20090421AVU to Staff 90-95, 97, etc.pdf

Avista Corp.
1411 East Mission P.O. Box 3727
Spokane. Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
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Corp.
.PR ? \ M~ 9: \11009 ~. i ,-
April 20, 2009
Idaho Public Utilities Commission
472 W. Washington
Boise, ID 83702-5918
Attn: Donald Howell & Krstine Sasser
Deputy Attorneys General
Re: Production Request of the Commission Staffin Case Nos. AVU-E-09-01 and
A VU-G-09-01
Dear Mr. Howell and Ms. Sasser,
Enclosed are an original and two copies of Avista's responses to IPUC Staffs production
requests in the above referenced docket. Included in this mailing are Avista's responses to
production requests 090 through 095, 097, 099 through 106 and 108 through 112. The
electronic versions of the responses were emailed on 04/20/09 and are also being provided in
electronic format on the CDs included in this mailing.
Also included is Avista's CONFIDENTIAL response to PR 102C. These responses contain
TRADE SECRET, PROPRIETARY or CONFIDENTIAL information and is separately filed
under IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code, and pursuant to the
Protective Agreement between Avista and IPUC Staff dated January 8, 2009. It is being
provided under a sealed separate envelope, marked CONFIDENTIA.
If there are any questions regarding the enclosed information, please contact me at (509) 495-
4546 or via e-mail at j oe.miler(favistacorp. com
Sincerely,nc: ~...71 ....
Joe Miler
Regulatory Analyst
Enclosures
CC (Paper):The Energy Project (Roseman)
WUTC Staff (Trautman - 3 copies)
ICNU (Schoenbeck, Van Cleve)
Public Counsel (fftch)
Avista Corp.
1411 East Mission P.O. Box 3727
Spokane. Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
~~~'V'STJI.
Corp.
CC (Email):The Energy Project (Roseman)
Public Counsel (ffitch, Johnson, Wiliams)
WUC Staff (Trautma)
ICNU (Schoenbeck, Van Cleve)
CC (CD only)The Energy Project (Eberdt)
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AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-090
DATE PREPARD:WISS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04/16/2009
Dave DeFelice
Dave DeFelice
Corporate Development
[phone]
REQUEST: NO. 90:
10";'
On Page 12-13 of his testimony, Mr. Defelice describes utiliy infrastructue cost increases that
have occured through October of 2008. Please provide any analysis conducted by the Company
showing how utilty infrastrctue costs have changed since that time. Is it the Company's
position that costs have continued to climb?
RESPONSE:
The most recent price information on various categories of materals indicate that some items are
experiencing moderate price decreases and others are facing price increases. Please see the
attached document labeled "Staff PR 090 Attachment A" containing 2009 material price
forecasts.
Overall, it appears that prices are stabilizing relative to the price changes seen over the last several
years. Based on this information, the Company does not anticipate a signficant change in the
ultimate transfers to plant in service in 2009 as compared to the forecasted transfers to plant in
service for 2009 that was used as the basis for the proposed pro forma capital adjustment
(forecasted transfers to plant included though December 2009).
While price reductions wil relieve some cost pressure on capital budgets, there is likely to be a
time lag from this phenomenon since the Company's inventory valuation system is based upon an
average unit value basis. Therefore, due to the average unit cost basis of inventory valuation and
the time lag of materials arving at the Company from the effective dates of new prices, the
Company does not anticipate an impact to the forecasted transfers to plant in 2009. If prices for
certain items were to remain at the moderately reduced levels throughout 2009, this may then, in
tu, impact transfers to plant in 2010, assuming that the level of capital construction work in 2010
would be similar to that in 2009.
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2009 Material Price Forecasts
Conductor (Secondary)Contracts renewed October 2008 to reset base price with
minimal increase. Agreements provide escalation or de-
escalation for metals at time of order. Currently
experiencing 3% - 6% de-escalation credit on invoices.
Conductor (UG Primary)20% decrease effective 1/1/09.Pnces are adjusted
monthly.
Elec Meters Same as 2008.
Gas Meters Same as 2008.
Line Hardware Prices holding steady as manufacturers try to recover costs.
Our price is recalculated at each order based on negotiated
mark-ups, volume discounts, direct shipping, and escalation
or de-escalation for metals and resins. Adjustments passed
back to Avista on a monthly basis. 2008 adjustments were
$163K credited to the stores burden pool.
Pipe -- PE 30% price decrease effective 1/1/09
Pipe - Steel Price set at market at time of order; however, recent orders
reflect about 30% decrease in price.
Poles -- Steel (Transmission)Price for steel transmission class poles is average 59.5%
over wood previously used for transmsision applications.
Poles -- Wood (Distribution)2.33% increase in price for 2009 related to manufacturing
costs only -- no change related to wood, oil/penta, or fueL.
Transformers 30% price decrease effective 1/1/09
While price reductions wil relieve some cost pressure on capital budgets, there is likely to be a time
lag from this phenomenon since the Company's inventory valuation system is based upon an average
unit value basis. Therefore, due to the average unit cost basis of inventory valuation and the time lag
of materials arving at the Company from the effective dates of new prices, the Company does not
anticipate an impact to the forecasted transfers to plant in 2009. Ifprices for certain items were to
remain at the moderately reduced levels throughout 2009, this may then, in tu, impact transfers to
plant in 2010, assuming that the level of capital construction work in 2010 would be similar to that in
. Updated 2/2/09
StafCPR_090 Attachment A - 2009 Material Price Forecasts.xls Page 1 of 1
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JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-091
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04/15/2009
Elizabeth Andrews
Heide Evans
Environmental Affairs
[phone]
Please provide a detailed listing of the Clark Fork PME measures planed for 2009, describe what
they are intended to accomplish and where they are identified as required in the settlement agreement
and FERC License.
RESPONSE:
Please see the attached folder labeled "StafCPR _ 091 Attachment A" containing a detailed listing of
the Clark Fork PME measures planed for 2009. Due to the voluminous natue of the attached
documents, they are being provided in electronic format only.
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JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-092
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04114/2009
Dave DeFelice
Scott Kinney
Transmission
[phone]
Please explain and justify the projects included in the $2.2 milion transmission replacement program
listed on page 18 of Mr. Defelice's direct testimony.
RESPONSE:
Please refer to the previously provided direct testimony of Mr. Kinney, page 21, lines 11 - 22
provided below.
. Replacement Programs ($2.23 milion): Avista has several different equipment replacement
programs to improve reliability by replacing aged. equipment that is beyond its useful life.
These programs include transmission air switch upgrades, arestor upgrades, restoration of
substation rock and fencing, recloser replacements, replacement of obsolete circuit switchers,
substation battery replacement, porcelain cutout replacement, high voltage fuse upgrades, and
replacement of fuses with circuit switchers. All of these individual projects improve system
reliability and customer servce.
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AVISTACORPORATION
RESPONSE TO REQUEST FOR INFORMTION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-093
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04117/2009
Scott Kinney
Liz Andrews
State & Federal Reg.
[phone]
REQUEST:
Please describe and justify the distribution investment amounts shown on page 18 of Mr. Defelice's
direct testimony that are par of the distrbution asset management program.
RESPONSE:
Ofthe projects listed on page 18 of Mr. DeFelice's direct testimony which describe the 2009 capital
projects pro formed into the Company's case, there are two 2009 projects associated with Asset
Management. These projects are the Wood Pole Management capital project totaling $3.7 millon
and the Electrc Underground Replacement capital project totaling $3.16 milion. These projects are
also discussed in more detail in Mr. Kinney's direct testimony at page 24, lines 9 through 20.
The O&M Asset Management programs and expense included in the Company's direct case is
described in Mr. Kinney's direct testimony staring at page 25. His testimony describes the 2010
system level of expense for these programs, of which half ofIdaho's share of the 2010 level of
expense was included in the Company's case. As stated at page 28 line 21, A vista is not asking for
any planed 2010 Capital Asset Management additions to be included at this time.
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JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-094
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/17/2009
Dave DeFelice
Liz Andrews
State & Federal Reg.
[phone]
REQUEST:
Please explain and justify the productivity initiative listed on page 20 of Mr. Defelice's testimony.
RESPONSE:
The Productivity Intiative capital item of $1.15 milion was included in the company's case in
error. This has been discussed with Commission Staff and has been removed in the updated 2009
transfers to plant workpaper previously provided in Avista's response to audit request
Audit-013S-1, which updated actual costs transferred to plant through Februar 2009, and updated
for any known future amount changes, in-service date changes, or other changes known at the time
ofthe supplemental response. The Company wil continue to fie supplemental information as any
changes become available.
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A VISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:.
REQUEST NO.:
IDAHO
A VU-E-09-0l 1 A VU-G-09-01
IPUC
Production Request
Staff-095
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04/15/2009
Scott Kinney
Scott Kinney
System Operations
[phone]
REQUEST:
Please describe how anual replacement projects for electrc and gas transmission are identified
and budgeted. Include any economic analysis used by the Company to prioritize projects.
RESPONSE:
Avista doesn't own or operate any gas transmission in the state ofIdaho.
Avista's anual electrc transmission replacement projects are all analyzed and identified though
the asset management program. A complete five year plan and budget summar of Avista' s asset
management plan is attached as "StafCPR_095 Attachment A". The plan discusses the need and
costs of the individual components of the Avista asset management plan for the next five years.
Project prioritization and budgeting is completed at several levels to determine what individual
projects are funded. The asset management team completes the proposed anual plan with input
from design engineers and data collected from the field. The proposed asset management plans are
then prioritized with other constrction projects by the Engineering deparent. Projects are
raned as high, medium, and low impact to reliability. The Engineering deparent then selects
projects and develops an annual Transmission and Distribution constrction and replacement plan
that equal its allocated capital funding as provided by the Finance Deparment. The Transmission
and Distrbution plan is then reviewed by the Capital Budget Committee to prioritize with other
company projects. The Capital Budget Committee approves and monitors the capital budget
expenditues throughout the year.
