other Adjustment (3.10) to include CS2/Colstrip incremental operating and maintenance (O&M) expense planned in 2016 for major
maintenance projects at these plants. (Note, with the removal of the CS2/Colstrip O&M from base power
supply expense in adjustment (3.00), and addition of the incremental amount included in adjustment
(3.10) there is no net increase in these costs from the Company's direct filed electric Pro Forma Study.)

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/02/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 252 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a detail of the Company’s historical capital expenditures on an annual basis over the years 2005 through 2014 (inclusive).

RESPONSE:
Please see ICNU_DR_252 Attachment A for details of historical capital transfers to plant from 2005
through 2014 and expected through the rate year in this filing.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/09/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 253 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a detail of Company’s historical capital expenditures placed into service on a monthly basis, by project, and over the period January 2012 to May 2015 (inclusive). Please include project
descriptions in a manner consistent with Exhibit No.___(KKS-4).

RESPONSE:
Please see ICNU_DR_253 Attachment A for system transfers to plant by month through June 2015.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/13/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 254 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Exhibit No.___(KKS-4). For each project listed in the exhibit, please detail the total amount of actual capital spending on a monthly basis between January 2014 and May 2015 (inclusive). Please also
include a column to indicate the total amount of spending made in prior years, as of January 1, 2014.

RESPONSE:
Please see the ICNU_DR_254 Attachment A for the January 2014 through June 2015 capital spending on a
system monthly basis. Please see ICNU_DR_254 Attachment B listing all 2012 and 2013 projects capital
spending. The Company does not have an analysis prepared that only includes projects for 2012 and 2013
that are also included in 2014-2015, therefore, all projects have been included in Attachment B.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/10/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Karen K. Schuh
REQUESTER: ICNU RESPONDER: Karen K. Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 255 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Exhibit No.___(KKS-4). For each project listed in the exhibit, please provide the most recently estimated in-service date and most recently estimated total project capital expenditures.

RESPONSE:
Please see ICNU_DR_255 Attachment A and B for estimated in-service dollars and in-service month for
2015 and 2016, respectively.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/09/2015
CASE NO: UE-150204 & UG-150205 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 256 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide the workpapers necessary to calculate the pro forma capital adjustments included in the
Company’s response to Staff Data Request 131, specifically the file “Staff_DR_131-Attachment B - Revised Pro Forma 09.2014 WA Electric Model.” Please provide these workpapers in a manner
consistent with the workpapers included in the Company’s initial filing at “N. UE__Smith Workpapers
(AVA-Feb2015)\PF-CAPITAL PROJECTS.”
RESPONSE: The Summary workpapers of the individual adjustments included in the Electric and Natural Gas Pro
Forma updated studies provided in response to Staff Data Request 131 were included with Avista’s
response in folder “Staff_DR_131-Attachment D – Pro Forma workpapers”. See file “1) CBR -CAP
SUMMARY-WA FINAL-updated pt.xlsx.”
Detailed capital activity which rolls up to the capital summary excel file noted above, was included with Avista’s response to Staff_DR_130 in folder “Staff_DR_130-Attachment E - 12.2014 Attrition Workpapers,”
see folder “CAPITAL” including excel files “1) CBR -CAP SUMMARY-WA FINAL-updated pt.xlsx”, “2)
CAP15 - WA CapX Additions 12.31.15-Updated PT.xlsx” and 3) CAP16 - WA CapX Additions 12.31.16
Updated PT.xlsx.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 7/2/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 257 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide workpapers calculating the average of monthly average (“AMA”) plant in service balances for calendar year 2014, on a Washington-allocated basis. Please detail the AMA plant balances in a
manner consistent with lines 31 through 45 of the Company’s results of operations table, including
accumulated deferred income taxes.

RESPONSE:
Please see ICNU_DR_257-Attachment A for the 13 months ended December 31, 2014 plant, accumulated
depreciation and ADFIT balances and the calculated AMA amount.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 258 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please state the total rate base associated with the corporate jet included in the Company’s results of operations.

