20140903Avista 2014 IRP Appendices.pdf

2014 Natural Gas Integrated
Resource Plan
Appendices
August 31, 2014
Safe Harbor Statement

This document contains forward-looking statements. Such statements are subject to a
variety of risks, uncertainties and other factors, most of which are beyond the
Company’s control, and many of which could have a significant impact on the
Company’s operations, results of operations and financial condition, and could cause
actual results to differ materially from those anticipated.

For a further discussion of these factors and other important factors, please refer to the
Company’s reports filed with the Securities and Exchange Commission. The forward-
looking statements contained in this document speak only as of the date hereof. The
Company undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events. New factors
emerge from time to time, and it is not possible for management to predict all of such
factors, nor can it assess the impact of each such factor on the Company’s business or
the extent to which any such factor, or combination of factors, may cause actual results
to differ materially from those contained in any forward-looking statement.
2014 Natural Gas IRP Appendices
TABLE OF CONTENTS: APPENDICES
Appendix 0.1 TAC Member List ............................................................................. Page 1
0.2 Comments and Responses to the 2014 IRP ............................................. 2
Appendix 1.1 Avista Corporation 2014 Natural Gas IRP Work Plan ................................ 7
1.2 IRP Guideline Compliance Summaries ................................................... 10
Appendix 2.1 Economic Outlook and Customer Count Forecast ................................... 25
2.2 Customer Forecasts by Region ............................................................... 34
2.3 Demand Coefficient Calculations ............................................................ 64
2.4 Heating Degree Day Data ....................................................................... 70
2.5 Demand Sensitivities and Demand Scenarios ......................................... 75
2.6 Demand Forecast Sensitivities and Scenarios Descriptions .................... 77
2.7 Annual Demand, Avg Day Demand & Peak Day Demand (Net of DSM) . 80
2.8 Demand Before and After DSM ............................................................... 84
2.9 Detailed Demand Data ............................................................................ 88
Appendix 3.1 Avista Gas CPA Report Final 4/23/2014 ................................................. 99
3.2 Environmental Externalities ................................................................... 127
Appendix 4.1 Current Transportation/Storage Rates and Assumptions ...................... 131
4.2 Alternate Supply Scenarios ................................................................... 132
Appendix 5.1 Monthly Price Data by Basin ................................................................. 133
5.2 Weighted Average Cost of Capital ........................................................ 139
5.3 Supply Side Resource Options ............................................................. 140
5.4 Avoided Costs Detail ............................................................................. 141
Appendix 6.1 High Case Demand and Resources Selected Graphs ........................... 157
6.2 Other Scenario Peak Day Demand Table ............................................. 159
Appendix 7.1 Distribution System Modeling ............................................................... 163
Appendix 8.1 TAC Meeting #1 ................................................................................... 169
8.2 TAC Meeting #2 ................................................................................ 256
8.3 TAC Meeting #3 ................................................................................ 324
8.4 TAC Meeting #4 ................................................................................ 426

APPENDIX - CHAPTER 0

APPENDIX 0.1: TAC MEMBER LIST
ORGANIZATION REPRESENTATIVES

Avista John Lyons Linda Gervais
Jon Powell Lori Hermanson
Jason Thackston Pat Ehrbar
Kerry Shroy
Terrence Brown
Annette Brandon Shawn Bonfield
Laura Pendergraft
Grant Forsyth
Tom Pardee
Mike Diedesch Clint Kalich

Cascade Natural Gas Company Brian Robertson Jon Whiting

Fortis BC Dana Wong Ken Ross
Intermountain Gas Mike McGrath Shelli Chase

Idaho Public Utility Commission Matt Elam Rick Sterling
Terri Carlock

Northwest Gas Association Ben Hemson Dan Kirschner
Northwest Industrial Gas Users Ed Finklea
Northwest Natural Gas Tammy Linver

Mark Thompson
Northwest Pipeline Teresa Hagins Ray Warner
Oregon Public Utility Commission Ryan Bracken
Erik Colville
Lisa Gorsuch
Oregon CUB Nadine Hanhan
Puget Sound Energy Gurvinder Singh Phillip Popoff
TransCanada David White Jay Story

Washington Attorney General’s Office Lea Daeschel Mary Kimball
Washington Utility and Transportation
Commission
David Nightingale
Brad Cebulko
Chris McGuire
WA Department of Commerce Greg Nothstein

Avista Utilities 2014 Natural Gas IRP Appendices 1
APPENDIX - CHAPTER 0

APPENDIX 0.2: COMMENTS AND RESPONSES TO 2014 DRAFT INTEGRATED
RESOURCE PLAN
The following table summarizes the significant comments on our DRAFT as submitted by TAC members
and Avista’s responses. These comments are those not directly incorporated into the primary document.
The planning environment in this IRP cycle was especially challenging given some of the most
challenging economic volatility seen in decades coupled with industry changing dynamics in natural gas
production. We continued our robust, flexible demand forecasting methodology that captured a broad
range of demand forecasts fully vetted with our TAC. This IRP produced reduced forecasted demand
scenarios and no near term resource needs even in our most robust demand scenario. We appreciate the
time and effort invested by all our TAC members throughout the IRP process. Many good suggestions
have been made and we have incorporated those that enhance the document.
Document
Reference[1] Comment/Question Avista Response
3 – DEMAND SIDE MANAGEMENT
Avista has a DSM preference adder, but does not quantify many natural gas non-energy benefits (NEBs). In chapter 9
the company has committed to analyzing “non-natural gas
benefits” as an action item. Perhaps this is an area the company could work with the Energy Trust of Oregon, the
advisory group and other regional actors to quantify
NEBs. The Commission’s
Policy Statement on the Evaluation of the Cost-Effectiveness of Natural Gas
Conservation Programs in Docket UG-121207 has a
preference for a fully
developed Total Resource Cost test, and staff would like to see the company works
towards that end.
It is Avista’s policy to include all non-natural gas impacts that can be quantified in a manner that is sufficiently rigorous and reasonable to defend to a critical but reasonable audience.
Where such degrees of rigor cannot be met the Company is committed to measuring the
presence of non-natural gas impacts to the extent possible so as to facilitate the discussion of non-quantifiable non-natural gas impacts. The primary non-natural gas impacts
currently quantified by the Company are non-natural gas energy savings (electric, propane
and other non-natural gas fuels), water and
sewage savings. Additionally, for low-income programs, the Company has a valuation of health and human safety investments and
provision of baseline end-use services. The Company treats the importation of funding from
outside of the Avista ratepayer population as
offsetting the customer incremental cost and not as a non-natural gas impact, but the consequences to the Total Resource Cost test
is similar. The Company has a mechanism with the site-specific program to capturing
unusual and unique non-natural gas impacts and incorporating them into the cost-
effectiveness analysis.
Avista Utilities 2014 Natural Gas IRP Appendices 2
APPENDIX - CHAPTER 0

3 – DEMAND SIDE
MANAGEMENT
As staff asked in its
acknowledgment letter in Docket UG-111588, Avista
should include an analysis and narrative describing the
“trigger point” avoided cost value, where the conservation
programs of the company become cost-effective.
The Company has committed to monitoring
the weighted average cost of gas (WACOG) as a proxy for the avoided cost between
Integrated Resource Plans. Though the WACOG and the avoided cost differ in some
significant and important ways, a significant upward movement in the WACOG would tend
to indicate a similar movement in the avoided cost. This could then trigger an immediate re-
evaluation of the potential between IRP cycles. Earlier analysis indicated that an increase of
approximately 90% in the avoided cost would be necessary to deliver a portfolio that was
cost-effective under the Total Resource Cost test.
3.10 – DEMAND SIDE
MANAGEMENT
The targets for 2015 and
2016 for Oregon are substantially lower than 2013
and 2014 (161 and 111 versus 225 and 250). Please
provide more information about why there is such a
large reduction. OPUC may be interested in the Company
continuing current levels of acquisition. Please present a
case where that can happen and what measures could fall
within the exception criteria in Order 94-590, Docket No. UM
551.
Incremental economic potential in the 2015
and 2016 biennium is 454 and 235 dekatherms. In the previous study, incremental
economic potential for 2013 and 2014 was 486 and 642 dekatherms. The lower economic
potential in the current study reflects lower avoided cost projections. This flows through to
achievable potential and the targets for 2015 and 2016 are lower than they were for 2013
and 2014. See the comparison of avoided costs in the separate tab.
3.12– DEMAND
SIDE MANAGEMENT
Good discussion on developing a regional natural
gas market transformation organization. Does Avista
have a timeline? Can this conversation be expanded?
Please update the final draft with the most current
information.
The interested regional natural gas utilities are continuing the process of developing a
proposal for review by the full Northwest Energy Efficiency Alliance (NEEA) board. The
deadline for completing that proposal is the end of the calendar year, but every attempt is
being made to expedite that process. The best opportunity for interested parties to contribute
to that discussion will be as part of the NEEA board review.
3.2 – DEMAND
SIDE MANAGEMENT
Please provide more details about how ramp rates were
calculated and how they were or weren’t consistent with
assumptions used by the Northwest Power Planning
Council. Also, please include a side by side comparison
with explanation of differences.
EnerNOC Consulting Services (now AEG) used the Council's Sixth Plan ramp rates as a
starting point for the Avista study. Then, we made adjustments to the ramp rates in the
early years of the projection to better align with Avista's recent program accomplishments. The
ramp rates were also adjusted in the out years for some measures. The resulting Avista ramp
rates are presented in the two tabs: Equip_Ramp Rates and Non_Equip_Ramp
Rates.
Avista Utilities 2014 Natural Gas IRP Appendices 3
APPENDIX - CHAPTER 0

3.4 – DEMAND SIDE
MANAGEMENT
More details are needed
about how achievable potential was calculated and
how each of the elements mentioned were incorporated
in practice.
In each year of the forecast, some number of
appliances fail and need to be replaced. If a measure is cost effective, then the ramp rate is
applied to determine what fraction of the market installs the cost-effective option. For
example, the ramp rate in 2015 for furnaces in the commercial sector, a cost-effective
measure, is 20%. Therefore, 20% of the furnaces that fail in 2015 are replaced with the
energy-conservation measure (high efficiency furnace) and the remaining furnaces are
replaced with the baseline option.
3.6 – DEMAND SIDE
MANAGEMENT
Please describe why only 74
percent of economic potential is achievable by 2034.
Provide details regarding underlying assumptions and
data files.
This 74% is actually a very high share of
economic potential and reflects the combination of lost-opportunity and non lost
opportunity measures, with ramp rates in the out years of up to 65% and 85% respectively.
3.8 – DEMAND
SIDE MANAGEMENT
In the Oregon achievable
potential numbers; please explain what assumptions are
made about which measures are included. Are only TRC
cost effective measures (and those measures required by
law) included in projections? How is low income handled
relative to cost effectiveness? Please include a sensitivity
case and numbers for the occasion where current
exceptions to cost effectiveness are continued
beyond the current two year window.
A comprehensive measure list was included in
the analysis. The total resource cost test (TRC) was used for cost-effectiveness screening with
a minimum threshold of 1.0. Only measures that are considered cost-effective are included
in economic, and therefore acheivable potential. The residential sector was
segmented by housing type. Low income was not specifically considered as part of the CPA.
However, the low-income segment is considered in the development of programs.
4.4 – SUPPLY SIDE RESOURCES
The last sentence of first full
paragraph mentions a process to acquire value from
each transaction. Please identify how that process is
carried out and identify who is involved.
The value of a transaction for the purchase of
natural gas can encompass many different aspects both financial and non-financial and is
assessed at the time the transaction is executed. Our natural gas buyers are actively
assessing the most cost effective way to meet customer demand and optimize unutilized
resources. Therefore value cannot be necessarily measured from a single
transaction. It may be a series of transactions that span across timeframes of a day, week,
month or season.
Avista Utilities 2014 Natural Gas IRP Appendices 4
APPENDIX - CHAPTER 0

4.11 – SUPPLY SIDE RESOURCES

Jackson Prairie paragraph
mentions that Avista will look for exchange and
transportation release opportunities. Please discuss
how the opportunities will be monitored and what will be
done with the intelligence gathered through such
monitoring.
These opportunities can be discovered in a
number of ways. For example, buyers may be contacted from marketers or other utility
counterparts. When the opportunity presents itself we assess if it makes sense from a
financial impact to customers as well as a reliability concerns.
5.20 –
INTEGRATED RESOURCE
PORTFOLIO
Avista has TF-2 service for its storage at Jackson Prairie.
Presumably the company draws down JP during cold
events when demand is high. Is TF-2 firm capacity? If not,
please explain why the company feels it can rely
upon the service for meeting peak demand.
TF2 is a firm service as noted on NWP website: "TF2 allows for contracting a daily
amount of firm service for a specified number of days rather than a daily amount on an
annual basis as is usually required."
5.23 – INTEGRATED RESOURCE
PORTFOLIO
ACTION ITEM discusses routine LDC activities. The
action items should not include actions that are
“normal” utility activities. The action plan items should be
specific and measurable.
With no resource deficiency in our expected case, there are no specific and measurable
near term action items.
6.5 – ALTERNATE
SCENARIOS
The last paragraph highlights a structural problem with the
IRP analysis. The point of calculating PVRR is to be
able to compare alternate portfolios (different ways of
meeting forecast demand). See Guideline 1.c. Please
expand the discussion to explain the intended PVRR
calculation value and why in this IRP the value is not
there.
Using PVRR analysis to compare various scenarios where some of the assumptions are
similar is a very useful analysis. However, looking strictly at PVRR calculations without
considering the assumptions of each scenario is not appropriate. For example the PVRR of
our Expected scenario is higher than the PVRR of the High Growth scenario. However, there
are lower supply costs and demand that remains unserved in the High Growth Scenario
so selecting the lowest PVRR scenarios is not applicable. There are also non-economic
factors that may make the selection of one scenario over the other based on pure PVRR
analysis undesirable.
7 – DISTRIBUTION
PLANNING
Will you be describing all projects on Table 7.1 and
7.2?
We only provide detail on specific projects that were driven from IRP analysis. We have
provided major capital expenditures for informational purposes only.
Avista Utilities 2014 Natural Gas IRP Appendices 5
APPENDIX - CHAPTER 0

8.2 – ACTION PLAN
There is no action item that
speaks to the exception period for non-cost effective
measures that will sunset in April 2015, and what action
will be taken to address this ongoing situation.
Ongoing situation of Oegon DSM program will
be addressed outside of the IRP through its Annual Plan, Year-End Reporting, and tariff
filings. IRP Action Plan was updated to reflect the progress made on the 2013/2014 Action
Items Ordered by the Commission.

Avista Utilities 2014 Natural Gas IRP Appendices 6
APPENDIX - CHAPTER 1

APPENDIX 1.1: AVISTA CORPORATION 2014 NATURAL GAS INTEGRATED
RESOURCE PLAN WORK PLAN
IRP WORK PLAN REQUIREMENTS
Section 480-90-238 (4), of the natural gas Integrated Resource Plan (“IRP”) rules, specify requirements
for the IRP Work Plan:
Not later than twelve months prior to the due date of a plan, the utility must provide a
work plan for informal commission review. The work plan must outline the content of the
integrated resource plan to be developed by the utility and the method for assessing
potential resources.
Additionally, Section 480-90-238 (5) of the WAC states:
The work plan must outline the timing and extent of public participation.
OVERVIEW
This Work Plan outlines the process Avista will follow to complete its 2014 Natural Gas IRP by Aug. 31,
2014. Avista uses a public process to obtain technical expertise and guidance throughout the planning
period via Technical Advisory Committee (TAC) meetings. The TAC will be providing input into
assumptions, scenarios, and modeling techniques.
PROCESS
The 2014 IRP process will be similar to that used to produce the previously published plan. Avista will
use SENDOUT® (a PC based linear programming model widely used to solve natural gas supply and
transportation optimization questions) to develop the risk adjusted least-cost resource mix for the 20 year
planning period.
This plan will continue to include demand analysis, demand side management and avoided cost
determination, existing and potential supply-side resource analysis, resource integration and alternative
sensitivities and scenario analysis.
Additionally, Avista intends to incorporate action plan items identified in the 2012 Natural Gas IRP
including more detailed demand analysis regarding use per customer, demand side management results
and possible price elastic responses to evolving economic conditions, an updated assessment of
conservation potential in our service territories, consideration of alternate forecasting methodologies, and
the changing landscape of natural gas supply (i.e. shale gas, Canadian exports, and US LNG exports) and
its implications to the planning process. Further details about Avista’s process for determining the risk
adjusted least-cost resource mix is shown in Exhibit 1.

Avista Utilities 2014 Natural Gas IRP Appendices 7
APPENDIX - CHAPTER 1

TIMELINE
The following is Avista’s TENTATIVE 2014 Natural Gas IRP timeline:
subject to change

Avista Utilities 2014 Natural Gas IRP Appendices 8
APPENDIX - CHAPTER 1

EXHIBIT 1: AVISTA’S 2014 NATURAL GAS IRP MODELING PROCESS

Demand Forecast by Area and Class
 Customer counts
 Use per customer
 Elasticity
Gas Prices
 Basis differential
 Volatility
 Seasonal Spreads
Existing Supply-Side Resources
 Costs
 Operational Characteristics


Demand-Side Resources
 Assess DSM resource options
 Integrate DSM in resource portfolio
Weather
 20-year NOAA average by area plus
Peak Day weather
SENDOUT®
Optimization
Run

Identify when and where
deficiencies occur in the 20-
year planning period.
Enter all Future Resource Options:
 Demand-Side
 Supply-Side
SENDOUT®
Optimization
Run

Solve for deficiencies and
incorporate those into the
least costs resource mix for
the 20-year period. Determine Base
Case Scenario
Avoided Cost
Determination
Compile Data and Write
the IRP Document.
Key Considerations
 Resource Cost
 Peak vs. Base Load
 Lead Time Requirements
 Resource Usefulness
 “Lumpiness” of Resource Options
Sensitivity/Scenario
Analysis
 Customer Counts
 Use per customer
 DSM
 Monte Carlo
 Etc.
Price Curve
Analysis
Gate Station
Analysis
Planning
Standard Review
Avista Utilities 2014 Natural Gas IRP Appendices 9
APPENDIX - CHAPTER 1

APPENDIX 1.2: WASHINGTON PUBLIC UTILITY COMMISSION IRP POLICIES AND
GUIDELINES – WAC 480-90-238
Rule Requirement Plan
Citation
WAC 480-90-238(4) Work plan filed no later than 12 months before next IRP due date. Work plan submitted to the WUTC on August 31, 2011, See
attachment to this Appendix 1.1.
WAC 480-90-238(4) Work plan outlines content of IRP. See workplan attached to this Appendix 0.1.
WAC 480-90-238(4) Work plan outlines method for
assessing potential resources. (See LRC analysis below)
See Appendix 1.1.
WAC 480-90-238(5) Work plan outlines timing and extent of
public participation.
See Appendix 1.1.
WAC 480-90-238(4) Integrated resource plan submitted within two years of previous plan. Last Integrated Resource Plan was submitted on August 31, 2012
WAC 480-90-238(5) Commission issues notice of public hearing after company files plan for
review.
TBD
WAC 480-90-238(5) Commission holds public hearing. TBD
WAC 480-90-238(2)(a) Plan describes mix of natural gas
supply resources.
See Chapter 4 on Supply Side
Resources
WAC 480-90-238(2)(a) Plan describes conservation supply. See Chapter 3 on Demand Side Resources
WAC 480-90-238(2)(a) Plan addresses supply in terms of
current and future needs of utility and ratepayers.
See Chapter 4 on Supply Side
Resources and Chapter 5 Integrated Resource Portfolio
WAC 480-90-
238(2)(a)&(b)
Plan uses lowest reasonable cost
(LRC) analysis to select mix of resources.
See Chapters 3 and 4 for Demand
and Supply Side Resources. Chapter 5 details how Demand
and Supply come together to select the least cost/best risk
portfolio for ratepayers.
WAC 480-90-238(2)(b) LRC analysis considers resource costs. See Chapters 3 and 4 for Demand and Supply Side Resources.
Chapter 5 details how Demand and Supply come together to
select the least cost/best risk portfolio for ratepayers.
WAC 480-90-238(2)(b) LRC analysis considers market-
volatility risks.
See Chapter 4 on Supply Side
Resources
WAC 480-90-238(2)(b) LRC analysis considers demand side uncertainties. See Chapter 2 Demand Forecasting
WAC 480-90-238(2)(b) LRC analysis considers resource
effect on system operation.
See Chapter 4 and Chapter 5
WAC 480-90-238(2)(b) LRC analysis considers risks
imposed on ratepayers.
See Chapter 4 procurement plan
section. We seek to minimize but cannot eliminate price risk for our
customers.
WAC 480-90-238(2)(b) LRC analysis considers public policies regarding resource preference
adopted by Washington state or federal government.
See Chapter 2 demand scenarios
Avista Utilities 2014 Natural Gas IRP Appendices 10
APPENDIX - CHAPTER 1

WAC 480-90-238(2)(b) LRC analysis considers cost of risks associated with environmental effects
including emissions of carbon dioxide.
See Chapter 2 on demand scenarios
WAC 480-90-238(2)(b) LRC analysis considers need for security of supply. See Chapter 4 on Supply Side Resources
Rule Requirement Plan Citation
WAC 480-90-238(2)(c) Plan defines conservation as any reduction in natural gas consumption
that results from increases in the efficiency of energy use or distribution.
See Chapter 3 on Demand Side Resources
WAC 480-90-238(3)(a) Plan includes a range of forecasts of
future demand.
See Chapter 2 on Demand
Forecast
WAC 480-90-238(3)(a) Plan develops forecasts using methods that examine the effect of
economic forces on the consumption of natural gas.
See Chapter 2 on Demand Forecast
WAC 480-90-238(3)(a) Plan develops forecasts using
methods that address changes in the number, type and efficiency of natural
gas end-uses.
See Chapter 2 on Demand
Forecast
WAC 480-90-238(3)(b) Plan includes an assessment of commercially available conservation, including load management.
See Chapter 3 on Demand Side Management including demand response section. WAC 480-90-238(3)(b) Plan includes an assessment of currently employed and new policies
and programs needed to obtain the conservation improvements.
See Chapter 3 and Appendix 3.1.
WAC 480-90-238(3)(c) Plan includes an assessment of
conventional and commercially available nonconventional gas
supplies.
See Chapter 4 on Supply Side
Resources
WAC 480-90-238(3)(d) Plan includes an assessment of opportunities for using company-
owned or contracted storage.
See Chapter 4 on Supply Side Resources
WAC 480-90-238(3)(e) Plan includes an assessment of pipeline transmission capability and
reliability and opportunities for additional pipeline transmission
resources.
See Chapter 4 on Supply Side Resources
WAC 480-90-238(3)(f) Plan includes a comparative evaluation of the cost of natural gas purchasing
strategies, storage options, delivery resources, and improvements in
conservation using a consistent method to calculate cost-effectiveness.
See Chapter 3 on Demand Side Resources and Chapter 4 on
Supply Side Resources
WAC 480-90-238(3)(g) Plan includes at least a 10 year long-
range planning horizon.
Our plan is a comprehensive 20
year plan.
WAC 480-90-238(3)(g) Demand forecasts and resource evaluations are integrated into the long
range plan for resource acquisition.
Chapter 5 Integrated Resource Portfolio details how demand and
supply come together to form the least cost/best risk portfolio.
WAC 480-90-238(3)(h) Plan includes a two-year action plan
that implements the long range plan.
See Section 8 Action Plan
WAC 480-90-238(3)(i) Plan includes a progress report on the
implementation of the previously filed plan.
See Section 8 Action Plan
Avista Utilities 2014 Natural Gas IRP Appendices 11
APPENDIX - CHAPTER 1

WAC 480-90-238(5) Plan includes description of consultation with commission staff.
(Description not required)
See Section 0 Introduction
WAC 480-90-238(5) Plan includes description of completion of work plan. (Description not required) See Appendix 1.1.

Avista Utilities 2014 Natural Gas IRP Appendices 12
APPENDIX - CHAPTER 1

APPENDIX 1.2: IDAHO PUBLIC UTILITY COMMISSION IRP POLICIES AND
GUIDELINES – ORDER NO. 2534
DESCRIPTION OF REQUIREMENT FULLFILLMENT OF REQUIREMENT
1 Purpose and Process. Each gas utility regulated
by the Idaho Public Utilities Commission with retail sales of more than 10,000,000,000 cubic feet in a
calendar year (except gas utilities doing business in Idaho that are regulated by contract with a
regulatory commission of another State) has the responsibility to meet system demand at least cost
to the utility and its ratepayers. Therefore, an ‘‘integrated resource plan’’ shall be developed by
each gas utility subject to this rule.
Avista prepares a comprehensive 20 year
Integrated Resource Plan every two years. Avista will be filing its 2014 IRP on or before
August 31, 2014.
2 Definition. Integrated resource planning. ‘‘Integrated resource planning’’ means planning by
the use of any standard, regulation, practice, or policy to undertake a systematic comparison
between demand-side management measures and the supply of gas by a gas utility to minimize
life-cycle costs of adequate and reliable utility services to gas customers. Integrated resource
planning shall take into account necessary features for system operation such as diversity,
reliability, dispatchability, and other factors of risk and shall treat demand and supply to gas
consumers on a consistent and integrated basis.
Avista's IRP brings together dynamic demand forecasts and matches them against demand-
side and supply-side resources in order to evaluate the least cost/best risk portfolio for its
core customers. While the primary focus has been to ensure customer's needs are met
under peak or design weather conditions, this process also evaluates the resource portfolio
under normal/average operating conditions. The IRP provides the framework and
methodology for evaluating Avista's natural gas demand and resources.
3 Elements of Plan. Each gas utility shall submit to
the Commission on a biennial basis an integrated resource plan that shall include:
2014 IRP to be filed on or before August 31,
2014. The last IRP was filed on August 31, 2012.
A range of forecasts of future gas demand in firm
and interruptible markets for each customer class for one, five, and twenty years using methods that
examine the effect of economic forces on the consumption of gas and that address changes in
the number, type and efficiency of gas end-uses.
See Chapter 2 - Demand Forecasts and
Appendix 2 et. al. for a detailed discussion of how demand was forecasted for this IRP.
An assessment for each customer class of the
technically feasible improvements in the efficient use of gas, including load management, as well as
the policies and programs needed to obtain the efficiency improvements.
See Chapter 3 - Demand Side Management
and DSM Appendices 3 et.al. for detailed information on the DSM potential evaluated
and selected for this IRP and the operational implementation process.
Avista Utilities 2014 Natural Gas IRP Appendices 13
APPENDIX - CHAPTER 1

An analysis for each customer class of gas supply
options, including: (1) a projection of spot market versus long-term purchases for both firm and
interruptible markets; (2) an evaluation of the opportunities for using company-owned or
contracted storage or production; (3) an analysis of prospects for company participation in a gas
futures market; and (4) an assessment of opportunities for access to multiple pipeline
suppliers or direct purchases from producers.
See Chapter 4 - Supply-Side Resources for
details about the market, storage, and pipeline transportation as well as other resource options
considered in this IRP. See also the procurement plan section in this same chapter
for supply procurement strategies.
A comparative evaluation of gas purchasing options and improvements in the efficient use of
gas based on a consistent method for calculating cost-effectiveness.
See Methodology section of Chapter 3 -
Demand-Side Resources where we describe
our process on how demand-side and supply-side resources are compared on par with each other in the SENDOUT® model. Chapter 3 also includes how results from the IRP are then
utilized to create operational business plans. Operational implementation may differ from
IRP results due to modeling assumptions.
The integration of the demand forecast and
resource evaluations into a long-range (e.g., twenty-year) integrated resource plan describing
the strategies designed to meet current and future needs at the lowest cost to the utility and its
ratepayers.
See Chapter 5 - Integrated Resource
Portfolio for details on how we model demand and supply coming together to provide the least
cost/best risk portfolio of resources.
A short-term (e.g., two-year) plan outlining the specific actions to be taken by the utility in
implementing the integrated resource plan.
See Chapter 8 - Action Plan for actions to be taken in implementing the IRP.
4 Relationship Between Plans. All plans following
the initial integrated resource plan shall include a progress report that relates the new plan to the
previously filed plan.
Avista strives to meet at least bi-annually with
Staff and/or Commissioners to discuss the state of the market, procurement planning
practices, and any other issues that may impact resource needs or other analysis within
the IRP.
5 Plans to Be Considered in Rate Cases. The integrated resource plan will be considered with
other available information to evaluate the performance of the utility in rate proceedings
before the Commission.
We prepare and file our plan in part to establish a public record of our plan.
6 Public Participation. In formulating its plan, the
gas utility must provide an opportunity for public participation and comment and must provide
methods that will be available to the public of validating predicted performance.
Avista held four Technical Advisory Committee
meetings beginning in January and ending in April. See Chapter 0 - Introduction for more
detail about public participation in the IRP process.
Avista Utilities 2014 Natural Gas IRP Appendices 14
APPENDIX - CHAPTER 1

7 Legal Effect of Plan. The plan constitutes the
base line against which the utility's performance will ordinarily be measured. The requirement for
implementation of a plan does not mean that the plan must be followed without deviation. The
requirement of implementation of a plan means that a gas utility, having made an integrated
resource plan to provide adequate and reliable service to its gas customers at the lowest system
cost, may and should deviate from that plan when presented with responsible, reliable opportunities
to further lower its planned system cost not anticipated or identified in existing or earlier plans
and not undermining the utility's reliability.
See section titled "Avista's Procurement Plan"
in Chapter 4 - Supply-Side Resources. Among other details we discuss plan revisions
in response to changing market conditions.
In order to encourage prudent planning and prudent deviation from past planning when
presented with opportunities for improving upon a plan, a gas utility's plan must be on file with the
Commission and available for public inspection. But the filing of a plan does not constitute approval
or disapproval of the plan having the force and effect of law, and deviation from the plan would
not constitute violation of the Commission's Orders or rules. The prudence of a utility's plan
and the utility's prudence in following or not following a plan are matters that may be
considered in a general rate proceeding or other proceedings in which those issues have been
noticed.
See also section titled "Alternate Supply-Side Scenarios" in Chapter 5 - Integrated
Resource Portfolio where we discuss different supply portfolios that are resonsive to changing
assumptions about resource alternatives.

Avista Utilities 2014 Natural Gas IRP Appendices 15
APPENDIX - CHAPTER 1

APPENDIX 1.2: OREGON PUBLIC UTILITY COMMISSION IRP STANDARD AND
GUIDELINES – ORDER 07- 002
Guideline 1: Substantive Requirements
1.a.1 All resources must be evaluated on
a consistent and comparable basis.
All resource options considered, including demand-
side and supply-side are modeled in SENDOUT®
utilizing the same common general assumptions,
approach and methodology.
1.a.2 All known resources for meeting the
utility’s load should be considered,
including supply-side options which
focus on the generation, purchase
and transmission of power – or gas
purchases, transportation, and
storage – and demand-side options
which focus on conservation and
demand response.
Avista considered a range of resources including
demand-side management, distribution system
enhancements, capacity release recalls, interstate
pipeline transportation, interruptible customer supply,
and storage options including liquefied natural gas.
Chapter 3 and Appendix 3.1 documents Avista’s
demand-side management resources considered.
Chapter 4 and Appendix 5.3 documents supply-side
resources. Chapter 5 and 6 documents how Avista
developed and assessed each of these resources.

1.a.3 Utilities should compare different
resource fuel types, technologies,
lead times, in-service dates,
durations and locations in portfolio
risk modeling.
Avista considered various combinations of
technologies, lead times, in-service dates, durations,
and locations. Chapter 5 provides details about the
modeling methodology and results. Chapter 4
describes resource attributes and Appendix 5.3
summarizes the resources’ lead times, in-service
dates and locations.
1.a.4 Consistent assumptions and
methods should be used for
evaluation of all resources.
Appendix 5.2 documents general assumptions used in
Avista’s SENDOUT® modeling software. All portfolio
resources both demand and supply-side were
evaluated within SENDOUT® using the same sets of
inputs.
1.a.5 The after-tax marginal weighted-
average cost of capital (WACC)
should be used to discount all future
resource costs.
Avista applied its after-tax WACC of 4.93% to discount
all future resource costs. (See general assumptions at
Appendix 5.2)
1.b.1 Risk and uncertainty must be
considered. Electric utilities only
Not Applicable
1.b.2 Risk and uncertainty must be
considered. Natural gas utilities
should consider demand (peak,
swing and base-load), commodity
supply and price, transportation
availability and price, and costs to
comply with any regulation of
greenhouse gas (GHG) emissions.
Risk and uncertainty are key considerations in long
term planning. In order to address risk and
uncertainties a wide range of sensitivity, scenario and
portfolio analysis is completed. A description of risk
associated with each scenario is included in Appendix
2.6.

One of the key risks is the “flat demand” risk as
described in Chapter 1. Avista performed 15
sensitivities on demand. From there five demand
scenarios were developed (Table 1.1) for SENDOUT®
modeling purposes. Monthly demand coefficients were
developed for base, heating demand while peak
demand was contemplated through modeling a
weather planning standard of the coldest day on
record (see heating degree day data in Appendix 2.4).

Avista Utilities 2014 Natural Gas IRP Appendices 16
APPENDIX - CHAPTER 1

Avista evaluated several price forecasts and selected
high, medium and low price scenarios for modeling
purposes. The annual average prices are then
weighted by month using fundamental forecast data.
Additionally, the Henry Hub price forecasts are basis
adjusted using the same fundamental forecast data.

Four supply scenarios were also evaluated, see Table
4.3. These supply scenarios were combined with
demand scenarios in order to establish portfolios for
evaluation. Ultimately 9 portfolios were evaluated
(See Table 6.3 for the PVRR results).

Avista stochastic modeling techniques for price and
weather variables to analyze weather sensitivity and
to quantify the risk to customers under varying price
environments. While there continues to be some
uncertainty around GHG emission, Avista considered
GHG emissions regulatory compliance costs in
Appendix 3.2. As currently modeled, we include a
carbon adder to our price curve to capture the costs of
emission regulation.
Utilities should identify in their plans
any additional sources of risk and
uncertainty.
Avista evaluated additional risks and uncertainties.
Risks associated with the planning environment are
detailed in Chapter 0 Introduction. Avista also
analyzed demand risk which is detailed in Chapter 2.
Chapter 3 discusses the uncertainty around how much
DSM is achievable. Supply-side resource risks are
discussed in Chapter 4. Chapter 5 and 6 discusses
the variables modeled for scenario and stochastic risk
analysis.
1c The primary goal must be the
selection of a portfolio of resources
with the best combination of
expected costs and associated risks
and uncertainties for the utility and
its customers.
Avista evaluated cost/risk tradeoffs for each of the risk
analysis portfolios considered. See Chapter 5 and 6
plus supporting information in Appendix 2.6 for
Avista’s portfolio risk analysis and determination of the
preferred portfolio.
The planning horizon for analyzing
resource choices should be at least
20 years and account for end
effects. Utilities should consider all
costs with a reasonable likelihood of
being included in rates over the long
term, which extends beyond the
planning horizon and the life of the
resource.
Avista used a 20-year study period for portfolio
modeling. Avista contemplated possible costs beyond
the planning period that could affect rates including
end effects such as infrastructure decommission costs
and concluded there were no significant costs
reasonably likely to impact rates under different
resource selection scenarios.
Utilities should use present value of
revenue requirement (PVRR) as the
key cost metric. The plan should
include analysis of current and
estimated future costs of all long-
lived resources such as power
plants, gas storage facilities and
pipelines, as well as all short-lived
resources such as gas supply and
Avista’s SENDOUT® modeling software utilizes a
PVRR cost metric methodology applied to both long
and short-lived resources.
Avista Utilities 2014 Natural Gas IRP Appendices 17
APPENDIX - CHAPTER 1

short-term power purchases.
To address risk, the plan should
include at a minimum: 1) Two
measures of PVRR risk: one that
measures the variability of costs and
one that measures the severity of
bad outcomes. 2) Discussion of the
proposed use and impact on costs
and risks of physical and financial
hedging.
Avista, through its stochastic analysis, modeled 200
scenarios around varying gas price inputs via Monte
Carlo iterations developing a distribution of Total 20
year cost estimates utilizing SENDOUT®’s PVRR
methodology. Chapter 6 further describes this
analysis. The variability of costs is plotted against the
Expected Case while the scenarios beyond the 95th
percentile capture the severity of outcomes. Chapter 4
discusses Avista’s physical and financial hedging
methodology.
The utility should explain in its plan
how its resource choices
appropriately balance cost and risk.
Chapter 4, 5, and 6 describe various specific resource
considerations and related risks, and describes what
criteria we used to determine what resource
combinations provide an appropriate balance between
cost and risk.
1d The plan must be consistent with
the long-run public interest as
expressed in Oregon and federal
energy policies.
Avista considered current and expected state and
federal energy policies in portfolio modeling. Chapter
5 describes the decision process used to derive
portfolios, which includes consideration of state
resource policy directions.
Guideline 2: Procedural Requirements
2a The public, including other utilities,
should be allowed significant
involvement in the preparation of the
IRP. Involvement includes
opportunities to contribute
information and ideas, as well as to
receive information. Parties must
have an opportunity to make
relevant inquiries of the utility
formulating the plan.
Chapter 0 provides an overview of the public process
and documents the details on public meetings held for
the 2014 IRP. Avista encourages participation in the
development of the plan, as each party brings a
unique perspective and the ability to exchange
information and ideas makes for a more robust plan.
While confidential information must
be protected, the utility should make
public, in its plan, any non-
confidential information that is
relevant to its resource evaluation
and action plan.
The entire IRP, as well as the TAC process, includes
all of the non-confidential information the company
used for portfolio evaluation and selection. Avista also
provided stakeholders with non-confidential
information to support public meeting discussions via
email. The document and appendices will be available
on the company website for viewing.
The utility must provide a draft IRP
for public review and comment prior
to filing a final plan with the
Commission.
Avista distributed a draft IRP document for external
review to all TAC members on May 25, 2014 and
requested comments by July 13, 2014.
Guideline 3: Plan Filing, Review and Updates
3a Utility must file an IRP within two
years of its previous IRP
acknowledgement order.
This Plan complies with this requirement as the 2012
Natural Gas IRP was acknowledged on 4/30/2013.
3b Utility must present the results of its
filed plan to the Commission at a
public meeting prior to the deadline
for written public comment.
Avista will work with Staff to fulfill this guideline
following filing of the IRP.
3c Commission staff and parties should
complete their comments and
recommendations within six months
of IRP filing
Pending
Avista Utilities 2014 Natural Gas IRP Appendices 18
APPENDIX - CHAPTER 1

3d The Commission will consider
comments and recommendations on
a utility’s plan at a public meeting
before issuing an order on
acknowledgment. The Commission
may provide the utility an
opportunity to revise the plan before
issuing an acknowledgment order
Pending
3e The Commission may provide
direction to a utility regarding any
additional analyses or actions that
the utility should undertake in its
next IRP.
Pending
3f Each utility must submit an annual
update on its most recently
acknowledged plan. The update is
due on or before the
acknowledgment order anniversary
date. Once a utility anticipates a
significant deviation from its
acknowledged IRP, it must file an
update with the Commission, unless
the utility is within six months of
filing its next IRP. The utility must
summarize the update at a
Commission public meeting. The
utility may request acknowledgment
of changes in proposed actions
identified in an update
Because the 2012 IRP was not acknowledged until
April 30, 2013 the Company did not submit an annual
update as the 2014 IRP process was well underway
by the anniversary date of the acknowledgement. The
Company provided updates and comparisons to its
2012 IRP during its 2014 IRP TAC meetings held on
January 24, 2014, February 25, 2014, March 26,
2014, and April 23, 2014, in which Commission Staff
and other TAC members were present. In addition the
Company provided an update during its Natural Gas
Quarterly update meeting held on April 17, 2014. No
request for acknowledgement was required as no
significant deviation from the 2012 IRP was
anticipated.
3g Unless the utility requests
acknowledgement of changes in
proposed actions, the annual update
is an informational filing that:
 Describes what actions the utility has taken to implement the plan;
 Provides an assessment of what has changed since the
acknowledgment order that affects the action plan, including
changes in such factors as load, expiration of resource contracts,
supply-side and demand-side resource acquisitions, resource
costs, and transmission availability; and
 Justifies any deviations from the acknowledged action plan.
The updates described in 3f above explained changes
since acknowledgment of the 2012 IRP and an update
of emerging planning issues. The updates did not
request acknowledgement of any changes.