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Staff PR 095 Attachment A Page 1 of 48
~\\'ilISTAæ
Utilities
ASSET MANAGEMENT
5 YEAR PLAN AND BUDGET
SUMMARY
2009
Prepared By: Glenn Madden
Rodney Pickett
Revision 1
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Staff PR 095 Attachment A Page 2 of48
Purpose of Asset Management.. ....... ......... ............... ................... ........... ....... ..... ....... ............ ....... 1
Benefits of Asset Management..................................................................................................... 1
Implementation of Asset Management....................................................................................... 4
Current Asset Management Programs....................................................................................... 6
Proposed or Modified Asset Management Programs................................................................ 6
Network...................................................................................................................................7
Transmission........................................................................................................................... 7
Substation.............................................................................................................................. .. 7
Distrbution............................................................................................................................. 8
Future Asset Management Programs .............................................................................. ........... 8
Needed Changes to support Proposed and Future Asset Management Programs ................. 9
Asset Management ProgramslPlan Details .............................................................................. 10
ER NEW28 Network ........................................................................................................... 10
Network Vaults ................................................................................................................. 10
Network Manole and Handholes .................................................................................... 12
ER 2054 - Electrc Underground Replacement.......................... ......................................... 14
ER 2057 - Transmission Minor Rebuilds.... ...... ............................................ ....................... 16
ER 2060 Wood Pole Management........................................................................................18
ER's 2001/2211/2215 Power Circuit Breakers..................................................................... 18
ER 2254 Transmission Air Switches ........... ..................................... ...... ........... ...... ............. 20
ER 2260 Surge Aresters ...................................................................................................... 21
ER 2275 Substation Fence and Rock.................................................................................... 22
ER 2278 Distrbution Reclosers..... ........ ............ .................. ........ ..... .... ......... ..... ..... ............. 22
ER 2280 Substation Circuit Switchers...................................... .............. .............................. 25
ER's 1006/2000/2336/2357 Power Transformers ................................................................ 27
ER 2204 System Wood Substation Rebuilds........................................................................ 30
ER 2252 System - Obsolete Protective Relays ................... .................... .............................. 32
ER 2425 Substation High Voltage Fuse Replacements........................................................ 34
ER 2294 System - Batteries .................................................................................................. 37
ER 2416 System - Porcelain Cutout Replacements .............................................................37
ER 2449 System - Replace Substation Air Switches ...........................................................37
ER NEW Distrbution Transformer Replacement ................................................................ 38
ER NEW?? Substation Voltage Regulators ...................... .................................................... 43
MAC 215 - 592550 Wildlife Guards .................................................................................... 43
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Staff PR 095 Attachment A Page 3 of48
Figure 1, Outage Management Tool Only Failure Information.............. ......... ............................... 3
Figure 2, General Asset Management Plan Development............................................................. 5
Figure 3, Network Vault Age Profile............................................................................................ 11
Table 1, Network Vault Capital and O&M Budget Estimates...................................................... 12
Figure 4, Vault Cumulative Costs and Risk Costs........................................................................ 12
Table 2, Network Manole and Handhole Capital and O&M Budget Estimates...... ................... 13
Figue 6, Manole/Handhole Cumulative Costs and Risk Costs.................................................. 14
Table 3 Underground Cable Replacement Financial Results .............. ......... ................................ 15
Table 4 Underground Cable Replacement Reliability Results ........... ............. ............ ... .............. 16
Figure 7, Power Circuit Breaker Age Profile........... .......... ............ ........ ...... ................................. 19
Table 5, Power Circuit Breaker Capital and O&M Budget Projections ....................................... 19
Figure 8, High Voltage Circuit Breaker Cumulative Costs and Risk Costs Comparson........ ..... 20
Table 6, Surge Arester Replacement Budget Projections....... .................................... ................. 22
Table 7, Fence and Rock Repair and Replacement Budget Projections....................................... 22
Figure 9, Substation Reclosers & Low Voltage Circuit Breaker Age Profile.............................. 23
Figure 10, Feeder Reclosers Age Profile ...................................................................................... 24
Table 8, Substation Recloser Budgets ...................... ..................... ...................... ................ ......... 24
Table 9, Distrbution Recloser Budgets ....................................... ............................ ..................... 25
Figure 11, Substation Circuit Switcher Age Profile ........ .......... ............. ......... ....... .... .................. 25
Table 10, Circuit Switcher Budget Projections................... ......... ................................................. 27
Figure 12, Power Transformer's Age Profile ............................................................................... 27
Figure 13, Autotransformer's Age Profile..................................................................................... 28
Table 11, Power Transformer Proj ected Budgets.............................................................. ..... ~..... 29
Figure 14, Power Transformer Cumulative Cost Comparson ... ...................................... ...... ...... 29
Table 12, Wood Substation Rebuild Results - ER 2204............ .......... ..... ........... .............. ........... 31
Figue 15, Power Fuse Age Profie Estimate................................................................................ 35
Figure 16, Power Fuse Cumulative Cost Projections ................. ......... ......................................... 36
Table 13, Power Fuse Replacement Capital Budget Projections.................................................. 37
Table 15, Substation Battery Budget Projections ......................................................................... 37
Table 16, Sub Air Switches Projected Budget............................................................................. 38
Figue 17, Overhead Single Phase Distrbution Transformers Age Profile.................................. 38
Table 14, Capital Budget Estimate for replacing pre-1960 Distrbution Transformers ............... 39
Figue 18, Padmounted Single Phase Distrbution Transformers Age Profile ........ ..... ............... 40
Figure 19, Padmounted Thee Phase Distrbution Transformers Age Profile................ .............. 41
Figure 20, Subsurface Single Phase Distrbution Transformers Age Profile.. ............................. 42
Figure 21, Distribution Transformer Cumulative Cost Projections.............................................. 43
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Purpose of Asset Management
Asset Management (AM strives to manage key company assets to perform optimally thoughout
their life and provide the best value for our customers, employees and investors. Bringing
together industr practices, company experts, key stakeholders, and analytical tools, Asset
Management creates a comprehensive plan including a sound tool set to manage an asset
thoughout its life from beginning to end, so an asset's value is maximized. Maximizing the
value to our customer wil come through minimizing the life cycle costs, maximizing system
reliability, balancing needs of other stakeholders, and minimizing the cost per kilowatt-hour to
generate and deliver energy. Maximizing the value to our shareholders wil come through
maintaining the assets for the least amount of life cycle costs, demonstrating prudent investment
in our curent assets, and enabling the investors to see a retu on their investment. For our
employees, providing a safe and reliable system with a practical and a well thought out asset
management plan creates an environment for them to succeed and satisfy their customers.
When fully implemented, Asset Management wil become a way of doing business and not a
program. People wil no longer use the term Asset Management to describe individual processes
but instead talk about an integrated business process. The company wil have an overarching
vision and plan of what is needed to manage their Generation, Transmission, Substation, and
Distrbution systems.
In 2007, A vista spent $10.6 milion in O&M money on Failed Electrc Maintenance and $1.25
milion of Capital budget on Failed Electrc Plant. Where it makes sense, AM works to transfer
money out of the failed accounts and into the planed activities at a lower cost. Implementing
the different programs wil stabilze the rising number of equipment failures and potentially
reduce them. This wil in tu improve our customer satisfaction.
Benefits of Asset Management
The Asset Management process brings the tools, people, and resources together in a way that
integrates information from a myrad of sources into a comprehensive and extensive picture for
everone to see and arve at a plan that maximizes the value of every asset. From this process,
we can then identify what approach provides the best life cycle costs, best reliability, resource
needs for the future, metrcs to prioritize projects, evaluate different alternatives or new
technology, and ultimately determine an overall asset management plan.
Without Asset Management, our equipment related failure rates wil continue their trend
upwards and drive our costs upwards as our system ages.
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Figue 1, Outage Management Tool Only Failure Information, shows how the number of failures
affecting our customers has changed over the past three years. The overall trend has been
upwards and is anticipated to continue without fuher action. While proactive maintenance is
not always the answer, just reacting to failures drives costs upward, reliabilty down, and
customer dissatisfaction. Applying asset management tools to several areas in Figue 1 wil help
determine the best approach to deal the issue and arve at the right answer.
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11 1:45 TRUE 8.4%
1380 0:47 TRUE 6.7%
1228 0:49 TRUE 6.0%
68 2:57 TRUE 5.3%
982 1:18 TRUE 5.0%
904 1:17 TRUE 4.7%
671 3:48 TRUE 4.4%
15 5:49 TRUE 4.1%
Connector - Sec 2 3:06 TRUE 3.9%
Cutout/Fuse 32 2:26 TRUE 3.7%
Pole Fire 175 3:58 TRUE 3.6%
9 4:36 TRUE 3.5%
Tree Growth 9 2:41 TRUE 3.3%
URD Cable - Sec 2 4:48 TRUE 3.3%
Switch/Disconnect 172 7:31 TRUE 3.2%
360 4:40 TRUE 3.2%
2 2:31 TRUE 2.9%
10 7:36 TRUE 2.5%.274 2:07 TRUE 2.1%
7 4:49 TRUE 2.0%
Conductor - Pri 65 3:28 TRUE 2.0%
Insulator 135 3:13 TRUE 2.0%
Crossarm-rotten 156 2:47 TRUE 2.0%
Connector - Pri 77 2:34 TRUE 1.9%
Insulator Pin 154 2:33 TRUE 1.7%
69 2:19 TRUE 1.4%
10 3:37 TRUE 1.3%
12 2:36 TRUE 1.2%
105 1:35 TRUE 1.1%
Elbow 7 3:09 TRUE 1.1%
Ca acitor 29 2:50 TRUE 1.1%
Junctions 37 2:31 TRUE 1.0%
2:22 TRUE 0.8%
Customers 351,585
Significant Degradation in performance for 2007
Small Degradation in performance for 2007
Improved performance in 2007
Recommended for better
tracking
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Implementation of Asset Management
Asset Management stars with questions like, "what do we need to achieve with this asset" "why
do we need to improve this assets performance", and "what do we hope to accomplish for ths
asset". Once questions like these have an answer, we then begin to work on arvig at an
answer. The process of arving at the answer stars with the data and a team. A team
representing the stakeholders and experts is put together and develop an Asset Management
Model and ultimately formulate the plan. The available data is examined and where it is not
available, expert opinion from the team is used to fill in the gaps. They can then begin the
process of developing the Asset Management Plan. Figure 2, General Asset Management Plan
Development, shows the steps in the process for developing an Asset Management Plan. The
foundation for the plan is in deterining what the futue failures wil look like based on available
data and expert opinion if nothing is done and becomes the failure modeL. The failure model
incorporates not only the frequency but all aspects of a failure such as environmental, reliabilty,
safety, customers, costs, labor, spare pars, time, and other consequences. The failure model then
becomes the baseline to compare all other options. The team reviews the failure model and
ensures that it makes sense and represents what they understand of the asset and its impacts.
With this foundation, all other alternatives can be examined and evaluated until the best
maintenance plan is identified. With the best maintenance plan, the team then must deterine
how we change and achieve the maintenance plan. This wil include determining and getting a
budget approved and resources identified to perform the work.
With the Asset Management Plan completed, someone is then assigned to become the plan
manager and implement the plan. Who ths person is vares based on the type of plan and
historically has been an engineer withn Substation, Transmission, Distrbution, or Substation
Support. However, as more AM plans come on line, ths practice wil need to change because
the existing workload already takes up all of the assigned resources time. More Senior I
Engineers wil be needed to act as program or project managers.
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.Current Asset Management Programs
Several Asset Management Programs have been implemented in recent years or are
continuations of existing historical programs. Wood Pole Management, Underground Cable
Replacement and Vegetation Management have existed several years. The Vegetation
Management Program reduces tree and vegetation related outages and has proven a success over
the past several years.
The Wood Pole Management program has been around for years. The level of work has not
been suffcient to reach all of the poles in a timely fashion until 2008. The plan is to inspect all
Distrbution wood poles on a 20 year cycle and all of the Transmission wood poles on a 15 year
cycle. We anticipate this program wil provide a tremendous benefit to our customers and
provide a cost effective method of reducing outages and costs related with wood pole failures.
The Underground Residential Distrbution Cable Replacement program has been replacing an
old direct bured primar distrbution cable that is plagued by frequent faults. Ths cable has a
high enough failure rate to justify planed replacement. Over the past few years, this program
has stabilized and slightly reduced the number of cable faults, but several thousands of feet of the
cable remain to be replaced before the full savings can be realized.