RESPONSE:
There is no rate based amount associated with the corporate jet, see the Company’s response to
ICNU_DR_244.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Bob Brandkamp
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 259 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide detail of each of the directors and officers insurance policies reflected in the test period. Please include a brief description of each policy, the insurer, and the policy premiums in the
test period.

RESPONSE: Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 259C. Please note that
Avista’s response to ICNU – 259C is Confidential per Protective Order in UTC Dockets UE-
150204 and UG-150205.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Scott Kinney
REQUESTER: ICNU RESPONDER: Tara Moses
TYPE: Data Request DEPT: Resource Accounting
REQUEST NO.: ICNU – 260 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the actual Colstrip O&M expense by unit, on a monthly basis, over the period January 2010 through December 2014 (inclusive).

RESPONSE:
Please see the Company’s response to ICNU_DR_182 and Staff_DR_174 for the requested information.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Scott Kinney
REQUESTER: ICNU RESPONDER: Tara Moses
TYPE: Data Request DEPT: Resource Accounting
REQUEST NO.: ICNU – 261 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the actual Coyote Springs 2 O&M expense, on a monthly basis, over the period January 2010 through December 2014 (inclusive).

RESPONSE:
Please see the Company’s response to ICNU_DR_179 and Staff_DR_174 for the requested information.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Scott Kinney
REQUESTER: ICNU RESPONDER: Tara Moses/Thomas Dempsey
TYPE: Data Request DEPT: Resource Accounting
REQUEST NO.: ICNU – 262 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all source documents relied upon to develop the forecasted O&M costs associated with Colstrip Units 1 – 4 in this proceeding, including but not limited to the pro forma budget issued by
PPL Montana. Please also indicate where in the source documents the amount of O&M cost proposed
by the Company in this proceeding can be found.

RESPONSE:
Avista is a 15% owner of Colstrip units 3 and 4 only. Please see the Company’s response to
ICNU_DR_180 and 181. Please see ICNU_DR_180C-Confidential Attachment A, row 57, column O for
the 2016 rate year amount proposed by the Company. See also Avista’s response to Staff_DR_173 and 176 for additional information.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Scott Kinney
REQUESTER: ICNU RESPONDER: Tara Moses/Thomas Dempsey
TYPE: Data Request DEPT: Resource Accounting
REQUEST NO.: ICNU – 263 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the pro forma O&M budgets issued by PPL Montana for each of the calendar years 2010 through 2013 (inclusive).

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 263C. Please note that
Avista’s response to ICNU – 263C is Confidential per Protective Order in UTC Dockets UE-
150204 and UG-150205.

Please see ICNU_DR_263C Confidential Attachment A for the PPL Montana budget information.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Scott Kinney
REQUESTER: ICNU RESPONDER: Tara Moses/T. Dempsey
TYPE: Data Request DEPT: Resource Accounting
REQUEST NO.: ICNU – 264 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all source documents relied upon to develop the forecasted O&M costs associated with Coyote Springs 2 in this proceeding. Please also indicate where in the source documents the amount
of O&M cost proposed by the Company in this proceeding can be found.