Also, as directed in Order No. 13-159, per the 2013-
2014 Action Plan, the Company continued its DSM
programs in Oregon with a minimum savings goal of
225,000 therms in 2013 and 250,000 therms in 2014.
On April 30, 2014, the Company submitted its 2013
DSM Annual Report to Commission Staff which
included updates and progress in meeting the DSM
Action Items contained in Order No. 13-159. Lastly,
as ordered the Company developed a potential
mechanism for allocating funding for a separate low-
income energy efficiency program and submitted a
report to Commission Staff outlining the mechanism
on October 30, 2013. On January 8, 2014 the
Company filed a tariff to implement the low-income
energy efficiency program, which was approved with
an effective date of March 1, 2014.
Guideline 4: Plan Components
At a minimum, the plan must include
the following
elements:

4a An explanation of how the utility met This table summarizes guideline compliance by
Avista Utilities 2014 Natural Gas IRP Appendices 19
APPENDIX - CHAPTER 1

each of the substantive and
procedural requirements.
providing an overview of how Avista met each of the
substantive and procedural requirements for a natural
gas IRP.
4b Analysis of high and low load growth
scenarios in addition to stochastic
load risk analysis with an
explanation of major assumptions.
Avista developed five demand growth forecasts for
scenario analysis. Stochastic variability of demand
was also captured in the risk analysis. Chapter 1
describes the demand forecast data and Chapter 5
provides the scenario and risk analysis results.
Appendix 5 details major assumptions.
4c For electric utilities only Not Applicable
4d A determination of the peaking,
swing and base-load gas supply and
associated transportation and
storage expected for each year of
the plan, given existing resources;
and identification of gas supplies
(peak, swing and base-load),
transportation and storage needed
to bridge the gap between expected
loads and resources.
Figures 0.6 and 0.7summarize graphically projected
annual peak day demand and the existing and
selected resources by year to meet demand for the
expected case. Appendix 6.1 and 6.2 summarizes the
peak day demand for the other demand scenarios.
4e Identification and estimated costs of
all supply-side and demand-side
resource options, taking into
account anticipated advances in
technology
Chapter 3 and Appendix 3.1 identify the demand-side
potential included in this IRP. Chapter 4 and 5 and
Appendix 5.3 identify the supply-side resources.
4f Analysis of measures the utility
intends to take to provide reliable
service, including cost-risk tradeoffs.
Chapter 5, 6, and 7 discusses the modeling tools,
customer growth forecasting and cost-risk
considerations used to maintain and plan a reliable
gas delivery system. These Chapters also captures a
summary of the reliability analysis process
demonstrated at the second TAC meeting.
Chapter 4 discusses the diversified infrastructure and
multiple supply basin approach that acts to mitigate
certain reliability risks. Appendix 2.6 highlights key
risks associated with each portfolio.
4g Identification of key assumptions
about the future (e.g. fuel prices and
environmental compliance costs)
and alternative scenarios
considered.
Appendix 5 and Chapter 5 describe the key
assumptions and alternative scenarios used in this
IRP.
4h Construction of a representative set
of resource portfolios to test various
operating characteristics, resource
types, fuels and sources,
technologies, lead times, in-service
dates, durations and general
locations - system-wide or delivered
to a specific portion of the system.
This Plan documents the development and results for
portfolios evaluated in this IRP (see Table 4.3 for
supply scenarios considered).
4i Evaluation of the performance of the
candidate portfolios over the range
of identified risks and uncertainties.
We evaluated our candidate portfolio by performing
stochastic analysis using SENDOUT® varying price
under 200 different scenarios. Additionally, we test
the portfolio of options with the use of SENDOUT®
under deterministic scenarios where demand and
price vary. For resources selected, we assess other
risk factors such as varying lead times required and
potential for cost overruns outside of the amounts
Avista Utilities 2014 Natural Gas IRP Appendices 20
APPENDIX - CHAPTER 1

included in the modeling assumptions.
4j Results of testing and rank ordering
of the portfolios by cost and risk
metric, and interpretation of those
results.
Avista’s four distinct geographic Oregon service
territories limit many resource option synergies which
inherently reduces available portfolio options.
Feasibility uncertainty, lead time variability and
uncertain cost escalation around certain resource
options also reduce reasonably viable options.
Chapter 4 describes resource options reviewed
including discussion on uncertainties in lead times and
costs as well as viability and resource availability (e.g.
LNG). Appendix 5.3 summarizes the potential
resource options identifying investment and variable
costs, asset availability and lead time requirements
while results of resources selected are identified in
Table 5.5 as well as graphically presented in Figure
5.18 and 5.19 for the Expected Case and Appendix
6.1 for the High Growth case.
4k Analysis of the uncertainties
associated with each portfolio
evaluated
See the responses to 1.b above.
4l Selection of a portfolio that
represents the best combination of
cost and risk for the utility and its
customers
Avista evaluated cost/risk tradeoffs for each of the risk
analysis portfolios considered. Chapter 5 and
Appendix 2.6 show the company’s portfolio risk
analysis, as well as the process and determination of
the preferred portfolio.
4m Identification and explanation of any
inconsistencies of the selected
portfolio with any state and federal
energy policies that may affect a
utility's plan and any barriers to
implementation
This IRP is presumed to have no inconsistencies.
4n An action plan with resource
activities the utility intends to
undertake over the next two to four
years to acquire the identified
resources, regardless of whether
the activity was acknowledged in a
previous IRP, with the key attributes
of each resource specified as in
portfolio testing.
Chapter 8 presents the IRP Action Plan with focus on
the following areas:
 Modeling
 Supply/capacity
 Forecasting
 Regulatory communication
 DSM
Guideline 5: Transmission
5 Portfolio analysis should include
costs to the utility for the fuel
transportation and electric
transmission required for each
resource being considered. In
addition, utilities should consider
fuel transportation and electric
transmission facilities as resource
options, taking into account their
value for making additional
purchases and sales, accessing
less costly resources in remote
locations, acquiring alternative fuel
supplies, and improving reliability.
Not applicable to Avista’s gas utility operations.
Avista Utilities 2014 Natural Gas IRP Appendices 21
APPENDIX - CHAPTER 1

Guideline 6: Conservation
6a Each utility should ensure that a
conservation potential study is
conducted periodically for its entire
service territory.
EnerNOC performed a conservation potential
assessment study for our 2014 IRP. A discussion of
the study is included in Chapter 3. The full study
document is in Appendix 3.1. Avista incorporates a
comprehensive assessment of the potential for utility
acquisition of energy-efficiency resources into the
regularly-scheduled Integrated Resource Planning
process.
6b To the extent that a utility controls
the level of funding for conservation
programs in its service territory, the
utility should include in its action
plan all best cost/risk portfolio
conservation resources for meeting
projected resource needs,
specifying annual savings targets.
A discussion on the treatment of conservation
programs is included in Chapter 3 while selection
methodology is documented in Chapter 5. The action
plan details conservation targets, if any, as developed
through the operational business planning process.
These targets are updated annually, with the most
current avoided costs. Given the challenge of the low
cost environment, current operational planning and
program evaluation is still underway and targets for
Oregon have not yet been set.
6c To the extent that an outside party
administers conservation programs
in a utility's service territory at a
level of funding that is beyond the
utility's control, the utility should: 1)
determine the amount of
conservation resources in the best
cost/ risk portfolio without regard to
any limits on funding of conservation
programs; and 2) identify the
preferred portfolio and action plan
consistent with the outside party's
projection of conservation
acquisition.
Not applicable. See the response for 5.b above.
Guideline 7: Demand Response
7 Plans should evaluate demand response resources,
including voluntary rate programs, on par with other
options for meeting energy, capacity, and transmission
needs (for electric utilities) or gas supply and
transportation needs (for natural gas utilities).
Avista has periodically evaluated
conceptual approaches to
meeting capacity constraints
using demand-response and
similar voluntary programs.
Technology, customer
characteristics and cost issues
are hurdles for developing
effective programs. See Chapter
3 Demand Response section for
more discussion.
Guideline 8: Environmental Costs
8 Utilities should include, in their base-case analyses, the
regulatory compliance costs they expect for CO2, NOx,
SO2, and Hg emissions. Utilities should analyze the
range of potential CO2 regulatory costs in Order No. 93-
695, from $0 - $40 (1990$). In addition, utilities should
perform sensitivity analysis on a range of reasonably
possible cost adders for NOx, SO2, and Hg, if applicable.
Avista’s current direct gas
distribution system infrastructure
does not result in any CO2, NOx,
SO2, or Hg emissions. Upstream
gas system infrastructure
(pipelines, storage facilities, and
gathering systems) do produce
CO2 emissions via compressors
used to pressurize and move gas
Avista Utilities 2014 Natural Gas IRP Appendices 22
APPENDIX - CHAPTER 1

throughout the system. The
Environmental Externalities
discussion in Appendix 3.2
describes our analysis
performed. See also the
guidelines addendum reflecting
revised guidance for
environmental costs per Order
08-339.

Guideline 9: Direct Access Loads
9 An electric utility's load-resource balance should exclude
customer loads that are effectively committed to service
by an alternative electricity supplier.
Not applicable to Avista’s gas
utility operations.
Guideline 10: Multi-state utilities
10 Multi-state utilities should plan their generation and
transmission systems, or gas supply and delivery, on an
integrated-system basis that achieves a best cost/risk
portfolio for all their retail customers.
The 2014 IRP conforms to the
multi-state planning approach.
Guideline 11: Reliability
11 Electric utilities should analyze reliability within the risk
modeling of the actual portfolios being considered. Loss
of load probability, expected planning reserve margin,
and expected and worst-case unserved energy should
be determined by year for top-performing portfolios.
Natural gas utilities should analyze, on an integrated
basis, gas supply, transportation, and storage, along with
demand-side resources, to reliably meet peak, swing,
and base-load system requirements. Electric and natural
gas utility plans should demonstrate that the utility’s
chosen portfolio achieves its stated reliability, cost and
risk objectives.
Avista’s storage and transport
resources while planned around
meeting a peak day planning
standard, also provides
opportunities to capture off
season pricing while providing
system flexibility to meet swing
and base-load requirements.
Diversity in our transport options
enables at least dual fuel source
options in event of a transport
disruption. For areas with only
one fuel source option the cost of
duplicative infrastructure is not
feasible relative to the risk of
generally high reliability
infrastructure.

Guideline 12: Distributed Generation
12 Electric utilities should evaluate distributed
generation technologies on par with other supply-side
resources and should consider, and quantify where
possible, the additional benefits of distributed generation.
Not applicable to Avista’s gas
utility operations.
Guideline 13: Resource Acquisition
13a An electric utility should: identify its proposed acquisition
strategy for each resource in its action plan; Assess the
advantages and disadvantages of owning a resource
instead of purchasing power from another party; identify
any Benchmark Resources it plans to consider in competitive bidding.
Not applicable to Avista’s gas
utility operations.
Avista Utilities 2014 Natural Gas IRP Appendices 23
APPENDIX - CHAPTER 1

13b Natural gas utilities should either describe in the IRP
their bidding practices for gas supply and transportation,
or provide a description of those practices following IRP
acknowledgment.
A discussion of Avista’s
procurement practices is detailed
in Chapter 4.
Guideline 8: Environmental Costs
a. BASE CASE AND OTHER COMPLIANCE SCENARIOS:
The utility should construct a base-case scenario to
reflect what it considers to be the most likely regulatory
compliance future for carbon dioxide (CO2), nitrogen
oxides, sulfur oxides, and mercury emissions. The utility
also should develop several compliance scenarios
ranging from the present CO2 regulatory level to the
upper reaches of credible proposals by governing
entities. Each compliance scenario should include a time
profile of CO2 compliance requirements. The utility
should identify whether the basis of those requirements,
or “costs”, would be CO2 taxes, a ban on certain types of
resources, or CO2 caps (with or without flexibility
mechanisms such as allowance or credit trading or a
safety valve). The analysis should recognize significant
and important upstream emissions that would likely have
a significant impact on its resource decisions. Each
compliance scenario should maintain logical consistency,
to the extent practicable, between the CO2 regulatory
requirements and other key inputs.
Avista’s current direct gas
distribution system infrastructure
does not result in any CO2, NOx,
SO2, or Hg emissions. Upstream
gas system infrastructure
(pipelines, storage facilities, and
gathering systems) do produce
CO2 emissions via compressors
used to pressurize and move gas
throughout the system.

The Environmental Externalities
discussion in Appendix 3.2
describes our process for
addressing these costs.

b. TESTING ALTERNATIVE PORTFOLIOS AGAINST THE
COMPLIANCE SCENARIOS: The utility should
estimate, under each of the compliance scenarios, the
present value of revenue requirement (PVRR) costs and
risk measures, over at least 20 years, for a set of
reasonable alternative portfolios from which the preferred
portfolio is selected. The utility should incorporate end-
effect considerations in the analyses to allow for
comparisons of portfolios containing resources with
economic or physical lives that extend beyond the
planning period. The utility should also modify projected
lifetimes as necessary to be consistent with the
compliance scenario under analysis. In addition, the
utility should include, if material, sensitivity analyses on a
range of reasonably possible regulatory futures for
nitrogen oxides, sulfur oxides, and mercury to further
inform the preferred portfolio selection.
The Environmental Externalities
discussion in Appendix 3.2
describes our process for
addressing these costs.

Avista Utilities 2014 Natural Gas IRP Appendices 24
APPENDIX - CHAPTER 2

APPENDIX 2.1: ECONOMIC OUTLOOK AND CUSTOMER COUNT FORECAST
I. Service Area Economic Performance and Outlook
Avista’s core service area for natural gas includes Eastern Washington, Northern Idaho, and
Southwest Oregon. Smaller service islands are also located in rural South-Central Washington
and Northeast Oregon. Our service area is dominated by four metropolitan statistical areas
(MSAs): the Spokane-Spokane Valley, WA MSA (Spokane-Stevens counties); the Coeur d’Alene,
ID MSA (Kootenai County); the Lewiston-Clarkson ID-WA, MSA (Nez Perce-Asotin counties); and
the Medford, OR MSA (Jackson County). These four MSAs represent the primary demand for
Avista’s natural gas and account for 75% of both customers (i.e., meters) and load. The
remaining 25% of customers and load are spread over low density rural areas in all three states.

Figure 1: Employment Recovery since the End of the Great Recession, 2009-2013

Data source: Employment from the BLS; population from the U.S. Census.

-7%
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-5%
-4%
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.
Non-Farm Employment Growth (Dashed Shaded Box = Recession Period)
Avista MSAs U.S.
1.7%
1.3%
1.0%
0.8%
0.5%0.6%
0.9%
0.0%
0.2%
0.4%
0.6%
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2007 2008 2009 2010 2011 2012 2013
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t
h
Population Growth in Avista MSAs
Avista Utilities 2014 Natural Gas IRP Appendices 25
APPENDIX - CHAPTER 2

Compared to the U.S. as a whole, our service area has been slow to recover from the Great
Recession. Although the U.S. recession officially ended in June 2009 (dated by the National
Bureau of Economic Research), our service area did not start a significant employment recovery
until the second half of 2012 (Figure 1, top graph). As a result, service area population growth,
which is significantly influenced by in-migration through employment opportunities, remains
much lower than pre-recession levels (Figure 1, bottom graph) and has recovered at a much
slower rate than anticipated in the 2012 IRP (Figure 2). In 2011, Avista’s MSA population
growth fell to around 0.5%, the lowest since the late 1980s. Since population growth is a long-
run proxy for residential and commercial customer growth, this IRP shows a significant
downward revision in total forecasted customers in WA-ID and OR compared to the 2012 IRP
(Figure 3). Industrial customer growth, which is not significantly correlated with population
growth, has been close to zero since the end of Great Recession. Over the same time period,
our rural service areas have seen very little growth in total customers.

Figure 2: Comparison of Average Annual Population Growth from 2011 to 2012

Data source: Actual population growth calculated U.S. Census data.

In large part, the downward revision in this IRP reflects an assumed lower long-run GDP growth in the U.S., which
filters down to our service area as lower employment growth relative to the U.S. In turn, this translates into lower
population growth due to slower in-migration. The current assumption for long-run GDP growth is 2.5%,
significantly lower than the to 3% assumption in the 2012 IRP. Based on demographic and productivity trends, the
2.5% growth assumption is consistent with a growing consensus that long-run GDP growth with be in the 2.2-2.7%
range. For example, the Energy Information Administration’s (EIA) 2014 Annual Energy Outlook forecast assumes
a 2.4% annual average growth rate out to 2040. Finally, since GDP is both a measure of output and income, the
lower GDP growth assumption also implies slower industrial production growth and household income growth
compared to the 2012 IRP.
1.6%
2.5%
1.9%
0.4%
1.0%
0.8%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
Spokane, WA Coeur d'Alene, ID Medford, OR
Av
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a
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G
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2012 IRP Base Case Forecast Actual
Avista Utilities 2014 Natural Gas IRP Appendices 26
APPENDIX - CHAPTER 2

Figure 3: Comparison of Forecasted Customer Growth WA-ID and OR, 2014-2040

II. Forecast Process and Methodology
Figure 4 summarizes the forecast process for natural gas. In non-IRP periods, the forecast from Financial Planning
and Analysis (FPA) is generated by schedule for each class (residential, commercial, and industrial) out five years.
For schedules with the most load and customers, forecasts are generated from regression models that are either
pure ARIMA models or ARIMA transfer function models. Pure ARIMA models use only past values of therm use per
customer (UPC) or customers to forecast future UPC or customers. ARIMA transfer function models are based on
weather, non-weather seasonal factors, long-run time trends, economic drivers, and ARIMA error correction
terms. These are standard time-series models that are estimated using SAS/ETS software.
The FPA customer forecasts are used as input into Sendout® to generate the IRP load forecasts for gas purchase
decisions. Sendout® forecasts are compared against FRP forecasts to ensure that there are no significant
deviations between the two forecasts. Over five year forecast horizon, the deviations are not typically material on
an aggregate annual basis.

150,000
175,000
200,000
225,000
250,000
275,000
300,000
325,000
350,000
20
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r
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WA-ID Region
(Annual Growth: 2014 IRP Base Case = 1.0%, 2012 IRP Base Case = 1.6%)
WA-ID 2014 IRP Base Case Forecast WA-ID 2012 IRP Base Case Forecast
60,000
70,000
80,000
90,000
100,000
110,000
120,000
130,000
140,000
150,000
20
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OR Region
(Annual Growth: 2014 IRP Base Case = 0.9%, 2012 IRP Base Case = 1.7%)
OR 2014 IRP Base Case Forecast OR 2012 IRP Base Forecast
Avista Utilities 2014 Natural Gas IRP Appendices 27
APPENDIX - CHAPTER 2

Figure 4: Avista’s Forecast Process for Natural Gas

Financial Planning and Analysis (FPA) Gas Forecast

Accounting revenue reports for ID, WA, and OR customer
count and load data.
Forecast Drivers: HDD, GDP, IP, non-farm employment,
and population.
Update spreadsheet with new data each month.
Gas forecast is done twice a year, in June and December. During IRP years, one of these forecasts will be extended to
produce the long-run customer projections. The FPA forecast is largely based on an ARIMA based approach with historical
billed load data.
Generate a monthly forecast of customers and load by rate schedule. The forecast is 5-years out non-IRP years and 20-
years out in IRP years. All forecasts assume average weather using a 20-yer moving average of HDD.
FPA customer forecasts sent to Gas Supply. Customer forecasts are used in Sendout® to (1) generate an aggregate load
forecast for firm customers and (2) verify that it lines up with the annual aggregated load forecast from FPA. This process
is a cross verification of both forecasts and ensures there are no material differences between the forecasts used for
financial forecasting and gas purchase decisions. A 20-year moving average also applied in the Sendout®. forecast.
Sendout® and FPA forecasts are sent to Resource Accounting. The FPA firm load forecast is converted into load shares by
schedule, and these shares are applied to the Sendout® forecast to generate the load forecast by firm class and schedule.
The forecast is allocated from the Sendout® total to capture the unbilled portion that is not present in the billed data used
by FPA. The forecasted loads are converted to revenues that reflect both billed and unbilled dollars. Forecasts for
transportation and interruptible schedules come directly from the FPA forecast, and not Sendout®.

The final revenue forecast from Resource Accounting is sent back to FPA for use in the company’s earnings model.
Avista Utilities 2014 Natural Gas IRP Appendices 28
APPENDIX - CHAPTER 2

Economic Drivers in Five Year Customer Forecasts
Population growth is the key driver for the residential customer forecast. Because of the high historic correlation
between residential and customer forecasts, population is also an indirect driver in forecast for commercial
customers. As will be discussed below, the implicit assumption is that commercial customer growth tends to
follow along with residential growth.
Population growth forecast is one of the key drivers behind the customer forecast for residential schedules 101 in
WA-ID and 410 in OR. These two schedules represent the majority of customers and, therefore, drive overall
residential customer growth. Because of their size and growth potential, a multi-step forecasting process has
been developed for the Spokane-Spokane Valley-Coeur d’Alene combined MSAs and the Medford MSA. Figure 5
describes the forecasting process for population growth for these MSAs.

Figure 5: Forecasting Population Growth

The forecasting models for regional employment growth are:

[1]

[2]

SPK+KOOT is for the combined area of Spokane, WA (Spokane MSA) and Kootenai, ID (Coeur d’Alene MSA), and
JACK is for Jackson County, OR (Medford MSA). GEMPy is employment growth in year y, GGDPy,US is U.S. real GDP
growth in year y. DKC is a dummy variable for the collapse of Kaiser Aluminum in Spokane, and DHB is a dummy for
the housing bubble, specific to each region. The average GDP forecasts are used in the estimated model to
generate five-year employment growth forecasts. Averaging the GDP forecasts reduces the systematic errors of a
single-source forecast. Discussed below, employment growth forecasts are then used to generate population
growth forecasts.

The major MSA forecasting models for regional population growth are:

[3]

[4]

D2001=1 and D1991=1 are outlier dummy variables for recession impacts. GEMPy-1,US is U.S. employment growth in year
y-1 and GEMPy-1,CA is California Employment growth in year y-1. Because of its close proximity to CA, CA
employment growth is better predictor of Medford’s population growth than U.S. growth.

Average GDP Growth
Forecasts:
 IMF, FOMC,
Bloomberg, etc.
 Average forecasts
out 5-yrs.
Non-farm Employment
Growth Model:
 Model links year y, y-1,
and y-2 GDP growth to
year y regional
employment growth.
 Forecast out 5-yrs.
Regional Population Growth Models:
 Model links regional, U.S., and CA
employment growth to regional
population growth.
 Forecast out 5-yrs for Spokane, WA;
Kootenai, ID; and Jackson, OR.
 Averaged with GI forecasts.
 Compare population forecasts to
base customer forecasts for
residential schedules 101 (WA) and
410 (OR).
 Adjust base forecasts if large
differences with base and
population forecasts exist.
EMP GDP
Avista Utilities 2014 Natural Gas IRP Appendices 29
APPENDIX - CHAPTER 2

Forecasts generated from [3] and [4] are combined with GI’s population (GIPOP) forecasts for the same areas in
the form of a simple average. As with the GDP forecasts, averaging with GI’s population forecast reduces the
systematic errors of a single-source forecast. In the case of Spokane-Kootenai, the forecasted growth rate is
broken apart by to generate an individual rate for each MSA:

[5]

[6]

Forecasts [5] and [6] are applied to base-line residential schedule 101 (WA-ID) and 410 (OR) customer forecasts
generated by ARIMA models. If the base-line forecast appears are in line with the population growth forecasts
from [5] and [6], then no direct adjustment is made to the base-line ARIMA forecasts. However, if the base-line
ARIMA forecasts appear to be too low or too high relative to the population forecast, [5] and [6] are applied to
adjust the base-line forecasts so that the final annual growth rate of forecasted customers matches the forecasted
population growth rate, FAvg(GPOPy) for each major MSA.
For La Grande, OR (Union County); Klamath Falls, OR (Klamath County); and Roseburg, OR (Douglas County), GI’s
forecasts are used in lieu of in-house forecasts. Because of their small size, the WA service areas around
Stevenson, WA (Skamania County) and Goldendale, WA (Klickitat County) are not broken out for forecasting
purposes. The Lewiston-Clarkston area is aggregated into the Spokane and Kootenai customer count used for
forecasting; therefore, it is not considered separately. Given its close proximity to the Medford area, this is also
the case for Grants Pass, OR (Josephine County).

The residential customer forecasts, generated from the process described above, are then used as a driver in the
forecasts for commercial schedule 101 (WA-ID) and schedule 420 (OR). The exception is Roseburg, OR, where
there is little correlation between residential and commercial customer growth. As with residential schedules 101
and 410, commercial schedules 101 (WA) and 420 (OR) are the main drivers of overall commercial customer
growth. This is a three step process. First, historical residential customers are used as an explanatory variable in
an ARIMA model for forecasting commercial customers. Second, commercial ARIMA models for WA, ID, and OR
are estimated from historical commercial and residential customer data. Third, five year commercial forecasts for
schedules 101 or 420 are generated using the 101 or 410 residential customer forecasts in the commercial ARIMA
models estimated with historical data. This method assumes this historical high correlation between residential
and commercial customer growth continues in the future.

Long-Run IRP Forecasts after the Five Year Forecast Horizon
Forecasts for IRP years are extend out from the five year forecasts by first assuming long-run values as inputs into
[1] and [2]. As discussed above, the current assumption is a long-run GDP growth rate of 2.5%. This assumption
generates long-run growth rate for employment growth, which is used in [3] and [4]. Finally, GI’s long-range
forecasts are combined with [3] and [4] to produce a base-line residential growth rate for the largest MSAs. As
with the 5-year out forecast, the smaller service areas in OR rely on GI’s forecasts as a proxy for residential
customer growth, which currently extend to the early 2040s.
With the exception of Roseburg, OR, commercial customer growth is assumed to be equal to residential customer
growth. This assumption is based on long-run relationship between residential and commercial customer growth
after 2018. Figure 6 shows system wide same month, year-over-year residential and commercial customer growth
(top graph) and industrial customer growth (bottom graph) for the 2007-2013 period.

Figure 6: Year-over-Year Customer Growth for the Three Rate Classes, 2007-2013
Avista Utilities 2014 Natural Gas IRP Appendices 30
APPENDIX - CHAPTER 2

Figure 6 demonstrates that residential and commercial growth rates are highly correlated and maintain similar
levels over the long-run—both classes’ growth rates averaged about 1% over this period. This growth is slightly
higher than population growth because of the housing boom and existing households retrofitting with natural gas.
However, by the end of 2009, with the collapse of the housing bubble and increased natural gas saturation,
customer growth moved in line with population growth. For Roseburg, OR, it is assumed commercial customer
growth will continue at an annual rate 0.02% after 2018, which reflects average commercial growth since 2008.
In contrast, the behavior of Industrial customer growth looks quite different. Customer growth is both lower and
more volatile. The average growth rate over this period is -0.4%, reflecting a trend of nearly flat or slowly declining
customers, depending on the service area region. In addition, the standard deviation of growth is 3.7% compared
to 0.6% for both residential and commercial growth—over five times higher. The current IRP forecast reflects this
historical trend of weak growth. Some energy industry analysts believe the U.S.’s increased supply of natural gas
and oil will attract industrial production back from overseas locations. However, in this IRP, we do not assume
plentiful energy supplies in the U.S. will alter long-run trends in industrial customer growth in our service area.

Establishing High-Low Cases for IRP Customer Forecast
The customer forecasts for this IRP include high and low cases that set the expected bounds around the base-case.
In the WA-ID area, the high and low cases were set by altering base case assumptions about U.S. and regional
employment growth in equation [3] for the Spokane-Coeur d’Alene region. In particular, the high-case reflects
more optimistic assumptions about long-run growth and the low case reflects more pessimistic assumptions. The
WA-ID high case effectively assumes long-run employment growth of over 2.0% (compared to a base-case of
around 1.7%), while the low-case assumes growth under 0.5%.
In the OR area, a similar approach was used for the Medford area using equation [4]. The Medford area high case
also assumes long-run employment growth of over 2.0% (compared to a base-case of around 1.5%), while the low-
case assumes growth under 0.5%. The range for employment growth was obtained by looking at different
scenarios of U.S. GDP growth, as was well as the historical distribution of employment growth rates since the early
1990s for our service area, U.S., and California. The areas of Klamath Falls, Roseburg, and La Grande were
-0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
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Residential (blue Line) and Commerical (red line)
-10%
-5%
0%
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10%
15%
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Industrial
Avista Utilities 2014 Natural Gas IRP Appendices 31
APPENDIX - CHAPTER 2

considered separately by looking the historical distributions population growth rates since the 1980s. Since the
early 1980s, annual population growth as averaged less than 1% in these three areas.