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A new program stared in 2007 is a focused replacement of a particularly problematic and failure
prone cutout used to isolate Distrbution Feeders and Transformers as well as hold fuses. Ths
program found that a planed replacement would provide a signficant benefit to our customers
and should be replaced on a planed basis. Many of these cutouts were replaced at the end of
2007, so the benefits have not been realized yet. It is anticipated the benefits of ths program wil
be seen in 2008.
Another new program staring in 2008 belongs to the Network. The Network is the distrbution
system supporting downtown Spokane with a highly reliable underground distrbution system.
The specific program is the planed inspection, maintenance, and replacement of the Network's
Vaults, Manoles, and Handholes. The program includes periodically inspecting them and then
repairing or replacing them as identified by condition. Many of these strctues are nearly 100
years old and are approaching their end of life, so this program wil begin a planed replacement
of them to ensure the reliable operation of the Network.
Other smaller programs are continuation of historical programs such as Substation Batteries,
Substation Inspections, Substation Power Transformers, High Voltage and Low Voltage Circuit
Breakers, Distrbution Reclosers, and others. The curent Asset Management process has not
been used to revise all of the existing practices but for those programs that wil be revised; these
are discussed in the next section.
Proposed or Modifed Asset Management Programs
The following represents the proposed changes to star in 2009 for Asset Management. These
programs usually represent a change from the past practices. However, some of the current
. practices have proven to be the best option and wil remain in place except their resource needs
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are projected to increase due to aging of the system. Each plan wil be discussed under
Transmission, Substation, Distribution, or Network areas.
Network
While the Network Vault and MH programs began in 2008. They are not fully implemented
and we plan on fully implementing it in 2009. So, we are including it as a modified program as
welL.
Transmission
A long standing Transmission activity, Minor Rebuilds, continues with modestly improved
fuding in 2008 and is projected to have steady fuding levels for 2009. This activity is follow-
on work to accomplish repairs identified durng Transmission Wood Pole Management
inspection and testing.
A new capital program is proposed for 2009 to replace a specific vintage of 230kV suspension
and dead-end insulators that experienced high failure rates with subsequent long duration
outages.
Several new, or expansions of former small programs, Operations and Maintenance measures
are considered for the Transmission system: (1) fire retardant paint for the lower 6 to 8.feet of
critical wood structues, (2) testing and replacement of sleeve couplings that are showing
increased failure with age and, (3) painting of older steel transmission strctures for corrosion
resistance.
Substation
While we are curently performing Dissolved Gas Analysis on our Substation Transformers, the
Power Transformer program involves the planed replacement of transformers not only based on
condition but also based on their efficiency. The purpose of the plan is to maximize the value of
the transformer. Several older transformers are ineffcient enough and old enough to justify
replacing them. This wil reduce system losses and improve the reliability ofthe system.
The Power Circuit Breaker AM Plan is based on our historical maintenance of these breakers.
However, more of the breakers are reaching their end oflife and are no longer supported by their
manufactuer. Based on our analysis, we wil begin to replace the worst high voltage circuit
breakers based on their condition and age.
Some of our smaller substations use a Power Fuse to provide protection on substation
transformers. The Power Fuse AM Plan wil replace these fuses with new protection systems.
These Power Fuses no longer have pars and do not meet our current requirements. The program
wil replace these on a planed basis and better protect our substation transformers.
The Recloser AM plan covers substation and distrbution system Reclosers. The plan calls for
maintenance and inspection of the substation Reclosers based on the type as well as the
anticipated replacements. The propose program matches the current plans but they have not
been achieved yet because of resource limitations. The plan also includes more planed
7
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.
.
replacements because several have already reached their end of life. This wil improve the
reliabilty and extend the life of the existing equipment.
The Relay Replacement AM Plan wil replace older Electromechanical Relays on our 115 kV
system with newer microprocessor based relays. While this program wil not save much money
overall, it wil reduce the amount and cost of maintenance. The old relays require a significant
amount of maintenance to keep fuctioning and replacing them wil cut this cost significantly
along with improve the reliabilty.
Several of our smaller substations are constrcted out of wood. The Wood Substation Rebuild
program wil either repair or replace the wood strctues based on their condition and deterine
when the whole substation strctue wil be rebuilt. The purose of this program is to retain the
systems reliability and prevent strctual failures within the substation.
The Circuit Switcher AM Plan addresses a circuit breaker týpe of device used to control and
protect several substation transformers. This plan wil implement a maintenance program to test
and maintain them based on condition as well as identify when a circuit switcher has reached its
end oflife and must be replàced. The function ofthis program is to maintain reliable operation
and protection of substation transformers.
Distribution
The Distrbution Transformer AM Plan covers the planed replacement of older transformers.
These older transformers are less effcient and are nearng their end of life, so a planed
replacement is cost justified largely due to the reduced system losses.
Future Asset Management Programs
The curent AM plans have focused on individual assets and have not examined improved
effciency with integrated maintenance. We selected the individual AM approach to develop the
fudamental building blocks needed to then develop the integrated models. The futue AM
programs wil begin to integrate into system programs based on a Distrbution Feeder model and
incorporate several efficiency improvement opportities so that our program goes from
individual AM plans into system plans like a Distrbution Feeder Plan. Work that is underway
on analyzing potential efficiency improvements within our system when integrated with AM
analysis should yield opportities to not only improve the systems reliability but also reduce
losses while replacing older components that alone are not cost justified to be replaced.
The Generation Plants have begun to develop AM plans that are curently focusing on Generator
Circuit Breakers and Generator Step-up Transformer Replacements. Based on the completion of
this analysis, these and other programs wil be developed to support Generation.
Asset Management programs wil also transition into a formal Root Cause Analysis (RCA) to
fuer improve AM plans. Combined with better information and tracking, Root Cause
Analysis wil allow for a better cause focused approach to managing all of our assets.
8
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.
As our information collection and data analysis capability grows and feedback comes in, we wil
periodically review the models to refine them and identify furter areas of improvement.
Needed Changes to support Proposed and Future Asset Management Programs
Over the past few years, Asset Management developed expertise, processes, tools, and
information systems focused on creating Asset Management plans. However, once the plan was
developed, it was handed over to a selected project owner or project manager to implement and
track. Ths work has been in addition to their existing workload. This approach has been
successful but has some drawbacks. With our curent resources, AM has been limited to
planng only, but they are looked to as the exper and owner ofthe program. However, as the
number of programs expands along with the need for furter expertise development, more time is
needed to support the programs and exceeds the current resources. To address these issues, we
propose adding two Senior Level I Engineers position for ths work.
These Senior Level I Engineering positions wil fill the role of project manager/owner. They
wil relieve much of the work from the curent program owners and allow for development of
Asset Management experts who can not only understand the curent plans but also seek out and
explore new technology. They wil also become a resource for the formal RCA and planed
maintenance expert. Whle the varous engineering deparents wil retain their current
responsibilties, these engineers wil support the AM portions of their system and coordinate with
them to get the plans implemented.
A second skill set needed to implement the proposed AM plans are two Customer Project
Coordinators (CPC). They are needed to support the Distrbution Transformer Replacement
Plan. The Distrbution Transformer Replacements wil take over 10 years to complete and
requires 1.5 full time CPC to support. The remaining 0.5 CPC wil provide support to other
Distrbution AM plans. The CPC's wil plan the specific work packages for the line crews to
perform the work and provide customer coordination for each of the outages required to replace
the transformers. For the remaining time of the CPC's not used for Distrbution Transformers,
other programs such as the Distrbution Infrared Inspection Pilot program, Wood Pole
Management, porcelain cutout replacements, and other programs wil need the same planing
and support to accomplish their purose.
Another portion of the AM program that has and wil continue to expand is the database
management, analysis, and maintenance. We are also proposing to expand the existing
Engineering Technician position from 20% to full time. An increasing amount of data is
gathered, stored, and analyzed each year to monitor existing programs, identify new trends, and
prepare information for the next round of analysis. With the implementation of a Failure
Tracking Process, we have centralized all failure information into one place, so we can begi to
paint a complete pictue of what is occurrg throughout the system. Our information comes
from all kinds of systems that include paper copies of reports and field work to automated data
systems. In order to integrate such a diverse set of information, we have used an Engineering
Technician and a student employee to help gather the information. However, our curent
resource allotment has begu to exceed our curent allotment. Over the past few years, AM has
9
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also worked on improving the data gathering process and systems. This effort has a lot more
work to accomplish and improve the automation of managing and collecting information.
To support all ofthe additional required work, seven Electrcians and one Relay Techncian are
needed. Our current resources are over extended and on average working 300 hours of overme
per individual to meet our curent workload. The program proposed and changes to our existing
programs wil drve increasing our curent workforce. However, the curent labor markets have
tapped all available resources, so we anticipate that they wil be hired as apprentices and will
require time to become qualified. This will force the implementation of several Asset
Management plans and programs in phases as people become qualified. The phase-in time is
estimated to take three years. Initially, these new personnel wil be loaded in the Operations and
Maintenance budgets exclusively and then transition into an appropriate mix of Capital and 0 &
M budgets. The cost estimates for these employees are included in the individual proposed
plans.
A program deficiency in our current AM planing process is an effective and system wide Root
Cause Analysis. In order to focus asset management activities properly, we must address the
root causes of failure and understand what the real impacts of failure are upon all stakeholders.
The Asset Management process needs to develop the administrative tools, processes, purchase
the technology, and train key personnel to support this portion of the program. While our experts
are effective at determining the causes of failures, retirements and promotions have reduced the
number of experts and the new generation needs to lear RCA to develop them fuer as
experts.
The largest issue and change needed to support AM in the futue is a new Work Management
System or Computerzed Maintenance Management System. Curently, AM processes gather
data manually from sources ranging from drawings, spreadsheet, a financial database, paper
reports, Outage Management Tool, and personnel interviews. Our Asset Management models
require an extensive amount of information that curently gets completed with exper opinion
and analysis instead of actual data and information. Much of the information needs could be met
with a new Work Management system such as MAO or equivalent systems. Most
companes using our AM tools get their information using such systems and have much more
accurate and refined information to base their analysis on.
Asset Management Programs/Plan Details
The following outlnes each of the individual AM plans for the next 5 years.
ER NEW28 Network
Network Vaults
The Network Vaults AM plan covers all of the vaults in downtown Spokane, WA. These vaults
usually contain a network transformer, a network protector, and feeder cable. Many wil have a
floor drain or a sump to aid removing water. Some of the vaults if flooded wil also flood a
customers building because of their location within a customers building or due to the vault
10
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.
.
access. Figue 3 shows the curent age profile of the Network Vaults. Below are some
signficant statistics on the Network Vaults:
.124 Vaults
20 Vaults are Vacant
8 Vaults can flood and cause customer damage
16 Vaults have Sump Pumps
29 Vaults have drains
.
.
.
.
Figure 3, Network Vault Age Profie
Vault Age Profile
18
60% )- 50 Years Old
16
14
12
~
~ 10
.E..QI~ 8
:0Z
6
4
2
o
# # ## # ~ ~ ¥ # # $ # ## # ~ ~ ~ # # # # ## # # #~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~
Year Installed
This program is based on inspecting the vaults every six months and making repairs based on
condition. The repairs could range from replacing the Vault plug, Vault top, or complete Vault.