RESPONSE:
Please see the Company’s response to ICNU_DR_177 and 178. See also Avista’s response to
Staff_DR_173 and 176 for additional information.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/08/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Scott Kinney
REQUESTER: ICNU RESPONDER: Tara Moses/T. Dempsey
TYPE: Data Request DEPT: Resource Accounting
REQUEST NO.: ICNU – 265 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Please provide the budgets or source documents provided in the previous request for Coyote Springs 2,
for each of the calendar years 2010 through 2013 (inclusive).
RESPONSE: Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 265C. Please note that
Avista’s response to ICNU – 265C is Confidential per Protective Order in UTC Dockets UE-150204 and UG-150205.
See the following confidential attachments:
ICNU_DR_265C-Confidential Attachment A - 2010 PGE Budget
ICNU_DR_265C-Confidential Attachment B -2010 LTSA Budget
ICNU_DR_265C-Confidential Attachment C - 2011 PGE Budget ICNU_DR_265C-Confidential Attachment D - 2011 LTSA Budget
ICNU_DR_265C-Confidential Attachment E - 2012 PGE Budget
ICNU_DR_265C-Confidential Attachment F - 2012 LTSA Budget
ICNU_DR_265C-Confidential Attachment G - 2013 PGE Budget
ICNU_DR_265C-Confidential Attachment H - 2013 LTSA Budget 2010: For 2010 the budget was established at $4.9M:
• $4.4M was prepared by PGE as part of their operating plan - see ICNU_DR_265C-Confidential
Attachment A
• $500k accounted for the Avista LTSA expenses-see ICNU_DR_265C-Confidential Attachment B

2011: For 2011 the budget was established at $4.4M:
• $3.9M was prepared by PGE as part of their operating plan - see ICNU_DR_265C-Confidential Attachment C
• $500k accounted for the Avista LTSA expenses-see ICNU_DR_265C-Confidential Attachment D
2012: For 2012 the budget was established at $11.5M:
• $7.0M was prepared by PGE as part of their operating plan - see ICNU_DR_265C-Confidential
Attachment E
• $4.5M accounted for the Avista LTSA expenses-see ICNU_DR_265C-Confidential Attachment F
2013: For 2013 the budget was established at $4.3M:
• $3.8M was prepared by PGE as part of their operating plan - see ICNU_DR_265C-Confidential
Attachment G
• $500k accounted for the Avista LTSA expenses-see ICNU_DR_265C-Confidential Attachment H

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 07/14/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Pat Ehrbar
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 266 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Joint Public Counsel and Energy Project Data Request (“DR”) 14 and the Company’s response in Attachment A. Please provide a narrative response explaining why the average unit cost per month for
Schedule 25 customers is so much higher than costs for other schedules listed.

RESPONSE:
The information provided in PC EP_DR_014 Attachment A was derived directly from the electric cost of
service study presented in this case. In the electric cost of service study, meters and meter-related costs are
assigned to customer classes based on the current weighted cost of metering equipment in service for the
each customer group. Schedule 25 metering equipment (which includes current transformers and potential transformers as well as three phase meters) is substantially more expensive than residential metering,
resulting in a cost per customer that is 19.92 times the cost per customer for residential metering. Schedule
25 customers also are directly assigned the costs associated with providing meter reading data to facilitate the
manual billing processes required for them. The combination of these two factors is reflected in the higher
average monthly metering and meter reading cost per customer than other customer groups.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 08/17/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 268 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

From 2005 to the present, please provide the annual amount of Schedule 91 Demand Side Management (“DSM”) funding collected from Schedule 25, including supporting documents.

RESPONSE:

See the attachment labeled “ICNU_DR_268 Attachment A” for supporting calculations of the
annual Schedule 25 DSM revenue shown above.

Page 1 of 1
Year Incentive Elec
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 08/11/2015
CASE NO.: UE-150204 & UG-150205 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 269 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

From 2005 to the present, please provide a quantification of benefits received by Schedule 25 customers from the Company’s DSM programs, including supporting documents.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 269C. Please note that
Attachment A in Avista’s response to ICNU – 269C is Confidential per Protective Order in UTC
Dockets UE-150204 and UG-150205.

Provided below are the energy efficiency incentives paid to Schedule 25 customers from 2005 through 2014, and 2015 year-to-date. Please note that these are the direct incentives paid to Schedule 25
customers for qualifying electric efficiency measures. The Company has not otherwise performed an
analysis showing the benefits Schedule 25 customers have received from the deployment of the
Company’s DSM resources in terms of reduced power supply costs. In addition, the Company has not
quantified the benefits provided to Schedule 25 customers from their use of the Company’s DSM staff for efficiency consultations, energy audits, or analysis and reporting on potential efficiency measures.