Table F.1

Avista Utilities 2014 Natural Gas IRP Appendices 32
APPENDIX - CHAPTER 2

Table F.2

Avista Utilities 2014 Natural Gas IRP Appendices 33
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Avista Utilities 2014 Natural Gas IRP Appendices 34
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Avista Utilities 2014 Natural Gas IRP Appendices 35
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Avista Utilities 2014 Natural Gas IRP Appendices 36
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Avista Utilities 2014 Natural Gas IRP Appendices 37
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Avista Utilities 2014 Natural Gas IRP Appendices 38
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Avista Utilities 2014 Natural Gas IRP Appendices 39
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Avista Utilities 2014 Natural Gas IRP Appendices 40
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Avista Utilities 2014 Natural Gas IRP Appendices 41
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Avista Utilities 2014 Natural Gas IRP Appendices 42
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Avista Utilities 2014 Natural Gas IRP Appendices 43
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Avista Utilities 2014 Natural Gas IRP Appendices 44
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Avista Utilities 2014 Natural Gas IRP Appendices 45
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Avista Utilities 2014 Natural Gas IRP Appendices 46
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Avista Utilities 2014 Natural Gas IRP Appendices 47
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Avista Utilities 2014 Natural Gas IRP Appendices 48
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Avista Utilities 2014 Natural Gas IRP Appendices 49
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Avista Utilities 2014 Natural Gas IRP Appendices 50
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Avista Utilities 2014 Natural Gas IRP Appendices 51
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Avista Utilities 2014 Natural Gas IRP Appendices 52
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Avista Utilities 2014 Natural Gas IRP Appendices 53
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Avista Utilities 2014 Natural Gas IRP Appendices 54
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Avista Utilities 2014 Natural Gas IRP Appendices 55
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Avista Utilities 2014 Natural Gas IRP Appendices 56
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Avista Utilities 2014 Natural Gas IRP Appendices 57
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Avista Utilities 2014 Natural Gas IRP Appendices 58
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Avista Utilities 2014 Natural Gas IRP Appendices 59
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Avista Utilities 2014 Natural Gas IRP Appendices 60
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Avista Utilities 2014 Natural Gas IRP Appendices 61
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Avista Utilities 2014 Natural Gas IRP Appendices 62
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Avista Utilities 2014 Natural Gas IRP Appendices 63
APPENDIX - CHAPTER 2

APPENDIX 2.3: DEMAND COEFFICIENTS

Avista Utilities 2014 Natural Gas IRP Appendices 64
APPENDIX - CHAPTER 2

APPENDIX 2.3: WA/ID BASE COEFFICIENT CALCULATION

Avista Utilities 2014 Natural Gas IRP Appendices 65
APPENDIX - CHAPTER 2

APPENDIX 2.3: MEDFORD BASE COEFFICIENT CALCULATION

Avista Utilities 2014 Natural Gas IRP Appendices 66
APPENDIX - CHAPTER 2

APPENDIX 2.3: ROSEBURG BASE COEFFICIENT CALCULATION

Avista Utilities 2014 Natural Gas IRP Appendices 67
APPENDIX - CHAPTER 2

APPENDIX 2.3: KLAMATH FALLS BASE COEFFICIENT CALCULATION

Avista Utilities 2014 Natural Gas IRP Appendices 68
APPENDIX - CHAPTER 2

APPENDIX 2.3: LA GRANDE BASE COEFFICIENT CALCULATION

Avista Utilities 2014 Natural Gas IRP Appendices 69
APPENDIX - CHAPTER 2

APPENDIX 2.4: HEATING DEGREE DAY DATA MONTHLY TABLES

Avista Utilities 2014 Natural Gas IRP Appendices 70
APPENDIX - CHAPTER 2

APPENDIX 2.4: HEATING DEGREE DAY DATA MONTHLY TABLES

Avista Utilities 2014 Natural Gas IRP Appendices 71
APPENDIX - CHAPTER 2

APPENDIX 2.4: HEATING DEGREE DAILY MONTH BY AREA

Avista Utilities 2014 Natural Gas IRP Appendices 72
APPENDIX - CHAPTER 2

APPENDIX 2.4: HEATING DEGREE DAILY MONTH BY AREA

Avista Utilities 2014 Natural Gas IRP Appendices 73
APPENDIX - CHAPTER 2

APPENDIX 2.4: HEATING DEGREE DAILY MONTH BY AREA

Avista Utilities 2014 Natural Gas IRP Appendices 74
APPENDIX - CHAPTER 2

APPENDIX 2.5: DEMAND SENSITIVITIES
SUMMARY OF ASSUMPTIONS – DEMAND SCENARIOS

Avista Utilities 2014 Natural Gas IRP Appendices 75
APPENDIX - CHAPTER 2

APPENDIX 2.5: DEMAND SCENARIOS
PROPOSED SCENARIOS

Avista Utilities 2014 Natural Gas IRP Appendices 76
APPENDIX - CHAPTER 2

APPENDIX 2.6: DEMAND FORECAST SENSITIVITIES AND SCENARIOS
DESCRIPTIONS
DEFINITIONS
DYNAMIC DEMAND METHODOLOGY – Avista’s demand forecasting approach wherein we 1) identify key
demand drivers behind natural gas consumption, 2) perform sensitivity analysis on each demand driver,
and 3) combine demand drivers under various scenarios to develop alternative potential outcomes for
forecasted demand.
DEMAND INFLUENCING FACTORS – Factors that directly influence the volume of natural gas consumed by our
core customers.
PRICE INFLUENCING FACTORS – Factors that, through price elasticity response, indirectly influence the volume
of natural gas consumed by our core customers.
REFERENCE CASE – A baseline point of reference that captures the basic inputs for determining a demand
forecast in SENDOUT® which includes number of customers, use per customer, average daily weather
temperatures (including an adjustment for global warming) and expected natural gas prices.
SENSITIVITIES – Focused analysis of a specific natural gas demand driver and its impact on forecasted
demand relative to the Reference Case when underlying input assumptions are modified.
SCENARIOS – Combination of natural gas demand drivers that make up a demand forecast.
Avista evaluates each sensitivities impact.
SENSITIVITIES
The following Sensitivities were performed on identified demand drivers against the reference case for
consideration in Scenario development. Note that Sensitivity assumptions reflect incremental adjustments
we estimate are not captured in the underlying reference case forecast.
Following are the Demand Influencing (Direct) Sensitivities we evaluated:
REFERENCE CASE PLUS PEAK – Same assumptions as in the Reference Case with and adjustment made to
normal weather to incorporate peak weather conditions. The peak weather data being the coldest day on
record for each weather area.
LOW & HIGH CUSTOMER GROWTH – In our low customer growth Sensitivity, annual customer growth rates
under perform the reference rate of growth by 40% over our 20 year planning horizon while annual
customer growth rates exceed the reference rate by 60% in our high growth Sensitivity.
NATURAL GAS VEHICLES (NGV) AND/OR COMPRESSED NATURAL GAS (CNG) VEHICLES – NGV/CNG vehicles
assumed to produce a 15% cumulative incremental demand over our 20 year planning horizon. Our
assumption utilized market consumption estimates from an independent analysis on NGV/CNG vehicle
viability. The analysis indicates significant challenges exist to widespread adoption but did provide a
scenario for significant market penetration (10% in 10 years).
Avista Utilities 2014 Natural Gas IRP Appendices 77
APPENDIX - CHAPTER 2

ALTERNATE WEATHER STANDARD (COLDEST DAY 20 YRS) – Peak Day weather temperature reduced to coldest
average daily temperature (HDDs) experienced in the most recent 20 years in each region.
DSM – Reference case assumptions including the potential DSM identified by the Conservation Potential
Assessment provided by Global Energy Partners. See Appendix 4.1 for full assessment report.
PEAK PLUS DSM – Reference plus peak weather assumptions including the potential DSM identified by the
Conservation Potential Assessment provided by Global Energy Partners. See Appendix 4.1 for the full
assessment report.
ALTERNATE USE PER CUSTOMER – Reference case use per customer was based upon 3 years of actual use per
customer per heating degree day data. This sensitivity used five years of historical use per customer per
heating degree day data.
Following are the Price Influencing (Indirect) Sensitivities we evaluated:
EXPECTED ELASTICITY – For our expected elasticity Sensitivity, we incorporate reduced consumption in
response to higher natural gas prices utilizing a price elasticity study prepared by the American Gas
Association.
LOW & HIGH PRICES – To capture a wide band of alternative prices forecasts, we use the Northwest Power
and Conservation Council’s “very low” and “very high” natural gas price forecast scenarios with first five
years modified to include blend of recent market prices (Nymex forward prices) consistent with our
Expected price forecast.
CARBON LEGISLATION LOW CASE – Utilizes carbon cost adders quantified by independent analysis from
Consultant #1. They identify both an adder reflecting carbon allowances as well as an adder to capture
the effect of increased natural gas demand as more gas turbines come online to replace coal plants and
back up wind generation. The allowance adder escalates from $14/ton in 2022 to $22/ton by 2033.
CARBON LEGISLATION MEDIUM CASE –Utilizes carbon cost adders quantified by independent analysis from
Consultant #1. They identify both an adder reflecting carbon allowances as well as an adder to capture
the effect of increased natural gas demand as more gas turbines come online to replace coal plants and
back up wind generation. The allowance adder escalates from $8.32/ton in 2021 to $14.83/ton by 2033.
This is the expected carbon adder utilized in our carbon case sensitivities.
CARBON LEGISLATION HIGH CASE – Utilizes carbon cost adders quantified by independent analysis from
Consultant #1. They identify both an adder reflecting carbon allowances as well as an adder to capture
the effect of increased natural gas demand as more gas turbines come online to replace coal plants and
back up wind generation. The allowance adder escalates from $16/ton in 2021 to $28/ton by 2033.
EXPORTED LNG – Beginning in 2017, we apply an estimate of $.50/mmbtu incremental adder each year to
regional natural gas prices to capture upward price pressure because of exports of LNG to Asian and
European counties. There is much uncertainty about the region price impact LNG will have. It is highly
dependent on many things including which export facilities get built and the pipeline infrastructure used
to serve them. There are several analyses that have been conducted where the price impact can be
minimal to $1.00/mmbtu.
Avista Utilities 2014 Natural Gas IRP Appendices 78
APPENDIX - CHAPTER 2

SCENARIOS
After identifying the above demand drivers and analyzing the various Sensitivities, we have developed
the following demand forecast Scenarios:
AVERAGE CASE – This Scenario we believe represents the most likely average demand forecast modeled.
We assume service territory customer growth rates consistent with the reference case, rolling 30 year
normal weather in each service territory, our expected natural gas price forecast (Consultant #1), expected
price elasticity, and the CO2 cost adders from our Carbon Legislation Medium Case Sensitivity, and
DSM. The Scenario does not include incremental cost adders for declining Canadian imports or drilling
restrictions beyond what is incorporated in the selected price forecast.
EXPECTED CASE – This Scenario represents the peak demand forecast. We assume service territory customer
growth rates consistent with the reference case, a weather standard of coldest day on record in each
service territory, our middle range natural gas price forecast (Consultant #1), expected price elasticity,
and the CO2 cost adders from our Carbon Legislation Medium Case Sensitivity, and DSM.
HIGH GROWTH, LOW PRICE – This Scenario models a rapid return to robust growth in part spurred on by low
energy prices. We assume customer growth rates 60% higher than the reference case, coldest day on
record weather standard, incremental demand from NGV/CNG, our low natural gas price forecast, no
price elasticity, DSM, and no CO2 adders.
LOW GROWTH, HIGH PRICE – This Scenario models an extended period of slow economic growth in part
resulting from high energy prices. We assume customer growth rates 40% lower than the reference case,
coldest day on record weather standard, our high natural gas price forecast, expected price elasticity, and
CO2 adders from our Carbon Legislation Medium Case Sensitivity.
ALTERNATE WEATHER STANDARD – This Scenario models all the same assumptions as the Expected Case
Scenario except for the change in the weather planning standard from coldest day on record to coldest day
in 20 years for each service territory. As noted in the Sensitivity analysis, this change does not affect the
Klamath Falls and La Grande service territories which have each experienced their coldest day on record
within the last 20 years.
A case incorporating Exported LNG was not included in this IRP’s scenario analysis. There is much
uncertainty about the location and timing of exported LNG and its potential price impacts. The
forecasters we subscribe to have incorporated some level of export LNG into their price forecasts and
therefore our expected price curve does include an export LNG assumption. At this time the effects of
LNG are minimal given the robust North American supply picture. Avista will closely monitor
developments with export LNG for the potential price and infrastructure impacts.

Avista Utilities 2014 Natural Gas IRP Appendices 79
APPENDIX - CHAPTER 2

APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY
DEMAND (NET OF DSM – CASE AVERAGE

Avista Utilities 2014 Natural Gas IRP Appendices 80
APPENDIX - CHAPTER 2

APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY
DEMAND (NET OF DSM) – CASE HIGH

Avista Utilities 2014 Natural Gas IRP Appendices 81
APPENDIX - CHAPTER 2

APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY
DEMAND (NET OF DSM) – CASE LOW

Avista Utilities 2014 Natural Gas IRP Appendices 82
APPENDIX - CHAPTER 2

APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY
DEMAND (NET OF DSM) – CASE COLDEST IN 20

Avista Utilities 2014 Natural Gas IRP Appendices 83
APPENDIX - CHAPTER 2

APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
WA/ID

Avista Utilities 2014 Natural Gas IRP Appendices 84
APPENDIX - CHAPTER 2

APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
MEDFORD/ROSEBURG

Avista Utilities 2014 Natural Gas IRP Appendices 85
APPENDIX - CHAPTER 2

APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
KLAMATH FALLS

Avista Utilities 2014 Natural Gas IRP Appendices 86
APPENDIX - CHAPTER 2

APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
LA GRANDE

Avista Utilities 2014 Natural Gas IRP Appendices 87
APPENDIX - CHAPTER 2

APPENDIX 2.9: DETAILED DEMAND DATA
EXPECTED MIX

Avista Utilities 2014 Natural Gas IRP Appendices 88
APPENDIX - CHAPTER 2

APPENDIX 2.9: DETAILED DEMAND DATA
EXPECTED MIX

Avista Utilities 2014 Natural Gas IRP Appendices 89
APPENDIX - CHAPTER 2

APPENDIX 2.9: DETAILED DEMAND DATA
LOW GROWTH HIGH PRICE

Avista Utilities 2014 Natural Gas IRP Appendices 90
APPENDIX - CHAPTER 2

APPENDIX 2.9: DETAILED DEMAND DATA
LOW GROWTH HIGH PRICE

Avista Utilities 2014 Natural Gas IRP Appendices 91
APPENDIX - CHAPTER 2

APPENDIX 2.9: DETAILED DEMAND DATA
HIGH GROWTH LOW PRICE

Avista Utilities 2014 Natural Gas IRP Appendices 92
APPENDIX - CHAPTER 2

APPENDIX 2.9: DETAILED DEMAND DATA
HIGH GROWTH LOW PRICE

Avista Utilities 2014 Natural Gas IRP Appendices 93
APPENDIX - CHAPTER 2

APPENDIX 2.9: DETAILED DEMAND DATA
AVERAGE MIX

Avista Utilities 2014 Natural Gas IRP Appendices 94
APPENDIX - CHAPTER 2

APPENDIX 2.9: DETAILED DEMAND DATA
AVERAGE MIX

Avista Utilities 2014 Natural Gas IRP Appendices 95
APPENDIX - CHAPTER 2

APPENDIX 2.9: DETAILED DEMAND DATA
COLDEST IN 20 YEARS

Avista Utilities 2014 Natural Gas IRP Appendices 96
APPENDIX - CHAPTER 2

APPENDIX 2.9: DETAILED DEMAND DATA
COLDEST IN 20 YEARS

Avista Utilities 2014 Natural Gas IRP Appendices 97
APPENDIX - CHAPTER 2

Avista Utilities 2014 Natural Gas IRP Appendices 98
APPENDIX – CHAPTER 3
APPENDIX 3.1: AVISTA GAS CPA REPORT 4/23/2014

Avista Natural Gas Conservation Potential
Assessment Results
April 23, 2014

2
Topics
• Overview of analysis approach
• Market characterization
• Energy market profile
• Baseline projection
• Conservation potential

Avista Utilities 2014 Natural Gas IRP Appendices 99
APPENDIX – CHAPTER 3

3
Approach Update
Develop energy market
profiles and project the
baseline
Customer surveys (optional)
Secondary data
Forecast assumptions
Prototypes and
energy analysis
Characterize the market
Utility dataCustomer surveys (optional)
Secondary data
DSM measure list
Measure descriptionAvoided costs
Perform measure
screening
Apply customer
participation rates Recent program resultsBest-practices research
Base-year energy
use by fuel &
segment
Base-year
profiles and
baseline projection
by fuel, segment &
end use
Technical and
economic potential
Achievable potential
Input Data Analysis Steps Results

4
Approach
Market
Dimension Segmentation Variable Dimension Examples
1 State Washington, Idaho, and Oregon
2 Sector Residential, Commercial, and Industrial
3 Building type
Residential: Single family, Multi Family,and Mobile Home
Commercial: Small Commercial and Large Commercial
Industrial: All sectors combined
4 Vintage Existing and new construction
5 End uses Space heating, water heating, appliances, process, etc.
(as appropriate by sector)
6 Appliances/end uses and technologies Technologies such as furnaces, boilers, ovens, fryers, etc
7 Equipment efficiency levels for new purchases Baseline and higher-efficiency options as appropriate for each technology
Avista Utilities 2014 Natural Gas IRP Appendices 100
APPENDIX – CHAPTER 3
Market Characterization

6
Avista market characterization (All states, 2013)
Avista Total 2013 Sales
(1,000Thrm)# of Meters Average Use per
Meter (Thrm)
Residential 199,115 288,088 691
Small Commercial 51,825 30,410 1,704
Large Commercial 74,664 3,875 19,266
Industrial 5,015 255 19,649
Total 330,619 322,628 1,025
• Based on 2013 Avista gas sales data
• Excludes transport and Oregon 444
Residential60%
Small Commercial16%
Large Commercial23%
Industrial1%
Avista Natural Gas Use (2013)

Avista Utilities 2014 Natural Gas IRP Appendices 101
APPENDIX – CHAPTER 3

7
Avista market characterization (2013)
Washington Rate Class 2013 Sales (1,000Thrm)% of Sales # of Meters % of Meters Average Use/Meter (Thrm)
Residential 101 102,680 59%135,792 90%756
Small Commercial 101 17,267 10%11,971 8%1,442
Large Commercial 111,132 51,078 29%2,469 2%20,687
Industrial 101,111,112 2,384 1%134 0%17,756
Washington total 173,409 100%150,366 100%1,153
Idaho Rate Class 2013 Sales (1,000Thrm)% of Sales # of Meters % of Meters Average Use/Meter (Thrm)
Residential 101 46,336 61%67,415 89%687
Small Commercial 101 7,725 10%7,292 10%1,059
Large Commercial 111,132 19,968 26%1,335 2%14,961
Industrial 101,111,112 2,222 3%94 0%23,698
Idaho total 76,250 100%76,136 100%1,001
Oregon Rate Class 2013 Sales
(1,000Thrm)
% of
Sales
# of
Meters
% of
Meters
Average
Use/Meter (Thrm)
Residential 410 50,099 62%84,881 88%590
Small Commercial 420 26,833 33%11,146 12%2,407
Large Commercial 424 3,618 4%72 0%50,484
Industrial 420,424 410 1%27 0%15,044
Oregon total 80,960 100%96,126 100%842

Residential Sector

Avista Utilities 2014 Natural Gas IRP Appendices 102
APPENDIX – CHAPTER 3

9
Avista residential market characterization
(All states, 2013)
All States Residential 2013 Sales
(1,000 Therms)# of Meters Average Use per
Household (Therms/HH)
Single Family 165,435 224,253 738
Multi Family 16,935 35,706 474
Mobile Home 16,745 28,128 595
Total 199,115 288,088 691
Single Family78%
Multi Family12%
Mobile Home10%
Avista Residential Natural Gas Use (2013)

10
Avista residential market characterization (2013)
Washington 2013 Sales (1,000 Therms)% of Sales # of Meters % of Meters
Average
Use/Meter
(Therms)
Single Family 86,211 84%106,732 79%808
Multi Family 9,743 9%19,147 14%509
Mobile Home 6,726 7%9,913 7%678
Washington total 102,680 100%135,792 100%756
Idaho 2013 Sales (1,000 Therms)% of Sales # of Meters % of Meters
Average
Use/Meter
(Therms)
Single Family 38,758 84%52,719 78%735
Multi Family 4,496 10%9,708 14%463
Mobile Home 3,081 7%4,989 7%618
Idaho total 46,336 100%67,415 100%687
Oregon 2013 Sales
(1,000 Therms)% of Sales # of Meters % of Meters
Average
Use/Meter
(Therms)
Single Family 40,466 81%64,803 76%624
Multi Family 2,695 5%6,851 8%393
Mobile Home 6,938 14%13,227 16%525
Oregon total 50,099 100%84,881 100%590

Avista Utilities 2014 Natural Gas IRP Appendices 103
APPENDIX – CHAPTER 3

11
Avista residential market characterization (2013)
• Energy Market Profiles
•Characterize energy use by sector, segment, end use, and technology
•Existing, replacement, and new construction
• Accounts for
•Codes and standards
•Previous DSM results
•Equipment saturation and fuel shares
Space Heating
77%
Water Heating
20%
Appliances
1%Miscellaneous
2%

12
Energy market profile for Washington, single family
UEC Intensity Usage
(Therms) (Therms/HH) (MMThrm)
Space Heating Furnace 87.8% 623.3 547.1 58.4
Space Heating Boiler 3.6% 705.8 25.5 2.7
Space Heating Other Heating 8.6% 600.0 51.7 5.5
Water Heating Water Heater 60.8% 256.1 155.6 16.6
Appliances Clothes Dryer 8.3% 30.8 2.5 0.3
Appliances Stove/Oven 10.3% 57.4 5.9 0.6
Miscellaneous Pool Heater 1.1% 219.0 2.5 0.3
Miscellaneous Miscellaneous 100.0% 16.9 16.9 1.8
807.7 86.2
End Use Technology Saturation
Total
Space Heating
77%
Water
Heating
19%
Appliances
1%
Miscellaneous
3%
Energy Usage, Washington Single Family

Avista Utilities 2014 Natural Gas IRP Appendices 104
APPENDIX – CHAPTER 3

13
Assumptions in the residential baseline projection
• Projection of growth without conservation programs
• Incorporates
•Customer growth, about 1.5% per year
•Differences in new homes (i.e., larger than average dwellings)
•Per capita income growth, about 2.1% per year
•Retail price forecast
•Trends in end-use/technology saturations
•Equipment purchase decisions
•Building codes and appliance standards Today's Efficiency or Standard Assumption
Next Standard (relative to today's standard)
End Use Technology 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Furnace
Boiler
Water Heater (<=55 gallons)
Water Heater (>55 gallons)
Clothes Dryer
Range/Oven
Miscellaneous Pool Heater
5% more efficient
EF 0.59
EF 0.59
Conventional
No Standing Pilot Light
EF 0.82
Space Heating
EF 0.82
Water Heating EF 0.62
Condensing Technology
AFUE 90% -Non-
weatherized AFUE 90% -Weatherized
Appliances

14
Residential baseline projection results
• Residential sector use increases 13% from 199 million therms to 224 million
therms
• Use per household decreases by 21%
•Larger home size and income effects are offset by efficiency standards
-
100
200
300
400
500
600
700
800
2013 2016 2019 2022 2025 2028 2031 2034
Intensity
(Thrm/HH)
-
50,000
100,000
150,000
200,000
250,000
2013 2016 2019 2022 2025 2028 2031 2034
Annual
Use
(1,000Thrm)
Space Heating
Water Heating
Appliances
Miscellaneous

Avista Utilities 2014 Natural Gas IRP Appendices 105
APPENDIX – CHAPTER 3

Commercial Sector

16
Avista commercial market characterization (2013)
Washington 2013 Sales
(1,000Thrm)% of Sales SqFt Average Use/SqFt (Thrm)
Small Commercial 17,267 25%47,567,634 0.36
Large Commercial 51,078 75%77,391,189 0.66
Washington total 68,345 100%124,958,823 0.55
Idaho 2013 Sales
(1,000Thrm)% of Sales SqFt Average Use/SqFt (Thrm)
Small Commercial 7,725 28%22,293,951 0.35
Large Commercial 19,968 72%31,695,198 0.63
Idaho total 27,693 100%53,989,149 0.51
Oregon 2013 Sales
(1,000Thrm)% of Sales SqFt Average Use/SqFt (Thrm)
Small Commercial 26,833 88%81,311,800 0.33
Large Commercial 3,618 12%6,030,062 0.60
Oregon total 30,451 100%87,341,862 0.35

Avista Utilities 2014 Natural Gas IRP Appendices 106
APPENDIX – CHAPTER 3

17
Avista commercial market characterization (2013)
• Energy Market Profiles
•Characterize energy use by sector, segment, end use, and technology
•Existing, replacement, and new construction
• Accounts for
•Codes and standards
•Previous DSM results
•Equipment saturation and fuel shares
Space Heating
65%
Water Heating
21%
Food Preparation
13%
Miscellaneous
1%

18
Energy market profile for Oregon, large commercial
EUI Intensity Usage
(Therms)(Therms/sqf (MMThrm)
Space Heating Furnace 45.2% 0.24 0.11 0.6
Space Heating Boiler 29.8% 0.77 0.23 1.4
Space Heating Other Heating 16.6% 0.21 0.04 0.2
Water Heating Water Heater 42.5% 0.32 0.14 0.8
Food Preparation Oven 16.2% 0.06 0.01 0.1
Food Preparation Fryer 16.2% 0.09 0.02 0.1
Food Preparation Broiler 16.2% 0.09 0.02 0.1
Food Preparation Griddle 16.2% 0.07 0.01 0.1
Food Preparation Range 16.2% 0.07 0.01 0.1
Food Preparation Steamer 16.2% 0.12 0.02 0.1
Miscellaneous Pool Heater 1.2% 0.09 0.00 0.0
Miscellaneous Miscellaneous 100.0% 0.01 0.01 0.1
0.600 3.6 Total
End Use Technology Saturation
Space Heating
62%
Water Heating
23%
Food Preparation
14%
Miscellaneous
1%
Energy Usage, Oregon Large Commercial

Avista Utilities 2014 Natural Gas IRP Appendices 107
APPENDIX – CHAPTER 3

19
Assumptions in the commercial baseline projection
• Projection of growth without conservation programs
• Incorporates
•Floor space growth, about 1.1% per year
•Differences in new construction
•Retail price forecast
•Trends in end-use/technology saturations
•Equipment purchase decisions
•Building codes and appliance standards
Today's Efficiency or Standard Assumption
Next Standard (relative to today's standard)
End Use Technology 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Furnace
Boiler
Water Heating Water Heater
Miscellaneous Pool Heater
Space Heating
EF 0.82
AFUE 76%
EF 0.82
EF 0.80

20
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
2013 2016 2019 2022 2025 2028 2031 2034
An
n
u
a
l

Us
e

(1
,
0
0
0
T
h
r
m
)
Space Heating
Water Heating
Food Preparation
Miscellaneous
-
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.50
2013 2016 2019 2022 2025 2028 2031 2034
In
t
e
n
s
i
t
y

(Th
r
m
/Sq
f
t
)
Commercial baseline projection results
• Commercial sector use increases 2% from 127 million therms to 130 million
therms
• Use per square footage decreases by 19%
•Energy consumption stays relatively flat while floor space increases

Avista Utilities 2014 Natural Gas IRP Appendices 108
APPENDIX – CHAPTER 3
Industrial Sector

22
Avista industrial market characterization (2013)
State 2013 Sales
(1,000 Therms)Square Feet Average Use/SqFt
(Therms)
Washington 2,384 3,009,759 0.79
Idaho 2,222 2,927,137 0.76
Oregon 410 564,683 0.73
All states total 5,015 6,501,579 0.77

Avista Utilities 2014 Natural Gas IRP Appendices 109
APPENDIX – CHAPTER 3

23
Avista industrial market characterization (2013)
• Energy Market Profiles
•Characterize energy use by sector, segment, end use, and technology
•Existing, replacement, and new construction
• Accounts for
•Codes and standards
•Previous DSM results
•Equipment saturation and fuel shares
Space Heating
6%
Process
87%
Miscellaneous
7%

24
Energy market profile for Idaho, industrial
EUI Intensity Usage
(Therms) (Therms/sqft) (MMThrm)
Space Heating Furnace 9.6% 0.017 0.00 0.00
Space Heating Boiler 81.3% 0.055 0.04 0.13
Space Heating Other Heating 4.8% 0.015 0.00 0.00
Process Process Heating 100.0% 0.656 0.66 1.92
Process Process Cooling 100.0% 0.001 0.00 0.00
Process Other Process 100.0% 0.004 0.00 0.01
Other Other Uses 100.0% 0.050 0.05 0.15
0.76 2.22Total
End Use Technology Saturation
Space Heating
6%
Process
87%
Miscellaneous
7%
Energy Usage, Idaho Industrial

Avista Utilities 2014 Natural Gas IRP Appendices 110
APPENDIX – CHAPTER 3
25
Assumptions in the industrial baseline projection
• Projection of growth without conservation programs
• Incorporates
•Floor space decline, about 0.5% per year (space consolidation)
•Differences in new construction
•Retail price forecast
•Trends in end-use/technology saturations
•Equipment purchase decisions
•Building codes and appliance standards
Today's Efficiency or Standard Assumption
Next Standard (relative to today's standard)
End Use Technology 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Furnace
Boiler
Space Heating AFUE 76%
EF 0.82

26
Industrial baseline projection results
• Industrial sector use decreases 10% from 5 million therms to 4.5 million therms
• Use per square footage slightly decreases by 1%
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
2013 2016 2019 2022 2025 2028 2031 2034
Annual
Use
(1,000Thrm)
Space Heating
Process
Miscellaneous
-
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
2013 2016 2019 2022 2025 2028 2031 2034
Intensity
(Thrm/Sqft)

Avista Utilities 2014 Natural Gas IRP Appendices 111
APPENDIX – CHAPTER 3

27
Baseline projection –all sectors
• Overall increase in use 8%
• Average annual growth 0.4%
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
Annual
Use
(1,000Thrm)
Residential Small Commercial Large Commercial Industrial

28
Energy conservation measures
• Assessed 1,785 measures
• Measure attributes
•Average lifetime
•Energy savings
•Cost
•Timing of standards
•Base-year saturation
•Applicability / feasibility
• Example: Washington, Single Family, Existing
Technology Efficiency
Level Lifetime Equipment
Cost
Energy Usage
(Therms/year)Off Market
Furnace 100.0%20 $3,651 565 2014
Furnace 97.5%20 $4,056 551 2014
Furnace 94.0%20 $4,259 531 2014
Furnace 87.7%20 $4,462 495 2034
Furnace 81.6%20 $6,084 461 2034
SK: Same number of measures as the previous
slide. I believe we didn’t
change the measure list

Avista Utilities 2014 Natural Gas IRP Appendices 112
APPENDIX – CHAPTER 3
29
Conservation potential assumptions
• Three levels of potential
•Technical potential – all applicable measures are implemented, regardless of cost
•Economic potential – all cost-effective measures
• TRC test with B/C ratio ≥ 1.0 (Idaho and Oregon)
• UCT test with B/C ratio ≥ 1.0 (Washington)
•Achievable potential – accounts for market acceptance and rates at which programs
can realistically be implemented
• Based on Sixth Plan ramp rates
SK: Same number of
measures as the previous
slide. I believe we didn’t change the measure list
$0
$1
$2
$3
$4
$5
$6
$/MMThrm
Avoided Costs

30
Summary of CPA results (across all states)
• Achievable potential begins at 40% of economic potential in 2015 and reaches
74% by 2034
2015 2016 2019 2024 2034
Baseline Forecast 328,757 331,980 338,917 336,073 358,562
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 1,677 2,639 9,854 20,369 36,110
Economic Potential 4,153 5,877 17,317 32,220 48,528
Technical Potential 12,207 18,677 51,810 96,562 162,236
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.5%0.8%2.9%6.1%10.1%
Economic Potential 1.3%1.8%5.1%9.6%13.5%
Technical Potential 3.7%5.6%15.3%28.7%45.2%

Avista Utilities 2014 Natural Gas IRP Appendices 113
APPENDIX – CHAPTER 3

31
Summary of CPA results (continued)
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
2015 2016 2019 2024 2034
Energy
Savings
(% of Baseline
Forecast)
Achievable Potential
Economic Potential
Technical Potential

Savings by State - Washington

Avista Utilities 2014 Natural Gas IRP Appendices 114
APPENDIX – CHAPTER 3

33
Total potential results, Washington
2015 2016 2019 2024 2034
Baseline Forecast 171,422 172,719 175,548 173,273 179,456
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 1,287 2,024 7,742 15,656 26,259
Economic Potential 3,127 4,385 13,330 24,445 35,042
Technical Potential 6,620 9,963 26,953 50,035 81,431
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.8%1.2%4.4%9.0%14.6%
Economic Potential 1.8%2.5%7.6%14.1%19.5%
Technical Potential 3.9%5.8%15.4%28.9%45.4%
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
2015 2016 2019 2024 2034
Energy Savings
(% of Baseline
Forecast)
Maximum Achievable Potential
Economic Potential
Technical Potential

34
Residential potential results, Washington
2015 2016 2019 2024 2034
Baseline Forecast 101,488 102,205 104,445 103,847 112,733
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 370 682 4,604 8,733 12,938
Economic Potential 964 1,471 7,571 13,180 16,955
Technical Potential 3,017 4,832 15,965 28,899 49,110
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.4%0.7%4.4%8.4%11.5%
Economic Potential 1.0%1.4%7.2%12.7%15.0%
Technical Potential 3.0%4.7%15.3%27.8%43.6%

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35
Residential results –Key measures, Washington
Measure / Technology
2024 Cumulative
Savings
(1,000Thrm)
Insulation -Infiltration Control 2,561
Water Heating -Low Flow Showerheads 1,269
Ducting -Repair and Sealing 1,182
Home Energy Management System 1,100
Thermostat -Clock/Programmable 682
Water Heating -Thermostat Setback 595
Water Heating -Hot Water Saver 429
Water Heating -Tank Blanket/Insulation 330
Water Heating -Faucet Aerators 259
Water Heating -Pipe Insulation 153
Insulation -Ceiling 61
Boiler -Pipe Insulation 58
Insulation -Attic Hatch 49
Insulation -Wall Cavity 5
Total 8,733
Water Heating
35%
Space Heating
65%

36
Commercial potential results, Washington
2015 2016 2019 2024 2034
Baseline Forecast 67,462 67,947 68,368 66,870 64,746
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 893 1,305 3,020 6,704 13,100
Economic Potential 2,138 2,874 5,635 11,012 17,839
Technical Potential 3,555 5,061 10,803 20,762 31,923
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 1.3%1.9%4.4%10.0%20.2%
Economic Potential 3.2%4.2%8.2%16.5%27.6%
Technical Potential 5.3%7.4%15.8%31.0%49.3%

Avista Utilities 2014 Natural Gas IRP Appendices 116
APPENDIX – CHAPTER 3
37
Commercial results –Key measures, Washington
Measure / Technology
2024 Cumulative
Savings
(1,000Thrm)
Space Heating -Heat Recovery Ventilator 1,545
Energy Management System 702
Custom Measures 474
Boiler -Hot Water Reset 420
Water Heating -Faucet Aerators 398
Furnace -Maintenance 391
Boiler -Maintenance 363
Space Heating -Furnace 357
Thermostat -Clock/Programmable 336
Insulation -Ceiling 293
Advanced New Construction Designs 271
Insulation -Wall Cavity 262
Boiler -High Efficiency Hot Water Circulation 197
Food Preparation -Fryer 179
Food Preparation -Oven 129
Food Preparation -Steamer 113
Food Preparation -Range 101
Food Preparation -Griddle 81
Water Heating -Tank Blanket/Insulation 53
Space Heating -Boiler 34
Water Heating -Hot Water Saver 4
Total 6,704
Water
Heating
10%
Space Heating
80%
Food Preparation
10%

38
Industrial potential results, Washington
2015 2016 2019 2024 2034
Baseline Forecast 2,472 2,567 2,735 2,555 1,977
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 24 38 118 220 220
Economic Potential 25 39 124 253 248
Technical Potential 48 69 184 374 398
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 1.0%1.5%4.3%8.6%11.1%
Economic Potential 1.0%1.5%4.5%9.9%12.6%
Technical Potential 1.9%2.7%6.7%14.6%20.1%

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APPENDIX – CHAPTER 3

39
Industrial results –Key measures, Washington
Measure / Technology
2024 Cumulative
Savings
(1,000Thrm)
Process -Boiler Hot Water Reset 196
Insulation -Wall Cavity 16
Space Heating -Heat Recovery Ventilator 9
Total 220
Space
Heating
11%
Process
89%

Savings by State - Idaho

Avista Utilities 2014 Natural Gas IRP Appendices 118
APPENDIX – CHAPTER 3
41
Total potential results, Idaho
2015 2016 2019 2024 2034
Baseline Forecast 77,988 79,291 82,115 82,171 89,483
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 228 342 1,031 2,320 4,503
Economic Potential 571 803 1,984 3,881 6,209
Technical Potential 2,818 4,387 12,471 23,483 40,252
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.3%0.4%1.3%2.8%5.0%
Economic Potential 0.7%1.0%2.4%4.7%6.9%
Technical Potential 3.6%5.5%15.2%28.6%45.0%
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
2015 2016 2019 2024 2034
Energy Savings
(% of Baseline
Forecast)
Maximum Achievable Potential
Economic Potential
Technical Potential

42
Residential potential results, Idaho
2015 2016 2019 2024 2034
Baseline Forecast 46,978 47,633 49,132 49,102 55,990
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 6 18 263 496 874
Economic Potential 10 31 434 756 1,117
Technical Potential 1,239 2,065 7,276 13,308 24,129
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.0%0.0%0.5%1.0%1.6%
Economic Potential 0.0%0.1%0.9%1.5%2.0%
Technical Potential 2.6%4.3%14.8%27.1%43.1%

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APPENDIX – CHAPTER 3

43
Residential results –Key measures, Idaho
Measure / Technology
2024 Cumulative
Savings
(1,000Thrm)
Water Heating -Pipe Insulation 219
Water Heating -Tank Blanket/Insulation 144
Water Heating -Low Flow Showerheads 124
Boiler -Pipe Insulation 6
Insulation -Ceiling 3
Total 496
Space Heating
2%
Water Heating
98%

44
Commercial potential results, Idaho
2015 2016 2019 2024 2034
Baseline Forecast 28,645 29,129 30,299 30,572 31,360
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 220 320 760 1,786 3,478
Economic Potential 559 768 1,543 3,083 4,921
Technical Potential 1,533 2,253 5,014 9,808 15,689
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.8%1.1%2.5%5.8%11.1%
Economic Potential 2.0%2.6%5.1%10.1%15.7%
Technical Potential 5.4%7.7%16.5%32.1%50.0%

Avista Utilities 2014 Natural Gas IRP Appendices 120
APPENDIX – CHAPTER 3
45
Commercial results –Key measures, Idaho
Measure / Technology
2024 Cumulative
Savings
(1,000Thrm)
Space Heating -Heat Recovery Ventilator 687
Energy Management System 213
Boiler -Hot Water Reset 174
Boiler -Maintenance 137
Space Heating -Furnace 130
Food Preparation -Fryer 88
Boiler -High Efficiency Hot Water Circulation 72
Food Preparation -Oven 64
Food Preparation -Steamer 56
Food Preparation -Range 50
Water Heating -Faucet Aerators 40
Food Preparation -Griddle 40
Water Heating -Tank Blanket/Insulation 26
Insulation -Ceiling 8
Total 1,786
Space Heating
79%
Water Heating
4%
Food
Preparation
17%

46
Industrial potential results, Idaho
2015 2016 2019 2024 2034
Baseline Forecast 2,365 2,530 2,684 2,497 2,133
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 3 4 7 38 151
Economic Potential 3 4 8 43 172
Technical Potential 46 69 181 368 434
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.1%0.1%0.3%1.5%7.1%
Economic Potential 0.1%0.1%0.3%1.7%8.1%
Technical Potential 1.9%2.7%6.8%14.7%20.3%

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APPENDIX – CHAPTER 3

47
Industrial results –Key measures, Idaho
Measure / Technology
2024 Cumulative
Savings
(1,000Thrm)
Process -Boiler Hot Water Reset 28
Insulation -Wall Cavity 10
Total 38
Space Heating
25%
Process
75%

Savings by State - Oregon

Avista Utilities 2014 Natural Gas IRP Appendices 122
APPENDIX – CHAPTER 3
49
Total potential results, Oregon
2015 2016 2019 2024 2034
Baseline Forecast 79,346 79,969 81,255 80,629 89,623
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 161 273 1,081 2,393 5,349
Economic Potential 454 690 2,004 3,894 7,276
Technical Potential 2,769 4,327 12,387 23,043 40,553
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.2%0.3%1.3%3.0%6.0%
Economic Potential 0.6%0.9%2.5%4.8%8.1%
Technical Potential 3.5%5.4%15.2%28.6%45.2%
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
2015 2016 2019 2024 2034
Energy Savings
(% of Baseline
Forecast)
Maximum Achievable Potential
Economic Potential
Technical Potential

50
Residential potential results, Oregon
2015 2016 2019 2024 2034
Baseline Forecast 49,029 49,426 50,374 50,070 55,947
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 8 27 376 679 1,368
Economic Potential 14 44 595 1,006 1,690
Technical Potential 1,326 2,218 7,699 13,823 24,244
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.0%0.1%0.7%1.4%2.4%
Economic Potential 0.0%0.1%1.2%2.0%3.0%
Technical Potential 2.7%4.5%15.3%27.6%43.3%

Avista Utilities 2014 Natural Gas IRP Appendices 123
APPENDIX – CHAPTER 3

51
Residential results –Key measures, Oregon
Measure / Technology
2024 Cumulative
Savings
(1,000Thrm)
Water Heating -Pipe Insulation 251
Water Heating -Tank Blanket/Insulation 181
Water Heating -Faucet Aerators 135
Water Heating -Low Flow Showerheads 104
Insulation -Ceiling 4
Boiler -Pipe Insulation 4
Total 679
Water Heating
99%
Space Heating
1%