Some maintenance includes re-painting any exposed steel and yearly cleaning out Vaults to
prevent fires and corrosion due to debris buildup. Based on the inspections, we anticipate
pedorming the following work:
.1 Fan Replace every 5 years
11 Sump Pumps every 4 years
12 Vault Plugs every 5 years
8 Vault Tops every 6 years
.
.
.
In order to accomplish this work,
11
.
.
.
Table 1 shows the estimated Capital and Operations and Maintenance budgets to support the
planed work. Ths work wil also require an average of 1,500 man-hours of Cableman labor to
perform the inspections and maintenance.
T bl 1 N k V ul C . I d O&M B d Estimatesa e ,etwor a t apita an u ll!et
O&M
Year Capita Costs Costs
2009 $60,000 $83,000
2010 $62,000 $86,000
2011 $65,000 $90,000
2012 $67,000 $94,000
2013 $69,000 $97,000
The benefits of the Vault Inspections and Maintenance come from reducing the overall costs of
the vaults and protecting the public. The financial savings of ths program come from the
projected additional costs associated with vault failures and mishaps since they are reaching their
end oflife. On average, the program is anticipated to save -$700,000 anually due to reduced
risks associated with the vaults and reduced customer outages or impacts. These savings are
predominately our customers saving as avoided costs due to a power outage, and Figue 4 shows
the cumulative effect of the plan compared to running to failure.
Figure 4, Vault Cumulative Costs and Risk Costs
"(1c:.iE J!l/o 000
:E (1oö .~o 1i" -c: :iC\ E_ :i.s 0
1i.
C\o
$45,000,000
$40,000,000
$35,000,000
$30,000,000
$25,000,000
$20,000,000
$15,000,000
$10,000,000
$5,000,000
$0
-- No Action Case
Vault Inspection,
Repair, and Replace
r-('O)LOT"r-('OT" T"N('('~0000000NNNNNNN
Year
~ tßo 0N N
Network Manhole and Handholes
The Network Manoles and Handholes AM plan covers all of the downtown Spokane Manoles
(MH and Handholes (HH) used in the Network. These MH and HH usually only contain feeder
cable and cable racks. The strctures are simpler and smaller than a vault. These also provide
connection points to tie customers into the Network and are usually located in the roadway.
12
.
.
.
Figue 5 shows the current age profile of the Network MH and HR. Below are some significant
statistics on the Network MH and HH:
· 287 Manoles
· 293 Handholes
This program recommends inspecting the MH and HH every five years and then makng repairs
or replacements based on the condition. The repairs could range from replacing the Ring and
Cover, MH Top, or complete MH. Based on the inspections, we anticipate performing
the following work:
· 5 Handholes every 4 years
· 4 Handhole Tops per year
· 6 Manoles every 5 years
· 4 Manole Tops per year
· 55 Racks per year
· 33 Rings and Covers per year
In order to accomplish the work, we anticipate budgets as outlined in
Table 2, and have an average anual resource requirement of 1,300 man-hours of Cableman
labor and 260 man-hours of Mechanic labor to complete all of the work.
Figure 5, Network Manholes and Handholes Age
Profies
120 98% / 50 Years Old
-
~ ~.IL I ..I..L
100
80
60
Number Installed
40
20
o
# ~ ~ ~ ~ ~ ## # # # ~ # ~ ~ ~~, # # ~ ~ # #;
Year Installed
Table 2, Network Manhole and Handhole Capital and O&M Budget Estimates
13
Year Capita Costs O&MCosts
2009 $190,000 $25,000
2010 $198,000 $28,000
2011 $206,000 $28,000
2012 $220,000 $28,000
2013 $244,000 $30,000
.
The benefits of the Manole and Handhole Inspections and Maintenance come from reducing the
overall costs of the MH and protecting the public. The financial savings of this program
come from the projected additional costs associated with vault failures and mishaps since they
are reaching their end of life. On average, the program is anticipated to save -$1,400,000
anually due to reduced risks associated with the Manoles and Handholes and reduced
customer outages or impacts. These savings are predominately our customers saving as avoided
costs due to a power outage and the savings comparson is shown in
Figure 6. For the company, this represents an average anual increased cost of -$21,000.
Figure 6, ManholelHandhole Cumulative Costs and Risk Costs
.~ ~
-g 8CI ~
~ æQ.
~ -g
CD CI.~ ~
~ 8
E
a
45000000
40000000
35000000
30000000
25000000
20000000
15000000
10000000
5000000
o
~ "C) ,,"- "co "Q) ri'V ~et~~~~~~
Year
- Manhole/Handhole -
Current Case
Manhole/Handhole -
Planned Case"
ER 2054 - Electric Underground Replacement
This ER addresses programed replacement of aging underground primar distrbution cable,
commonly referred to as UR. UR installation began in 1971. Outage problems exist on cable
installed before 1982, cable installed after 1982 has not shown the high failure rate of the pre-
1982 cable..
14
.Over 6,000,000 feet ofUR was installed before 1982. Programed replacement of the
problem cable has been on-going at varyng levels of fuding since 1984. Approximately
900,000 feet of the pre-1982 cable remains in service as of Januar, 2008.
Historically, over 200 faults primar cable fault happen anually. There have been as many as
264 primary cable faults in 2003. Durng 2007 there were 168 primar faults. Since 1992 faults
have increased from 2 per 10 miles of cable to 8 per 10 miles. The number of faults per mile has
stabilized durng the last 3 years after steadily climbing between 1992 and 2005.
Programs of differing length after 2009 were evaluated: 2 years, 3 years and 4 years. The option
of no programed replacement after 2009 was also evaluated.
Analysis indicates replacing the remainder of the pre-1982 cable in a short time frame is a
fiscally sound decision. The replacement program was fuded at $3 milion during 2007, the
budget amount is again $3 milion for 2008 and the budget is projected to be $4 milion for 2009.
The computed IR values between a 7 year program and a 4 year program are withn .07% of
each other. However, the total number of faults with a 7 year program vs. a 4 year program is
estimated to be 30% higher during a 10 year timeframe. Estimated faults double between a 4
year program and the current replacement pace of about 100,000 ft per year durng the next 10
years. The results are in
Table 3 Underground Cable Replacement Financial Results.
. IR of 4 year program compared to 10 year program basis is 10.15%.
Table 3 Underground Cable Replacement Financial Results
10 Year Results Total Cost O&MCost Total Capital,Average Capital
Capital, O&M,For Outage 3.5% inflation Budget during
Consequences,Response per year applied replacement
Installation,Over 10 timeframe
O&M Response Years
Note (a)
Current $29,970,000 $9,300,000 $18,036,548 $1,803,655
Replacement Pace,
10 years to replace
all original cable
Accelerated $22,700,000 $2,935,000 $16,166,461 $4,041,615
Replacement Pace,
4 years to replace
all original cable
Upgrade Voltage $433,000
Surge Suppression
Savings $7,270,000 $6,365,000
Note (a) Cost to respond to outages has been decreased as number of outages decreases with the
quantity of cable replaced..
15
. Table 4 Underground Cable Replacement Reliabilty Results
10 Year Results Number of UR CAIDI SAIFI
Primary Note (a)Note (b)
Voltage Cable
Faults
Current 4466 6 hours .017
Replacement Pace,
10 years to replace
all origial cable
Accelerated 500 6 hours .0019
Replacement Pace,
4 years to replace
all origial cable
Improvement 893%0%893%
Note (a) CAIDI is predicted as flat value due to estimated time to repair fault remaining
constant. Multiple simultaneous outages would result in larger CAIDI value
Note (b) SAII value is calculated from the number of faults times average number of customers
per fault (13) divided by number of years (10) divided total number of customers (number of
. customers has been rounded to 340,000).
ER 2057 - Transmission Minor Rebuilds
The Wood Pole Management plan optimizes programed inspection and testing of the
transmission system structues at an interval of 15 years.
This optimized time interval comes with a caveat - there are a number of 115kV transmission
lines where predominate age of poles is over 70 years. Several lines have significant populations
over 80 years old. Data regarding the futue performance of wood strctues that old is minimaL.
Projections of performance regarding these poles, which are among the oldest in the nation, is
inconclusive; but, statistical projections point toward a high probability of strctural problems.
We plan to schedule two ofthe older lines for inspection during 2008. Results of ths testing
may revise projections of follow-on capital work. That is, a capital rebuild project exceeding the
normal scope of the traditional minor rebuild work is possible.
The majority of wood structues are post-1950 installation. Virtally all 230kV poles were
installed after 1950 and about 70% of the 115kV poles are post 1950. Statistical projections
predict a characteristic age of 80 years for the 115kV tye strctues and over 80 years for
230kV type strctues. The transmission minor rebuilds are projected to be very effective for the
. next 20 years in maintaining the integrty of these systems.
16
.
.
.
115KV Wood Pole Population
(Steel Poles Not Included)
12.00%
10.00%
45% OF 115KV POLES ARE AGE 45 YEARS OR MORE
32% OF 115KV POLES ARE AGE 55 YEARS OR MORE
21% OF 115KV POLES ARE AGE 75 YEARS OR MORE
8.00%
BASED ON 20,055 POLES SURVEYED,
ESTIMATED .. 80% OF OVERALL 115KV POPULATION
6.00%
4.00%
2.00%
0.00%
1919 1936 1948 1959 1969 1979 1989 1999
230KV WOOD POLES
(Steel Pole Population Not Included)
25%
20%1\
15%"
10%
5%I
lii0%i i I
68% OF POLES ARE 45 YEARS OR OLDER
BASED ON POPULATION OF 7300 POLES,
ESTIMATED ..100% OF POPULATION
AÂ/\.. ./i I -
I
.-
II I I I I~~~~~~~~~~~~~~~~d~~~~~~~~~~~~~~~~~
17
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.
.
ER 2060 Wood Pole Management
This is a continuation of the curent program to inspect all wood distrbution poles on a 20 year
cycle. . Ths includes the O&M costs for the inspections and the capital costs to replace or
reinforce the wood poles and cross-ars. Since the program is an existing and approved
program already in rates, the projections wil be updated after seeing what the actual costs are
from the first year. For the rate case, the previous projection was used with $31,000 added to
O&M for Distrbution Wood Poles for overheads and training expenses.
Also included in ER 2060 is continued testing and inspection of wood transmission poles on a 15
year cycle. Ths includes the O&M costs for the inspections. The capital costs to replace or
reinforce the wood poles and cross-ars are accomplished under ER 2057. Since the program is
an existing and approved program already in rates, the projections wil be updated after seeing
what the actual costs are from the first year.
ER's 2001/2211/2215 Power Circuit Breakers
The Power Circuit Breaker AM Plan has been an ongoing and successful program by
maintaining approximately 300 High Voltage Oil Circuit Breakers. Due to resource constraints
A vista has been unable to reach our goal of a 10 year maintenance cycle are curently at a 15
year cycle, so extra resources are needed to achieve the 10 year cycle. Approximately 14% of
these breakers are greater than 40 years old and are reaching their end of life or are no longer
supported by their manufactuer. Figure 7 shows the curent age profile for all Power Circuit
Breakers. Of the 300 Power Circuit Breakers, about 110 are newer Gas Circuit Breakers.
Based on our analysis, A vista wil need to replace approximately 5 Substation Power Circuit
Breakers every two years to keep up with the number of breakers reaching their end of life.
However, achieving a 10 year maintenance cycle is constrained by available resources and
canot be fully implemented until labor resources are in place and qualified. The Transmission
Maintenance Inspection Plan outlnes an inspection cycle of 15 years for these circuit breaker to
support NERC and WECC standards, but this is just a minimum, and our analysis indicates that
it should be more frequent to maximize the value of the asset to our customers.
18
. Figure 7, Power Circuit Breaker Age Profie
10
70
60
50
40
Quantity
30
20
o
..5 10 15 20 25 30 35 40 45 50 55 60
Age Ranges
Our curent resources limit the number of breakers maintained each year. In order to achieve a
10 year cycle, The O&M budgets must be increase to $300,000 (see Table 5) and represents
about a $170,000 increase in spending from 2007. The labor resources needed to accomplish
ths level of maintenance and replacement is as follows:
. Substation Electrcians - 6,200 man-hours anually
. Relay Technician - 160 man-hours anually
. Substation Engineer - 100 man-hours anually
. Mechanic - 90 man-hours anually
Table 5 Power Circuit Breaker Capital and O&M Budget Projections,
Capital O&M
Year Costs Costs
$2,009 $435,000 $306,000
$2,010 $300,000 $409,000
$2,011 $466,000 $379,000
$2,012 $322,000 $397,000
$2,013 $499,000 $407,000
$2,014 $344,000 $425,000.
19
.
.
.
The benefits of this program come in the future. The breaker maintenance wil extend the life of
the existing circuit breakers and replace old circuit breakers when they become obsolete and un-
maintainable. Figue 8 shows the cumulative cost comparson to taking no action. The no action
case is not acceptable because ofWECC and NERC standards and the 10 year maintenance cycle
balances the requirements and cost to customers.
Figure 8, ffgh Voltage Circuit Breaker Cumulative Costs and Risk Costs Comparison
.l
enæ
"'i:a:
-m J!o eno 0(I 0)-
:;
:J
E:Jo
$140,000,000
$120,000,000
$100,000,000
$80,000,000
$60,000,000
$40,000,000
$20,000,000
$0
- No Action Case
- Current Action Case
I' ~ ~o ~ C\o 0 0C\ C\ C\
00 LOC\ C"o 0C\ C\
Year
C\ 0' co~ ~ LOo 0 0C\ C\ C\
ER 2254 Transmission Air Switches
The transmission air switches have been being replaced at a steady but modest pace during
recent years. The average capital expenditue has averaged about $100,000 per year durng the
past 3 years. This translates to changing or refurbishing 3-4 switches per year. The curent
115kV Air Switch inventory consists of370 operational unts.
There are some switches also installed on the 230kV and 60kV systems, however, the
preponderance of Air Switches are installed on the 115kV system.
80 air switches are being fit with grounding platforms for worker safety durng 2008. During
this process a new worm gear handle is installed and disconnecting whips are adjusted.
Operating pivot joints of the switch mechanisms are not affected by this work. In short, the 2008
work is safety related, not switch mechanism related.
Avista has an inventory listing of Transmission Air Switches that lists the location and type of
switch. Information regarding age of the equipment is not complete but a general age profile can
be obsered.
20
.
.
.
35
30
25
~ 20c
co
d 15
10
115kV Air Switch Age Profile
Information
regarding
equipment age
is for 298 of 370
total air switches.
As of 5/29/2008
5
o
~Ç) ~O; ~'ò roCò ~Ç) ~~ ~'\ 9;Ç) 9;0; 9;Cò 9;0) ~f) ~~ ~'ò ~" d~~~~~~~~~~~~~~~~
Year Installed
At this time, there is not a distubing trend in Air Switch failure. However, as seen in the age
profile, a bow-wave of aging switches wil begin to approach durng the coming decade.
Transmission outage cause tracking is being improved at this time. The improved information
wil allow tracking of failure trends for the air switch population.
ER 2260 Surge Arresters
Substation Surge Aresters or Lightnng Aresters provide protection to several Substation
components. Over time the insulating characteristics degrade. This is especially tre for the
older Silcon Carbide type of Surge Aresters. A vista plans to replace an average of 24 per year
on a planed basis out of the approximately 760 in the Substations. The estimated budget by
year for ths project is shown in Table 6.
21
.
.
.
T bl 6 S ent Budget Projectionsa e ,url!e Arrester Replacem
Capital O&M
Year Costs Costs
2008 $165,000 $39,000
2009 $178,000 $41,000
2010 $195,000 $42,000
2011 $205,000 $44,000
2012 $204,000 $45,000
2013 $226,000 $47,000
2014 $243,000 $49,000
ER 2275 Substation Fence and Rock
The Substation Rock and Fence AM plan covers the maintenance and replacement of Avista's
164 substations. A vista anticipates an average of 4 Substations wil require repairs to the fence
or rock ground cover in order to keep the public out and maintain the insulating properties of the
Substation Rock. A vista also anticipates that 5 Substations each year wil need to be completely
resuraced with new rock. See Table 7 for the projected budget needs.
T bl 7 F d R k R . nd Replacement Budget Projectionsa e ,ence an oc epair a
Capital O&M
Year Costs Costs
2009 $49,000 $49,000
2010 $53,000 $53,000
2011 $58,000 $58,000
2012 $63,000 $63,000
2013 $63,000 $63,000
ER 2278 Distribution Reclosers
The Distrbution Recloser AM Plan covers the Low Voltage Breakers and Reclosers installed in
the substations and out on the varous feeders thoughout our system. Switchgear or metalclad
circuit breakers used in the distrbution system are not covered by this program and are included
in the Switchgear AM plan. Reclosers and Low Voltage Circuit Breakers provide isolation and
protection to a feeder or a portion of a feeder and in the case of a Recloser, they provide
restoration of a momentar fault. Our system has ~415 Substation Reclosers or Low Voltage
Circuit Breakers and ~145 Feeder Reclosers. From Figue 9, we can see that only a small
portion of our RecloserslLow Voltage Circuit breakers, but as shown in these figues, a
signficant portion of our Reclosers wil become;: 40 years old and begin to reach their end of
life.
22
.For substations, we have been maintaining Reclosers for several years and have an ongoing
maintenance program for them. The current program attempts to perform maintenance on these
devices once every 10 years, but due to resources constraints, it has not always been achieved.
The change to the maintenance proposed here is to go to a 13 year maintenance cycle on the
older Vacuum style Reclosers and on all of the Oil style Reclosers. We wil continue to
refubish Reclosers as they fail or come into the shop for other reasons. However, the older
Reclosers, usually older than 45 years old, that no longer can be refubish wil require inspection
every 5 years until they are replaced. As an additional par of the program, 60 old style Reclosers
wil be replaced on a planed basis because they are old, spare pars are no longer available and
have reached their end of life. The planed replacements include 6 per year over a 5 year period.
The new style of Vacuum type Reclosers canot be refurbished but can only have the mechanical
linkages lubricated and a few components replaced, so their maintenance cycle is recommended
to be 5 years. Over the next 10 years we anticipate the following pars use based on ths program:
. 35 refubished Reclosers
. 5 new Reclosers
. 60 Planed Replacements
Figure 9, Substation Reclosers & Low Voltage Circuit Breaker Age Profie
8.00%
7.00%.c0 6.00%:¡l'
'5Q.5.00%0
D.
~4.00%
'õ 3.00%-c
CDu 2.00%..
CD
D.
1.00%
.
~ 30 Recloser must be replaced due to prove Safety and
Unreliability issues
15% ~ 40 Years Old
,.
./\
~"
1\ f' ,
""1
V "V \ /\/"\0.00%
o 20 30 40
Age (Years)
50 60 70 8010
For the Feeder Reclosers, no maintenance or planed replacement is recommended over the next
10 years. Feeder Rec10sers are not easily accessible as in a substation, so any maintenance on
them is equivalent to a planed replacement. Our analysis indicates that any planed
replacement program is not cost effective for our customers. Furher analysis wil be pedormed
to ensure this is the correct approach, but until information is available, no change in our curent
approach is recommended. Over the next 10 years we anticipate the following pars use based
on this program:
23
.. 15 refubished Reclosers
. 7 new Reclosers
12.00%
Figure 10, Feeder Reclosers Age Proïie
c 10.00%
0
~'3 8.00%c.0ii
m 6.00%Õi-
'õ-4.00%c
CDUI-
CDii 2.00%
0.00%.0
.
14%:; 40 Years Old
10 20 40 50 60 70 8030
Age (Years)
This program wil used existing resources and reflects a slight drop in the labor requirements.
On average, we wil need 1,800 man-hours from Substation Electricians, 60 man-hours from
Relay Technicians, and 90 man-hours of Linemen's time each year to manage Reclosers. The
budget requirements for Substations is in Table 8 and for Distrbution, the budget is in Table 9.
T 8 Sable , ubstation Recloser Bude:ets
O&M
Year Capital Costs Costs
2009 $351,000 $93,000
2010 $362,000 $95,000
2011 $376,000 $87,000
2012 $389,000 $91,000
2013 $405,000 $74,000
24
.
.
.
T bl 9 D' "b . R I B da e ,istri ution ec oser u il!ets
O&M
Year Capital Costs Costs
2009 $35,000 $3,000
2010 $36,000 $3,000
2011 $37,000 $3,000
2012 $41,000 $4,000
2013 $44,000 $4,000
This program is only a small change from our current program and only reduces our maintenance
requirements by a small percentage. The benefits of the program come in the out years as the
system begins to age fuher and starts to really benefit our customers out in 2014. Compared to
our curent case, it has an Internal Rate of Retu to our customers of 8.8% due to their avoided
costs associated with power outages and durations.
ER 2280 Substation Circuit Switchers
Substation Circuit Switchers are used like Circuit Breakers in a Substation to provide isolation
and protection for Substation Transformers and is located on the High Voltage side of the
transformer. Some Circuit switchers are used to control capacitor bans in larger substation that
provide voltage support on the system. They are normally located on smaller and more rual
type of substations except when they are used to control capacitor bans.
Figure 11 shows the age profile for our approximately 120 Circuit Switchers used thoughout our
system.
Figure 11, Substation Circuit Switcher Age Profie
25
.
40
35
"'30~-
ns 25-tJr:
~20
(I.c 15E:JZ 10
5
0
.
.
Substation Circuit Switchers
2% ~ 40 Years Old
29% ~ 30 Years Old
o 5 10 15 20 25 30
Age (Years)
35 40 45 50
Our revised plan is to perform periodic testing, inspection, and maintenance on the Circuit
Switchers to ensure their timing of operations are within specifications, lubricate the mechancal
linkages, and identify when a Circuit Switcher must be replaced. Circuit Switchers are also
inspected as par of the month Substation Inspection Program that identifies when a Circuit
Switcher's Interrpter does not have enough SF6 gas for futue operations and must be replaced
or refilled with gas depending upon the design. The program outlines an inspection program that
is time based and vares with the age of the Circuit Switcher. The inspection cycle vares from
11 years for a new one and reduces to a 5 year cycle for the oldest circuit switchers. This wil
result in approximately 20 Circuit Switcher Inspects per year. Based on the inspections, we
anticipate that 2 Circuit Switcher Interrpters wil need to be replaced each year, and two new
Circuit Switchers wil be needed to replace old ones over then next 10 years.