52
Commercial potential results, Oregon
2015 2016 2019 2024 2034
Baseline Forecast 29,902 30,115 30,433 30,134 33,296
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 153 245 704 1,704 3,944
Economic Potential 440 645 1,407 2,876 5,545
Technical Potential 1,434 2,097 4,657 9,158 16,232
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.5%0.8%2.3%5.7%11.8%
Economic Potential 1.5%2.1%4.6%9.5%16.7%
Technical Potential 4.8%7.0%15.3%30.4%48.7%

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APPENDIX – CHAPTER 3

53
Commercial results –Key measures, Oregon
Measure / Technology
2024 Cumulative
Savings
(1,000Thrm)
Space Heating -Heat Recovery Ventilator 712
Space Heating -Furnace 329
Water Heating -Faucet Aerators 154
Water Heating -Tank Blanket/Insulation 90
Food Preparation -Fryer 76
Food Preparation -Oven 55
Boiler -Maintenance 53
Food Preparation -Steamer 48
Food Preparation -Range 43
Energy Management System 37
Food Preparation -Griddle 34
Insulation -Ceiling 30
Boiler -Hot Water Reset 29
Boiler -High Efficiency Hot Water Circulation 13
Total 1,704
Water
Heating
13%
Space Heating
64%
Food Preparation
23%

54
Industrial potential results, Oregon
2015 2016 2019 2024 2034
Baseline Forecast 415 427 448 425 380
Cumulative Natural Gas Savings (1,000Thrm)
Achievable Potential 0 1 1 10 36
Economic Potential 0 1 1 11 41
Technical Potential 8 12 30 63 77
Cumulative Natural Gas Savings (% of Baseline)
Achievable Potential 0.1%0.1%0.3%2.4%9.6%
Economic Potential 0.1%0.1%0.3%2.7%10.9%
Technical Potential 1.9%2.7%6.8%14.7%20.3%

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APPENDIX – CHAPTER 3

55
Industrial results –Key measures, Oregon
Measure / Technology
2024
Cumulative
Savings
(1,000Thrm)
Process -Boiler Hot Water Reset 7
Insulation -Wall Cavity 3
Total 10
Space Heating
26%
Process
74%

Ingrid Rohmund
[e-mail]
Bridget Kester
[e-mail]
Sogol Kananizadeh
[e-mail]
Sharon Yoshida
[e-mail]

Avista Utilities 2014 Natural Gas IRP Appendices 126
APPENDIX – CHAPTER 3
APPENDIX 3.2: ENVIRONMENTAL EXTERNALITIES OVERVIEW
(OREGON JURISDICTION ONLY)
The methodology for determining avoided costs from reduced incremental natural gas usage considers
commodity and variable transportation costs only. These avoided cost streams do not include
environmental externality costs related to the gathering, transmission, distribution or end-use of natural
gas.
Per traditional economic theory and industry practice, an environmental externality factor is typically
added to the avoided cost when there is an opportunity to displace traditional supply-side resources with
an alternative resource with no adverse environmental impact.
REGULATORY GUIDANCE
The Oregon Public Utility Commission (OPUC) issued Order 93-965 (UM-424) to address how utilities
should consider the impact of environmental externalities in planning for future energy resources. The
Order required analysis on the potential natural gas cost impacts from emitting carbon dioxide (CO2) and
nitric-oxide (NOx).
The OPUC’s Order No. 07-002 in Docket UM 1056 (Investigation Into Integrated Resource Planning)
established the following guideline for the treatment of environmental costs used by energy utilities that
evaluate demand-side and supply-side energy choices:
UM 1056, Guideline 8 - Environmental Costs
“Utilities should include, in their base-case analyses, the regulatory compliance costs they expect
for carbon dioxide (CO2), nitrogen oxides (NOx), sulfur oxides (SO2), and mercury (Hg)
emissions. Utilities should analyze the range of potential CO2 regulatory costs in Order No. 93-
695, from $0 - $40 (1990$). In addition, utilities should perform sensitivity analysis on a range of
reasonably possible cost adders for nitrogen oxides (NOx), sulfur dioxide (SO2), and mercury
(Hg), if applicable.
In June 2008, the OPUC issued Order 08-338 (UM1302) which revised UM1056, Guideline 8. The
revised guideline requires the utility should construct a base case portfolio to reflect what it considers to
be the most likely regulatory compliance future for the various emissions. Additionally the guideline
requires the utility to develop several compliance scenarios ranging from the present CO2 regulatory level
to the upper reaches of credible proposals and each scenario should include a time profile of CO2 costs.
The utility is also required to include a “trigger point” analysis in which the utility must determine at what
level of carbon costs its selection of portfolio resources would be significantly different.
ANALYSIS
Unlike electric utilities, environmental cost issues rarely impact a natural gas utility's supply-side resource
options. This is because the only supply-side energy resource is natural gas. The utility cannot choose
between say "dirty" coal-fired generation and "clean" wind energy sources. The supply-side implication
of environmental externalities generally relates to combustion of fuel to move or compress natural gas.
Avista’s direct gas distribution system infrastructure relies solely on the upstream line pressure of the
Avista Utilities 2014 Natural Gas IRP Appendices 127
APPENDIX – CHAPTER 3

interstate pipeline transportation network to distribute natural gas to its customers and thus does not
directly combust fuels that result in any CO2, NOx, SO2, or Hg emissions.
Upstream gas system infrastructure (pipelines, storage facilities, and gathering systems), however, do
produce CO2 emissions via compressors used to pressurize and move natural gas. Accessing CO2
emissions data on these upstream activities to perform detailed meaningful analysis is challenging. In the
2009 Natural Gas IRP there was significant momentum regarding GHG legislation and the movement
towards the creation of carbon cap and trade markets or tax structure. Since then, the momentum has
slowed significantly. Where there is still a focus on reducing GHG emissions and improving the nation’s
carbon footprint, the timing of implementing a carbon cap and trade/tax framework has been delayed.
Additionally, the pricing level of the framework has been greatly reduced.. Whichever structure
ultimately gets implemented, Avista believes the cost pass through mechanisms for upstream gas system
infrastructure will not make a difference in supply-side resource selection although the amount of cost
pass through could differ widely.
Table 3.2.1 summarizes a range of environmental cost adders we believe capture several compliance
futures including our expected scenario. The CO2 cost adders reflect outlooks we obtained from one of
our consultants, and following discussion and feedback from the TAC, have been incorporated into our
Expected, Low Growth/High Price, and Alternate Planning Standard portfolios.
The guidelines also call for a trigger point analysis that reflects a “turning point” at which an alternate
resource portfolio would be selected at different carbon cost adders levels. Because natural gas is the only
supply resource applicable to LDC’s any alternate resource portfolio selection would be a result of
delivery methods of natural gas to customers. Conceptually, there could be differing levels of cost adders
applicable to pipeline transported supply versus in service territory LNG storage gas. From a practical
standpoint however, the differences in these relative cost adders would be very minor and would not
change supply-side resource selection regardless of various carbon cost adder levels. We do acknowledge
there is influence to the avoided costs which would impact the cost effectiveness of demand-side
measures in the DSM business planning process.
CONSERVATON COST ADVANTAGE
For this IRP, we also incorporated a 10 percent environmental externality factor into our assessment of
the cost-effectiveness of existing demand-side management programs. Our assessment of prospective
demand-side management opportunities is based on an avoided cost stream that includes this 10 percent
factor.
Environmental externalities were evaluated in the IRP by adding the cost per therm equivalent of the
externality cost values to supply-side resources as described in OPUC Order No. 93-965. Avista found
that the environmental cost adders had no impact on the company’s supply-side choices, although they
did impact the level of demand-side measures that could be cost-effective to acquire.
REGULATORY FILING
Avista will file revised cost-effectiveness limits (CELs) based upon the updated avoided costs available
from this IRP process within the prescribed regulatory timetable.

Avista Utilities 2014 Natural Gas IRP Appendices 128
APPENDIX – CHAPTER 3
TABLE 3.2.1: ENVIRONMENTAL EXTERNALITIES COST ADDER ANALYSIS (2012$)

Avista Utilities 2014 Natural Gas IRP Appendices 129
APPENDIX – CHAPTER 3

Avista Utilities 2014 Natural Gas IRP Appendices 130
Appendix - Chapter 4

APPENDIX 4.1: CURRENT TRANSPORTATION/STORAGE RATES AND ASSUMPTIONS

Avista Utilities 2014 Natural Gas IRP Appendices 131
Appendix - Chapter 4

APPENDIX 4.2: ALTERNATE SUPPLY SCENARIOS

Existing Resources Existing + Expected Available GTN Fully Subscribed
Resources
Currently contracted
capacity net of long term
releases
Currently contracted capacity
net of long term releases
Currently contracted capacity
net of long term releases
Currently available GTN
Capacity Release Recalls Capacity Release Recalls
NWP Expansions NWP Expansions
Satellite LNG Satellite LNG
Rates Current Rates Current Rates Current Rates
INPUT ASSUMPTIONS
Avista Utilities 2014 Natural Gas IRP Appendices 132
Appendix - Chapter 5

APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
EXPECTED PRICE

Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Expected Case AECO 2013-2014 3.26$ 3.65$ 4.18$ 3.34$ 3.44$ 3.42$ 3.37$ 3.38$ 3.37$ 3.30$ 3.33$ 3.18$
Expected Case AECO 2014-2015 3.28$ 3.26$ 3.34$ 3.38$ 3.48$ 3.36$ 3.35$ 3.39$ 3.45$ 3.49$ 3.54$ 3.61$
Expected Case AECO 2015-2016 3.78$ 3.91$ 3.96$ 3.88$ 3.93$ 3.73$ 3.60$ 3.61$ 3.62$ 3.45$ 3.36$ 3.38$
Expected Case AECO 2016-2017 3.52$ 3.45$ 3.45$ 3.49$ 3.54$ 3.40$ 3.37$ 3.39$ 3.40$ 3.40$ 3.42$ 3.46$
Expected Case AECO 2017-2018 3.60$ 3.61$ 3.62$ 3.62$ 3.59$ 3.38$ 3.31$ 3.28$ 3.25$ 3.23$ 3.25$ 3.27$
Expected Case AECO 2018-2019 3.48$ 3.40$ 3.25$ 3.28$ 3.36$ 3.22$ 3.18$ 3.16$ 3.19$ 3.18$ 3.21$ 3.25$
Expected Case AECO 2019-2020 3.46$ 3.46$ 3.24$ 3.32$ 3.45$ 3.32$ 3.28$ 3.30$ 3.31$ 3.32$ 3.32$ 3.39$
Expected Case AECO 2020-2021 3.53$ 3.47$ 3.33$ 3.40$ 3.57$ 3.57$ 3.57$ 3.60$ 3.59$ 3.62$ 3.67$ 3.72$
Expected Case AECO 2021-2022 3.84$ 3.89$ 3.96$ 3.95$ 3.85$ 3.60$ 3.54$ 3.52$ 3.52$ 3.52$ 3.63$ 3.68$
Expected Case AECO 2022-2023 3.95$ 3.97$ 3.94$ 3.93$ 3.91$ 3.71$ 3.58$ 3.55$ 3.55$ 3.56$ 3.65$ 3.71$
Expected Case AECO 2023-2024 4.02$ 4.11$ 4.22$ 4.26$ 4.26$ 4.04$ 3.92$ 3.89$ 3.88$ 3.90$ 3.99$ 4.05$
Expected Case AECO 2024-2025 4.34$ 4.43$ 4.50$ 4.48$ 4.45$ 4.26$ 4.23$ 4.22$ 4.21$ 4.23$ 4.30$ 4.37$
Expected Case AECO 2025-2026 4.61$ 4.69$ 4.67$ 4.70$ 4.70$ 4.47$ 4.40$ 4.37$ 4.36$ 4.38$ 4.45$ 4.50$
Expected Case AECO 2026-2027 4.79$ 4.85$ 4.73$ 4.67$ 4.76$ 4.45$ 4.39$ 4.36$ 4.36$ 4.38$ 4.44$ 4.49$
Expected Case AECO 2027-2028 4.83$ 4.86$ 4.71$ 4.67$ 4.71$ 4.48$ 4.44$ 4.42$ 4.42$ 4.44$ 4.52$ 4.58$
Expected Case AECO 2028-2029 5.05$ 5.12$ 5.24$ 5.32$ 5.30$ 4.98$ 4.92$ 4.88$ 4.86$ 4.87$ 4.93$ 4.98$
Expected Case AECO 2029-2030 5.32$ 5.37$ 5.36$ 5.24$ 5.21$ 4.84$ 4.72$ 4.69$ 4.68$ 4.69$ 4.78$ 4.85$
Expected Case AECO 2030-2031 5.42$ 5.50$ 5.40$ 5.27$ 5.30$ 5.04$ 5.01$ 4.98$ 5.02$ 5.04$ 5.12$ 5.20$
Expected Case AECO 2031-2032 5.67$ 5.39$ 5.45$ 5.47$ 5.65$ 5.42$ 5.39$ 5.31$ 5.20$ 5.20$ 5.39$ 5.44$
Expected Case AECO 2032-2033 5.73$ 5.59$ 5.70$ 5.73$ 5.87$ 5.67$ 5.66$ 5.61$ 5.53$ 5.53$ 5.75$ 5.80$
Expected Case Malin 2013-2014 3.62$ 4.53$ 4.69$ 3.81$ 3.83$ 3.82$ 3.78$ 3.77$ 3.77$ 3.71$ 3.74$ 3.61$
Expected Case Malin 2014-2015 3.71$ 3.75$ 3.79$ 3.83$ 3.82$ 3.76$ 3.74$ 3.79$ 3.86$ 3.90$ 3.96$ 4.03$
Expected Case Malin 2015-2016 4.25$ 4.43$ 4.49$ 4.39$ 4.30$ 4.16$ 4.04$ 4.01$ 4.03$ 3.89$ 3.85$ 3.83$
Expected Case Malin 2016-2017 4.04$ 3.99$ 3.97$ 3.97$ 3.93$ 3.88$ 3.91$ 3.92$ 3.93$ 3.96$ 4.00$ 4.00$
Expected Case Malin 2017-2018 4.17$ 4.17$ 4.16$ 4.12$ 4.02$ 3.92$ 3.91$ 3.85$ 3.83$ 3.87$ 3.92$ 3.90$
Expected Case Malin 2018-2019 4.08$ 4.00$ 3.85$ 3.82$ 3.83$ 3.81$ 3.82$ 3.81$ 3.84$ 3.86$ 3.92$ 3.96$
Expected Case Malin 2019-2020 4.09$ 4.05$ 3.79$ 3.79$ 3.91$ 3.93$ 3.89$ 3.91$ 3.94$ 3.98$ 4.00$ 4.04$
Expected Case Malin 2020-2021 4.20$ 4.14$ 3.83$ 3.88$ 4.06$ 4.22$ 4.15$ 4.19$ 4.24$ 4.27$ 4.35$ 4.40$
Expected Case Malin 2021-2022 4.55$ 4.49$ 4.41$ 4.30$ 4.27$ 4.16$ 4.13$ 4.11$ 4.11$ 4.15$ 4.29$ 4.34$
Expected Case Malin 2022-2023 4.63$ 4.54$ 4.45$ 4.45$ 4.45$ 4.35$ 4.21$ 4.13$ 4.14$ 4.15$ 4.36$ 4.42$
Expected Case Malin 2023-2024 4.76$ 4.68$ 4.72$ 4.64$ 4.79$ 4.69$ 4.51$ 4.49$ 4.51$ 4.56$ 4.66$ 4.72$
Expected Case Malin 2024-2025 5.05$ 5.02$ 5.00$ 4.83$ 4.93$ 4.90$ 4.86$ 4.83$ 4.90$ 4.92$ 5.01$ 5.05$
Expected Case Malin 2025-2026 5.33$ 5.27$ 5.22$ 5.20$ 5.28$ 5.14$ 5.05$ 5.02$ 5.08$ 5.10$ 5.21$ 5.24$
Expected Case Malin 2026-2027 5.52$ 5.53$ 5.28$ 5.09$ 5.24$ 5.11$ 5.05$ 5.03$ 5.04$ 5.08$ 5.15$ 5.22$
Expected Case Malin 2027-2028 5.56$ 5.48$ 5.26$ 5.16$ 5.26$ 5.14$ 5.08$ 5.08$ 5.10$ 5.17$ 5.25$ 5.31$
Expected Case Malin 2028-2029 5.78$ 5.69$ 5.80$ 5.72$ 5.68$ 5.54$ 5.51$ 5.47$ 5.52$ 5.55$ 5.63$ 5.68$
Expected Case Malin 2029-2030 6.01$ 5.94$ 5.88$ 5.68$ 5.64$ 5.47$ 5.37$ 5.34$ 5.36$ 5.42$ 5.52$ 5.58$
Expected Case Malin 2030-2031 6.14$ 6.08$ 5.98$ 5.75$ 5.73$ 5.65$ 5.64$ 5.62$ 5.69$ 5.75$ 5.85$ 5.91$
Expected Case Malin 2031-2032 6.37$ 6.02$ 5.95$ 5.97$ 6.07$ 5.90$ 5.85$ 5.77$ 5.65$ 5.67$ 5.89$ 5.99$
Expected Case Malin 2032-2033 6.26$ 6.12$ 6.23$ 6.25$ 6.29$ 6.14$ 6.13$ 6.06$ 5.99$ 6.01$ 6.26$ 6.35$
Expected Case Rockies 2013-2014 3.53$ 4.56$ 4.66$ 3.77$ 3.79$ 3.77$ 3.75$ 3.74$ 3.73$ 3.67$ 3.70$ 3.57$
Expected Case Rockies 2014-2015 3.67$ 3.72$ 3.76$ 3.80$ 3.78$ 3.71$ 3.71$ 3.76$ 3.82$ 3.86$ 3.91$ 3.96$
Expected Case Rockies 2015-2016 4.17$ 4.39$ 4.45$ 4.36$ 4.26$ 4.12$ 4.01$ 3.98$ 3.99$ 3.85$ 3.80$ 3.78$
Expected Case Rockies 2016-2017 3.95$ 3.95$ 3.93$ 3.93$ 3.89$ 3.83$ 3.83$ 3.82$ 3.83$ 3.85$ 3.88$ 3.89$
Expected Case Rockies 2017-2018 4.07$ 4.13$ 4.12$ 4.08$ 3.98$ 3.84$ 3.81$ 3.75$ 3.73$ 3.72$ 3.77$ 3.75$
Expected Case Rockies 2018-2019 3.92$ 3.95$ 3.81$ 3.77$ 3.78$ 3.72$ 3.69$ 3.68$ 3.68$ 3.71$ 3.76$ 3.76$
Expected Case Rockies 2019-2020 3.84$ 3.91$ 3.75$ 3.75$ 3.77$ 3.71$ 3.70$ 3.72$ 3.73$ 3.75$ 3.78$ 3.81$
Expected Case Rockies 2020-2021 3.90$ 3.98$ 3.78$ 3.80$ 3.82$ 3.87$ 3.94$ 3.92$ 4.00$ 4.03$ 4.09$ 4.11$
Expected Case Rockies 2021-2022 4.15$ 4.25$ 4.21$ 4.12$ 3.92$ 3.78$ 3.75$ 3.73$ 3.73$ 3.75$ 3.85$ 3.88$
Expected Case Rockies 2022-2023 4.13$ 4.14$ 4.15$ 4.11$ 4.04$ 3.94$ 3.83$ 3.80$ 3.82$ 3.84$ 3.93$ 3.99$
Expected Case Rockies 2023-2024 4.22$ 4.29$ 4.32$ 4.30$ 4.25$ 4.15$ 4.03$ 3.98$ 4.00$ 4.01$ 4.10$ 4.21$
Expected Case Rockies 2024-2025 4.43$ 4.50$ 4.72$ 4.72$ 4.61$ 4.52$ 4.53$ 4.50$ 4.55$ 4.57$ 4.62$ 4.66$
Expected Case Rockies 2025-2026 4.85$ 4.88$ 4.90$ 4.90$ 4.84$ 4.73$ 4.67$ 4.64$ 4.67$ 4.69$ 4.75$ 4.83$
Expected Case Rockies 2026-2027 4.97$ 5.02$ 5.10$ 5.00$ 4.96$ 4.86$ 4.83$ 4.81$ 4.84$ 4.85$ 4.92$ 4.97$
Expected Case Rockies 2027-2028 5.19$ 5.24$ 5.10$ 5.07$ 4.99$ 4.89$ 4.88$ 4.85$ 4.88$ 4.91$ 4.99$ 5.05$
Expected Case Rockies 2028-2029 5.39$ 5.45$ 5.50$ 5.43$ 5.36$ 5.24$ 5.22$ 5.15$ 5.18$ 5.21$ 5.27$ 5.29$
Expected Case Rockies 2029-2030 5.54$ 5.56$ 5.55$ 5.44$ 5.28$ 5.16$ 5.05$ 5.02$ 5.05$ 5.08$ 5.17$ 5.24$
Expected Case Rockies 2030-2031 5.58$ 5.65$ 5.61$ 5.52$ 5.36$ 5.27$ 5.26$ 5.24$ 5.31$ 5.36$ 5.44$ 5.47$
Expected Case Rockies 2031-2032 5.81$ 5.64$ 5.53$ 5.55$ 5.62$ 5.49$ 5.44$ 5.35$ 5.25$ 5.26$ 5.47$ 5.54$
Expected Case Rockies 2032-2033 5.76$ 5.67$ 5.76$ 5.78$ 5.81$ 5.71$ 5.69$ 5.61$ 5.55$ 5.56$ 5.79$ 5.86$
2012$
Avista Utilities 2014 Natural Gas IRP Appendices 133
Appendix - Chapter 5

APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
EXPECTED PRICE

Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Expected Case Stanfield 2013-2014 3.60$ 4.56$ 4.66$ 3.72$ 3.76$ 3.73$ 3.72$ 3.73$ 3.73$ 3.67$ 3.69$ 3.53$
Expected Case Stanfield 2014-2015 3.67$ 3.66$ 3.72$ 3.76$ 3.78$ 3.67$ 3.71$ 3.75$ 3.81$ 3.85$ 3.90$ 3.94$
Expected Case Stanfield 2015-2016 4.17$ 4.43$ 4.49$ 4.39$ 4.24$ 4.08$ 3.96$ 3.97$ 3.99$ 3.82$ 3.77$ 3.74$
Expected Case Stanfield 2016-2017 3.95$ 3.99$ 3.97$ 3.88$ 3.85$ 3.78$ 3.78$ 3.78$ 3.79$ 3.81$ 3.85$ 3.87$
Expected Case Stanfield 2017-2018 4.15$ 4.18$ 4.17$ 4.03$ 3.94$ 3.79$ 3.76$ 3.69$ 3.68$ 3.69$ 3.73$ 3.71$
Expected Case Stanfield 2018-2019 4.04$ 4.00$ 3.85$ 3.83$ 3.75$ 3.76$ 3.64$ 3.62$ 3.65$ 3.66$ 3.71$ 3.85$
Expected Case Stanfield 2019-2020 3.91$ 4.04$ 3.79$ 3.70$ 3.82$ 3.75$ 3.71$ 3.72$ 3.76$ 3.78$ 3.80$ 3.84$
Expected Case Stanfield 2020-2021 4.01$ 4.07$ 3.84$ 3.79$ 3.96$ 4.02$ 3.98$ 4.01$ 4.04$ 4.07$ 4.15$ 4.19$
Expected Case Stanfield 2021-2022 4.45$ 4.48$ 4.46$ 4.36$ 4.17$ 4.00$ 3.96$ 3.93$ 3.93$ 3.95$ 4.09$ 4.13$
Expected Case Stanfield 2022-2023 4.56$ 4.54$ 4.35$ 4.35$ 4.28$ 4.15$ 4.03$ 4.01$ 4.01$ 4.02$ 4.13$ 4.18$
Expected Case Stanfield 2023-2024 4.65$ 4.68$ 4.74$ 4.57$ 4.64$ 4.48$ 4.34$ 4.31$ 4.30$ 4.32$ 4.45$ 4.51$
Expected Case Stanfield 2024-2025 4.97$ 5.02$ 4.90$ 4.78$ 4.81$ 4.70$ 4.69$ 4.65$ 4.67$ 4.69$ 4.78$ 4.83$
Expected Case Stanfield 2025-2026 5.24$ 5.27$ 5.24$ 5.10$ 5.10$ 4.93$ 4.85$ 4.82$ 4.85$ 4.86$ 4.96$ 5.11$
Expected Case Stanfield 2026-2027 5.42$ 5.47$ 5.30$ 5.05$ 5.13$ 5.02$ 4.86$ 4.83$ 4.84$ 4.86$ 4.92$ 5.12$
Expected Case Stanfield 2027-2028 5.45$ 5.48$ 5.27$ 5.06$ 5.11$ 5.05$ 4.89$ 4.88$ 4.90$ 4.93$ 5.01$ 5.20$
Expected Case Stanfield 2028-2029 5.67$ 5.69$ 5.82$ 5.79$ 5.61$ 5.39$ 5.34$ 5.29$ 5.32$ 5.34$ 5.42$ 5.46$
Expected Case Stanfield 2029-2030 5.95$ 5.96$ 5.94$ 5.74$ 5.54$ 5.41$ 5.17$ 5.14$ 5.14$ 5.18$ 5.28$ 5.48$
Expected Case Stanfield 2030-2031 6.06$ 6.11$ 6.00$ 5.82$ 5.66$ 5.59$ 5.46$ 5.44$ 5.48$ 5.53$ 5.61$ 5.68$
Expected Case Stanfield 2031-2032 6.31$ 6.02$ 5.94$ 5.97$ 6.06$ 5.74$ 5.69$ 5.60$ 5.48$ 5.48$ 5.69$ 5.80$
Expected Case Stanfield 2032-2033 6.25$ 6.11$ 6.22$ 6.24$ 6.29$ 5.98$ 6.08$ 5.89$ 5.81$ 5.82$ 6.07$ 6.16$
Expected Case Sumas 2013-2014 3.93$ 5.31$ 4.68$ 3.87$ 3.83$ 3.60$ 3.66$ 3.60$ 3.63$ 3.50$ 3.56$ 3.40$
Expected Case Sumas 2014-2015 3.82$ 3.97$ 3.98$ 3.91$ 3.82$ 3.55$ 3.65$ 3.61$ 3.67$ 3.67$ 3.78$ 3.84$
Expected Case Sumas 2015-2016 4.33$ 4.65$ 4.66$ 4.46$ 4.30$ 3.92$ 3.91$ 3.83$ 3.84$ 3.64$ 3.61$ 3.62$
Expected Case Sumas 2016-2017 4.11$ 4.21$ 4.14$ 4.04$ 3.93$ 3.59$ 3.68$ 3.64$ 3.65$ 3.59$ 3.67$ 3.75$
Expected Case Sumas 2017-2018 4.22$ 4.39$ 4.34$ 4.20$ 4.03$ 3.65$ 3.63$ 3.54$ 3.51$ 3.43$ 3.50$ 3.58$
Expected Case Sumas 2018-2019 4.11$ 4.22$ 4.02$ 3.90$ 3.84$ 3.50$ 3.48$ 3.43$ 3.46$ 3.42$ 3.45$ 3.47$
Expected Case Sumas 2019-2020 3.94$ 4.26$ 3.96$ 3.86$ 3.79$ 3.50$ 3.58$ 3.56$ 3.58$ 3.56$ 3.56$ 3.60$
Expected Case Sumas 2020-2021 4.01$ 4.29$ 4.00$ 3.95$ 3.95$ 3.75$ 3.86$ 3.86$ 3.85$ 3.85$ 3.90$ 3.92$
Expected Case Sumas 2021-2022 4.52$ 4.70$ 4.63$ 4.43$ 4.22$ 3.80$ 3.85$ 3.79$ 3.79$ 3.77$ 3.88$ 3.91$
Expected Case Sumas 2022-2023 4.63$ 4.76$ 4.62$ 4.37$ 4.18$ 3.92$ 3.86$ 3.79$ 3.84$ 3.78$ 3.90$ 3.95$
Expected Case Sumas 2023-2024 4.50$ 4.90$ 4.91$ 4.65$ 4.58$ 4.29$ 4.22$ 4.16$ 4.19$ 4.13$ 4.26$ 4.33$
Expected Case Sumas 2024-2025 4.81$ 5.23$ 5.18$ 4.87$ 4.76$ 4.51$ 4.53$ 4.48$ 4.51$ 4.46$ 4.57$ 4.65$
Expected Case Sumas 2025-2026 5.08$ 5.49$ 5.41$ 5.27$ 5.05$ 4.72$ 4.69$ 4.63$ 4.66$ 4.61$ 4.72$ 4.74$
Expected Case Sumas 2026-2027 5.26$ 5.69$ 5.47$ 5.22$ 5.07$ 4.68$ 4.70$ 4.63$ 4.67$ 4.63$ 4.72$ 4.75$
Expected Case Sumas 2027-2028 5.31$ 5.70$ 5.44$ 5.23$ 5.05$ 4.71$ 4.72$ 4.67$ 4.71$ 4.70$ 4.78$ 4.81$
Expected Case Sumas 2028-2029 5.74$ 5.91$ 5.99$ 5.86$ 5.68$ 5.23$ 5.24$ 5.14$ 5.19$ 5.18$ 5.24$ 5.26$
Expected Case Sumas 2029-2030 6.02$ 6.25$ 6.31$ 5.81$ 5.64$ 5.08$ 5.02$ 4.94$ 4.99$ 4.97$ 5.06$ 5.12$
Expected Case Sumas 2030-2031 6.13$ 6.39$ 6.47$ 5.89$ 5.76$ 5.28$ 5.32$ 5.24$ 5.35$ 5.34$ 5.42$ 5.47$
Expected Case Sumas 2031-2032 6.38$ 6.41$ 6.16$ 6.19$ 6.11$ 5.58$ 5.45$ 5.19$ 5.34$ 5.33$ 5.50$ 5.62$
Expected Case Sumas 2032-2033 6.30$ 6.43$ 6.55$ 6.58$ 6.34$ 5.83$ 5.73$ 5.49$ 5.67$ 5.67$ 5.87$ 5.98$
2012$
Avista Utilities 2014 Natural Gas IRP Appendices 134
Appendix - Chapter 5

APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
HIGH GROWTH LOW PRICE

Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
High Growth & Low Prices AECo 2013-2014 3.44$ 3.35$ 3.36$ 3.38$ 3.50$ 3.48$ 3.44$ 3.45$ 3.43$ 3.42$ 3.45$ 3.47$
High Growth & Low Prices AECo 2014-2015 3.50$ 3.43$ 3.55$ 3.56$ 3.70$ 3.63$ 3.56$ 3.55$ 3.52$ 3.51$ 3.55$ 3.61$
High Growth & Low Prices AECo 2015-2016 3.63$ 3.54$ 3.45$ 3.46$ 3.62$ 3.55$ 3.49$ 3.51$ 3.48$ 3.45$ 3.46$ 3.50$
High Growth & Low Prices AECo 2016-2017 3.54$ 3.45$ 3.41$ 3.43$ 3.54$ 3.44$ 3.37$ 3.37$ 3.35$ 3.34$ 3.36$ 3.41$
High Growth & Low Prices AECo 2017-2018 3.42$ 3.31$ 3.30$ 3.29$ 3.40$ 3.33$ 3.28$ 3.28$ 3.26$ 3.24$ 3.25$ 3.29$
High Growth & Low Prices AECo 2018-2019 3.40$ 3.27$ 3.11$ 3.12$ 3.31$ 3.22$ 3.17$ 3.14$ 3.12$ 3.10$ 3.12$ 3.17$
High Growth & Low Prices AECo 2019-2020 3.30$ 3.18$ 3.06$ 3.11$ 3.37$ 3.28$ 3.21$ 3.18$ 3.14$ 3.13$ 3.15$ 3.20$
High Growth & Low Prices AECo 2020-2021 3.28$ 3.13$ 3.12$ 3.16$ 3.38$ 3.28$ 3.20$ 3.16$ 3.08$ 3.07$ 3.13$ 3.18$
High Growth & Low Prices AECo 2021-2022 3.27$ 3.24$ 3.32$ 3.36$ 3.48$ 3.38$ 3.31$ 3.25$ 3.22$ 3.21$ 3.29$ 3.34$
High Growth & Low Prices AECo 2022-2023 3.39$ 3.32$ 3.20$ 3.19$ 3.32$ 3.19$ 3.05$ 2.99$ 2.96$ 2.94$ 3.01$ 3.06$
High Growth & Low Prices AECo 2023-2024 3.27$ 3.25$ 3.24$ 3.27$ 3.43$ 3.31$ 3.18$ 3.11$ 3.06$ 3.05$ 3.14$ 3.18$
High Growth & Low Prices AECo 2024-2025 3.29$ 3.31$ 3.39$ 3.37$ 3.50$ 3.39$ 3.33$ 3.28$ 3.22$ 3.22$ 3.30$ 3.35$
High Growth & Low Prices AECo 2025-2026 3.44$ 3.42$ 3.31$ 3.33$ 3.48$ 3.35$ 3.24$ 3.17$ 3.13$ 3.12$ 3.20$ 3.25$
High Growth & Low Prices AECo 2026-2027 3.40$ 3.39$ 3.23$ 3.15$ 3.45$ 3.24$ 3.16$ 3.08$ 3.05$ 3.04$ 3.13$ 3.18$
High Growth & Low Prices AECo 2027-2028 3.35$ 3.32$ 3.07$ 3.04$ 3.32$ 3.16$ 3.09$ 3.03$ 2.98$ 2.98$ 3.05$ 3.11$
High Growth & Low Prices AECo 2028-2029 3.33$ 3.30$ 3.30$ 3.36$ 3.58$ 3.37$ 3.31$ 3.24$ 3.20$ 3.18$ 3.24$ 3.28$
High Growth & Low Prices AECo 2029-2030 3.44$ 3.44$ 3.42$ 3.31$ 3.63$ 3.34$ 3.26$ 3.19$ 3.15$ 3.13$ 3.19$ 3.26$
High Growth & Low Prices AECo 2030-2031 3.57$ 3.52$ 3.32$ 3.22$ 3.61$ 3.41$ 3.36$ 3.29$ 3.28$ 3.27$ 3.34$ 3.39$
High Growth & Low Prices AECo 2031-2032 3.55$ 3.31$ 3.27$ 3.28$ 3.44$ 3.28$ 3.27$ 3.19$ 3.08$ 3.07$ 3.21$ 3.26$
High Growth & Low Prices AECo 2032-2033 3.37$ 3.31$ 3.31$ 3.30$ 3.45$ 3.28$ 3.27$ 3.22$ 3.10$ 3.08$ 3.24$ 3.31$
High Growth & Low Prices Malin 2013-2014 3.90$ 3.87$ 3.85$ 3.85$ 3.88$ 3.88$ 3.85$ 3.84$ 3.84$ 3.83$ 3.86$ 3.91$
High Growth & Low Prices Malin 2014-2015 3.93$ 3.93$ 4.00$ 4.01$ 4.04$ 4.03$ 3.96$ 3.95$ 3.93$ 3.92$ 3.97$ 4.02$
High Growth & Low Prices Malin 2015-2016 4.09$ 4.06$ 3.98$ 3.97$ 3.99$ 3.99$ 3.93$ 3.90$ 3.89$ 3.89$ 3.94$ 3.96$
High Growth & Low Prices Malin 2016-2017 4.07$ 3.98$ 3.92$ 3.91$ 3.93$ 3.91$ 3.91$ 3.89$ 3.89$ 3.89$ 3.94$ 3.94$
High Growth & Low Prices Malin 2017-2018 3.99$ 3.88$ 3.84$ 3.80$ 3.83$ 3.87$ 3.87$ 3.85$ 3.84$ 3.87$ 3.92$ 3.92$
High Growth & Low Prices Malin 2018-2019 4.01$ 3.86$ 3.70$ 3.66$ 3.78$ 3.81$ 3.81$ 3.79$ 3.77$ 3.79$ 3.82$ 3.87$
High Growth & Low Prices Malin 2019-2020 3.93$ 3.77$ 3.61$ 3.59$ 3.83$ 3.89$ 3.82$ 3.79$ 3.78$ 3.78$ 3.82$ 3.86$
High Growth & Low Prices Malin 2020-2021 3.95$ 3.80$ 3.63$ 3.63$ 3.87$ 3.93$ 3.78$ 3.74$ 3.73$ 3.73$ 3.81$ 3.86$
High Growth & Low Prices Malin 2021-2022 3.98$ 3.84$ 3.76$ 3.71$ 3.89$ 3.95$ 3.90$ 3.84$ 3.82$ 3.84$ 3.95$ 4.00$
High Growth & Low Prices Malin 2022-2023 4.06$ 3.88$ 3.71$ 3.71$ 3.86$ 3.83$ 3.69$ 3.57$ 3.55$ 3.53$ 3.72$ 3.76$
High Growth & Low Prices Malin 2023-2024 4.00$ 3.82$ 3.75$ 3.66$ 3.96$ 3.96$ 3.77$ 3.71$ 3.69$ 3.71$ 3.82$ 3.85$
High Growth & Low Prices Malin 2024-2025 4.01$ 3.89$ 3.89$ 3.72$ 3.98$ 4.03$ 3.96$ 3.89$ 3.91$ 3.91$ 4.01$ 4.03$
High Growth & Low Prices Malin 2025-2026 4.16$ 4.00$ 3.86$ 3.83$ 4.06$ 4.01$ 3.89$ 3.83$ 3.84$ 3.84$ 3.96$ 4.00$
High Growth & Low Prices Malin 2026-2027 4.14$ 4.07$ 3.77$ 3.58$ 3.94$ 3.90$ 3.82$ 3.74$ 3.74$ 3.75$ 3.84$ 3.91$
High Growth & Low Prices Malin 2027-2028 4.09$ 3.94$ 3.62$ 3.52$ 3.87$ 3.82$ 3.74$ 3.69$ 3.66$ 3.70$ 3.78$ 3.84$
High Growth & Low Prices Malin 2028-2029 4.06$ 3.88$ 3.86$ 3.77$ 3.97$ 3.93$ 3.90$ 3.84$ 3.87$ 3.85$ 3.93$ 3.98$
High Growth & Low Prices Malin 2029-2030 4.13$ 4.00$ 3.94$ 3.75$ 4.06$ 3.97$ 3.91$ 3.84$ 3.83$ 3.87$ 3.94$ 3.98$
High Growth & Low Prices Malin 2030-2031 4.29$ 4.11$ 3.90$ 3.70$ 4.04$ 4.02$ 4.00$ 3.93$ 3.94$ 3.98$ 4.06$ 4.09$
High Growth & Low Prices Malin 2031-2032 4.25$ 3.95$ 3.77$ 3.78$ 3.86$ 3.76$ 3.73$ 3.65$ 3.54$ 3.53$ 3.71$ 3.82$
High Growth & Low Prices Malin 2032-2033 3.90$ 3.85$ 3.83$ 3.83$ 3.87$ 3.75$ 3.74$ 3.67$ 3.56$ 3.56$ 3.76$ 3.86$
High Growth & Low Prices Rockies 2013-2014 3.86$ 3.84$ 3.82$ 3.81$ 3.85$ 3.83$ 3.82$ 3.81$ 3.80$ 3.79$ 3.81$ 3.86$
High Growth & Low Prices Rockies 2014-2015 3.89$ 3.89$ 3.97$ 3.97$ 4.01$ 3.97$ 3.93$ 3.92$ 3.89$ 3.88$ 3.93$ 3.95$
High Growth & Low Prices Rockies 2015-2016 4.02$ 4.02$ 3.94$ 3.94$ 3.95$ 3.95$ 3.90$ 3.87$ 3.84$ 3.84$ 3.89$ 3.91$
High Growth & Low Prices Rockies 2016-2017 3.98$ 3.94$ 3.89$ 3.87$ 3.90$ 3.86$ 3.83$ 3.80$ 3.79$ 3.78$ 3.82$ 3.84$
High Growth & Low Prices Rockies 2017-2018 3.89$ 3.83$ 3.80$ 3.76$ 3.79$ 3.79$ 3.78$ 3.75$ 3.74$ 3.73$ 3.77$ 3.77$
High Growth & Low Prices Rockies 2018-2019 3.85$ 3.81$ 3.66$ 3.61$ 3.73$ 3.73$ 3.68$ 3.65$ 3.61$ 3.64$ 3.67$ 3.68$
High Growth & Low Prices Rockies 2019-2020 3.68$ 3.63$ 3.57$ 3.54$ 3.69$ 3.67$ 3.62$ 3.60$ 3.57$ 3.56$ 3.60$ 3.62$
High Growth & Low Prices Rockies 2020-2021 3.65$ 3.65$ 3.57$ 3.55$ 3.63$ 3.58$ 3.57$ 3.48$ 3.49$ 3.48$ 3.54$ 3.57$
High Growth & Low Prices Rockies 2021-2022 3.58$ 3.61$ 3.57$ 3.52$ 3.54$ 3.57$ 3.52$ 3.46$ 3.44$ 3.44$ 3.52$ 3.54$
High Growth & Low Prices Rockies 2022-2023 3.56$ 3.49$ 3.41$ 3.37$ 3.45$ 3.41$ 3.30$ 3.24$ 3.23$ 3.22$ 3.29$ 3.33$
High Growth & Low Prices Rockies 2023-2024 3.46$ 3.43$ 3.35$ 3.31$ 3.42$ 3.42$ 3.29$ 3.20$ 3.18$ 3.17$ 3.26$ 3.34$
High Growth & Low Prices Rockies 2024-2025 3.38$ 3.38$ 3.61$ 3.62$ 3.66$ 3.65$ 3.63$ 3.56$ 3.56$ 3.56$ 3.62$ 3.64$
High Growth & Low Prices Rockies 2025-2026 3.68$ 3.61$ 3.53$ 3.52$ 3.61$ 3.60$ 3.51$ 3.44$ 3.44$ 3.43$ 3.50$ 3.58$
High Growth & Low Prices Rockies 2026-2027 3.59$ 3.57$ 3.59$ 3.48$ 3.66$ 3.65$ 3.60$ 3.52$ 3.53$ 3.52$ 3.61$ 3.65$
High Growth & Low Prices Rockies 2027-2028 3.71$ 3.70$ 3.47$ 3.43$ 3.60$ 3.57$ 3.53$ 3.45$ 3.45$ 3.45$ 3.52$ 3.58$
High Growth & Low Prices Rockies 2028-2029 3.67$ 3.63$ 3.56$ 3.47$ 3.65$ 3.64$ 3.61$ 3.51$ 3.52$ 3.52$ 3.58$ 3.59$
High Growth & Low Prices Rockies 2029-2030 3.66$ 3.63$ 3.61$ 3.51$ 3.70$ 3.66$ 3.59$ 3.52$ 3.52$ 3.52$ 3.58$ 3.64$
High Growth & Low Prices Rockies 2030-2031 3.73$ 3.67$ 3.53$ 3.46$ 3.67$ 3.64$ 3.61$ 3.54$ 3.56$ 3.59$ 3.65$ 3.66$
High Growth & Low Prices Rockies 2031-2032 3.68$ 3.56$ 3.36$ 3.36$ 3.42$ 3.35$ 3.32$ 3.23$ 3.13$ 3.12$ 3.29$ 3.36$
High Growth & Low Prices Rockies 2032-2033 3.40$ 3.39$ 3.36$ 3.36$ 3.38$ 3.32$ 3.30$ 3.22$ 3.13$ 3.11$ 3.29$ 3.37$
2012$
Avista Utilities 2014 Natural Gas IRP Appendices 135
Appendix - Chapter 5

APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
HIGH GROWTH LOW PRICE

Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
High Growth & Low Prices Stanfield 2013-2014 3.82$ 3.87$ 3.85$ 3.76$ 3.81$ 3.79$ 3.80$ 3.81$ 3.79$ 3.79$ 3.81$ 3.82$
High Growth & Low Prices Stanfield 2014-2015 3.89$ 3.83$ 3.93$ 3.94$ 4.01$ 3.94$ 3.92$ 3.91$ 3.89$ 3.87$ 3.91$ 3.93$
High Growth & Low Prices Stanfield 2015-2016 4.02$ 4.06$ 3.98$ 3.98$ 3.93$ 3.90$ 3.85$ 3.87$ 3.84$ 3.81$ 3.86$ 3.87$
High Growth & Low Prices Stanfield 2016-2017 3.97$ 3.99$ 3.93$ 3.82$ 3.86$ 3.82$ 3.77$ 3.75$ 3.75$ 3.75$ 3.78$ 3.81$
High Growth & Low Prices Stanfield 2017-2018 3.97$ 3.88$ 3.85$ 3.70$ 3.75$ 3.74$ 3.73$ 3.70$ 3.69$ 3.69$ 3.73$ 3.73$
High Growth & Low Prices Stanfield 2018-2019 3.97$ 3.86$ 3.70$ 3.67$ 3.69$ 3.77$ 3.63$ 3.60$ 3.58$ 3.59$ 3.62$ 3.77$
High Growth & Low Prices Stanfield 2019-2020 3.75$ 3.75$ 3.61$ 3.50$ 3.74$ 3.71$ 3.63$ 3.60$ 3.60$ 3.58$ 3.62$ 3.65$
High Growth & Low Prices Stanfield 2020-2021 3.76$ 3.73$ 3.63$ 3.54$ 3.77$ 3.73$ 3.61$ 3.57$ 3.53$ 3.53$ 3.61$ 3.65$
High Growth & Low Prices Stanfield 2021-2022 3.88$ 3.84$ 3.82$ 3.76$ 3.80$ 3.79$ 3.73$ 3.67$ 3.64$ 3.63$ 3.75$ 3.80$
High Growth & Low Prices Stanfield 2022-2023 4.00$ 3.88$ 3.61$ 3.61$ 3.70$ 3.63$ 3.51$ 3.45$ 3.42$ 3.41$ 3.49$ 3.52$
High Growth & Low Prices Stanfield 2023-2024 3.89$ 3.82$ 3.76$ 3.59$ 3.80$ 3.75$ 3.59$ 3.53$ 3.49$ 3.48$ 3.60$ 3.64$
High Growth & Low Prices Stanfield 2024-2025 3.92$ 3.89$ 3.79$ 3.68$ 3.86$ 3.82$ 3.79$ 3.71$ 3.68$ 3.68$ 3.77$ 3.81$
High Growth & Low Prices Stanfield 2025-2026 4.07$ 4.00$ 3.88$ 3.72$ 3.88$ 3.81$ 3.69$ 3.63$ 3.61$ 3.60$ 3.71$ 3.86$
High Growth & Low Prices Stanfield 2026-2027 4.03$ 4.02$ 3.79$ 3.53$ 3.82$ 3.82$ 3.63$ 3.55$ 3.53$ 3.53$ 3.62$ 3.81$
High Growth & Low Prices Stanfield 2027-2028 3.98$ 3.94$ 3.63$ 3.43$ 3.72$ 3.73$ 3.55$ 3.49$ 3.46$ 3.46$ 3.54$ 3.73$
High Growth & Low Prices Stanfield 2028-2029 3.95$ 3.88$ 3.88$ 3.83$ 3.90$ 3.78$ 3.73$ 3.66$ 3.66$ 3.65$ 3.73$ 3.76$
High Growth & Low Prices Stanfield 2029-2030 4.07$ 4.02$ 4.00$ 3.81$ 3.97$ 3.91$ 3.72$ 3.64$ 3.61$ 3.63$ 3.70$ 3.88$
High Growth & Low Prices Stanfield 2030-2031 4.21$ 4.13$ 3.92$ 3.76$ 3.98$ 3.96$ 3.81$ 3.75$ 3.74$ 3.75$ 3.82$ 3.87$
High Growth & Low Prices Stanfield 2031-2032 4.18$ 3.94$ 3.77$ 3.78$ 3.86$ 3.60$ 3.56$ 3.48$ 3.36$ 3.35$ 3.52$ 3.62$
High Growth & Low Prices Stanfield 2032-2033 3.88$ 3.83$ 3.82$ 3.82$ 3.87$ 3.59$ 3.69$ 3.51$ 3.38$ 3.37$ 3.56$ 3.67$
High Growth & Low Prices Sumas 2013-2014 3.97$ 4.09$ 4.02$ 3.91$ 3.88$ 3.66$ 3.73$ 3.68$ 3.70$ 3.62$ 3.68$ 3.70$
High Growth & Low Prices Sumas 2014-2015 4.04$ 4.15$ 4.19$ 4.09$ 4.04$ 3.82$ 3.87$ 3.77$ 3.74$ 3.69$ 3.79$ 3.83$
High Growth & Low Prices Sumas 2015-2016 4.18$ 4.28$ 4.15$ 4.05$ 3.99$ 3.74$ 3.80$ 3.72$ 3.69$ 3.63$ 3.70$ 3.75$
High Growth & Low Prices Sumas 2016-2017 4.14$ 4.21$ 4.10$ 3.98$ 3.93$ 3.63$ 3.68$ 3.62$ 3.61$ 3.53$ 3.60$ 3.69$
High Growth & Low Prices Sumas 2017-2018 4.04$ 4.10$ 4.01$ 3.87$ 3.84$ 3.60$ 3.59$ 3.54$ 3.52$ 3.43$ 3.50$ 3.60$
High Growth & Low Prices Sumas 2018-2019 4.04$ 4.08$ 3.87$ 3.74$ 3.78$ 3.50$ 3.47$ 3.40$ 3.39$ 3.34$ 3.36$ 3.39$
High Growth & Low Prices Sumas 2019-2020 3.79$ 3.97$ 3.78$ 3.66$ 3.71$ 3.46$ 3.50$ 3.44$ 3.41$ 3.36$ 3.38$ 3.41$
High Growth & Low Prices Sumas 2020-2021 3.76$ 3.95$ 3.80$ 3.71$ 3.75$ 3.46$ 3.49$ 3.42$ 3.34$ 3.30$ 3.36$ 3.38$
High Growth & Low Prices Sumas 2021-2022 3.95$ 4.06$ 3.99$ 3.83$ 3.84$ 3.59$ 3.62$ 3.53$ 3.50$ 3.46$ 3.54$ 3.57$
High Growth & Low Prices Sumas 2022-2023 4.07$ 4.10$ 3.88$ 3.63$ 3.60$ 3.40$ 3.33$ 3.23$ 3.25$ 3.16$ 3.27$ 3.29$
High Growth & Low Prices Sumas 2023-2024 3.74$ 4.04$ 3.93$ 3.66$ 3.75$ 3.57$ 3.48$ 3.38$ 3.37$ 3.29$ 3.41$ 3.46$
High Growth & Low Prices Sumas 2024-2025 3.77$ 4.11$ 4.07$ 3.76$ 3.82$ 3.63$ 3.63$ 3.54$ 3.53$ 3.45$ 3.57$ 3.62$
High Growth & Low Prices Sumas 2025-2026 3.91$ 4.22$ 4.05$ 3.90$ 3.82$ 3.60$ 3.53$ 3.43$ 3.43$ 3.35$ 3.47$ 3.50$
High Growth & Low Prices Sumas 2026-2027 3.88$ 4.24$ 3.96$ 3.70$ 3.76$ 3.47$ 3.47$ 3.35$ 3.37$ 3.29$ 3.41$ 3.44$
High Growth & Low Prices Sumas 2027-2028 3.83$ 4.16$ 3.80$ 3.59$ 3.65$ 3.39$ 3.38$ 3.28$ 3.27$ 3.24$ 3.31$ 3.34$
High Growth & Low Prices Sumas 2028-2029 4.02$ 4.10$ 4.05$ 3.90$ 3.97$ 3.62$ 3.63$ 3.50$ 3.53$ 3.48$ 3.54$ 3.56$
High Growth & Low Prices Sumas 2029-2030 4.14$ 4.32$ 4.38$ 3.88$ 4.06$ 3.58$ 3.56$ 3.44$ 3.46$ 3.41$ 3.48$ 3.52$
High Growth & Low Prices Sumas 2030-2031 4.27$ 4.42$ 4.39$ 3.83$ 4.08$ 3.65$ 3.67$ 3.55$ 3.60$ 3.56$ 3.63$ 3.66$
High Growth & Low Prices Sumas 2031-2032 4.25$ 4.34$ 3.99$ 4.00$ 3.90$ 3.44$ 3.33$ 3.07$ 3.23$ 3.20$ 3.33$ 3.44$
High Growth & Low Prices Sumas 2032-2033 3.93$ 4.16$ 4.15$ 4.16$ 3.92$ 3.44$ 3.33$ 3.10$ 3.25$ 3.22$ 3.36$ 3.49$
2012$
Avista Utilities 2014 Natural Gas IRP Appendices 136
Appendix - Chapter 5

APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
LOW GROWTH HIGH PRICE

Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Low Growth & High Prices AECo 2013-2014 3.26$ 3.65$ 4.18$ 3.34$ 3.90$ 3.88$ 3.84$ 3.85$ 3.83$ 3.82$ 3.85$ 3.87$
Low Growth & High Prices AECo 2014-2015 3.90$ 3.83$ 4.15$ 4.16$ 4.30$ 4.23$ 4.16$ 4.15$ 4.12$ 4.11$ 4.15$ 4.21$
Low Growth & High Prices AECo 2015-2016 4.23$ 4.14$ 4.25$ 4.26$ 4.42$ 4.35$ 4.29$ 4.31$ 4.28$ 4.25$ 4.26$ 4.30$
Low Growth & High Prices AECo 2016-2017 4.34$ 4.25$ 4.41$ 4.43$ 4.54$ 4.44$ 4.37$ 4.37$ 4.35$ 4.34$ 4.36$ 4.41$
Low Growth & High Prices AECo 2017-2018 4.42$ 4.31$ 4.60$ 4.59$ 4.70$ 4.63$ 4.58$ 4.58$ 4.56$ 4.54$ 4.55$ 4.59$
Low Growth & High Prices AECo 2018-2019 4.70$ 4.57$ 4.61$ 4.62$ 4.81$ 4.72$ 4.67$ 4.64$ 4.62$ 4.60$ 4.62$ 4.67$
Low Growth & High Prices AECo 2019-2020 4.80$ 4.68$ 4.66$ 4.71$ 4.97$ 4.88$ 4.81$ 4.78$ 4.74$ 4.73$ 4.75$ 4.80$
Low Growth & High Prices AECo 2020-2021 4.88$ 4.73$ 4.84$ 4.87$ 5.09$ 5.00$ 4.91$ 4.87$ 4.79$ 4.78$ 4.84$ 4.89$
Low Growth & High Prices AECo 2021-2022 4.99$ 4.95$ 5.32$ 5.36$ 5.48$ 5.38$ 5.31$ 5.25$ 5.23$ 5.21$ 5.30$ 5.34$
Low Growth & High Prices AECo 2022-2023 5.39$ 5.32$ 5.39$ 5.38$ 5.51$ 5.38$ 5.24$ 5.18$ 5.15$ 5.13$ 5.20$ 5.24$
Low Growth & High Prices AECo 2023-2024 5.45$ 5.43$ 5.71$ 5.74$ 5.90$ 5.78$ 5.65$ 5.59$ 5.54$ 5.53$ 5.61$ 5.66$
Low Growth & High Prices AECo 2024-2025 5.76$ 5.78$ 6.04$ 6.03$ 6.16$ 6.04$ 5.99$ 5.93$ 5.88$ 5.87$ 5.95$ 6.00$
Low Growth & High Prices AECo 2025-2026 6.09$ 6.08$ 6.25$ 6.27$ 6.42$ 6.29$ 6.18$ 6.11$ 6.06$ 6.05$ 6.14$ 6.19$
Low Growth & High Prices AECo 2026-2027 6.34$ 6.33$ 6.45$ 6.37$ 6.67$ 6.46$ 6.38$ 6.30$ 6.27$ 6.26$ 6.35$ 6.40$
Low Growth & High Prices AECo 2027-2028 6.57$ 6.54$ 6.57$ 6.54$ 6.82$ 6.66$ 6.59$ 6.53$ 6.48$ 6.48$ 6.55$ 6.61$
Low Growth & High Prices AECo 2028-2029 6.82$ 6.80$ 7.07$ 7.14$ 7.36$ 7.15$ 7.09$ 7.02$ 6.98$ 6.95$ 7.02$ 7.06$
Low Growth & High Prices AECo 2029-2030 7.21$ 7.21$ 7.47$ 7.36$ 7.68$ 7.39$ 7.31$ 7.24$ 7.20$ 7.18$ 7.24$ 7.31$
Low Growth & High Prices AECo 2030-2031 7.62$ 7.57$ 7.64$ 7.54$ 7.94$ 7.73$ 7.68$ 7.62$ 7.60$ 7.59$ 7.66$ 7.71$
Low Growth & High Prices AECo 2031-2032 7.87$ 7.64$ 7.87$ 7.88$ 8.04$ 7.88$ 7.86$ 7.79$ 7.68$ 7.66$ 7.81$ 7.86$
Low Growth & High Prices AECo 2032-2033 7.96$ 7.91$ 8.28$ 8.27$ 8.42$ 8.25$ 8.24$ 8.19$ 8.07$ 8.05$ 8.21$ 8.28$
Low Growth & High Prices Malin 2013-2014 3.62$ 4.53$ 4.69$ 3.81$ 4.28$ 4.28$ 4.25$ 4.24$ 4.24$ 4.23$ 4.26$ 4.31$
Low Growth & High Prices Malin 2014-2015 4.33$ 4.33$ 4.60$ 4.61$ 4.64$ 4.63$ 4.56$ 4.55$ 4.53$ 4.52$ 4.57$ 4.62$
Low Growth & High Prices Malin 2015-2016 4.69$ 4.66$ 4.78$ 4.77$ 4.79$ 4.79$ 4.73$ 4.70$ 4.69$ 4.69$ 4.74$ 4.76$
Low Growth & High Prices Malin 2016-2017 4.87$ 4.78$ 4.92$ 4.91$ 4.93$ 4.91$ 4.91$ 4.89$ 4.89$ 4.89$ 4.94$ 4.94$
Low Growth & High Prices Malin 2017-2018 4.99$ 4.88$ 5.14$ 5.10$ 5.13$ 5.17$ 5.17$ 5.15$ 5.14$ 5.17$ 5.22$ 5.22$
Low Growth & High Prices Malin 2018-2019 5.31$ 5.16$ 5.20$ 5.16$ 5.28$ 5.31$ 5.31$ 5.29$ 5.27$ 5.29$ 5.32$ 5.37$
Low Growth & High Prices Malin 2019-2020 5.43$ 5.27$ 5.21$ 5.19$ 5.43$ 5.49$ 5.42$ 5.39$ 5.38$ 5.38$ 5.42$ 5.46$
Low Growth & High Prices Malin 2020-2021 5.55$ 5.40$ 5.34$ 5.35$ 5.58$ 5.65$ 5.50$ 5.46$ 5.44$ 5.44$ 5.52$ 5.58$
Low Growth & High Prices Malin 2021-2022 5.70$ 5.55$ 5.76$ 5.71$ 5.90$ 5.95$ 5.90$ 5.84$ 5.82$ 5.84$ 5.95$ 6.00$
Low Growth & High Prices Malin 2022-2023 6.07$ 5.88$ 5.90$ 5.89$ 6.05$ 6.02$ 5.87$ 5.75$ 5.74$ 5.72$ 5.91$ 5.95$
Low Growth & High Prices Malin 2023-2024 6.19$ 6.01$ 6.22$ 6.13$ 6.43$ 6.43$ 6.24$ 6.18$ 6.16$ 6.19$ 6.29$ 6.33$
Low Growth & High Prices Malin 2024-2025 6.48$ 6.37$ 6.55$ 6.38$ 6.64$ 6.68$ 6.62$ 6.54$ 6.57$ 6.57$ 6.66$ 6.68$
Low Growth & High Prices Malin 2025-2026 6.82$ 6.66$ 6.80$ 6.76$ 6.99$ 6.95$ 6.83$ 6.77$ 6.78$ 6.78$ 6.89$ 6.93$
Low Growth & High Prices Malin 2026-2027 7.08$ 7.01$ 6.99$ 6.79$ 7.16$ 7.12$ 7.04$ 6.96$ 6.95$ 6.97$ 7.06$ 7.13$
Low Growth & High Prices Malin 2027-2028 7.31$ 7.16$ 7.12$ 7.02$ 7.37$ 7.32$ 7.23$ 7.18$ 7.16$ 7.20$ 7.28$ 7.33$
Low Growth & High Prices Malin 2028-2029 7.56$ 7.38$ 7.63$ 7.54$ 7.74$ 7.71$ 7.67$ 7.61$ 7.64$ 7.63$ 7.71$ 7.76$
Low Growth & High Prices Malin 2029-2030 7.91$ 7.78$ 8.00$ 7.80$ 8.11$ 8.03$ 7.96$ 7.89$ 7.88$ 7.92$ 7.99$ 8.04$
Low Growth & High Prices Malin 2030-2031 8.34$ 8.16$ 8.23$ 8.03$ 8.37$ 8.34$ 8.32$ 8.26$ 8.27$ 8.30$ 8.39$ 8.42$
Low Growth & High Prices Malin 2031-2032 8.57$ 8.27$ 8.37$ 8.38$ 8.46$ 8.36$ 8.33$ 8.24$ 8.13$ 8.13$ 8.31$ 8.41$
Low Growth & High Prices Malin 2032-2033 8.50$ 8.44$ 8.80$ 8.79$ 8.83$ 8.72$ 8.70$ 8.64$ 8.53$ 8.52$ 8.72$ 8.83$
Low Growth & High Prices Rockies 2013-2014 3.53$ 4.56$ 4.66$ 3.77$ 4.25$ 4.23$ 4.22$ 4.21$ 4.20$ 4.19$ 4.21$ 4.26$
Low Growth & High Prices Rockies 2014-2015 4.29$ 4.29$ 4.57$ 4.57$ 4.61$ 4.57$ 4.53$ 4.52$ 4.49$ 4.48$ 4.53$ 4.55$
Low Growth & High Prices Rockies 2015-2016 4.62$ 4.62$ 4.74$ 4.74$ 4.75$ 4.75$ 4.70$ 4.67$ 4.64$ 4.64$ 4.69$ 4.71$
Low Growth & High Prices Rockies 2016-2017 4.78$ 4.74$ 4.89$ 4.87$ 4.90$ 4.86$ 4.83$ 4.80$ 4.79$ 4.78$ 4.82$ 4.84$
Low Growth & High Prices Rockies 2017-2018 4.89$ 4.83$ 5.10$ 5.06$ 5.09$ 5.09$ 5.08$ 5.05$ 5.04$ 5.03$ 5.07$ 5.07$
Low Growth & High Prices Rockies 2018-2019 5.15$ 5.11$ 5.16$ 5.11$ 5.23$ 5.23$ 5.18$ 5.15$ 5.11$ 5.14$ 5.17$ 5.18$
Low Growth & High Prices Rockies 2019-2020 5.18$ 5.13$ 5.17$ 5.14$ 5.29$ 5.27$ 5.22$ 5.20$ 5.17$ 5.16$ 5.20$ 5.22$
Low Growth & High Prices Rockies 2020-2021 5.25$ 5.25$ 5.28$ 5.27$ 5.34$ 5.29$ 5.28$ 5.19$ 5.21$ 5.20$ 5.25$ 5.28$
Low Growth & High Prices Rockies 2021-2022 5.29$ 5.32$ 5.57$ 5.52$ 5.55$ 5.57$ 5.52$ 5.47$ 5.44$ 5.44$ 5.52$ 5.54$
Low Growth & High Prices Rockies 2022-2023 5.57$ 5.49$ 5.59$ 5.56$ 5.64$ 5.60$ 5.49$ 5.43$ 5.41$ 5.41$ 5.48$ 5.52$
Low Growth & High Prices Rockies 2023-2024 5.65$ 5.61$ 5.82$ 5.79$ 5.89$ 5.89$ 5.76$ 5.67$ 5.65$ 5.64$ 5.73$ 5.81$
Low Growth & High Prices Rockies 2024-2025 5.86$ 5.85$ 6.27$ 6.28$ 6.32$ 6.31$ 6.28$ 6.21$ 6.22$ 6.21$ 6.28$ 6.29$
Low Growth & High Prices Rockies 2025-2026 6.33$ 6.27$ 6.47$ 6.46$ 6.55$ 6.54$ 6.45$ 6.38$ 6.38$ 6.37$ 6.44$ 6.52$
Low Growth & High Prices Rockies 2026-2027 6.53$ 6.50$ 6.81$ 6.70$ 6.88$ 6.87$ 6.82$ 6.74$ 6.75$ 6.74$ 6.83$ 6.87$
Low Growth & High Prices Rockies 2027-2028 6.93$ 6.92$ 6.96$ 6.93$ 7.09$ 7.07$ 7.03$ 6.95$ 6.95$ 6.94$ 7.02$ 7.08$
Low Growth & High Prices Rockies 2028-2029 7.17$ 7.13$ 7.34$ 7.25$ 7.42$ 7.41$ 7.38$ 7.29$ 7.30$ 7.30$ 7.35$ 7.37$
Low Growth & High Prices Rockies 2029-2030 7.43$ 7.40$ 7.66$ 7.56$ 7.75$ 7.72$ 7.64$ 7.57$ 7.57$ 7.57$ 7.64$ 7.70$
Low Growth & High Prices Rockies 2030-2031 7.78$ 7.72$ 7.86$ 7.79$ 8.00$ 7.97$ 7.93$ 7.87$ 7.89$ 7.91$ 7.98$ 7.99$
Low Growth & High Prices Rockies 2031-2032 8.01$ 7.89$ 7.96$ 7.96$ 8.01$ 7.95$ 7.92$ 7.83$ 7.73$ 7.72$ 7.89$ 7.96$
Low Growth & High Prices Rockies 2032-2033 8.00$ 7.99$ 8.33$ 8.33$ 8.35$ 8.29$ 8.27$ 8.19$ 8.09$ 8.08$ 8.25$ 8.34$
2012$
Avista Utilities 2014 Natural Gas IRP Appendices 137
Appendix - Chapter 5

APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
LOW GROWTH HIGH PRICE

Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Low Growth & High Prices Stanfield 2013-2014 3.60$ 4.56$ 4.66$ 3.72$ 4.21$ 4.19$ 4.20$ 4.21$ 4.19$ 4.19$ 4.21$ 4.22$
Low Growth & High Prices Stanfield 2014-2015 4.29$ 4.23$ 4.53$ 4.54$ 4.61$ 4.54$ 4.52$ 4.51$ 4.49$ 4.47$ 4.51$ 4.53$
Low Growth & High Prices Stanfield 2015-2016 4.62$ 4.66$ 4.78$ 4.78$ 4.73$ 4.70$ 4.65$ 4.67$ 4.64$ 4.61$ 4.66$ 4.67$
Low Growth & High Prices Stanfield 2016-2017 4.77$ 4.79$ 4.93$ 4.82$ 4.86$ 4.82$ 4.77$ 4.75$ 4.75$ 4.75$ 4.78$ 4.81$
Low Growth & High Prices Stanfield 2017-2018 4.97$ 4.88$ 5.15$ 5.00$ 5.05$ 5.04$ 5.03$ 5.00$ 4.99$ 4.99$ 5.03$ 5.03$
Low Growth & High Prices Stanfield 2018-2019 5.27$ 5.16$ 5.20$ 5.17$ 5.19$ 5.27$ 5.13$ 5.10$ 5.08$ 5.09$ 5.12$ 5.27$
Low Growth & High Prices Stanfield 2019-2020 5.25$ 5.25$ 5.21$ 5.10$ 5.34$ 5.31$ 5.23$ 5.20$ 5.20$ 5.18$ 5.22$ 5.25$
Low Growth & High Prices Stanfield 2020-2021 5.36$ 5.33$ 5.34$ 5.25$ 5.48$ 5.44$ 5.32$ 5.28$ 5.25$ 5.24$ 5.32$ 5.37$
Low Growth & High Prices Stanfield 2021-2022 5.59$ 5.55$ 5.82$ 5.76$ 5.80$ 5.79$ 5.73$ 5.67$ 5.64$ 5.64$ 5.75$ 5.80$
Low Growth & High Prices Stanfield 2022-2023 6.00$ 5.89$ 5.79$ 5.79$ 5.88$ 5.81$ 5.69$ 5.63$ 5.60$ 5.59$ 5.68$ 5.71$
Low Growth & High Prices Stanfield 2023-2024 6.08$ 6.01$ 6.24$ 6.06$ 6.27$ 6.22$ 6.07$ 6.00$ 5.96$ 5.95$ 6.07$ 6.12$
Low Growth & High Prices Stanfield 2024-2025 6.39$ 6.36$ 6.44$ 6.33$ 6.52$ 6.48$ 6.44$ 6.36$ 6.34$ 6.33$ 6.43$ 6.46$
Low Growth & High Prices Stanfield 2025-2026 6.72$ 6.66$ 6.81$ 6.66$ 6.82$ 6.75$ 6.63$ 6.56$ 6.55$ 6.54$ 6.65$ 6.80$
Low Growth & High Prices Stanfield 2026-2027 6.97$ 6.96$ 7.01$ 6.75$ 7.04$ 7.03$ 6.85$ 6.77$ 6.75$ 6.75$ 6.83$ 7.02$
Low Growth & High Prices Stanfield 2027-2028 7.20$ 7.16$ 7.13$ 6.93$ 7.22$ 7.23$ 7.05$ 6.99$ 6.96$ 6.96$ 7.04$ 7.23$
Low Growth & High Prices Stanfield 2028-2029 7.45$ 7.38$ 7.65$ 7.60$ 7.67$ 7.56$ 7.50$ 7.43$ 7.44$ 7.42$ 7.50$ 7.54$
Low Growth & High Prices Stanfield 2029-2030 7.85$ 7.80$ 8.06$ 7.86$ 8.02$ 7.97$ 7.77$ 7.69$ 7.66$ 7.68$ 7.75$ 7.93$
Low Growth & High Prices Stanfield 2030-2031 8.26$ 8.18$ 8.25$ 8.09$ 8.30$ 8.29$ 8.14$ 8.07$ 8.06$ 8.08$ 8.15$ 8.19$
Low Growth & High Prices Stanfield 2031-2032 8.51$ 8.27$ 8.37$ 8.37$ 8.45$ 8.20$ 8.16$ 8.08$ 7.96$ 7.94$ 8.12$ 8.22$
Low Growth & High Prices Stanfield 2032-2033 8.48$ 8.43$ 8.79$ 8.78$ 8.83$ 8.56$ 8.66$ 8.47$ 8.35$ 8.34$ 8.53$ 8.63$
Low Growth & High Prices Sumas 2013-2014 3.93$ 5.31$ 4.68$ 3.87$ 4.28$ 4.06$ 4.13$ 4.08$ 4.10$ 4.02$ 4.08$ 4.10$
Low Growth & High Prices Sumas 2014-2015 4.44$ 4.55$ 4.79$ 4.69$ 4.64$ 4.42$ 4.47$ 4.37$ 4.34$ 4.29$ 4.39$ 4.43$
Low Growth & High Prices Sumas 2015-2016 4.78$ 4.88$ 4.95$ 4.85$ 4.79$ 4.54$ 4.60$ 4.52$ 4.49$ 4.43$ 4.50$ 4.55$
Low Growth & High Prices Sumas 2016-2017 4.94$ 5.01$ 5.10$ 4.98$ 4.93$ 4.63$ 4.68$ 4.62$ 4.61$ 4.53$ 4.60$ 4.69$
Low Growth & High Prices Sumas 2017-2018 5.04$ 5.10$ 5.31$ 5.17$ 5.14$ 4.90$ 4.89$ 4.84$ 4.82$ 4.73$ 4.80$ 4.90$
Low Growth & High Prices Sumas 2018-2019 5.34$ 5.38$ 5.37$ 5.24$ 5.28$ 5.00$ 4.97$ 4.90$ 4.89$ 4.84$ 4.86$ 4.89$
Low Growth & High Prices Sumas 2019-2020 5.29$ 5.47$ 5.38$ 5.26$ 5.31$ 5.06$ 5.10$ 5.04$ 5.01$ 4.96$ 4.98$ 5.01$
Low Growth & High Prices Sumas 2020-2021 5.36$ 5.55$ 5.51$ 5.42$ 5.47$ 5.18$ 5.21$ 5.13$ 5.05$ 5.02$ 5.07$ 5.10$
Low Growth & High Prices Sumas 2021-2022 5.66$ 5.77$ 5.99$ 5.83$ 5.84$ 5.59$ 5.62$ 5.53$ 5.50$ 5.46$ 5.54$ 5.57$
Low Growth & High Prices Sumas 2022-2023 6.07$ 6.10$ 6.07$ 5.82$ 5.78$ 5.59$ 5.52$ 5.41$ 5.43$ 5.35$ 5.45$ 5.48$
Low Growth & High Prices Sumas 2023-2024 5.93$ 6.23$ 6.41$ 6.14$ 6.22$ 6.04$ 5.95$ 5.85$ 5.84$ 5.76$ 5.89$ 5.94$
Low Growth & High Prices Sumas 2024-2025 6.24$ 6.58$ 6.72$ 6.42$ 6.47$ 6.29$ 6.28$ 6.19$ 6.18$ 6.11$ 6.22$ 6.28$
Low Growth & High Prices Sumas 2025-2026 6.57$ 6.88$ 6.98$ 6.83$ 6.76$ 6.54$ 6.47$ 6.37$ 6.36$ 6.29$ 6.41$ 6.43$
Low Growth & High Prices Sumas 2026-2027 6.82$ 7.18$ 7.18$ 6.92$ 6.98$ 6.69$ 6.69$ 6.57$ 6.59$ 6.51$ 6.63$ 6.66$
Low Growth & High Prices Sumas 2027-2028 7.05$ 7.38$ 7.30$ 7.09$ 7.15$ 6.89$ 6.87$ 6.78$ 6.77$ 6.74$ 6.81$ 6.84$
Low Growth & High Prices Sumas 2028-2029 7.52$ 7.60$ 7.82$ 7.67$ 7.74$ 7.40$ 7.41$ 7.28$ 7.31$ 7.26$ 7.32$ 7.34$
Low Growth & High Prices Sumas 2029-2030 7.92$ 8.09$ 8.43$ 7.93$ 8.12$ 7.64$ 7.62$ 7.49$ 7.51$ 7.47$ 7.53$ 7.58$
Low Growth & High Prices Sumas 2030-2031 8.33$ 8.47$ 8.72$ 8.16$ 8.40$ 7.98$ 8.00$ 7.88$ 7.93$ 7.89$ 7.96$ 7.99$
Low Growth & High Prices Sumas 2031-2032 8.58$ 8.66$ 8.59$ 8.59$ 8.50$ 8.04$ 7.93$ 7.67$ 7.82$ 7.79$ 7.92$ 8.04$
Low Growth & High Prices Sumas 2032-2033 8.53$ 8.75$ 9.12$ 9.12$ 8.88$ 8.41$ 8.30$ 8.07$ 8.21$ 8.19$ 8.33$ 8.45$
2012$
Avista Utilities 2014 Natural Gas IRP Appendices 138
Appendix - Chapter 5