This work wil be performed by our own workforce since it is performed inside our existing
substations.
Table 10 shows the Capital and O&M Budget projects for the work. The resources needed are
600 man-hours of Electrcian and 200 man-hours of Relay Technician support to complete on
average each year.
The benefits of this program come from several areas. The program is anticipated to save
~$45,000 anually in O&M costs and ~$16,000 in Capital costs during the first 10 years by
reducing the number of unplanned outages and extending the life of the existing equipment.
Compared to the current case, the planed maintenance case has an Internal Rate of Return of
10% and saves our customers ~$180,000 in avoided costs due to outages.
26
.
.
.
T 10 . . Sable, Circwt witcher Budget Projections
5 Year Budçiet
Year Capital O&M
2009 $67,000 $104,000
2010 $0 $108,000
2011 $0 $112,000
2012 $0 $116,000
2013 $0 $120,000
ER's 1006/2000/2336/2357 Power Transformers
Avista's Power Transformer plan covers the large transformers used in the substation to change
the power from Transmission voltage levels to distrbution level voltage or Autotransformers
used to control high voltage levels also located in some substations. For Power Transformers,
Avista's system has approximately 175 and an additional 27 Autotransformers. From Figue 12,
26% of Avista's Power Transformers are over 40 years old, but for the Autotransformers, only
2% are more than 40 years old (see Figue 13).
The current Asset Management maintenance and inspection plan is fully described in "Avista
Utilities Transmission Maintenance Inspection Plan." In addition, Avista has identified old
transformers that based on their age and lower efficiency compared to new transformers should
be replaced on a planed basis. Based on ths assessment, A vista anticipates replacing one to
two transformers per year based on condition and cost savings due to improved efficiency.
This work wil require a projected budget shown in Table 11. The labor to complete the work on
an anual basis is described below. Some other resource wil be required based on different
circumstances, but the following represent the average anticipated labor needs.
. Electrcians - 860 man-hours
. Lineman - 20 man-hours
. Relay Techncian - 100 man-hours
For installing and removing the mobile substation anually, Avista projects we wil us the
following additional resources:
. Electrcians - 400 man-hours
. Communications Technician - 15 man-hours
. Equipment Operator - 50 man-hours
. Substation Engineer - 40 man-hours
Figure 12, Power Transformer's Age Profie
27
.
.
.
Power Transformers
0--10 11--20 21--30 31--40 41--50 51--60 61--70 71--80Age
60
50 ..t/c
40 l!l-..
30 0
l!(I20.c
E::10 z
0
Figure 13, Autotransformer's Age Profie
230/115kV Auto Transformers
0-10 11-20 21-30 31-40 41-50 51-60 61-70 71-80
Age
7
6
5
4 f'tCD C.i f!
3 E i-:i _Z 0
2
1
o
28
.
.
.
a e , ower rans ormer rOJecte u 12ets
O&M
Year Capita Costs Costs
2009 $1,176,000 $40,000
2010 $1,290,000 $42,000
2011 $1,398,000 $43,000
2012 $1,554,000 $45,000
2013 $1,674,000 $46,000
2014 $1,842,000 $48,000
T bI 11 P T i P' dB d
More than 26% of Avista's Substation Transformers are over 40 years old. Replacing them
would save an anticipated average of $15,000 per year per transformer through improved
efficiency. The combined factors of improving effciency and age justify a planed replacement
of old and inefficient transformers. The overall savings impacts are show in the cumulative cost
comparson shown below in Figure 14. Based on the analysis, other options would save money
in the future, but not enough to change from our curent case.
Figure 14, Power Transformer Cumulative Cost Comparison
en $450,000,000c0:¡$400,000,000u
CD $350,000,000'õ'..$300,000,000Q...$250,000,000en0$200,000,0000
CD $150,000,000~:¡$100,000,000CI
::$50,000,000E::$00 r-C"0)i."l r-C"0)i.0 "l "l C'C"C"~~i.0 0 0 0 0 0 0 0 0
C'C'C'C'C'C'C'C'C'
Year
- Power Transformer
Current Case
- Power Transformer
Planned Case
- Power Transformer
Optimized Case
29
. ER 2204 System Wood Substation Rebuilds
This ER addresses capital work for substations built with wood timber frame constrction. This
type of construction utilizes wood poles for vertical strctue and treated timbers for horizontal
strctual components.
There are at least 56 substations in the A vista system that are either all wood or have a major
portion of framework that is wood. This count includes installations with signficant horizontal
strctual wood framing. Take offpoles, etc, are not included.
The analysis of examines on two complimentar failurelrepair scenaros: (1) the substation
requires complete rebuild due to poor condition of the wood strctue or (2) individual strctual
timbers can be replaced to extend overall station life. These scenaros are complimentar in that
timely inspection and replacement of individual timbers reduces the need for complete rebuilds.
In reality, a fuer consideration in the decision between these alteratives is the condition of
substation components such as insulators and switches. The analysis accounts for this factor
indirectly. The study utilizes a statistical cure derived from the historical age of
wood
substations that have been replaced during the last 20 years. Expert opinion of personnel
employed in the Substation Design Group indicates that there is no doubt that strcture
replacement was necessary in these cases; additionally, a heavily weighted factor in the decision
process is the age, condition and maintainability of other substation equipment..The data set used in the statistical analysis of whole substation replacement ages included those
substations rebuilt primarly due to strctural reasons. Wood constrction substations that were
replaced due to capacity upgrades were excluded.
Statistical analysis using the Weibull function regarding the wholly replaced substations yields
65 years as the characterstic life. This cure may be manually adjusted to account for the
influence of substation equipment in the decision process. The manual adjustment can also
account for strctual component replacement that has occured in the past and has the effect of
having extended substation strctue usable life.
Adjustment of the cure can then bring results of analysis into a closer match with inspection
observations of condition. Analysis and comparson with inspections is indicating an adjustment
to bring the characteristic life value to 72 years from 65 years. Ths value is about 10 years
lower than transmission wood pole life cycle analysis results.
A data set used for individual timbers was estimated by a count of timbers observed to be failed
durng inspections. Failure in this case is defined as visible strctual deterioration. Also
included in the timber replacement data set is an estimated count and estimated age of previously
replaced timbers; i.e., replaced prior to inspections conducted during 2007.
.The Weibull cure resulting from estimates regarding the timbers is unsatisfactory. It is widely
agreed that timbers, on average, last at most 2/3 as long as a large wood pole. Many timbers
30
.
.
have been replaced via maintenance activities that are lost as data points. We are not confident
in the visual estimates of age accomplished to date regarding the horizontal timbers.
We are utilizing a failure curve for the horizontal members relying heavily on information
gathered during the Wood Pole Management analysis. It is generally agreed that the life of a
cross-arm is, at most, about two-thirds the life of a wood pole. The small amount of information
gathered on the substation horizontal member had given a characteristic life not much shorter
than the substation. The curve was manually manipulated to match the two thirds value for
component characteristic life versus the substation overall failure curve.
An informal surey was done via input from area engineers, line personnel, and the electrcians
who conduct monthly substation inspections. Ths surey generated a raned listing by
condition of the wood frame substations. An engineer from Substation Engineering and an Asset
Management engineer then inspected the 12 substations that raned worst through the informal
surey.
The inspections indicate that 2 of the worst 12 substations should be replaced as soon as
possible. Deterioration was extensive enough that intermediate rebuilding of select portions of
the substations is not feasible.
Of the remaining substations inspected a majority would benefit from select replacement of
timber framing. Several do not need immediate attention.
Title IRR Net Levelied
Req Savings
Estimated
Rate
Impact
Levelied
Anual Cost
COMPAR: Wood Substations
(w/o effects, With Inspection
and PM plan) vs. (w/o effects,
wlo Inspection and PM plan)
$350,307 -0.047%$1,103,142
COMPAR: Wood Substations
(wI effects, With Inspection
and PM plan) vs. (wI effects,
wlo Inspection and PM plan)
$442,462 -0.059%$1,119,341
. Table 12, Wood Substation Rebuild Results - ER 2204
31
.
.
.
20 Year Results Total Cost Predicted Average Anual
Capital, O&M,Replacements Capital Budget
Consequences,
Installation
No Program, $26,800,000 23 Replacements $1,130,000
Respond with
replacements as
necessar only
Proactive,$14,100,000 13 Replacements $683,000
Inspections, Minor 30 Minor Rebuilds
Rebuilds, Replace
per statistical
predictions
Savings $12,700,000 (-$447,000)
ER 2252 System - Obsolete Protective Relays
Maintenancelreplacement of protective relays is one of the most complex single areas Asset
Management has analyzed. The complexity stems from the many types of faults and subsequent
differing levels of impact to the system that can result from relay failure or miss-operation.
Industry data regarding the age related life cycle performance of protective relays is virtally
non-existent. However, A vista has maintaned a log of relay operations that was helpful in the
analysis of miss-operation and failure to operate probabilities. The input of the Protection Group
staff was invaluable; their combined decades of experence made the conclusions possible.
Traditional protective relaying installations are comprised of multiple devices which work
together to protect personnel and equipment durng a multitude of fault and system conditions.
The Asset Management studies modeled this multi-component architectue as "relay groups";
i.e., a transmission line circuit breaker might be called upon to operate by any of a half-dozen
different components but performance is characterzed as action of a single protective system.
Modern protective relay hardware technology takes advantage of micro-processors to eliminate
the need for multiple hardware devices. Many functions can now be accomplished by a single
integrated device. Additionally, the new devices have remote alar capabilities to alert
operators of internal problems before system conditions might require relay operation. With the
alarm function it is possible to double the inspection, calibration and test cycles versus older
technology.
There are more than 6400 separate relay hardware items listed in the database maintained by the
Avista Protection Group. The age distrbution of these devices is shown in the graph below.
32
.Protective Relays
500
400~.- 300-as
5 200
100
o~~ ~~~~~~~~~~~*~d~"Ç) "Ç) "OJ "a¡ "a¡ "a) "a) "Ç) ,,OJ "OJ "OJ "OJ "a¡ "a¡ ct ct ct
Year Installed
Two relay replacement strategies were studied: (1) replace all remaining electro-mechancal
relays with microprocessor technology and (2) (a subset of (1)), replace electro-mechanical
relays that support transmission lines and major substation equipment with microprocessor
technology.
.The following table documents the results from the Revenue Resource Requirement Model for
the two alternatives. Option (2) from the paragraph above is refered to as "PRI UPGRAED"
as an abbreviation to priority upgrades in the table below. "UPGRAED" is the option of
replacement of all remaining electromechanical relays with current technology.
Net Estimated Avg
Title IRR Levelied Rate Annual AvgAnnual
Req Savigs Impact Capital O&MCosts
Cost
Relays, AS-IS wI
effects vs.