APPENDIX 5.2: WEIGHTED AVERAGE COST OF CAPITAL

Avista Utilities 2014 Natural Gas IRP Appendices 139
Appendix - Chapter 5

APPENDIX 5.3: POTENTIAL SUPPLY SIDE RESOURCE OPTIONS

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Avista Utilities 2014 Natural Gas IRP Appendices 140
Appendix - Chapter 5

APPENDIX 5.4: EXPECTED CASE AVOIDED COST

Avista Utilities 2014 Natural Gas IRP Appendices 141
Appendix - Chapter 5

APPENDIX 5.4: LOW GROWTH CASE AVOIDED COST

Avista Utilities 2014 Natural Gas IRP Appendices 142
Appendix - Chapter 5

APPENDIX 5.4: HIGH GROWTH CASE AVOIDED COST

Avista Utilities 2014 Natural Gas IRP Appendices 143
Appendix - Chapter 5

APPENDIX 5.4: CARBON LEGISLATION – MEDIUM CASE AVOIDED COST

Avista Utilities 2014 Natural Gas IRP Appendices 144
Appendix - Chapter 5

APPENDIX 5.4: COLD DAY 20 YR WEATHER STANDARD AVOIDED COST

Avista Utilities 2014 Natural Gas IRP Appendices 145
Appendix - Chapter 5

APPENDIX 5.4: WASHINGTON AND IDAHO AVOIDED COSTS -
LOW GROWTH/HIGH PRICE CASE

APPENDIX 5.4: NATURAL GAS OREGON AVOIDED COSTS -
LOW GROWTH/HIGH PRICE CASE

Avista Utilities 2014 Natural Gas IRP Appendices 146
Appendix - Chapter 5

APPENDIX 5.4: LOW GROWTH – HIGH PRICE MONTHLY DETAIL

Avista Utilities 2014 Natural Gas IRP Appendices 147
Appendix - Chapter 5

APPENDIX 5.4: LOW GROWTH – HIGH PRICE MONTHLY DETAIL

Avista Utilities 2014 Natural Gas IRP Appendices 148
Appendix - Chapter 5

APPENDIX 5.4: LOW GROWTH – HIGH PRICE MONTHLY DETAIL

Avista Utilities 2014 Natural Gas IRP Appendices 149
Appendix - Chapter 5

APPENDIX 5.4: EXPECTED MONTHLY DETAIL

Avista Utilities 2014 Natural Gas IRP Appendices 150
Appendix - Chapter 5

APPENDIX 5.4: EXPECTED MONTHLY DETAIL

Avista Utilities 2014 Natural Gas IRP Appendices 151
Appendix - Chapter 5

APPENDIX 5.4: EXPECTED MONTHLY DETAIL

Avista Utilities 2014 Natural Gas IRP Appendices 152
Appendix - Chapter 5

APPENDIX 5.4: HIGH GROWTH – LOW PRICE MONTHLY DETAIL

Avista Utilities 2014 Natural Gas IRP Appendices 153
Appendix - Chapter 5

APPENDIX 5.4: HIGH GROWTH – LOW PRICE MONTHLY DETAIL

Avista Utilities 2014 Natural Gas IRP Appendices 154
Appendix - Chapter 5

APPENDIX 5.4: HIGH GROWTH – LOW PRICE MONTHLY DETAIL

Avista Utilities 2014 Natural Gas IRP Appendices 155
Appendix - Chapter 5

Avista Utilities 2014 Natural Gas IRP Appendices 156
Appendix - Chapter 6

APPENDIX 6.1: HIGH GROWTH CASES
SELECTED RESOURCES VS. PEAK DAY DEMAND
EXISTING PLUS EXPECTED AVAILABLE

Avista Utilities 2014 Natural Gas IRP Appendices 157
Appendix - Chapter 6

APPENDIX 6.1: HIGH GROWTH CASES
SELECTED RESOURCES VS. PEAK DAY DEMAND
EXISTING PLUS EXPECTED AVAILABLE

Avista Utilities 2014 Natural Gas IRP Appendices 158
Appendix - Chapter 6

APPENDIX 6.2: PEAK DAY DEMAND TABLE
HIGH GROWTH

Avista Utilities 2014 Natural Gas IRP Appendices 159
Appendix - Chapter 6

APPENDIX 6.2: PEAK DAY DEMAND TABLE
LOW GROWTH

Avista Utilities 2014 Natural Gas IRP Appendices 160
Appendix - Chapter 6

APPENDIX 6.2: PEAK DAY DEMAND TABLE
COLDEST IN 20 YEARS

Avista Utilities 2014 Natural Gas IRP Appendices 161
Appendix - Chapter 6

Avista Utilities 2014 Natural Gas IRP Appendices 162
APPENDIX – CHAPTER 7

APPENDIX 7.1: DISTRIBUTION SYSTEM MODELING
OVERVIEW
The primary goal of distribution system planning is to design for present needs and to plan for future
expansion to serve demand growth. This allows Avista to satisfy current demand-serving requirements
while taking steps toward meeting future needs. Distribution system planning identifies potential
problems and areas of the distribution system that require reinforcement. By knowing when and where
pressure problems may occur, the necessary reinforcements can be incorporated into normal maintenance.
Thus, more costly reactive and emergency solutions can be avoided.
COMPUTER MODELING
When designing new main extensions, computer modeling can help determine the optimum size facilities
for present and future needs. Undersized facilities are costly to replace, and oversized facilities incur
unnecessary expenses to Avista and its customers.
THEORY AND APPLICATION OF STUDY
Natural gas network load studies have evolved in the last decade to become a highly technical and useful
means of analyzing the operation of a distribution system. Using a pipeline fluid flow formula, a specified
parameter of each pipe element can be simultaneously solved. Through years of research, pipeline
equations have been refined to the point where solutions obtained closely represent actual system
behavior.
Avista conducts network load studies using GL Noble Denton’s SynerGEE® 4.6.0 software. This
computer-based modeling tool runs on a Windows operating system and allows users to analyze and
interpret solutions graphically.
CREATING A MODEL
To properly study the distribution system, all natural gas main information is entered (length, pipe
roughness and ID) into the model. "Main" refers to all pipelines supplying services.
Nodes are placed at all pipe intersections, beginnings and ends of mains, changes in pipe
diameter/material, and to identify all large customers. A model element connects two nodes together.
Therefore, a "to node" and a "from node" will represent an element between those two nodes. Almost all
of the elements in a model are pipes.
Regulators are treated like adjustable valves in which the downstream pressure is set to a known value.
Although specific regulator types can be entered for realistic behavior, the expected flow passing through
the actual regulator is determined and the modeled regulator is forced to accommodate such flows.
FLUID MECHANICS OF THE MODEL
Pipe flow equations are used to determine the relationships between flow, pressure drop, diameter and
pipe length. For all models, the Fundamental Flow equation (FM) is used due to its demonstrated
reliability.
Avista Utilities 2014 Natural Gas IRP Appendices 163
APPENDIX – CHAPTER 7

Efficiency factors are used to account for the equivalent resistance of valves, fittings and angle changes
within the distribution system. Starting with a 95 percent factor, the efficiency can be changed to fine tune
the model to match field results.
Pipe roughness, along with flow conditions, creates a friction factor for all pipes within a system. Thus,
each pipe may have a unique friction factor, minimizing computational errors associated with generalized
friction values.
LOAD DATA
All studies are considered steady state; all natural gas entering the distribution system must equal the
natural gas exiting the distribution system at any given time.
Customer loads are obtained from Avista’s customer billing system and converted to an algebraic format
so loads can be generated for various conditions. Customer Management Module (CMM), a new add-on
application for SynerGEE, processes customer usage history and generates a base load (non-temperature
dependent) and heat load (varying with temperature) for each customer.
In the event of a peak day or an extremely cold weather condition, it is assumed that all curtailable loads
are interrupted. Therefore, the models will be conducted with only core loads.
DETERMINING NATURAL GAS CUSTOMERS’ MAXIMUM HOURLY USAGE
DETERMINING DESIGN PEAK HOURLY LOAD
The design peak hourly load for a customer is estimated by adding the hourly base load and the hourly
heat load for a design temperature. This estimate reflects highest system hourly demands, as shown in
Table 1:

This method differs from the approach that we use for IRP peak day load planning. The primary reason
for this difference is due to the importance of responding to hourly peaking in the distribution system,
while IRP resource planning focuses on peak day requirements to the city gate.
APPLYING LOADS
Having estimated the peak loads for all customers in a particular service area, the model can be loaded.
The first step is to assign each load to the respective node or element.
GENERATING LOADS
Temperature-based and non-temperature-based loads are established for each node or element, thus loads
can be varied based on any temperature (HDD). Such a tool is necessary to evaluate the difference in flow
and pressure due to different weather conditions.

Table 1 - Determining Peak* Hourly Load
Peak Hourly Base
Load
Peak Hourly
Heat Load
Peak Hourly
Load + =
Avista Utilities 2014 Natural Gas IRP Appendices 164
APPENDIX – CHAPTER 7

GEOGRAPHIC INFORMATION SYSTEM (GIS)
Several years ago Avista converted its natural gas facility maps to GIS. While the GIS can provide a
variety of map products, its power lies in its analytical capability. A GIS consists of three components:
spatial operations, data association and map representation.
A GIS allows analysts to conduct spatial operations (relating a feature or facility to another
geographically). A spatial operation is possible if a facility displayed on a map maintains a relationship to
other facilities. Spatial relationships allow analysts to perform a multitude of queries, including:
 Identify electric customers adjacent to natural gas mains who are not currently using natural
gas
 Display the ratio of customers to length of pipe in Emergency Operating Procedure zones
(geographical areas defined by the number of customers and their safety in the event of an
emergency)
 Classify high-pressure pipeline proximity criteria
The second component of the GIS is data association. This allows analysts to model relationships
between facilities displayed on a map to tabular information in a database. Databases store facility
information, such as pipe size, pipe material, pressure rating, or related information (e.g., customer
databases, equipment databases and work management systems). Data association allows interactive
queries within a map-like environment.
Finally, the GIS provides a means to create maps of existing facilities in different scales, projections and
displays. In addition, the results of a comparative or spatial analysis can be presented pictorially. This
allows users to present complex analyses rapidly and in an easy-to-understand method.
BUILDING SYNERGEE® MODELS FROM A GIS
The GIS can provide additional benefits through the ease of creation and maintenance of load studies.
Avista can create load studies from the GIS based on tabular data (attributes) installed during the mapping
process.
MAINTENANCE USING A GIS
The GIS helps maintain the existing distribution facility by allowing a design to be initiated on a GIS.
Currently, design jobs for the company’s natural gas system are managed through Avista’s Facility
Management (AFM) tool. Once jobs are completed, the as-built information is automatically updated on
GIS, eliminating the need to convert physical maps to a GIS at a later date. Because the facility is
updated, load studies can remain current by refreshing the analysis.
DEVELOPING A PRESENT CASE LOAD STUDY
In order for any model to have accuracy, a present case model has to be developed that reflects what the
system was doing when downstream pressures and flows are known. To establish the present case,
pressure charts located throughout the distribution system are used.
Pressure charts plot pressure (some include temperature) versus time over several days. Various locations
recording simultaneously are used to validate the model. Customer loads on SynerGEE® are generated to
correspond with actual temperatures recorded on the pressure charts. An accurate model’s downstream
Avista Utilities 2014 Natural Gas IRP Appendices 165
APPENDIX – CHAPTER 7

pressures will match the corresponding location’s field pressure chart. Efficiency factors are fine-tuned to
further refine the model's pressures.
Since telemetry at the gate stations record hourly flow, temperature and pressure, these values are used to
validate the model. All loads are representative of the average daily temperature and are defined as hourly
flows. If the load generating method is truly accurate, all natural gas entering the actual system (physical)
equals total natural gas demand solved by the simulated system (model).
DEVELOPING A PEAK CASE LOAD STUDY
Using the calculated peak loads, a model can be analyzed to identify the behavior during a peak day. The
efficiency factors established in the present case are used throughout subsequent models.
ANALYZING RESULTS
After a model has been balanced, several features within the SynerGEE® model are used to translate
results. Color plots are generated to depict flow direction, pressure, pipe diameter and gradient with
specific break points. Reinforcements can be identified by visual inspection. When user edits are
completed and the model is re-balanced, pressure changes can be visually displayed, helping identify
optimum reinforcements.
An optimum reinforcement will have the largest pressure increase per unit length. Reinforcements can
also be deferred and occasionally eliminated through load mitigation of DSM efforts.
PLANNING CRITERIA
In most instances, models resulting in node pressures below 15 psig indicate a likelihood of distribution
low pressure, and therefore necessitate reinforcements. For most Avista distribution systems, a minimum
of 15 psig will ensure deliverability as natural gas exits the distribution mains and travels through service
pipelines to a customer’s meter. Some Avista distribution areas operate at lower pressures and are
assigned a minimum pressure of 5 psig for model results. Given a lower operating pressure, service
pipelines in such areas are sized accordingly to maintain reliability.
DETERMINING MAXIMUM CAPACITY FOR A SYSTEM
Using a peak day model, loads can be prorated at intervals until area pressures drop to 15 psig. At that
point, the total amount of natural gas entering the system equals the maximum capacity before new
construction is necessary. The difference between natural gas entering the system in this scenario and a
peak day model is the maximum additional capacity that can be added to the system.
Since the approximate natural gas usage for the average customer is known, it can be determined how
many new customers can be added to the distribution system before necessitating system reinforcements.
The above models and procedures are utilized with new construction proposals or pipe reinforcements to
determine the potential increase in capacity.
FIVE-YEAR FORECASTING
The intent of our load study forecasting is to predict the system’s behavior and reinforcements necessary
within the next five years. Various Avista personnel provide information to determine where and why
certain areas may experience growth.
Avista Utilities 2014 Natural Gas IRP Appendices 166
APPENDIX – CHAPTER 7

By combining information from Avista’s demand forecast, IRP planning efforts, regional growth plans
and area developments, proposals for pipeline reinforcements and expansions can be evaluated with
SynerGEE®.

Avista Utilities 2014 Natural Gas IRP Appendices 167
APPENDIX – CHAPTER 7

Avista Utilities 2014 Natural Gas IRP Appendices 168
1

2014 Avista Natural Gas IRP
Technical Advisory Committee Meeting 1
January 24, 2014
Portland, Oregon
Avista Utilities 2014 Natural Gas IRP Appendices 169
2
Agenda
•Introductions & Logistics
•Purpose of IRP and Avista’s IRP Process
•Avista’s Demand Overview and 2012 IRP Revisited
•Economic Outlook and Customer Count Forecast
•Demand Forecast Methodology
•Dynamic Demand Forecasting
•Demand Side Management
•Questions/Wrap Up
Avista Utilities 2014 Natural Gas IRP Appendices 170
3
2014 IRP Timeline
•August 31, 2013 – Work Plan filed with WUTC
•January through April 2014 – Technical Advisory Committee
meetings. Meeting topics will include:
– Demand Forecast and Demand Side Management – January
24
– Supply/Infrastructure, Natural Gas Pricing, and Potential Case
Discussion– February 25
– Distribution Planning, SENDOUT® Preliminary Output Results
and Further Case Discussion – March 26
– SENDOUT® results – April 23
•May 30, 2014 – Draft of IRP document to TAC
•June 30, 2014 – Comments on draft due back to Avista
•July 2014 – TAC final review meeting (if necessary)
•August 31, 2014 – File finalized IRP document
Avista Utilities 2014 Natural Gas IRP Appendices 171
4
Purpose of Gas Integrated Resource
Planning
•Comprehensive long-range resource planning tool
•Fully integrates forecasted demand requirements with
potential demand side and supply side resources
•Process determines the least cost, risk adjusted
means for meeting demand requirements for our firm
residential, commercial and industrial customers
•Responsive to Idaho, Oregon and Washington rules
and/or orders
Avista Utilities 2014 Natural Gas IRP Appendices 172
5
Avista’s IRP Process
• Comprehensive analysis bringing demand forecasting and
existing and potential supply-side and demand-side
resources together into a 20-year, risk adjusted least-cost
plan
• Considers:
– Customer growth and usage
– Weather planning standard
– Demand-side management opportunities
– Existing and potential supply-side resource options
– Risk
– Public participation through Technical Advisory Committee meetings (TAC)
•2012 IRP completed and filed in all three jurisdictions on
August 31, 2012 and acknowledged
Avista Utilities 2014 Natural Gas IRP Appendices 173
6
Avista’s Demand Overview and 2012 IRP
Re-Visited

Avista Utilities 2014 Natural Gas IRP Appendices 174
7
Avista’s Demand Overview
Avista Utilities 2014 Natural Gas IRP Appendices 175
8
– Population of service area 1,590,341
365,000 electric customers
331,000 natural gas customers
•Have one of the smallest carbon
footprints among America’s 100
largest investor-owned utilities
•Committed to environmental
stewardship and efficient use
of resources
Service Territory and Customer Overview
•Serves electric and natural gas customers in eastern Washington and northern Idaho,
and natural gas customers in southern and eastern Oregon
State Total Customers % of Total
Washington 157,557 47%
Oregon 97,404 29%
Idaho 76,739 23%
Total 331,700 100% Avista Utilities 2014 Natural Gas IRP Appendices 176
9
2013 Customer Make Up and Demand Mix

88.34%
11.63% 0.03%
Customer Make up
Oregon
89.94%
9.97% 0.10%
Customer Make up
WA-ID
62.5%
36.2%
1.3%
Annual Demand
WA-ID
64.1%
35.7%
0.2%
Annual Demand
Oregon
Avista Utilities 2014 Natural Gas IRP Appendices 177
10
Historical Demand Mix
0%
20%
40%
60%
80%
100%
2013 2012 2011 2010 2009 2008 2007
Industrial 1% 1% 2% 2% 2% 2% 2%
Commercial 36% 36% 37% 37% 37% 37% 37%
Residential 63% 63% 61% 61% 61% 61% 61%
WA-ID
0%
20%
40%
60%
80%
100%
2013 2012 2011 2010 2009 2008 2007
Industrial 0% 0% 0% 0% 0% 0% 0%
Commercial 11% 10% 11% 11% 11% 10% 10%
Residential 89% 90% 89% 89% 89% 89% 90%
Klamath Falls
0%
20%
40%
60%
80%
100%
2013 2012 2011 2010 2009 2008 2007
Industrial 0% 0% 0% 0% 0% 0% 0%
Commercial 12% 12% 12% 12% 12% 12% 12%
Residential 88% 88% 88% 88% 88% 88% 88%
LaGrande
0%
20%
40%
60%
80%
100%
2013 2012 2011 2010 2009 2008 2007
Industrial 0% 0% 0% 0% 0% 0% 0%
Commercial 12% 12% 12% 12% 12% 12% 12%
Residential 88% 88% 88% 88% 88% 88% 88%
Medford/Roseburg
Avista Utilities 2014 Natural Gas IRP Appendices 178
11
Seasonal Demand Profiles

0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
De
k
a
t
h
e
r
m
s

Klamath Falls
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
De
k
a
t
h
e
r
m
s

WA-ID
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
De
k
a
t
h
e
r
m
s

Medford/Roseburg
Avista Utilities 2014 Natural Gas IRP Appendices 179
12
Daily Demand Profiles

0
50,000
100,000
150,000
200,000
250,000
0 20 40 60 80 100
De
k
a
t
h
e
r
m
s

2013 Average Temp (°F)
WA-ID
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
-20 0 20 40 60 80 100
De
k
a
t
h
e
r
m
s

2013 Average Temp (°F)
Klamath Falls
0
10,000
20,000
30,000
40,000
50,000
60,000
0 20 40 60 80 100
De
k
a
t
h
e
r
m
s

2013 Average Temp (°F)
Medford/Roseburg
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
0 20 40 60 80 100
De
k
a
t
h
e
r
m
s

2013 Average Temp (°F)
LaGrande Historical
Peak (-7°F)
Avista Utilities 2014 Natural Gas IRP Appendices 180
13
Avista’s 2012 Natural Gas IRP Re-Visited
Avista Utilities 2014 Natural Gas IRP Appendices 181
14 Avista Utilities 2014 Natural Gas IRP Appendices 182
15 Avista Utilities 2014 Natural Gas IRP Appendices 183
16 Avista Utilities 2014 Natural Gas IRP Appendices 184
17 Avista Utilities 2014 Natural Gas IRP Appendices 185
18 Avista Utilities 2014 Natural Gas IRP Appendices 186
19 Avista Utilities 2014 Natural Gas IRP Appendices 187
20
Year First Unserved
Scenario Comparisons
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
WA/ID Medford/Roseburg Klamath La Grande
Fi
r
s
t
-Ye
a
r
De
m
a
n
d

U
n
s
e
r
v
e
d
Figure 1.13 -First Year Peak Demand Not Met with Existing Resources
Scenario Comparisons
Expected Case High Growth & Low Prices
Low Growth & High Prices Cold Day 20yr
Average Case
Avista Utilities 2014 Natural Gas IRP Appendices 188
21
Best Cost/Risk Resources
Expected Case – WA/ID
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
Dth
Existing GTN Existing NWP Spokane Supply GTN Capacity Add Peak Day Demand
Current Short
Figure 1.10 - Expected Case - WA/ID Selected Resources vs. Peak Day Demand
(Net of DSM )
FEB 15
Avista Utilities 2014 Natural Gas IRP Appendices 189
22
Best Cost/Risk Resources
Expected Case – Medford/Roseburg
Avista Utilities 2014 Natural Gas IRP Appendices 190
23
Best Cost/Risk Resources
Expected Case – Klamath Falls
Avista Utilities 2014 Natural Gas IRP Appendices 191
24
Our Biggest Risk Last IRP
“Flat Demand” Risk
Avista Utilities 2014 Natural Gas IRP Appendices 192
25
December 8, 2013 Cold Weather Stats
Area Actual
HDD
Peak
HDD
Actual Demand
(Dth/d)
Forecasted
Peak Demand
(Dth/d)
Klamath Falls 72 72 12,656 12,830
LaGrande 65 74 6,709 7,310
Medford 52 61 48,060 53,120
Roseburg 44 55 13,058 13,930
Washington/Idaho 57 82 218,178 257,650
Note: Klamath Falls and Medford set record high loads. LaGrande and Roseburg had second
highest demand days.
Avista Utilities 2014 Natural Gas IRP Appendices 193
26
Near Term Action Items
• Demand trend monitoring
• Demand side management cost effectiveness and
targets
• Gate station analysis

On-going Action Items
• Price elasticity study inquiry
• NGV/CNG and other demand potential
• Supply side resource trends/availability
• Meet regularly with Commission Staff
Avista Utilities 2014 Natural Gas IRP Appendices 194
27
Economic Outlook and Customer Forecast
Development
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]

Avista Utilities 2014 Natural Gas IRP Appendices 195
28
Load Forecasts-Two Step Process
•First, forecast customers (C) by month by schedule (s) by
residential (r), commercial (c), industrial (i)—for example, Ct,y,s.r

•Forecast use per customer (U) by month by schedule by
class—for example, Ut,y,s.r

•Load forecast (L) is the product of the two:

Lt,y,s.r = Ct,y,s.r X Ut,y,s.r

For weather sensitive schedules a
20-yr MA defines normal weather.
For non-IRP years,
forecast is run out 5-
yrs.
Avista Utilities 2014 Natural Gas IRP Appendices 196
29
Forecast Method—Methodology Change
•5-year out forecasts: ARIMA based models with economic drivers and
traditional smoothing models.

•For IRP years, will push out 5-year forecasts based on longer-run
growth assumptions and historical relationships.

•SAS/ETS software.

•Also consider external analysis such as the University of Oregon’s
Regional Economic Indexes. Framing forecast in a broader economic
context.

•Model building is dynamic and model improvements/changes constant.

•Forecast is lower than last IRP…Why?

Avista Utilities 2014 Natural Gas IRP Appendices 197
30
WA-ID Region: 2014 IRP and 2012 IRP
100,000
150,000
200,000
250,000
300,000
350,000
20
1
2
20
1
3
20
1
4

F
20
1
5

F
20
1
6

F
20
1
7

F
20
1
8

F
20
1
9

F
20
2
0

F
20
2
1

F
20
2
2

F
20
2
3

F
20
2
4

F
20
2
5

F
20
2
6

F
20
2
7

F
20
2
8

F
20
2
9

F
20
3
0

F
20
3
1

F
20
3
2

F
20
3
3

F
20
3
4

F
20
3
5

F
20
3
6

F
20
3
7

F
20
3
8

F
20
3
9

F
20
4
0

F
To
t
a
l

C
u
s
t
o
m
e
r
s
WA-ID Region
(Annual Growth: Current Base = 1.0%, Previous IRP Base = 1.6%)
WA-ID Base WA-ID 2012 IRP Base Forecast
Avista Utilities 2014 Natural Gas IRP Appendices 198
31
OR Region: 2014 IRP and 2012 IRP
60,000
70,000
80,000
90,000
100,000
110,000
120,000
130,000
140,000
150,000
20
1
2
20
1
3
20
1
4

F
20
1
5

F
20
1
6

F
20
1
7

F
20
1
8

F
20
1
9

F
20
2
0

F
20
2
1

F
20
2
2

F
20
2
3

F
20
2
4

F
20
2
5

F
20
2
6

F
20
2
7

F
20
2
8

F
20
2
9

F
20
3
0

F
20
3
1

F
20
3
2

F
20
3
3

F
20
3
4

F
20
3
5

F
20
3
6

F
20
3
7

F
20
3
8

F
20
3
9

F
20
4
0

F
To
t
a
l

C
u
s
t
o
m
e
r
s
OR Region
(Annual Growth: Current Base = 0.9%, Previous IRP Base = 1.7%)
OR Base OR 2012 IRP Base Forecast
Avista Utilities 2014 Natural Gas IRP Appendices 199
32
The Relationship Between Classes
Customers Residential Commercial Industrial Load Residential Commercial Industrial
Residential 1.00 Residential 1.00
Commercial 0.83 1.00 Commercial 0.94 1.00
Industrial -0.44 -0.35 1.00 Industrial 0.33 0.34 1.00
Year-over-year Growth, Gas Correlations by Class, Jan. 2006-May 2013
Residential customer growth is approximately equal
to population growth in the long-run.
Commercial customer growth is highly correlated
with and approximately equal to residential growth
in the long-run.
Industrial’s correlation to residential is lower and
negative. Customer numbers stable or slightly
declining.
(1) Estimate with historical data: Ct,y,WA101.r = α0 + ωSDDt,y + ARIMAЄt,y(10,1,0)(0,0,0)12
(3) Estimate with historical data: Ct,y,WA101.c = α0 + α1 Ct,y,WA101.r + ωSDDt,y + ARIMAЄt,y(12,1,0)(0,0,0)12
(2) 5-yr forecasts of Ct,y,WA101.r adjusted (post-forecast) for forecasted population growth to get C*t,y,WA101.r
(4) 5-yr forecasts of Ct,y,WA101.c are generated by using C*t,y,WA101.r in the estimate of (3).
Avista Utilities 2014 Natural Gas IRP Appendices 200
33
Getting to Population as a Driver

Average GDP Growth
Forecasts:
 IMF, FOMC,
Bloomberg, etc.
 Average forecasts
out 5-yrs.
Non-farm Employment
Growth Model:
 Model links year y, y-1,
and y-2 GDP growth to
year y regional
employment growth.
 Forecast out 5-yrs.
Regional Population Growth Models:
 Model links regional, U.S., and CA
employment growth to regional
population growth.
 Forecast out 5-yrs for Spokane, WA;
Kootenai, ID; and Jackson, OR.
 Averaged with GI forecasts.
 Compare population forecasts to
base customer forecasts for
residential schedules 1, 101, and
410.
 Adjust base forecasts if large
differences with base and
population forecasts exist.
EMP GDP
By assuming different long-run values for
regional employment growth, we can obtain
long-run residential and commercial customer
growth rates for base, low, and high cases.
Avista Utilities 2014 Natural Gas IRP Appendices 201
34
WA-ID Region, 2012-2040
100,000
150,000
200,000
250,000
300,000
350,000
400,000
20
1
2
20
1
3
20
1
4

F
20
1
5

F
20
1
6

F
20
1
7

F
20
1
8

F
20
1
9

F
20
2
0

F
20
2
1

F
20
2
2

F
20
2
3

F
20
2
4

F
20
2
5

F
20
2
6

F
20
2
7

F
20
2
8

F
20
2
9

F
20
3
0

F
20
3
1

F
20
3
2

F
20
3
3

F
20
3
4

F
20
3
5

F
20
3
6

F
20
3
7

F
20
3
8

F
20
3
9

F
20
4
0

F
To
t
a
l

C
u
s
t
o
m
e
r
s
WA-ID Region
(Annual Growth: Low = 0.5%, Base = 1.0%, HIgh = 1.5%)
WA-ID Base WA-ID Low WA-ID High
Avista Utilities 2014 Natural Gas IRP Appendices 202
35
OR Region, 2012-2040
60,000
70,000
80,000
90,000
100,000
110,000
120,000
130,000
140,000
150,000
20
1
2
20
1
3
20
1
4

F
20
1
5

F
20
1
6

F
20
1
7

F
20
1
8

F
20
1
9

F
20
2
0

F
20
2
1

F
20
2
2

F
20
2
3

F
20
2
4

F
20
2
5

F
20
2
6

F
20
2
7

F
20
2
8

F
20
2
9

F
20
3
0

F
20
3
1

F
20
3
2

F
20
3
3

F
20
3
4

F
20
3
5

F
20
3
6

F
20
3
7

F
20
3
8

F
20
3
9

F
20
4
0

F
To
t
a
l

C
u
s
t
o
m
e
r
s
OR Region
(Annual Growth: Low = 0.5%, Base = 0.9%, HIgh = 1.4%)
OR Base OR Low OR High
Avista Utilities 2014 Natural Gas IRP Appendices 203
36
OR by Individual Region, 2012-2040
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
20
1
2
20
1
4

F
20
1
6

F
20
1
8

F
20
2
0

F
20
2
2

F
20
2
4

F
20
2
6

F
20
2
8

F
20
3
0

F
20
3
2

F
20
3
4

F
20
3
6

F
20
3
8

F
20
4
0

F
To
t
a
l

C
u
s
t
o
m
e
r
s
Medford Region
(Annual Growth: Low = 0.5%, Base = 1.1%, High = 1.7%)
Medford Base Medford Low Medford High
10,000
12,000
14,000
16,000
18,000
20,000
22,000
20
1
2
20
1
4

F
20
1
6

F
20
1
8

F
20
2
0

F
20
2
2

F
20
2
4

F
20
2
6

F
20
2
8

F
20
3
0

F
20
3
2

F
20
3
4

F
20
3
6

F
20
3
8

F
20
4
0

F
To
t
a
l

C
u
s
t
o
m
e
r
s
Roseburg Region
(Annual Growth: Low = 0.3%, Base = 0.6%, High = 1.0%)
Roseburg Base Roseburg Low Roseburg High
10,000
12,000
14,000
16,000
18,000
20,000
22,000
20
1
2
20
1
4

F
20
1
6

F
20
1
8

F
20
2
0

F
20
2
2

F
20
2
4

F
20
2
6

F
20
2
8

F
20
3
0

F
20
3
2

F
20
3
4

F
20
3
6

F
20
3
8

F
20
4
0

F
To
t
a
l

C
u
s
t
o
m
e
r
s
Klamath Region
(Annual Growth: Low = 0.3%, Base = 0.6%, High = 1.0%)
Klamath Base Klamath Low Klamath High
6,500
7,000
7,500
8,000
8,500
9,000
20
1
2
20
1
4

F
20
1
6

F
20
1
8

F
20
2
0

F
20
2
2

F
20
2
4

F
20
2
6

F
20
2
8

F
20
3
0

F
20
3
2

F
20
3
4

F
20
3
6

F
20
3
8

F
20
4
0

F
To
t
a
l

C
u
s
t
o
m
e
r
s
La Grande Region
(Annual Growth: Low = 0.2%, Base = 0.4%, High = 0.6%)
La Grande Base La Grande Low La Grande HighAvista Utilities 2014 Natural Gas IRP Appendices 204
37
Future Modeling
• Attempt to integrate employment and/or
population directly into the residential customer
model.

• Continue to explore the best way to model price,
household income, and household size.
Avista Utilities 2014 Natural Gas IRP Appendices 205
38
Example: West Household Size and
Usage, 2009 RECS
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
1 2 3 4 5 6 or More
In
d
e
x

o
f

U
s
a
g
e

R
e
l
a
t
i
v
e

t
o

1

P
e
r
s
o
n

H
o
u
s
e
h
o
l
d
,

Ho
u
s
e
h
o
l
d

S
i
z
e

=

1
Persons in Household
Electricity Natural Gas
Avista Utilities 2014 Natural Gas IRP Appendices 206
39

Demand Forecast Methodology
Avista Utilities 2014 Natural Gas IRP Appendices 207
40
Natural Gas Demand Forecasting
Financial
Planning and
Analysis
Resource
Accounting Gas Supply Rates Regulatory
Staff
Industry
Stakeholders
Average
Demand
Procurement
Planning
PGA Corporate
Budget
IRP
Peak Day
Planning
IRP
Scenario
Analysis
Other
Avista Utilities 2014 Natural Gas IRP Appendices 208
41
Natural Gas Demand Forecast
Use per
Customer
Weather
Forecast
Customer
Forecast
What goes into the Natural Gas Demand
Forecast?
Avista Utilities 2014 Natural Gas IRP Appendices 209
42
Customer
Forecast
by Class
Start with national
economic forecasts
then drill down to
regional economies
Population growth
expectations and
employment
Company-specific
knowledge about
sub-regional
construction activity,
trends and historical
data
The Customer Forecast
Avista Utilities 2014 Natural Gas IRP Appendices 210
43
Weather
Forecast
Most
recent 20
year HDD’s
Planning
Standard
Other
The Weather Forecast
Avista Utilities 2014 Natural Gas IRP Appendices 211
44
Weather
•NOAA 20 year actual average daily HDD’s (1994-
2013)
•Peak weather includes two winter storms (5 day
durration), one in December and one in February
•Planning Standard – coldest day on record
•Sensitivity around planning standard including
– Normal/Average
– Coincidental vs. Non-coincidental
– Coldest in 20 years
– Monte Carlo simulation
Avista Utilities 2014 Natural Gas IRP Appendices 212
45
Use per
Customer
Most recent year(s) of
historical use:
•“Big Meter” Data
• 5 Areas
• Allocated based on
“little meter” data
Determine
Base
Demand
Determine
Heat
Demand
Determine
“Super Peak”
Demand
The Use per Customer Forecast
Avista Utilities 2014 Natural Gas IRP Appendices 213
46
The Use per Customer Forecast cont.

• Historical data is used to determine initial base and heat
coefficients.
• Adjustments are made to incorporate DSM and price
elastic responses.
Avista Utilities 2014 Natural Gas IRP Appendices 214
47 Avista Utilities 2014 Natural Gas IRP Appendices 215
48 Avista Utilities 2014 Natural Gas IRP Appendices 216
49 Avista Utilities 2014 Natural Gas IRP Appendices 217
50 Avista Utilities 2014 Natural Gas IRP Appendices 218
51 Avista Utilities 2014 Natural Gas IRP Appendices 219
52
Demand Modeling Equation – a closer look

SENDOUT® requires inputs expressed in the below format to
compute daily demand in dekatherms. The base and weather
sensitive usage (degree-day usage) factors are developed
outside the model and capture a variety of demand usage
assumptions.
# of customers x Daily weather sensitive usage / customer
# of customers x Daily base usage / customer
Plus
Table 3.2 Basic Demand Formula
Avista Utilities 2014 Natural Gas IRP Appendices 220
53
1.Customer annual growth rates:

2.Use per customer coefficients – Flat all classes, 5 year, 3 year or last year
average use per HDD per customer
3. Weather planning standard – coldest day on record
WA/ID 82; Medford 61; Roseburg 55; Klamath 72; La Grande 74
Developing a Reference Case

Customer
count
forecast
Use per
customer
coefficients
Weather Reference
Case Demand
Avista Utilities 2014 Natural Gas IRP Appendices 221
54
Dynamic Demand Methodology
Avista Utilities 2014 Natural Gas IRP Appendices 222
55
Dynamic Demand Methodology

Demand Influencing
– Conditions that DIRECTLY
affect core customer
volume consumed
Price Influencing
–PRICE SENSITIVE
conditions that, through price
elasticity, INDIRECTLY affect
core customer volume
consumed

Avista Utilities 2014 Natural Gas IRP Appendices 223
56
Demand
Customer Growth
•New Construction
•Conversion/Direct Use
•Economy
Customer Mix Shifts
•Res/Com/Ind
•Core vs. Transport
•Interruptible
Weather
•Normal
•Planning Standard
•Other
Technology
•Increased
efficiency/DSM
•New Uses
•Demand Response
3rd Party Demand
Trends
•Thermal Generation
•Non-Core Customer
•LNG Exports Supply Trends
•Conventional vs.
Unconventional
•Canadian Imports
•LNG
Pipeline Trends
•Regional Pipeline
Projects
•National Pipeline
Projects
•International Pipeline
Projects
Other
•Storage
•Climate Change
Legislation
•Energy Correlations
(i.e. oil and gas)
Demand Drivers
Avista Utilities 2014 Natural Gas IRP Appendices 224
57
Customer Growth and Mix – Demand
Influencing
•Key driver in demand growth
•Can change the timing and/or location of resource
needs
•Currently we model expected, high, and low growth
scenarios
•New construction vs. conversions
•Residential/Commercial/Industrial vs. Transportation
•New uses – CNG/NGV

Avista Utilities 2014 Natural Gas IRP Appendices 225
58
Weather Standard – Demand Influencing
•Has the potential to significantly change timing of
resource needs
•Significant qualitative considerations
– No infrastructure response time if standard
exceeded
– Significant safety and property damage risks
•Current Peak HDD Planning Standards
– WA/ID 82
– Medford 61
– Roseburg 55
– Klamath 72
– LaGrande 74
Avista Utilities 2014 Natural Gas IRP Appendices 226
59
Global Warming – Demand Influencing

•There is a lack of studies or information on the affect
global warming has on peak weather conditions
•Uncertain whether any change in timing of resource
needs
•Peak and trough weather appears more volatile – does
not influence the peak
•Will reduce annual consumption over time for LDC but
could increase consumption for thermal generation
•Proposing to remove global warming adjustment
Avista Utilities 2014 Natural Gas IRP Appendices 227
60
Technology – Demand Influencing
•Demand side management initiatives will reduce
demand HOWEVER, it is dependent upon customers
willingness/ability to participate.
•Development of new uses for natural gas
•CNG
•NGV
•LNG
•???NG
•Demand response (Smart Grid)
•New technologies in Demand Side Management

Avista Utilities 2014 Natural Gas IRP Appendices 228
61
Price Elasticity Factors Defined
• Price elasticity is usually expressed as a numerical factor
that defines the relationship of a consumer’s consumption
change in response to price change.