UPGRAED wI 7.65%$158,968 -0.021%$1,229,922 $1,299,045
effects & w
constrction
Relays,
UPGRAED wI 7.22%-$42,895 0.006%$1,369,597 $980,527effects & const vs.
As-Is wI effects
.
33
.
.
.
Relays,
UPGRAED wlo
effects and wI 6.11%-$443,386 0.059%$1,369,597 $27,351
const vs. As* Is
wlo effects
Relays, PRJ
UPGRAEDw
effects and wI 7.46%$75,382 -0.010%$1,114,409 $1,273,684
const vs. As-Is w
effects
Relays, PRJ
UPGRAED wlo
effects and wI 7.44%$38,969 -0.005%$1,114,409 $281,914
const vs. As-Is
wlo effects
The estimated cost to accomplish the upgrade to priority transmission and substation equipment
relaying is $15 millon. Most distrbution level relay upgrades are best accomplished in
conjunction with recloser replacement. The cost of relay work for reclosers is included in that
project's estimate.
The comparson results of the alternatives are extremely close. The overrding factors brought
up time and again in favor of the replacement are diffculty of repair and the appreciable
improvement in hardware technology. Especially on transmission and substation equipment
relays, there is a growing unavailability of repair pars and difficulty in reliably repairing the
older hardware. The alar feature of the new hardware is a great advantage; at ths time, an
older EM relay might be tested or repaired, then suffer a component failure that would go
undetected until failing when it was required to operate.
ER 2425 Substation High Voltage Fuse Replacements
About 60 of our smaller substations use power fuses to provide protection for substation
transformers instead of relays. Of these 60 substations, 18 have High Voltage Power Fuses that
are no longer rated to handle the curently available maximum fault curents and 14 of this group
average about 50 years old and no longer have spare pars. Approximately, 21 % are more than
40 years old. Four of the substations have a fault duty current that exceeds all types of fuses and
must be replaced by a Circuit Switcher.
Figure 15 shows an estimated age of the Power Fuses based on the age of the substation.
Based on Avista's analysis, Power Fuses should also be replaced every 40 years, because they
become uneliable and not supported with spare pars. The Power Fuse AM Plan wil replace an
average of 5 fuse installations each year until 18 underated Power Fuses are removed from the
system. Those requiring a Circuit Switcher wil be replaced at the end of the replacement of the
18 underrated Power Fuses. Once all of the underrated fuses have been replaced, A vista wil
34
.
.
.
continue to replace the remaining as they reach approximately 40 years of age or are no longer
supported with spare pars.
Figure 15, Power Fuse Age Profie Estimate
6-
"C(I..5C'
E.-..l/4(I-
"C(I 3--
C'..l/c 2..(I.c
1E~z
0
Power Fuse Age Profile
18 Power Fuses are installed in sysems 21%)0 40 Years Old
that exceed their fa ult capacity
f---
-
rr,,I
Ç)~ Cb "I) "CO ~ ~ ~ ~I) ~co b? ~ ~Cb ~I) ~co coÇ)
Age (Years)
35
. Figure 16, Power Fuse Cumulative Cost Projections
80000000
70000000tiC
~ 60000000u
CI
'! 50000000-!40000000(J
CI
~30000000
ca
"3
E 20000000:J(J
10000000
- Power Fuse - Base
Case
- Power Fuse - Planned
Case
.. Power Fuse -
Optimized Case
0 i-..i.en (Y i-c;i.en (Y i-u;i.0 0 0 ..N N (Y (Y .q .q i.0 0 0 0 0 0 0 0 0 0 0NNNNNNNNNNNNN
Year
.The resources required to complete the work is shown in Table 13, Power Fuse Replacement
Capital Budget Projections. The labor resources require are listed below:
. Substation Engineer - 50 man-hours
. Substation Electrician - 210 man-hours
. Linemen - 60 man-hours
For installng and removing the mobile substation anually to support the work, A vista projects
we wil us the following additional resources:
. Electrcians - 600 man-hours
. Communications Technician - 20 man-hours
. Equipment Operator - 75 man-hours
. Substation Engineer - 60 man-hours
The benefits of this program includes improved reliability due to replacing these uneliable
Power Fuses with new and more reliable fuses and greatly reducing the risk of damaging the
Power Transformer the fuse tres to protect. A vista estimates that the plan wil save our
customers approximately $55,000 per year in avoided costs due to power outages caused by
Power Fuse failure. Figue 16 shows the cumulative cost benefit of the planned replacement
program..
36
. Table 13, Power Fuse Replacement Capital Budget Projections
.
.
Capital
Year Costs
2009 $297,000
2010 $275,333
2011 $253,571
2012 $237,875
2013 $220,556
ER 2294 System - Batteries
This budget item covers the replacement and maintenance on all Substation batteres. The range
of batteries covers from 24 vdc to 125 vdc and can be located in battery rooms or specific
equipment. We analyzed not only the capital budget needs, but also the O&M Budget needs to
develop the budget requirements shown in Table 14, Substation Battery Budget Projections.
However, a decision was made to put the analysis on these batteries on hold until a batteryan
was in place and testing batteries before going ahead with any recommendations. So, the curent
budget requirements wil be based on historical spending levels adjusted for inflation until
furter analysis has been completed.
T bl 14 S b B P .Ba e , u station atterv udl!et ro.iections
O&M
Year Capita Costs Costs
2009 $106,000 $181,000
2010 $115,000 $187,000
2011 $156,000 $193,000
2012 $113,000 $200,000
2013 $95,000 $207,000
ER 2416 System - Porcelain Cutout Replacements
A program was implemented in 2007 and scheduled to be completed in 2008 to replace all of the
Chance cutouts in the system. Ths program should address the immediate issues with the
broader category of Porcelain Cutouts. However, we anticipate the other styles of porcelain
cutouts to star failng prematuely in the near future and have seem some early indication of ths.
However, until more data is gathered, we plan on monitoring the data and develop a new plan in
the future when the information warants another look.
ER 2449 System - Replace Substation Air Switches
This program covers the planed and unplanned replacement of Substation Air Switches. Air
Switches used in the Transmission System located outside of a substation are covered by ER
2254 discussed above. The analysis used for this budget item was an earlier model and wil need
to be updated in the futue if the need arses. However, we anticipated that the use of an
37
.
.
.
integrated Substation analysis wil provide future direction on what should be done to replace
Substation Air Switches. The integrated approach wil more accurately reflect the best
opportity to use a planed approach since are switches are best replaced when the substation is
rebuilt or undergoing a major upgrade. Table 15, Sub Air Switches Projected Budget, provides
the basis analysis and estimated needs to address Air Switches that fail each year.
T bl 15 S b Ai S . h P' d Budgetae, u witc es roiecte
Year Capital Costs
2009 $114,000
2010 $122,000
2011 $140,000
2012 $156,000
2013 $157,000
ER NEW Distribution Transformer Replacement
Ths program covers all of the Distrbution Transformers on our A vista feeders that supply
power to our customers. Specifically, the program replaces two.sets of less efficient
transformers based on their losses and age. The first set is all Distrbution Transformers installed
before 1960 and includes about 11,000 transformers that wil be replaced over a five year period.
The pre 1960 transformers have the largest no-load losses and are the oldest, so they wil be the
focus of the program first. All of the pre 1960 transformers are overhead transformers mounted
on poles and their age profie is shown in
Figue 17. After the pre 1960 transformers are replaced, A vista wil work to replace the pre
1980 transformers and includes about 42,000 transformers. The second batch of transformers
has a mix of types that includes overhead transformers, pad-mounted transformers (see Figure 18
and for age profiles), and subsurace transformers (see Figue 20 for age profile). The
replacement of the pre 1980 batch of transformers wil also eliminate the last of the PCB
Distrbution Transformers from our system.
Figure 17, Overhead Single Phase Distribution Transformers Age Profie
38
.
18.00%
16.00%
14.00%
12.00%
Gl
gi 10.00%ëGl
~8.00%Gl0-
6.00%
4.00%
2.00%
0.00%
0
Single Phase Overhead Transformer Age Profile
17%:; 40 Years Old
39%:; 30 Years Old
5 10 15 20 25 30 35 40 45 50 55 60 65 70 75
Age (Years).The planed approach to accomplish the transformer replacement is to use thee man contract
crews with support from one to two Customer Project Coordinators (CPC). The contract crews
wil work an average of 1,600 hours for five years and require 3,200 man-hours ofCPC's time to
support them. The budget for the work is shown in Table 16.
T bl 16 C .r replacing pre-1960 Distribution Transformersae,anital Budget Estimate fo
5 Year Capital
Year Budget
2009 $3,768,000
2010 $3,899,880
2011 $4,036,376
2012 $4,177,649
2013 $4,323,867
.
39
. Figure 18, Padmounted Single Phase Distribution Transformers Age Profie
Padmounted Singe Phase Transformer Age Profile
30.00%
1 % ~ 30 Years Old
5.00%
25.00%
20.00%
Percentag
15.00%
10.00%
0.00%.o 5 10 15 20 25 30 35
Age (Years)
40 45 50 55 65
The benefits of the program come in two forms, reliability improvement and cost savings. Over
10 years, we anticipate that the program wil reduce the number of Distrbution Transformer
outages by ~900 events. In energy savings, we anticipate replacing the pre 1960 transformers to
save an average 15,300 aM or 1.75 MW of generation. Our customers wil see a 10%
Internal Rate of Return on this investment due to the reduced number of outages and especially
from the power savings. After the pre 1980 Distribution Transformer are replaced, we anticipate
an additional savings of an average 33,900 aM or 3.87 MW of generation. Figure 21 shows
the cumulative costs of the alternatives and ilustrates the potential savings over time due to
planned replacement of the transformers.
.
40
.
.
.
Figure 19, Padmounted Three Phase Distribution Transformers Age Profie
25.00%
20.00%
Gl 15.00%Cl.!c
~Gl
0. 10.00%
Padmounted Three Phase Transformers Age Profile
5.00%
5% :; 30 Years Old
0.00%
o 15 30 35 40 55452025
Age (Years)
5 10
41
.
.
.
Figure 20, Subsurface Single Phase Distribution Transformers Age
Profie
60.00%
50.00%
40.00%
IICIl'-i:30.00%~..II0-
20.00%
Subsunace Distribution Transformers Age Profile
40% ;: 30 Years Old
10.00%
0.00%
o 5 20 25
Age (Years)
30 35 40
42
.
.
.
Figure 21, Distribution Transformer Cumulative Cost
Projections
$1,400,000,000
CIi:$1,200,000,0000:;(J
G)$1,000,000,000...
2ti $800,000,000-
CI00 $600,000,000G)~:;$400,000,00012~
E $200,000,000~0
$0
~ "n: "Q) rt !1" ~ ~ ~ ~~rl ~ ~ ~ ~ ~ rf rf ri~
Year
- Distribution
Transformers Base
Case
- Distrbution
Transformers Planned
Replacement Case
-- Distribution
Transformers Planned
Replacement 50 kV A
and Higher Case
ER NEW?? Substation Voltage Regulators
The recently completed analysis indicates that our existing program is best approach overalL.