• Typically, the factor is a negative number as consumers
normally reduce their consumption in response to higher
prices or will increase their consumption in response to
lower prices.

• For example, a price elasticity factor of -0.13 means:
– A 10% price increase will prompt a 1.3% consumption
decrease
– A 10% price decrease will prompt a 1.3% consumption
increase Avista Utilities 2014 Natural Gas IRP Appendices 229
62
Price Elasticity
•Establishes factors for use in other price influencing
scenarios
•Very complex relationship – we use historical data
however……
•Historical data has DSM, rate changes (PGA,
general rate, etc.), economic conditions,
technological changes, etc.
•History is not necessarily the best predictor of future
behavior
Avista Utilities 2014 Natural Gas IRP Appendices 230
63
2007 AGA Study Results
•American Gas Assn Study
– National results
• Short-run -0.09
•Long-run -0.18
– Pacific & Mtn Region
results
• Short-run -0.07 & -0.07
• long-run -0.12 & -0.10
–Min-Max range
• Short-run +0.01 to -
0.13
•Long-run -.01 to -.29
•Avista Specific Results
– Oregon
• Short-run -0.08
• long-run -0.13
– Idaho
• Short-run -0.05
• long-run -0.10
– Washington
• Short-run -0.12
• long-run -0.14
Avista Utilities 2014 Natural Gas IRP Appendices 231
64
Price Elasticity Assumptions
From 2012 IRP
Elasticity
Assumption
Real Price annual increase
within 30%
High Negative .20
Expected Negative .13
Low No response
Avista Utilities 2014 Natural Gas IRP Appendices 232
65
3rd Party Demand Trends – Price Influencing
•Gas fired generation – the largest contributor to
future growth
•Coal plant retirements driving gas for power
•CNG/NGV Transportation Fleets
•Export LNG
•Non-firm customer trends

Avista Utilities 2014 Natural Gas IRP Appendices 233
66
Supply Trends – Price Influencing
•Not all its “Frack-ed” up to be or “Fracking” Awesome
•Shale is Everywhere
•O’ Canada vs. Canada Dry
•LNG Export
•Basis - Location, location, location
Avista Utilities 2014 Natural Gas IRP Appendices 234
67
Pipeline Trends – Price Influencing
•Regional Pipeline Proposals
•N-Max/Palomar – cross Cascades pipeline (NWN,
GTN and NWP)
•Pacific Connector – from Jordan Cove LNG to
various interconnects in the Pacific Northwest
(Williams, Fort Chicago Energy Partners, and
PG&E)
•National Pipeline Proposals
•International Pipeline Proposals

Avista Utilities 2014 Natural Gas IRP Appendices 235
68
Other Supply Issues – Price Influencing
•Storage
•Climate Change and Carbon Legislation
•Energy Correlations
Avista Utilities 2014 Natural Gas IRP Appendices 236
69
Sensitivities, Scenarios, Portfolios
Sensitivities
Demand
Supply
Scenarios
Group demand
drivers into
meaningful sets
Group supply
drivers into
meaningful sets
Portfolios
Bringing together demand and supply scenarios
Avista Utilities 2014 Natural Gas IRP Appendices 237
70
Demand Sensitivities from 2012 IRP
What do we want to consider for 2014?
Avista Utilities 2014 Natural Gas IRP Appendices 238
71
Mix and Match to Make Scenarios
Avista Utilities 2014 Natural Gas IRP Appendices 239
72
The Goal – A Bunch of Meaningful Lines
0
20
40
60
80
100
120
140
160
Mdth/d
Figure 1.1 Average Daily Demand 2012 IRP Demand Scenarios
(Net of DSM Savings)
Average Case -Mix Expected Case -Coldest on Record -Mix
Coldest in 20 years -Mix High Growth & Low Prices -Mix
Low Growth & High Prices -Mix
0
100
200
300
400
500
600
Mdth/d
Figure 1.2 Peak Day (Feb 15) 2012 IRP Demand Scenarios
(Net of DSM Savings)
Average Case -Mix Expected Case -Coldest on Record -Mix
Coldest in 20 years -Mix High Growth & Low Prices -Mix
Low Growth & High Prices -Mix
Avista Utilities 2014 Natural Gas IRP Appendices 240
73
Forecast Methodology Considerations
• Know the goal – what is the purpose of the forecast?
• Know your data – what you have, what you need
• Is there sufficient quantitative data available?
• Is the change small or large?
• Is their conflict among decision makers?
• Are the relationships among variable complicated?
• Have there been similar situations?

Avista Utilities 2014 Natural Gas IRP Appendices 241
74
Demand Side Management
Lori Hermanson
Utility Resource Analyst
Avista Utilities 2014 Natural Gas IRP Appendices 242
75
Agenda
• DSM in the last IRP
– Target/Acquisition
• What’s happened since
the last IRP
– Cost-effectiveness
comparison
• What’s different with
avoided costs?
• Proposed DSM modeling
methodology
• Business planning process

Avista Utilities 2014 Natural Gas IRP Appendices 243
76
DSM in the 2012 IRP - Annual
30,000
32,000
34,000
36,000
38,000
40,000
42,000
44,000
46,000
Md
t
h
Annual Demand Before and After DSM
Total System
Total System Demand Total System Demand after DSM
Avista Utilities 2014 Natural Gas IRP Appendices 244
77
DSM in the 2012 IRP – Peak Day
300
320
340
360
380
400
420
440
Md
t
h
Peak Day Demand Before and After DSM
Total System
Total System Demand Total System Demand after DSM
Avista Utilities 2014 Natural Gas IRP Appendices 245
78
2012 IRP DSM Targets
• 2013 targets & (Unverified) acquisition (achievable
potential)

• OPUC established “minimum” target

State Therms Target % Achieved
Idaho 18,804 364,000 5.17
Oregon 217,177 289,000 75.14
Washington 595,614 893,000 66.70
Therms Target % Achieved
217,177 225,000 96.52
Avista Utilities 2014 Natural Gas IRP Appendices 246
79
Recap of Recent History
• Idaho – Schedule 190
suspended effective 10/1/12
• Oregon – two year cost-
effectiveness pass and
revised savings expectation
for 2013-2014
• Washington – WUTC
adopted the gross UCT as
the cost-effectiveness test
for natural gas DSM
Avista Utilities 2014 Natural Gas IRP Appendices 247
80
Cost-effective Test Comparison
• Total Resource Cost
(TRC) =
(avoided costs +
non-energy benefits)
____________________
(customer incremental
cost +
non-incentive utility costs)
• Utility Cost Test (UCT) =

avoided costs
__________________
incentives +
non-incentive utility costs
Avista Utilities 2014 Natural Gas IRP Appendices 248
81
TRC vs UCT
TRC
• Traditional cost-
effectiveness metric
• Includes non-energy
benefits
• Results in programs that
influence customer
decisions

UCT
• Customer costs are
ignored
• Incentives are reduced in
order to offer programs
below avoided costs
• Ignore free-riders in order
to be cost-effective
Avista Utilities 2014 Natural Gas IRP Appendices 249
82
Avoided Costs (2013 $)
2009 IRP 2012 IRP 2014 IRP*
Annual Winter Annual Winter Annual Winter
WA/ID $12.56 $12.88 $5.31 $5.40 ?? ??
OR $12.74 $13.18 $5.34 $5.45 ?? ??
*Similar avoided costs levels anticipated from the
upcoming IRP

Avista Utilities 2014 Natural Gas IRP Appendices 250
83
Proposed DSM Modeling Methodology
Avista Utilities 2014 Natural Gas IRP Appendices 251
84
Business Planning Process
• IRP generated target (CPA
achievable potential)
• Bottom-up evaluation of all
measures regardless of cost-
effectiveness
• Add in non-incentive utility costs
• Evaluate with final avoided costs
• Process results in updated
operational plan
Avista Utilities 2014 Natural Gas IRP Appendices 252
85
Questions?
Avista Utilities 2014 Natural Gas IRP Appendices 253
86
2014 IRP Timeline
•August 31, 2013 – Work Plan filed with WUTC
•January through April 2014 – Technical Advisory Committee
meetings. Meeting topics will include:
– Demand Forecast and Demand Side Management – January
24
– Supply/Infrastructure, Natural Gas Pricing, and Potential Case
Discussion– February 25
– Distribution Planning, SENDOUT® Preliminary Output Results
and Further Case Discussion – March 26
– SENDOUT® results – April 23
•May 30, 2014 – Draft of IRP document to TAC
•June 30, 2014 – Comments on draft due back to Avista
•July 2014 – TAC final review meeting (if necessary)
•August 31, 2014 – File finalized IRP document
Avista Utilities 2014 Natural Gas IRP Appendices 254
87
Tentative Agenda for the Next TAC Meeting
• Natural Gas Prices
• Supply Side Resources (Current and Future)
• Transportation
• Storage
• Other
• Gate Station Analysis

Avista Utilities 2014 Natural Gas IRP Appendices 255
88
2014 Avista Natural Gas IRP
Technical Advisory Committee Meeting 2
February 25, 2014
Portland, Oregon
Avista Utilities 2014 Natural Gas IRP Appendices 256
89
Agenda
•Introductions & Logistics
•Update from NWP and GTN
•Regional and Avista’s Supply Side
Resources/Resource Optimization
•Gate Station Analysis
•Solving Unserved Demand

Avista Utilities 2014 Natural Gas IRP Appendices 257
90
2014 IRP Timeline
•August 31, 2013 – Work Plan filed with WUTC
•January through April 2014 – Technical Advisory Committee
meetings. Meeting topics will include:
– Demand Forecast and Demand Side Management – January
24
–Supply and Infrastructure, Gate Station Analysis, Supply
Side Resources, Resource Optimization – February 25
– Distribution Planning, Natural Gas Pricing, CNG/NGV,
SENDOUT® Preliminary Results and Further Case Discussion
– March 26
– SENDOUT® results – April 23
•May 30, 2014 – Draft of IRP document to TAC
•June 30, 2014 – Comments on draft due back to Avista
•July 2014 – TAC final review meeting (if necessary)
•August 31, 2014 – File finalized IRP document
Avista Utilities 2014 Natural Gas IRP Appendices 258
91
Regional and Avista’s Supply and
Infrastructure
Avista Utilities 2014 Natural Gas IRP Appendices 259
92
NWP Presentation
Avista Utilities 2014 Natural Gas IRP Appendices 260
93
GTN Presentation
Avista Utilities 2014 Natural Gas IRP Appendices 261
94
Connecting Supply and Storage with Customers
Avista Utilities 2014 Natural Gas IRP Appendices 262
95
Storage – A valuable asset
•Peaking resource
•Improves reliability
•Enables capture of price spreads between time
periods
– Inter seasonal spreads
– Intra seasonal spreads
•Enables efficient counter cyclical utilization of
transportation (i.e. summer injections)
•May require transportation to service territory
•In-service territory storage offers most flexibility

Avista Utilities 2014 Natural Gas IRP Appendices 263
96
Regional Natural Gas Storage Resources

Jackson Prairie Natural Gas Facility
Chehalis, Washington
Avista Utilities 2014 Natural Gas IRP Appendices 264
97
Washington and Idaho
Owned Jackson Prairie
• 7.7 Bcf of Capacity with approximately 346,000 Dth/d of deliverability

Oregon
Owned Jackson Prairie
• 823,000 Dth of Capacity with approximately 52,000 Dth/d of deliverability
Leased Jackson Prairie
• 95,565 Dth of Capacity with approximately 2,654 Dth/d of deliverability

Avista’s Storage Resources
Avista Utilities 2014 Natural Gas IRP Appendices 265
98
Interstate Pipeline Resources
• The Integrated Resource Plan (IRP) brings together the various
components necessary to ensure proper resource planning for
reliable service to utility customers.

• One of the key components for natural gas service is interstate
pipeline transportation. Low prices, firm supply and storage
resources are rendered meaningless to a utility customer without
the ability to transport the gas reliably during cold weather events.

• Acquiring firm interstate pipeline transportation provides the most
reliable delivery of supply.
Avista Utilities 2014 Natural Gas IRP Appendices 266
99
• TransCanada Alberta (NOVA)
– Transporting gas out of Alberta,
Canada
• TransCanada BC (ANG)
– Transporting gas through BC,
Canada to US
• Spectra Energy (WestCoast)
– Transporting gas from western BC
Canada to US
• Gas Transmission Northwest (GTN)
– Transporting gas from Canada/US
border to CA
• Williams Pipeline West (NWP)
– Transporting gas from western BC
and US Rockies
• El Paso Ruby Pipeline
– Transporting gas from the
Rockies to Malin
Regional Transportation
Resources
Source: NWGA
Avista Utilities 2014 Natural Gas IRP Appendices 267
100
Overview of Transportation
AECO
Station 2
Sumas
Stanfield
Rockies
Jackson Prairie
Malin
Starr Rd
Kingsgate
Avista Utilities 2014 Natural Gas IRP Appendices 268
101
Proposed Pipeline
Infrastructure
•Pacific Connector/Jordan Cove
•N-Max/Palomar
•Washington Expansion
•Oregon LNG
Avista Utilities 2014 Natural Gas IRP Appendices 269
102
Pipeline Contracting
Simply stated: The right to move (transport) a specified amount
of gas from Point A to Point B
A B
Avista Utilities 2014 Natural Gas IRP Appendices 270
103
Rate Structure
•Pipeline charges a higher demand charge
and a lower variable or commodity charge
Straight Fixed
Variable (SFV)
•Pipeline charges a lower demand charge
and a higher variable or commodity charge
Enhanced
fixed variable
•Pay the same demand and variable costs
regardless of how far the gas is transported
Postage Stamp
Rate
•Pay a variable and demand charge based
on how far the gas is transported Mileage Based
Avista Utilities 2014 Natural Gas IRP Appendices 271
104
Types of Pipeline Contracts
Firm Transport
•Contractual rights to:
•Receive
•Transport
•Deliver
•From point A to point B
Interruptible Transport
•Contractual rights to:
•Receive
•Transport
•Deliver
•From point A to Point B AFTER FIRM TRANSPORT HAS BEEN SCHEDULED – and can be BUMPED later!
Seasonal Transport
•Firm service available for limited periods (Nov-Mar) or for a limited amount (TF2 on NWP)
•Usually matched, paired or utilized with storage.
Alternate Firm Transport
•The use of firm transport outside of the primary path
•Priority rights below firm
•Priority rights above interruptible
Avista Utilities 2014 Natural Gas IRP Appendices 272
105
Postage Stamp Rate
Postage Stamp:
Same costs
regardless of
distance or locations
Avista Utilities 2014 Natural Gas IRP Appendices 273
106
Pipeline Revenue
NWP Example: Postage Stamp
• Postage Stamp (NWP)
– Pay $0.37 to reserve the space
• Whether you use it or not
– Pay $0.03 when used
• Only when you use it
– Net $0.40
• Demand Charge = $0.37
• Commodity Charge = $0.03

Avista Utilities 2014 Natural Gas IRP Appendices 274
107
Mileage Rate
Mileage Base:
Pay based on how
far you move the gas
Avista Utilities 2014 Natural Gas IRP Appendices 275
108
Pipeline Revenue
GTN Example: Mileage Based
• Mileage Based (GTN)
– Pay $0.01 per mile to reserve the space
• Whether you use it or not
– Pay $0.002 per mile when used
• Only when you use it
– $0.021 per mile when used
• Demand Charge = $0.01
• Commodity Charge = $0.002

Avista Utilities 2014 Natural Gas IRP Appendices 276
109
Interruptible Rates
• Pay as you go!
• Pay full firm rate for any gas transported (may be
discounted)
– Pay $0.37 equivalent to cost to reserve the space
– Pay $0.03 variable charge when used
– Net $0.40 for all gas transported
• So IT rate is $0.40
• NO GUARANTEE it will flow.
• Can be “BUMPED” by Firm Shippers

Avista Utilities 2014 Natural Gas IRP Appendices 277
110
Fuel Rates
To move gas through the
pipelines the gas is
compressed to a higher
pressure.

To run the compressors, the
pipeline takes some of your
gas – this is referred to as
pipeline fuel. It is a percent of
what you are transporting.

For example, if we purchase
1000 Dth in a supply basin,
we will only receive 975 Dth
at our gate station for the
customers.
Avista Utilities 2014 Natural Gas IRP Appendices 278
111
Pipeline Contracting

Transport contract #123 with “primary” points A to B
A B Transport Contract 123
C D Transport Contract 123
Firm Service Pt to Pt
Alternate Firm (non-primary points)
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112
Capacity Firm or Not?
Firm:
• Primary Receipt
• Delivery Path

Secondary:
• Any part not firm
• Requires knowledge and
experience to rely on
interruptible

No on NWP
Yes on GTN
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Capacity Firm or Not?
Avista Utilities 2014 Natural Gas IRP Appendices 281
114
Capacity Firm or Not?
Avista Utilities 2014 Natural Gas IRP Appendices 282
115
Capacity Firm or Not?
Firm Point to Point Avista Utilities 2014 Natural Gas IRP Appendices 283
116
Capacity Firm or Not?
Alternate capacity – flex delivery point
- Subject to cuts through constraints Avista Utilities 2014 Natural Gas IRP Appendices 284
117
Pipeline Capacity can be “lumpy”
Expansion
Expansion
5 years? $
10 years? $$
15 years? $$$
Alternatives can be
expensive and timing
unknown
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118
How to Manage the “LUMPS”
• Transport Optimization
– Contract Terms (seasonal)
– Long term releases
– Short term releases
– Daily Optimization
– Segmentation

Daily basin spread arbitrage
Short Term
Long Term
Segmentation
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119
Long Term Releases
•1 year – 20 plus years
•Negotiated – but subject to bidding
•Can be subject to recall
•Cannot exceed Maximum Rate

Short Term Releases
•Less than 1 year (can be for 1 day)
•Negotiated – but subject to bidding
•Can be posted for bidding only
•“Sweet Heart” rules prevent rolling from term to term
•Can be higher than Max Rate
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120
Daily Transportation Optimization
Example:
Cost to own transport is $0.70
• Whether used or not (demand)
Cost to actually move gas is $0.10
AECO
Malin
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121
Daily Transportation Optimization
AECO Price is $4.00
AECO
Malin
Malin Price is $4.50
Buy AECO gas at $4.00
Pay $0.10 to transport it (fuel costs)
Sell Malin gas at $4.50
Net is $4.50-$4.00 is $0.50; less $0.10 to transport yields $0.40
We have reduced customer’s costs by $0.40 Avista Utilities 2014 Natural Gas IRP Appendices 289
122
Segmentation
Primary Path:
Sumas to CDA
10,000 Dth/day
Guaranteed Delivery

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123
Segmentation
Segment:
Sumas to JP – FIRM
10,000 Dth/day

JP to CDA – FIRM
10,000 Dth/day

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124
Segmentation
Segment:
Sumas to JP – FIRM
10,000 Dth/day

JP to Spokane – FIRM
10,000 Dth/day

Starr Rd to CDA – FIRM
10,000 Dth/day

One payment
3 x capacity
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125
Pipeline Optimization
Avista Utilities 2014 Natural Gas IRP Appendices 293
126
Points Along the Pipe
Avista Utilities 2014 Natural Gas IRP Appendices 294
127
Gate Stations
My house
Pipeline
Receipt Pt
Delivery Pt/Gate Station
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128
Pipeline Contracting
Gate stations may have the ability to deliver volume in excess of contract
demand. This may be a result for future growth and construction efficiencies.
10,000
2000
Contract Demand: 10,000 MDDO’s: 11,000
3000
4000
2000
Avista Utilities 2014 Natural Gas IRP Appendices 296
129
Pipeline Contracting
Blending of Pipelines under Avista’s service territory has many positive
results but dramatically adds to the complexity of planning.
10,000
2000
Contract Demand: 10,000 MDDO’s: 11,000
3000
4000
2000
Avista Utilities 2014 Natural Gas IRP Appendices 297
130
Zones Along the Pipe
Avista Utilities 2014 Natural Gas IRP Appendices 298
131
Jackson Prairie
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132
Modeling Transportation In SENDOUT®
•Start with a point in time look at each jurisdiction’s resources
•Contracts – Receipt and Delivery Points
•Rates
•Contractual vs. Operational
•Contractual can be overly restrictive
•Operational can be overly flexible
•Incorporating operational realities into our modeling can defer
the need to acquire new resources.
•Gas Supply’s job is to get gas from the supply basin to the
pipeline citygate.
•Gas Engineering/Distribution’s job is to take gas from the
pipeline gate to our customers.
•The major limiting factor is receipt quantity – how much can you
bring into the system?

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133
Modeling Challenges
• Supply needs to get gas to the gate.
• Contracts were created years ago, based on demand projections at that point in time.
• Stuff happens (i.e. growth differs from forecast).
• Sum of receipt quantity and aggregated delivery quantity don’t identify resource deficiency
for quite some time however…..
• The aggregated look can mask individual city gate issues, and the disaggregated look can
create deficiencies where they don’t exist.
• In many cases operational capacity is greater than contracted.
• Transportation resources are interconnected (two pipes can serve one area).
• WARNING – we need to mindful of the modeling limitations.

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What is in SENDOUT® ?
Inside:
• Demand forecasts at an aggregated level
• Existing transportation resources and current rates
• Receipt point to aggregated delivery
points/“zone”
• Jurisdictional considerations
• Long term capacity releases
• Potential resources, both supply and demand side

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135
What is outside SENDOUT®?
Outside:
• Gate station analysis
• Forecasted demand behind the gate
• Growth rates consistent with IRP assumptions
• Actual hourly/daily city gate flow data
• Gate station MDDO’s
• Gate station operational capacities

Avista Utilities 2014 Natural Gas IRP Appendices 303
136 CONFIDENTIAL – Do Not Distribute Avista Utilities 2014 Natural Gas IRP Appendices 304
137
City Gate Analysis
Avista Utilities 2014 Natural Gas IRP Appendices 305
138
City Gate Analysis Issues to Address
• MDQ vs. MDDO
• Our gate vs. Pipeline gate
• Operational capacity vs. contracted capacity
• Pipeline differences
• Zonal vs. Point Specific
• Laterals and Mainlines

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139
Forecasting Demand Behind the Gate
• Our IRP desire has always been to forecast to as granular a level as possible using the
available data.

• Attempts to forecast demand behind the gate using existing forecasting methodology has
been challenging.
• Revenue data does not have daily meter reads for core customers making
regression analysis on a use per HDD per customer difficult.
• DSM would become more burdensome than it already is.
• Some towns can be served by multiple pipelines and the mix can change over time.

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140
Forecasting Demand Behind the Gate cont.

While there are challenges, there is modeling that we can do to help identify more
granular city gate deficiencies.

• Utilize daily/hourly pipeline flow data from each meter station to estimate what
demand could be on a peak day or any heating degree day.
• Apply growth factors to estimate what the demand could grow to consistent with
IRP assumptions/methodology.

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141
The Pieces and Parts
Supply
Basin
(40,000 MDQ)
• Contracted MDQ
• Basis for billing (i.e. what we pay for)

Pipeline Citygate
(15,000 MDDO
18,000 Op Cap)
• Contracted MDDO
• Operational Capacity
• Not always the same volumes, provides flexibility on the system
• Point where the gas enters the LDC’s system

• What’s behind the gate?
Avista Gate
Avista Demand
(5,000 Dth/d)
Avista Utilities 2014 Natural Gas IRP Appendices 309
142
From Supply Basin to Meet Demand

Pipeline Citygate
(15,000 MDDO
15,000 Op Cap)
Avista Gate Avista Demand
(18,000 Dth/d)
Pipeline Citygate
(30,000 MDDO
35,000 Op Cap)
Pipeline Citygate
(5,000 MDDO
10,000 Op Cap)
Avista Gate
Avista Gate
Avista Demand
(5,000 Dth/d)
Avista Demand
(17,000 Dth/d)
Total
(50,000 MDDO
60,000 Op Cap)
Total
40,000 Dth/d
Supply
Basin
(40,000 MDQ)
Avista Utilities 2014 Natural Gas IRP Appendices 310
143
Not all gates are created equal

Pipeline Citygate
(15,000 MDDO
15,000 Op Cap)
Avista Gate Avista Demand
(18,000 Dth/d)
Pipeline Citygate
(30,000 MDDO
35,000 Op Cap)
Pipeline Citygate
(5,000 MDDO
10,000 Op Cap)
Avista Gate
Avista Gate
Avista Demand
(5,000 Dth/d)
Avista Demand
(17,000 Dth/d)
Total
(50,000 MDDO
60,000 Op Cap)
Total
40,000 Dth/d
Supply
Basin
(40,000 MDQ)
OK
OK
OK
Avista Utilities 2014 Natural Gas IRP Appendices 311
144
Where is the deficiency?

Pipeline Citygate
(15,000 MDDO
15,000 Op Cap)
Avista Gate Avista Demand
(18,000 Dth/d)
Pipeline Citygate
(30,000 MDDO
35,000 Op Cap)
Pipeline Citygate
(5,000 MDDO
10,000 Op Cap)
Avista Gate
Avista Gate
Avista Demand
(5,000 Dth/d)
Avista Demand
(17,000 Dth/d)
Total
(50,000 MDDO
60,000 Op Cap)
Total
40,000 Dth/d
Supply
Basin
(40,000 MDQ)
Interstate Pipeline Issue Avista Distribution Issue
Avista Utilities 2014 Natural Gas IRP Appendices 312
145
Where is the deficiency?

Pipeline Citygate
(15,000 MDDO
15,000 Op Cap)
Pipeline Citygate
(30,000 MDDO
35,000 Op Cap)
Pipeline Citygate
(5,000 MDDO
10,000 Op Cap)
Total
(50,000 MDDO
60,000 Op Cap)
Supply
Basin
(40,000 MDQ)
Pipeline Issue
• Can they get you the supply you have
contracted for?

• Can they get it through the gate?
Solutions
• Mainline expansion
• Upgrade the meter station
• Realignment of MDDO
Avista Utilities 2014 Natural Gas IRP Appendices 313
146
Where is the deficiency?

Avista Gate Avista Demand
(18,000 Dth/d)
Avista Gate
Avista Gate
Avista Demand
(5,000 Dth/d)
Avista Demand
(17,000 Dth/d)
Total
40,000 Dth/d
Avista Issue • Do you have enough mainline
capacity?
• Is it a gate station design issue?
• What is your demand behind the
gate?
Solutions
• Distribution system enhancements
• High pressure looping
• New gate station
• Recall capacity releases
• Acquire additional pipeline capacity
• Existing
• Expansion
• Storage
• On system vs. Off System
• Peaking agreements
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Solving Unserved Demand
Avista Utilities 2014 Natural Gas IRP Appendices 315
148
When unserved demand does show up……
There are few questions we need to ask:
1.Why is the demand unserved?
2.What is the magnitude of the short? (i.e Are we 1 Dth or 1000 Dth’s short?)
3.What are my options to meet it?
Avista Utilities 2014 Natural Gas IRP Appendices 316
149
When current resources don’t meet demand
what do we consider?
• Transport capacity release recalls
•“Firm” backhauls
•Contract for existing available transportation
•Expansions of current pipelines
•Peaking arrangements with other utilities (swaps/mutual assistance
agreements) or marketers
•In-service territory storage
•Satellite/Micro LNG (storage inside service territory)
•Large scale LNG with corresponding pipeline build into our service
territory
•Structured products/exchange agreements delivered to city gates
•Biogas
•Avista distribution system enhancements
•Demand side management

Avista Utilities 2014 Natural Gas IRP Appendices 317
150
New Resource Risk Considerations
•Does is get supply to the gate?
•Is it reliable/firm?
•Does it have a long lead time?
•How much does it cost?
•New build vs. depreciated cost
•The rate pancake
•Is it a base load resource or peaking?
•How many dekatherms do I need?
•What is the “shape” of resource?
•Is it tried and true technology, new technology, or yet to be discovered?
•Who else will be competing for the resource?

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151
Sensitivities, Scenarios, Portfolios
Sensitivities
Demand
Supply
Scenarios
Group demand
drivers into
meaningful sets
Group supply
drivers into
meaningful sets
Portfolios
Bringing together demand and supply scenarios
Avista Utilities 2014 Natural Gas IRP Appendices 319
152
Supply Scenarios from the 2012 IRP
Table 5.2
Supply Scenarios
Existing Resources
Existing + Expected Available
GTN Fully Subscribed
Avista Utilities 2014 Natural Gas IRP Appendices 320
153
Supply Scenarios for the 2014 IRP
Supply Scenarios
?????
?????
?????
?????
• Do they get gas to the gate?
• Does this affect pricing at the basins?
• Rank the risk of these scenarios.
Avista Utilities 2014 Natural Gas IRP Appendices 321
154
Questions?
Avista Utilities 2014 Natural Gas IRP Appendices 322
155
2014 IRP Timeline
•August 31, 2013 – Work Plan filed with WUTC
•January through April 2014 – Technical Advisory Committee
meetings. Meeting topics will include:
– Demand Forecast and Demand Side Management – January
24
– Supply and Infrastructure, Gate Station Analysis, Supply Side
Resources, Resource Optimization – February 25
–Distribution Planning, Natural Gas Pricing, CNG/NGV,
SENDOUT® Preliminary Results and Further Case
Discussion – March 26
– SENDOUT® results – April 23
•May 30, 2014 – Draft of IRP document to TAC
•June 30, 2014 – Comments on draft due back to Avista
•July 2014 – TAC final review meeting (if necessary)
•August 31, 2014 – File finalized IRP document
Avista Utilities 2014 Natural Gas IRP Appendices 323
156
2014 Avista Natural Gas IRP
Technical Advisory Committee Meeting 3
March 26, 2014
Coeur d’Alene, ID
Avista Utilities 2014 Natural Gas IRP Appendices 324
157
Agenda
•Introductions & Logistics
•Distribution System Planning
•CNG/NGV Initiatives
•Natural Gas Prices
•Procurement Planning
•Preliminary Results and Scenario
Discussion

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158
2014 IRP Timeline
•August 31, 2013 – Work Plan filed with WUTC
•January through April 2014 – Technical Advisory Committee
meetings. Meeting topics will include:
– Demand Forecast and Demand Side Management – January
24
– Supply and Infrastructure, Gate Station Analysis, Supply Side
Resources, Resource Optimization – February 25
–Distribution Planning, Natural Gas Pricing, CNG/NGV,
SENDOUT® Preliminary Results and Further Case
Discussion – March 26
– DSM CPA results, further SENDOUT® results and Stochastic
analysis – April 23
•May 30, 2014 – Draft of IRP document to TAC
•June 30, 2014 – Comments on draft due back to Avista
•July 2014 – TAC final review meeting (if necessary)
•August 31, 2014 – File finalized IRP document Avista Utilities 2014 Natural Gas IRP Appendices 326
159

Distribution System Planning
Terrence Browne, Senior Gas Planning Engineer
Natural Gas Technical Advisory Committee
March 26, 2014
Avista Utilities 2014 Natural Gas IRP Appendices 327
160
Mission
• Using technology to plan and design a safe, reliable, and
economical distribution system
Avista Utilities 2014 Natural Gas IRP Appendices 328
161
Gas Distribution Planning Overview
• Scope of Gas Distribution Planning
• SynerGEE Load Study
•Preparing a Load Study
•Balancing Model
•Validating Model
• Planning Criteria
• Interpreting Results
• Long-term Planning Objectives
• Sharing Load Study Results
• Electronic Pressure Recorders
• Project Examples

Avista Utilities 2014 Natural Gas IRP Appendices 329
162
__
Pup Pdown
Q
L ||
D
__
5 Variables for Any Given Pipe
Avista Utilities 2014 Natural Gas IRP Appendices 330
163
Scope of Gas Distribution
Planning
Supplier Pipeline
High Pressure Main
Reg.
Distribution Main and Services
Reg. Reg.
Gate
Sta.
Avista Utilities 2014 Natural Gas IRP Appendices 331
164
Scope of Gas Distrib. Planning
cont.
Gate
Sta.
Reg. Reg. Reg.
Reg. Reg.
Gate
Sta.
Gate
Sta.
Avista Utilities 2014 Natural Gas IRP Appendices 332
165
SynerGEE Load Study
• Simulate distribution behavior
• Identify low pressure areas
• Coordinate reinforcements with expansions
• Measure reliability
Avista Utilities 2014 Natural Gas IRP Appendices 333
166
35 DD
30’ F
Avista Utilities 2014 Natural Gas IRP Appendices 334
167
Preparing a Load Study
•Estimating Customer Usage
•Creating a Pipeline Network
•Join Customer Loads to Pipes
•Convert to Load Study
Avista Utilities 2014 Natural Gas IRP Appendices 335
168
Estimating Customer Usage
•Gathering Data
– Days of service
– Degree Days
– Usage
– Name, Address, Revenue Class, Rate Schedule…
Avista Utilities 2014 Natural Gas IRP Appendices 336
169
Estimating Customer Usage cont.
•Degree Days
– Heating (HDD)
– Cooling (CDD)
•Temperature - Usage Relationship
– Load vs. HDD’s
– Base Load (constant)
– Heat Load (variable)
– High correlation with residential

Avg. Daily Heating Cooling
Temperature Degree Days Degree Days
('Fahrenheit) (HDD) (CDD)
85 20
80 15
75 10
70 5
65 0 0
60 5
55 10
50 15
45 20
40 25
35 30
30 35
25 40
20 45
15 50
10 55
5 60
4 61
0 65
-5 70
-10 75
-15 80
-17 82
Avista Utilities 2014 Natural Gas IRP Appendices 337
170 Avista Utilities 2014 Natural Gas IRP Appendices 338
171
Heat Base
Avista Utilities 2014 Natural Gas IRP Appendices 339
172
Estimating Customer Usage cont.
•Peaking Factor
– Peaking Factor = 6.25% of daily load
– “Observed ratio” of greatest hourly flow to total daily flow at
Gate Stations
•Industrial Customers
– Model maximum hourly usage per Contractual Agreement
– Firm Transportation customers only
– Low Temperature-Usage correlation

Avista Utilities 2014 Natural Gas IRP Appendices 340
173
Creating a Pipeline Network
• Elements
– Pipes, regulators, valves
– Attributes: Length, internal diameter,
roughness
• Nodes
– Sources, usage points, pipe ends
– Attributes: Flow, pressure
Avista Utilities 2014 Natural Gas IRP Appendices 341
174 Avista Utilities 2014 Natural Gas IRP Appendices 342
175 Avista Utilities 2014 Natural Gas IRP Appendices 343
176
Join Customer Loads to a Model
• Residential and commercial loads are assigned to pipes
• Industrial or other large loads are assigned to nodes
Avista Utilities 2014 Natural Gas IRP Appendices 344
177 Avista Utilities 2014 Natural Gas IRP Appendices 345
178 Avista Utilities 2014 Natural Gas IRP Appendices 346
179 Avista Utilities 2014 Natural Gas IRP Appendices 347
180 Avista Utilities 2014 Natural Gas IRP Appendices 348
181
Balancing Model
• Simulate system for any temperature
– HDD’s
• Solve for pressure at all nodes
Avista Utilities 2014 Natural Gas IRP Appendices 349
182
35 DD
30˚ F
Avista Utilities 2014 Natural Gas IRP Appendices 350
183
Validating Model
•Simulate recorded condition
•Pressure Recorders
– Do calculated results match field data?
•Gate Station Telemetry
– Do calculated results match source data?
•Possible Errors
– Missing pipe
– Source pressure changed
– Industrial loads

Avista Utilities 2014 Natural Gas IRP Appendices 351
184
41 psig
Location: N. Orchard, Moscow ID
Observation Date: Friday, March 1st
Hi = 35˚ F
Low = 25˚F
Avg = 30˚F
= 35 DD
Validating Model cont.
Avista Utilities 2014 Natural Gas IRP Appendices 352
185
35 DD
30˚ F
N. Orchard Moscow, ID
Avista Utilities 2014 Natural Gas IRP Appendices 353
186
• Reliability during design HDD
– Spokane 82 HDD
– Medford 61 HDD
– Klamath Falls 72 HDD
– La Grande 74 HDD
– Roseburg 55 HDD

• Maintain minimum of 15 psig in system at all times
– 5 psig in lower MAOP areas
Planning Criteria
Avista Utilities 2014 Natural Gas IRP Appendices 354
187
35 DD
30˚ F
Avista Utilities 2014 Natural Gas IRP Appendices 355
188
50 DD
15˚ F
Avista Utilities 2014 Natural Gas IRP Appendices 356
189
65 DD
0˚ F
Avista Utilities 2014 Natural Gas IRP Appendices 357
190
Interpreting Results
•Identify Low Pressure Areas
– Number of feeds
– Proximity to source
•Looking for Most Economical Solution
–Length (minimize)
– Construction obstacles (minimize)
– Customer growth (maximize)
Avista Utilities 2014 Natural Gas IRP Appendices 358
191 Avista Utilities 2014 Natural Gas IRP Appendices 359
192 Avista Utilities 2014 Natural Gas IRP Appendices 360
193
65 DD
0’ F
Avista Utilities 2014 Natural Gas IRP Appendices 361
194
65 DD
0’ F
R
Avista Utilities 2014 Natural Gas IRP Appendices 362
195
82 DD
-17’ F
R
Avista Utilities 2014 Natural Gas IRP Appendices 363
196
Long-term Planning Objectives
•Future Growth/Expansion
•Design Day Conditions
•Facilitate Customer Installation Targets
Avista Utilities 2014 Natural Gas IRP Appendices 364
197
• Gas Planning Proposals
• Gas Planning AOI

Sharing Load Study Results
Avista Utilities 2014 Natural Gas IRP Appendices 365
198
Gas Planning Proposals
• Proposed pipe - dashed line

• Gas Planning recommendations for main
extensions
Add
4”
Avista Utilities 2014 Natural Gas IRP Appendices 366
199
Gas Planning AOI
• Different colors to show the types of areas

• Geographic-specific information to help make
decisions
Low
pressure
Avista Utilities 2014 Natural Gas IRP Appendices 367
200
Electronic Pressure Recorders
• Daily Feedback
• Real time if necessary

Avista Utilities 2014 Natural Gas IRP Appendices 368
201
Post Falls State Line
Avista Utilities 2014 Natural Gas IRP Appendices 369
202
Hayden Lake
Avista Utilities 2014 Natural Gas IRP Appendices 370
203
South Hayden Lake
Avista Utilities 2014 Natural Gas IRP Appendices 371
204

Compressed Natural Gas Services
Marc Schaffner, Strategic Initiatives Manager

Natural Gas Technical Advisory Committee
March 26, 2014
Avista Utilities 2014 Natural Gas IRP Appendices 372
205
Natural Gas Reserves and Utilization

U.S. Natural Gas Reserves
The U.S.’s total recoverable resource base at 2,384 trillion cubic feet
Projected to meet total domestic demand over the next 100 years
This year’s estimates rose significantly at 22.1 percent since 2010
Source: Potential Gas Committee (PGC)
Natural Gas Vehicles (NGV) Worldwide
Estimated 15 million natural gas vehicles (NGVs)
Asia and Middle East 8.8M, South America 4.3 M, Africa .16M and North America .14M
NGVs on U.S. Highways
Estimated 120,000 NGVs on U.S. highways
Estimated 15,000 NGVs were added to U.S. highways in 2012
Source: American Clean Skies
The Future of NGVs
• Since 2003, the use of natural gas for vehicles has doubled in the U.S.
• The number of natural gas fueling stations is expected to more than double by 2015
• Natural gas is projected to overtake oil as the most-used fuel in the U.S. by 2030
Source: IEA World Outlook Report
Avista Utilities 2014 Natural Gas IRP Appendices 373
206
U.S. CNG Infrastructure
1,334 Private and Public Refueling
Stations

Source: U.S. Department of Energy, February 2014
<5% in Oregon, Washington
and Idaho
Avista Utilities 2014 Natural Gas IRP Appendices 374
207
U.S. CNG Infrastructure
585 Public Refueling Stations

Source: U.S. Department of Energy, March 2013 Avista Utilities 2014 Natural Gas IRP Appendices 375
208
Avista’s Investment in Compressed Natural Gas

Environmentally responsible
It’s clean and efficient
25% less CO2 emissions than gasoline or diesel
A vital part of an alternative transportation portfolio
Cost effective
Lowers fuel costs
Tax credits and incentives
Reduces dependency on imported fuel sources
Natural gas is an abundant, domestic resource
A clean fueling solution across an increasing range of NGV classes
Extends benefits to commercial fleets and private operators
Mobilizes safe and reliable CNG equipment
Vehicles
Public fueling infrastructure

Avista Utilities 2014 Natural Gas IRP Appendices 376
209
Over the past 25 years Avista has fueled light duty vehicles,
service continuity equipment and fork lifts with CNG
Ten of our gas operating centers have maintained private CNG
refueling infrastructure over that time period
2011, we began devising plans to upgrade CNG infrastructure
at our highest volume service centers in Idaho, Oregon and
Washington
2012, we completed construction of a new refueling station at
our Mission Avenue service center in Spokane, WA
2013, we completed a second Spokane refueling station at our
Dollar Road gas service center
Q2 of 2014 we intend to start on construction of a new refueling
station at our Coeur d‘ Alene, ID and begin upgrading an
existing station at Klamath Falls, OR
Q4 of 2014 construction of a new refueling station at White
City, OR is projected to begin
Avista CNG – Yesterday and Today
Spokane Refueling Stations
Mission Avenue (top)
Dollar Road (bottom)
Avista Utilities 2014 Natural Gas IRP Appendices 377
210
Avista’s CNG Station Schedule
CNG Refueling
Location
Project
Status
Compression
Capability
Storage
Capacity
Public
Access *
Mission Avenue SC
Spokane, Wash.

Completed 2012
125 HP Compressor
202 SCFM 280 GGE at 4500 psi
Dollar Road SC
Spokane, Wash. Completed 2013 125 HP Compressor
202 SCFM 280 GGE at 4500 psi X
Coeur d’Alene SC
Coeur d’Alene,
Idaho
Construction 2014
(2) 50 HP
Compressors
75 SCFM
280 GGE at 4500 psi X
Klamath Falls SC
Klamath Falls, Ore. Upgrade 2013-14 30 HP Compressor
60 SCFM 90 GGE at 4500 psi
White City Industrial
Medford, Ore. Construction 2014-15
200 HP Dual
Compressor
300 SCFM
450 GGE at 4500 psi X
* Public access subject to regulatory approval
Avista Utilities 2014 Natural Gas IRP Appendices 378
211
CNG Investment Recovery
CNG fueling equipment can be effectively treated like conventional utility
infrastructure
• gas pipe and regulators, power poles and transformers
• compressors, storage vessels and dispensers
The financial tests and investment recovery mechanisms are familiar
• standard service agreements may be offered to anchor fleet operators with
special provisions that define annual consumption minimum, schedule and
deficiency requirements
However…
CNG fueling infrastructure offers an average operating life of 20 years
The service life of commercial grade NGVs ranges from 5 to 10 years

Avista Utilities 2014 Natural Gas IRP Appendices 379
212
Investment Recovery Illustration

Avista’s Investment $1M capital to fund a turn key CNG
station
Consumption minimum 350k gas gallon equivalents (GGE)
annually*
Consumption schedule 10 years
CNG Rate $2.00 per GGE

* equivalent to approximately 35 natural gas fueled waste hauling vehicles

Dollar Road
CNG Fuel Dispenser Avista Utilities 2014 Natural Gas IRP Appendices 380
213
Natural Gas Vehicle Investment Recovery
Waste Hauling NGV
Customer Investment $35,000 per vehicle
Miles per gallon 3
Annual mileage 25,000
CNG per gallon $2.00
Diesel per gallon $4.00
Estimated payback 25 months
Annual fuel savings $16,800
Five–year ROI 238%

Avista Utilities 2014 Natural Gas IRP Appendices 381
214
Make or Buy Decisions

Point of Sale Customer Billing
CNG Station Maintenance and Service Continuity

• Availability of full service providers
• Transaction processors
• Billing cost per unit of measure
• Required menu of services

• Technical expertise and equipment monitoring systems
• Planned maintenance - resources and costs
• Unplanned repairs and restoration - resources and costs
• Outage response and service continuity

Avista Utilities 2014 Natural Gas IRP Appendices 382
215
Avista Contributors
Energy Solutions Account
Executives
Customer Solutions
Regional Business Managers
Government Relations
Lobbyists
Legal Counsel Risk
Real Estate
Contract Administration
Real Estate
Legal
Property Acquisition
Regulatory
Rates & Tariffs
Treasury
Billing Analysis
Financial Planning & Analysis
Facilities
Project Management
Fleet
NGV Management
CNG Infrastructure Maintenance
Distribution Infrastructure
Gas Engineering

Avista Utilities 2014 Natural Gas IRP Appendices 383
216
Organizational Capability

What are we learning?
• The value of broad-based collaboration occurring across a dynamic natural gas for
transportation marketplace. Private & public sector customers, industry
associations, government, contractors and vendors
What skills are we developing?
• NGV acquisition and maintenance
• CNG fueling infrastructure planning, construction and maintenance
• CNG/NGV consultation
What value does Avista’s CNG capability provide our employees, customers
and business community?
• A more robust portfolio of energy offerings
• Enhanced revenue and cost saving opportunities for regional businesses
• An innovative, sustainable way to positively affect environmental
quality and energy independence

Avista Utilities 2014 Natural Gas IRP Appendices 384
217
Thank You
Avista Utilities 2014 Natural Gas IRP Appendices 385
218

Natural Gas Prices
Kelly Fukai, Manager of Natural Gas Planning

Natural Gas Technical Advisory Committee
March 26, 2014
Avista Utilities 2014 Natural Gas IRP Appendices 386
219
What Drives the Natural Gas Market?
Natural Gas Spot Prices (Henry Hub)

Supply
– Type: Conventional vs. Non-conventional
– Location
– Cost
Demand
– Residential/Commercial/Industrial
– Power Generation
– Natural Gas Vehicles
Legislation
– Environmental
Energy Correlations
– Oil vs. Gas
– Coal vs. Gas
– Natural Gas Liquids
Weather
Storage
???
Avista Utilities 2014 Natural Gas IRP Appendices 387
220
Short Term Market Perspective
Avista Utilities 2014 Natural Gas IRP Appendices 388
221
The Long Term Fundamentals
Demand
• Economy (Recession, Depression, Inflation,
etc.)
• Industrial Demand
• Power Generation
• Any NG (LNG, NGV, CNG)
US Natural Gas Supply and Production
• Resource Base
• Drilling Efficiency
• Associated Gas
Global Dynamics – LNG Imports and Exports
North American Storage Capacity
Correlation (or lack thereof) with other energy
products
The Environment
• Carbon Legislation
• The “F” Word – FRACKING
• Renewable Portfolio Standards Avista Utilities 2014 Natural Gas IRP Appendices 389
222
Shale is almost EVERYWHERE
Avista Utilities 2014 Natural Gas IRP Appendices 390
223
Changing the Flow Dynamics
Avista Utilities 2014 Natural Gas IRP Appendices 391
224
NGL’s Impact on the Cost to Produce
NGL’s enhance the production economics for producers. NGL’s are a main contributor to
understanding why gas production companies continue to produce even with gas prices at very
low levels.

The following table illustrates how the economics can improve with a credit for NGL’s.

Shale Play Cost to Produce
without NGL’s
Credit
Cost to Produce
including NGL’s
Credit
Marcellus $4.81 $2.83
Montney $3.85 $0.57
Barnett $5.39 $2.41
Note: These costs are indicative of the historical impact. The costs can vary from play to play and company to company and will
change as market conditions change.
Avista Utilities 2014 Natural Gas IRP Appendices 392
225
Canada Dry vs. Canada Not Dry
Why won’t Canada be dry?
• Tons of JV money
• IP rates are proving to be better
than anticipated.
• Horn River IP rates have
increased 150%
• Economics are pretty good too.
• Duverney in particular is liquids
rich.

Source: NEB Canada’s Energy Future 2013
Avista Utilities 2014 Natural Gas IRP Appendices 393
226
Current vs. Historical US Dry Gas Production
Avista Utilities 2014 Natural Gas IRP Appendices 394
227
Source: EIA January Drilling Productivity Report
The Learning Curve
Avista Utilities 2014 Natural Gas IRP Appendices 395
228
Forecasted Natural Gas Production
Avista Utilities 2014 Natural Gas IRP Appendices 396
229
Oil and Gas Production are like Peas and Carrots
More oil = More gas
Avista Utilities 2014 Natural Gas IRP Appendices 397
231
Carbon Prices
• Currently our consultant forecasts include carbon tax adders to the Henry Hub gas price.
• Adders start in early 2020’s
• Modest adders
• One will drop carbon in next long term forecast.
• Primarily a demand effect
• Can result in demand change due to price elastic response, however tax must be
significant enough to trigger.
• Could possibly trigger increased usage due to fuel switching.
• May increase the DSM potential.
• Changes total portfolio costs but does not necessarily change the resource mix.
Avista Utilities 2014 Natural Gas IRP Appendices 398
232
How prices affect IRP Planning?
• Major component of the total cost
• Change in price can trigger price elastic response
•THE major piece of avoided costs and therefore cost
effectiveness of DSM
• Can change resource selection based on basin differentials
• Storage utilization

Avista Utilities 2014 Natural Gas IRP Appendices 399
233
IRP Natural Gas Price Forecast Methodology
1.Examine fundamental forecasts (Consultant #1, Consultant #2, EIA, etc.)
2.Forward prices
3.Carbon legislation adder beginning in 2022 ($8.49/ton grows to
$15.24/ton)
4.Basin adjusted based on forecasted
5.Monthly shape set based on forecasted
6. 50% Nymex, 50% blended Consultants Year 1
7. 40% Nymex, 60% blended Consultants Year 2
8. 30% Nymex, 70% blended Consultants Year 3
9. 20% Nymex, 80% blended Consultants Year 4
10. 10% Nymex, 90% blended Consultants Year 5
11.100% blended Consultants Year 6 – 18
12.100% Consultant #1 year 18 - 20

Avista Utilities 2014 Natural Gas IRP Appendices 400
234
2012 IRP Forecasted Prices
Avista Utilities 2014 Natural Gas IRP Appendices 401
235
Current Long Term Henry Hub Forecasts NOMINAL
Avista Utilities 2014 Natural Gas IRP Appendices 402
236
Current Long Term Henry Hub Forecasts
REAL
Avista Utilities 2014 Natural Gas IRP Appendices 403
237
Low – Med – High from 2012 IRP
NOMINAL
Avista Utilities 2014 Natural Gas IRP Appendices 404
238
Proposed Price Forecasts
NOMINAL
Avista Utilities 2014 Natural Gas IRP Appendices 405
239
Low – Med - High from 2012 IRP
REAL
Avista Utilities 2014 Natural Gas IRP Appendices 406
240
Proposed Price Forecasts
REAL
Avista Utilities 2014 Natural Gas IRP Appendices 407
241
Regional Price Assumptions
Regional Price as a percent of Henry Hub Price
AECO Sumas Rockies Malin Stanfield
Consultant1
Forecast Average 84.0% 92.0% 90.6% 95.4% 93.2%
Consultant2
Forecast Average 88.5% 94.4% 95.1% 97.0% 95.0%
Historic Cash
Three Yr Average 87.4% 98.4% 96.9% 99.2% 97.5%
Prior IRP 87.0% 88.3% 89.4% 91.1% 90.2%
Avista Utilities 2014 Natural Gas IRP Appendices 408
242
Monthly Price Shape
Monthly Price as a percent of Average Price
Jan Feb Mar Apr May Jun
Consult1 104.7% 104.2% 96.8% 95.9% 96.6% 98.2%
Consult2 101% 101.6% 101.5% 98.9% 98.8% 98.5%
Prior IRP 102% 101.5% 98.5% 98.0% 98.5% 100.5%
Jul Aug Sep Oct Nov Dec
Consult1 99.2% 99.7% 98.9% 99.4% 101% 105.2%
Consult2 99.3% 99.3% 100.3% 99.3% 100.5% 101.1%
Prior IRP 101.5% 102.0% 98.5% 98.5% 99.0% 103%
Avista Utilities 2014 Natural Gas IRP Appendices 409
243

Procurement Planning
Kelly Fukai, Manager of Natural Gas Planning

Natural Gas Technical Advisory Committee
March 26, 2014
Avista Utilities 2014 Natural Gas IRP Appendices 410
244
Procurement Plan Philosophy
Mission
To provide a diversified portfolio of reliable supply and a
level of price certainty in volatile markets.

We cannot accurately predict what natural gas prices will do, however we
can use experience, market intelligence, and fundamental market analysis to
structure and guide our procurement strategies.

Our goal is to develop a plan that utilizes customer resources (storage and
transportation), layers in pricing over time for stability (time averaging),
allows discretion to take advantage of pricing opportunities should they arise,
and appropriately manages risk.

Avista Utilities 2014 Natural Gas IRP Appendices 411
245
Review conducted with SOG includes:
• Mission statement and approach
• Current and future market dynamics
• Hedge percentage
• Resources available (i.e. storage and transportation)
• Hedge windows (how many, how long)
• Long term hedging approach
• Storage utilization
• Analysis (volatility, past performance, scenarios, etc.)

Comprehensive Review of Previous Plan
Avista Utilities 2014 Natural Gas IRP Appendices 412
246
A Thorough Evaluation of Risks
Risk
Assessment
Load Volatility
•Seasonal Swings
Price
•Cash vs. Forward
Market
Liquidity
•Is there enough?
Counterparty
•Who can we
transact with?
Foreign
Currency
•What’s our
exposure?
Legislation
•Does it impact
our plan?
Avista Utilities 2014 Natural Gas IRP Appendices 413
247
Procurement Plan Structure
The procurement plan incorporates a portfolio approach that is
diversified in terms of:
–Components: The plan utilizes a mix of index, fixed price, and
storage transactions.
–Transaction Dates: Hedge windows are developed to distribute the
transactions throughout the plan.
–Supply Basins: Plan to primarily utilize AECO, execute at lowest
price basis at the time.
–Delivery Periods: Hedges are completed in annual and/or seasonal
timeframes. Long-term hedges may be executed.
Transactions are executed pursuant to a plan and process; however,
the procurement plan allows Avista to be flexible to market conditions
and opportunistic when appropriate.

Avista Utilities 2014 Natural Gas IRP Appendices 414
248
21%
18%
17%
44%
2014-2015 Procurement Plan Components
All Jurisdictions
Prior Year Hedges
Storage Withdrawals
One Year or Less
Hedges
Index
Avista Utilities 2014 Natural Gas IRP Appendices 415
249

Preliminary Modeling Results
Kelly Fukai, Manager of Natural Gas Planning

Natural Gas Technical Advisory Committee
March 26, 2014
Avista Utilities 2014 Natural Gas IRP Appendices 416
250
1.Customer annual growth rates:

2.Use per customer coefficients –3 year average use per HDD per customer
3. Weather planning standard – coldest day on record
WA/ID 82; Medford 61; Roseburg 55; Klamath 72; La Grande 74
Developing a Reference Case

Customer
count
forecast
Use per
customer
coefficients
Weather Reference
Case Demand
Avista Utilities 2014 Natural Gas IRP Appendices 417
251
Reference Demand Case
Avista Utilities 2014 Natural Gas IRP Appendices 418
252
Demand Sensitivities
20 Yr
Avista Utilities 2014 Natural Gas IRP Appendices 419
253
Demand Sensitivities- Preliminary Results
Avista Utilities 2014 Natural Gas IRP Appendices 420
254
Mix and Match to Make Scenarios
Avista Utilities 2014 Natural Gas IRP Appendices 421
255
Demand Scenarios – Proposed
Avista Utilities 2014 Natural Gas IRP Appendices 422
256
Demand Scenarios – Preliminary Results
Avista Utilities 2014 Natural Gas IRP Appendices 423
257
First Year Unserved – Preliminary Results
Need:
Chart showing first year unserved Figure 1.13
Avista Utilities 2014 Natural Gas IRP Appendices 424
258
2014 IRP Timeline
•August 31, 2013 – Work Plan filed with WUTC
•January through April 2014 – Technical Advisory Committee
meetings. Meeting topics will include:
– Demand Forecast and Demand Side Management – January
24
– Supply and Infrastructure, Gate Station Analysis, Supply Side
Resources, Resource Optimization – February 25
– Distribution Planning, Natural Gas Pricing, CNG/NGV,
SENDOUT® Preliminary Results and Further Case Discussion
– March 26
–DSM CPA results, further SENDOUT® results and
Stochastic analysis – April 23
•May 30, 2014 – Draft of IRP document to TAC
•June 30, 2014 – Comments on draft due back to Avista
•July 2014 – TAC final review meeting (if necessary)
•August 31, 2014 – File finalized IRP document Avista Utilities 2014 Natural Gas IRP Appendices 425
259
2014 Avista Natural Gas IRP
Technical Advisory Committee Meeting 4
April 23, 2014
Spokane, WA
Avista Utilities 2014 Natural Gas IRP Appendices 426
260
Agenda

•Introductions & Logistics
•Demand Side Management Potential
•Assumptions Review
•Demand Sensitivities and Scenarios Updates
•Supply Side Resource Options
•Stochastic Analysis
•Key Issues & Document Discussion
Avista Utilities 2014 Natural Gas IRP Appendices 427
261
2014 IRP Timeline
•August 31, 2013 – Work Plan filed with WUTC
•January through April 2014 – Technical Advisory Committee
meetings. Meeting topics will include:
– Demand Forecast and Demand Side Management – January
24
– Supply and Infrastructure, Gate Station Analysis, Supply Side
Resources, Resource Optimization – February 25
– Distribution Planning, Natural Gas Pricing, CNG/NGV,
SENDOUT® Preliminary Results and Further Case Discussion
– March 26
–DSM CPA results, further SENDOUT® results and
document discussion – April 23
•May 30, 2014 – Draft of IRP document to TAC
•June 30, 2014 – Comments on draft due back to Avista
•July 2014 – TAC final review meeting (if necessary)
•August 31, 2014 – File finalized IRP document Avista Utilities 2014 Natural Gas IRP Appendices 428
262
Demand Side Management CPA Results
Avista Utilities 2014 Natural Gas IRP Appendices 429
263
Assumptions Review

Avista Utilities 2014 Natural Gas IRP Appendices 430
264
1.Customer annual growth rates:

2.Use per customer coefficients – 3 year historical use per customer by
class
3. Weather planning standard – coldest day on record
WA/ID 82; Medford 61; Roseburg 55; Klamath 72; La Grande 74
Developing a Reference Case

Customer
count
forecast
Use per
customer
coefficients
Weather Reference
Case Demand
Avista Utilities 2014 Natural Gas IRP Appendices 431
265
WA-ID Region: 2014 IRP and 2012 IRP
100,000
150,000
200,000
250,000
300,000
350,000
20
1
2
20
1
3
20
1
4

F
20
1
5

F
20
1
6

F
20
1
7

F
20
1
8

F
20
1
9

F
20
2
0

F
20
2
1

F
20
2
2

F
20
2
3

F
20
2
4

F
20
2
5

F
20
2
6

F
20
2
7

F
20
2
8

F
20
2
9

F
20
3
0

F
20
3
1

F
20
3
2

F
20
3
3

F
20
3
4

F
20
3
5

F
20
3
6

F
20
3
7

F
20
3
8

F
20
3
9

F
20
4
0

F
To
t
a
l

C
u
s
t
o
m
e
r
s
WA-ID Region
(Annual Growth: Current Base = 1.0%, Previous IRP Base = 1.6%)
WA-ID Base WA-ID 2012 IRP Base Forecast
Avista Utilities 2014 Natural Gas IRP Appendices 432
266
OR Region: 2014 IRP and 2012 IRP
60,000
70,000
80,000
90,000
100,000
110,000
120,000
130,000
140,000
150,000
20
1
2
20
1
3
20
1
4

F
20
1
5

F
20
1
6

F
20
1
7

F
20
1
8

F
20
1
9

F
20
2
0

F
20
2
1

F
20
2
2

F
20
2
3

F
20
2
4

F
20
2
5

F
20
2
6

F
20
2
7

F
20
2
8

F
20
2
9

F
20
3
0

F
20
3
1

F
20
3
2

F
20
3
3

F
20
3
4

F
20
3
5

F
20
3
6

F
20
3
7

F
20
3
8

F
20
3
9

F
20
4
0

F
To
t
a
l

C
u
s
t
o
m
e
r
s
OR Region
(Annual Growth: Current Base = 0.9%, Previous IRP Base = 1.7%)
OR Base OR 2012 IRP Base Forecast
Avista Utilities 2014 Natural Gas IRP Appendices 433
267
Natural Gas Prices
Avista Utilities 2014 Natural Gas IRP Appendices 434
268
Price Elasticity: What does the research
show?
Avista Utilities 2014 Natural Gas IRP Appendices 435
269
Price Elasticity Proposed
Assumptions

• The data is a mixed bag at best:
• 8 of 9 super regions have statistically
significant short and long run elasticities.
• At a state level only 10 of 50 show statistical
significant elasticities.
• In some cases, the estimated elasticities are
positive.

We incorporated a -.15 price elastic response
for our expected elasticity assumption.
Avista Utilities 2014 Natural Gas IRP Appendices 436
270
Carbon Legislation Sensitivities
Carbon Legislation Case 2013 2033
Low 5.00$ 5.00$
Medium 8.32$ 14.83$
High 16.00$ 28.00$
*Real Dollars per Ton of CO2
Avista Utilities 2014 Natural Gas IRP Appendices 437
271
Demand Sensitivities & Scenarios
Update

Avista Utilities 2014 Natural Gas IRP Appendices 438
272
Sensitivities, Scenarios, Portfolios
Sensitivities
Demand
Supply
Scenarios
Group demand
drivers into
meaningful sets
Group supply
drivers into
meaningful sets
Portfolios
Bringing together demand and supply scenarios
Avista Utilities 2014 Natural Gas IRP Appendices 439
273
Sensitivity Analysis
Avista Utilities 2014 Natural Gas IRP Appendices 440
274 Avista Utilities 2014 Natural Gas IRP Appendices 441
275 Avista Utilities 2014 Natural Gas IRP Appendices 442
276
Demand Sensitivity Analysis – DIRECT
Peak Day Demand
Avista Utilities 2014 Natural Gas IRP Appendices 443
277
Demand Sensitivity Analysis – DIRECT
Peak Day Demand
Avista Utilities 2014 Natural Gas IRP Appendices 444
278
Demand Sensitivity Analysis – DIRECT
Peak Day Demand
Avista Utilities 2014 Natural Gas IRP Appendices 445
279
Demand Sensitivity Analysis – DIRECT
Peak Day Demand
Avista Utilities 2014 Natural Gas IRP Appendices 446
280
Demand Sensitivity Analysis – INDIRECT
Peak Day Demand
Avista Utilities 2014 Natural Gas IRP Appendices 447
281
Demand Sensitivity Analysis – INDIRECT
Peak Day Demand
Avista Utilities 2014 Natural Gas IRP Appendices 448
282 Avista Utilities 2014 Natural Gas IRP Appendices 449
283
Scenario Analysis

Avista Utilities 2014 Natural Gas IRP Appendices 450
284
Proposed Scenarios

Avista Utilities 2014 Natural Gas IRP Appendices 451
285
Existing Resources vs. Peak Day
Demand
Avista Utilities 2014 Natural Gas IRP Appendices 452
286
Existing Resources vs. Peak Day
Demand
Expected Case – Medford/Roseburg (DRAFT)
Avista Utilities 2014 Natural Gas IRP Appendices 453
287
Existing Resources vs. Peak Day
Demand
Expected Case – Klamath Falls (DRAFT)
Avista Utilities 2014 Natural Gas IRP Appendices 454
288
Existing Resources vs. Peak Day
Demand
Expected Case – La Grande (DRAFT)
Avista Utilities 2014 Natural Gas IRP Appendices 455
289 Avista Utilities 2014 Natural Gas IRP Appendices 456
290 Avista Utilities 2014 Natural Gas IRP Appendices 457
291 Avista Utilities 2014 Natural Gas IRP Appendices 458
292
Resource Options for Meeting
Unserved Demand
Avista Utilities 2014 Natural Gas IRP Appendices 459
293
Potential New Supply Resources
Considerations

• Availability
– By Region – which region(s) can the resource be utilized?
– Lead time considerations – when will it be available?
• Type of Resource
– Peak vs. Baseload
– Firm or Non-Firm
– “Lumpiness”
• Usefulness
– Does it get the gas where we need it to be?
– Last mile issues
• Cost
Avista Utilities 2014 Natural Gas IRP Appendices 460
294
Supply Resources Available

Additional Resource Size Cost/Rates Availability Notes
Capacity Release Recall 30,000 Dth NWPL Rate 2018 Recall of previously released capacity
Unsubscribed GTN Capacity Up to 50,000 Dth GTN Rate plus
Upstream TCPL
Now Currently available unsubscribed capacity from
Kingsgate to Stanfield or Malin plus associated
Alberta transport
NWP Expansion Up to 50,000 Dth NWPL Rate x 4 2016 Expansion from Sumas/JP to WA/ID or
Sumas/JP to OR
Citygate Deliveries Variable Varies Now Represents the ability to buy a delivered
product from another utility or marketer.
Limited counterparties
Satellite LNG 90,000 Dth
w/30,000 Dth
deliverability
$6.5 Million capital
cost plus $350K
O&M
2016 Provides for peaking services and alleviates
the need for costly pipeline expansions.
Avista Utilities 2014 Natural Gas IRP Appendices 461
295
Supply Resources Available

Additional Resource Size Cost/Rates Availability Notes
Medford Lateral Exp 25,000 Dth GTN Rate 2016 Additional compression to facilitate more gas
to flow from mainline GTN to Medford.
Malin Backhauls 25,000 GTN Rate Now Currently available
Avista Utilities 2014 Natural Gas IRP Appendices 462
296
Future Supply Resources
Other Resources Considered
Additional Resource Size Cost/Rates Availability Notes
Co. Owned LNG 600,000 Dth w/
150,000 of
deliverability
$75 Million plus
$2 Million annual
O&M
2020 On site, in service territory liquefaction and
vaporization facility
Various pipelines – Pacific
Connector, Cross-Cascades,
etc.
Varies Precedent
Agreement Rates
2018 Requires additional mainline capacity on
NWPL or GTN to get to service territory
Large Scale LNG Varies Commodity less Fuel 2018 Speculative, needs pipeline transport
In Ground Storage Varies Varies Varies Requires additional mainline transport to
get to service territory
Avista Utilities 2014 Natural Gas IRP Appendices 463
297
DSM Avoided Cost

•Avoided cost determined by comparison to the marginal
supply side resources to meet incremental demand, primarily
commodity costs.
•Preliminary avoided costs were provided to Enernoc for cost
effectiveness testing and development of the DSM acquirable
potential.
•Potential is then input into SENDOUT® and avoided costs are
re-evaluated.

Avista Utilities 2014 Natural Gas IRP Appendices 464
298 Avista Utilities 2014 Natural Gas IRP Appendices 465
299
Stochastic Analysis

Avista Utilities 2014 Natural Gas IRP Appendices 466
300
What is it?
•Stochastic vs. Deterministic
•Facilitates a statistical approach to analysis
•Reiterative runs of SENDOUT (e.g. 200 “Draws”)
•Utilizes statistically generated price curves and
weather patterns derived from historical data
•Develops a distribution of the “draws” results
– Normal and lognormal distribution
Avista Utilities 2014 Natural Gas IRP Appendices 467
301
Analytical Objectives
•Weather
– Validate reasonableness of our weather planning standard
– Compare demand and unserved results
– Quantify potential alternate weather planning standards via
comparison of alternate aggregate NPV portfolio costs

•Price
– Substantiate preferred portfolio selection (commodity cost
perspective)
– Compare distribution of aggregate NPV cost to preferred portfolio
Avista Utilities 2014 Natural Gas IRP Appendices 468
302
Avistsa IRP Total 20 Year Cost
0
5
10
15
20
25
30
35
40
45
$9.2
8
$9.3
4
$9.4
0
$9.4
6
$9.5
1
$9.5
7
$9.6
3
$9.6
8
$9.7
4
$9.8
0
$9.8
5
$9.9
1
$9.9
7
$10.
0
2
$10.
0
8
$10.
1
4
$10.
1
9
$10.
2
5
$10.
3
1
$10.
3
7
$10.
4
2
$10.
4
8
$ Billions
Fr
e
q
u
e
n
c
y
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Cu
m
u
l
a
t
i
v
e
Frequency
Cumulative
Mean 90th
Percentile
95th
Percentile
5%
P(Cost>10.127)=5%
10%
P(Cost>10.067)=10%
Average: 9.854
StdDev: 0.169
Min: 9.285
90% percentile: 10.067
95% percentile: 10.127
Max: 10.422
VectorGas™ Reports
EXAMPLE ONLY
Avista Utilities 2014 Natural Gas IRP Appendices 469
303
Sample Weather Pattern
Medford HDDs - Four example draws
Medford Monte Carlo HDD Results
0
10
20
30
40
50
60
70
Nov-
0
9
Jan-
1
0
Mar-1
0
May-
1
0
Jul-1
0
Sep-
1
0
Nov-
1
0
Jan-
1
1
Mar-1
1
May-
1
1
Jul-1
1
Sep-
1
1
Nov-
1
1
Jan-
1
2
Mar-1
2
Da
i
l
y

H
D
D
Draw 4 Draw 12 Draw 46 Draw 148
Avista Utilities 2014 Natural Gas IRP Appendices 470
304
Key Issues / Document Discussion
Avista Utilities 2014 Natural Gas IRP Appendices 471
305
Highlights of the 2014 IRP
•No near-term resource needs under most
scenarios.
•Lower long term customer growth rates.
•20 year rolling average is the new “normal”.
•No global warming adjustment.
•Updated DSM potential and resultant avoided
costs.

Avista Utilities 2014 Natural Gas IRP Appendices 472
306
2012 IRP Acknowledgement Comments
• Describe more clearly derivation of growth scenarios, including high and low in
demand forecasting chapter.
• Use 5 year use per customer data set
• Provide a comparative avoided cost analysis in future IRP’s
• Do an analysis and/or narrative describing the “trigger point” avoided cost value
where conservation programs become cost-effective.
• Between IRP’s compare modeling assumptions with actual demand.
• Include a Washington specific city gate analysis, including a narrative of its
conclusions as a result of such analysis.

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2012 IRP Acknowledgement Comments
• Include an easily identifiable progress report that relates new plan to previous plan.
• Reconcile inconsistencies between models used in demand forecasting and
implementation and description of these models.
• Hold public outreach meetings in locations convenient for customers.
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2012 IRP Acknowledgement Comments
• Continue DSM programs in Oregon to achieve minimum savings of 225,000 therms
in 2013 and 250,000 therms in 2014.
• Provide results of the following:
• Savings and cost effectiveness of DSM program.
• Actions taken to reduce delivery costs, including admin and audit costs.
• Actions taken to increase cost effective efficiency measures in the portfolio.
• Analysis of non-natural gas benefits of existing and proposed measures.
• Analysis of measure lives for all measures.
• Develop mechanism for allocating funding for a separate low-income energy
efficiency program.
• Pursue possibility of regional elasticity study through NWGA or AGA.
• Assess potential demand impact from NGV/CNG vehicles and other new uses of
natural gas.
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Key Issues
•Where’s the Demand?
– Even flatter demand – How long does this trend continue?
– What impacts on consumption? Temporary or permanent
change?
– What is the demand boost?
• Resource Management
– Prudent management of resource length
•“The Price is Right”
– $5 gas forever?
•Environmental Impacts
– Carbon Tax?
– Hydraulic Fracturing Bans

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2014 IRP Timeline
•August 31, 2013 – Work Plan filed with WUTC
•January through April 2014 – Technical Advisory Committee
meetings. Meeting topics will include:
– Demand Forecast and Demand Side Management – January
24
– Supply and Infrastructure, Gate Station Analysis, Supply Side
Resources, Resource Optimization – February 25
– Distribution Planning, Natural Gas Pricing, CNG/NGV,
SENDOUT® Preliminary Results and Further Case Discussion
– March 26
– DSM CPA results, further SENDOUT® results and document
discussion – April 23
•May 30, 2014 – Draft of IRP document to TAC
•June 30, 2014 – Comments on draft due back to Avista
•July 2014 – TAC final review meeting (if necessary)
•August 31, 2014 – File finalized IRP document Avista Utilities 2014 Natural Gas IRP Appendices 477