However, a more detailed analysis may reveal that specific types or applications may gain some
benefit from a different approach. Furher analysis wil be performed in the futue and we wil
continue to monitor their performance.
MAC 215 - 592550 Wildlife Guards
Wildlife caused outages have a signficant impact on electrc servce reliability to customers.
The improved outage tracking implemented in 2001 has consistently shown, withn a percent or
two either way, that animals cause 19% of outages experienced by electrc customers. Whle
generally short in duration, labor impacts to respond are significant.
The need for wildlife guards exists for both bird and squirrel outages. Squirrel outages are more
widespread and present a pictue that allows quantification of the problem magnitude.
The tables below show the impact of squirrel caused outages occurng on approximately one-
fifth (63 out of325) of the Avista distribution feeders versus the total squirrel caused outages in
43
.
.
.
the system. The benchmark of feeders having had 30 documented squirrel caused outages from
2001 though 2007 was chosen to ilustrate how these feeders account for more than half of
document squirrel caused outages.
800
815
819
654
2001
2002
2003
2004
2005
2006
2007
408
496
415
775
A relevant statistic that canot be quantified is what proportion of outages is caused by squirrels
and birds but evidence of the outage cause is not found. There were 852 sustained outages with
undetermined cause during 2007. Estimating that 20% of undetermined outages are caused by
animals raises the impact of squirrel caused outages to between 900 and 1000 per year
thoughout the system.
Momentar outages have not been included in cost impact of animal caused outages. There are
11,135 documented momentar outages between 2001 and March, 2008. Of these, 329 are
anotated as being squirrel or bird caused and 4,723 momentar outages are undeterined cause.
Several feeders located in the Palouse Area were historically among the worst feeders in the
Avista terrtory for animal caused outages. The graph below indicates the effectiveness of
squirrel guards in preventing outages. Feeders that were having as many as 9 outages during a
summer month had outages reduced to zero once gud installation was complete.
44
.
.
.
Palouse Area Feeder Improvement
45
40
35
30
25
20
15
10
5
o
2001 2002 2003 2004 2005 2006 2007
-M15512 M15513 -M15514 -PUL116 -SPU123
The proposed initial program for wildlife guards involves installation of guards on 60 feeders.
These 60 feeders account for almost exactly half of documented animal caused outages.
IR information is fuished in table below as calculated with the Revenue Resource
Requirement modeL.
Without Effects: H:\2008
AM studies
dan _ w\Squirrels\fnancials\sq
guards cost profie for REV
REQ.xls
$222,071 -0.030%$93,728
ul n
performing feeder for animal outages.
Assumes 90% effectiveness for squirrl
guards. Labor cost of bas case is equivalent
to 400 outages per year. Effects such as
outage cost to customer is not considered,
ecnomic analysis is based on avoided cost
of response to squirrel caused outage verus
cost of squirrl guar instalation is
With Effects: (H:\2008 AM
studies
dan _ w\Squirrels\fnancials\cost
profie_base case.xls) ver
H:\2008 AM studies
da _ w\Squils\fnancials\cost
profie_with guar.xls)
$441,659 -0.059% $104,292
Estimated cost of squirrel guard installation on the 60 worst pedorming feeders is $1.6 milion to
$1.8 millon.
45
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-097
DATE PREPARD:WISS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04/17/2009
Don Kopczynski
Jim Corder
ISIIT Dept.
[phone]
REQUEST:
Please describe the Company's refresh cycles and the justification used to replace $11.5 milion in
technology equipment.
RESPONSE:
Mr DeFelice's testimony identified $11.5 milion for the Company's total technology investment.
The testimony listed the following major areas. The information provided in the testimony was the
investment areas and amounts planed to transfer to plant-in-servce by December 31, 2009
totaling $11.5 milion.
$4,410,000 Technology Refresh Program
$ 981,000 Technology Expansion Program
$1,115,000 AFM Product Development
$ 556,000 Nucleus Development
$ 627,000 Web Development
$ 473,000 Enterprise Business Continuity
$ 216,000 Enterprise Data Architectue
$ 800,000 Mobile Dispatch Upgrade
$ 1,372,000 Mobile Dispatch II (electrc)
$ 896,000 Technology Projects Minor Blanet
$11,446,000 Total
The technology refresh program is a sub-set of the Company's total technology investment. The
Technology Refresh Program total 2009 spend planed is currently $5,567,620 (of which,
$4,410,000 is planed to move into servce in 2009 and has been included in this case). The other
major areas of investment are generally drven by technology expansion and other business
requirements.
The technology refresh program funds technology for Generation & Production, Transmission &
Distrbution, Customer Service, Corporate Services (A&G), basically all areas of the Company.
The refresh program consists of the following categories (in spend dollars):
$1,982,000 Distributed Systems: (Office PC Systems, Fieldlugged PC Systems, Projectors,
Printers, Fax, Scaners, Plotters, Cameras, etc.) Refresh cycle range forthis area is 3 to 7 years.
$ 521,400 Communications Systems: (Radio/Smarhone, Telephone Systems, Voicemail
Systems, E-Mail Systems, VideolTele Conferencing, Voice Recording Systems, Voice Portal
System, etc.) Refresh cycle range for this area is 3 to 10 years.
.
.
.
Response to Staff Request No. 097
Page 2
$1,094,720 Network Systems: (Wide Area Networks, Local Area Networks, Metro Area
Networks, Point to Point Networks, Wireless Networks, Mobile Networks for T &D, G&P, A&G,
etc.) Refresh cycle range for this area is 3 to 10 years.
$1,239,500 Central Systems: (Server Systems, Storage Systems, Database Systems, etc.) Refresh
cycle range for this area is 3 to 5 years.
$ 100,000 Security Systems: (Cyber Based Solutions, Firewalls, Access Controls, Protection,
Detection, etc.) Refresh cycle range for this area is 3 to 5 years.
$ 100,000 Environmental Systems: (power Protection, UPS, Fire Protection, Emergency
Generators, HV AC, etc.) Refresh cycle range for this area is 3 to 15 years.
$ 430,000 Application Systems: (Office and other PC applications that meet crteria.) Refresh
cycle range for this area is 3 to 5 years.
Overall, the technology refresh cycles are in place to maintain reliabilty, serviceabilty,
availability, and functional integration. The financial drver to the technology refresh program is to
avoid extreme technology investment with incremental advancement.
The technology infrastrcture organization employ's technology engineers with focus on each
category of technology. Their role is to manage and plan prudent technology investment operating
models. The technology refresh programs have steering committees for governance.
Infrastrctue engineers make recommendations on refresh cycles for technology items and
multi-year refresh schedules. Decisions and objectives are established each year by the steering
committee.
Refresh cycles are generally established by working with industry analysts and take into
consideration manufacturers' planed obsolescence, waranty periods, maintenance costs, spare
part availability, and functionality constraints with product integration points. The team deals with
personal computers on the short cycle to emergency generators and fiber cable on the long cycle.
The technology refresh program is allocated fuding each year. A percentage or portion of each
technology category is scheduled for replacement each year. This operating model has been
developed to manage the refresh cycle incrementally and establish a more predictable investment
plan. For example, a desktop computer might be on a 4 year refresh cycle; therefore 25% of the
desktop population would be targeted for replacement in every year.
.JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-099
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/17/2009
Scott Kinney
Liz Andrews
State & Federal Reg.
[phone]
What is the total anual revenue requirement requested by A vista in this case to paricipate in
Columbia Grd?
RESPONSE:
The anual revenue requirement requested in this case to paricipate in Columbia Grd is as follows:
(See Mr. Kinney's Exhibit NO.8 - lines 3-5)
Columbia Grid Development
Columbia Grid Planning
Columbia Grid OASIS
Total System Columbia Grid expenses
$240,000
$180,000
$100,000
$520,000
.10 Share included in pro forma
adjustment (PF5) expense $ 184,132 35.41%
SIT - 1.2216%$2,249
$181,883
FIT - 35%$ 63,659
$118,224
Conversion Factor 0.638787
Revenue Requirement $185,075
.
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-l 00
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
REQUEST:
04117/2009
Scott Kinney
Mark Baker/L. Andrews
Transmission Operations
[phone]
What is the total anual revenue requirement aside from Columbia Grid and Grid West requested
by A vista in this case for transmission planng functions?
RESPONSE:
The transmission planing fuctions (excluding Columbia Grid and Grd West) include a portion
of the Northwest Power Pool expenses and the transmission planing portion of the System
Planng departent.
Nortwest Power Pool
Transmission
Planning
related costs
Northwest Power Pool
Transmission Expense
Power Supply Expense
Total NWPP
Total
$ 31,248 26.4% $
$ 63,444
$ 94,692
8,249
System Planning Dept.
FERC Accounts 560/566 Labor
Non-labor
$97,574
$24,029
Total Planning costs (System)$ 129,852
As shown in the table above:
Total system anual NWP costs are $94,692, of which $31,248 (see Note 1) is transmission
related, and $8,249 (or 26.4%) is allocated to transmission planng fuctions.
(Note 1- see Mr. Kinney's Exhibit No.8, line 1)
System Planing Deparent expenses included in the test period, include O&M anual
transmission planing expenses of$121,603 (non-labor = $24,029 I labor = $97,574).
Total System Planing costs included:
Total = $129,852 (system)
Idaho's share of these total expenses is approximately $45,981 (or 35.41 %), for a total revenue
requirement of $46,217.
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-101
DATE PREPARD:
WITNSS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04/15/2009
Scott Kinney
Scott Kinney
System Operations
[phone]
REQUEST:
Please identify and explain any overlap between A vista functions for Columbia Grd and other
Avista transmission planing fuctions and why these fuctions are not duplicative.
RESPONSE:
The Columbia Grd Planing fuction is not duplicative of the A vista Planng processes. The
Columbia Grd Planng function provides for a coordinated regional planning process across the
Columbia Grd footprint. This coordinated process has been mandated by FERC to meet some of
the requirements of Order 890 (and the "Attachment K process" associated with the Company's
Open Access Transmission Tarff (OATI)). The Columbia Grd planing fuction has added
slightly to the A vista planning workload. Columbia Grid requires additional base case reviews and
submittals, data checking, meeting attendance, and review of study results in addition to what is
presently performed by the A vista Planng Deparent. The A vista Planng fuctions are
traditionally focused on area load servce, meeting national reliability standard requirements and
the Western Electrc Coordinating Council planng processes. However, the additional workload
and associated costs are justified because the Columbia Grd function evaluates transmission
projects from a regional standpoint, which is a valuable work product to analyze interaction
between proposed projects and existing system capacities and contractual rights. Columbia Grid
gives Avista a forum to engage other utilities to develop a regional solution to transmission system
congestion.
.
.
.
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
AVISTACORPORATION
RESPONSE TO REQUEST FOR INFORMATION
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-l 02
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/15/2009
Scott Kinney
Mark Baker
Transmission Operations
[phone]
Please provide total reimbursement received by Avista in each of the last five years for generation
interconnection planng studies.
RESPONSE:
Please see Avista's response 102C, which contains TRAE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately fied under
IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code, and pursuant to the
Protective Agreement between A vista and IPUC Staff dated Januar 8, 2009.
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-l 03
REQUEST:
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/15/2009
Scott Kinney
Scott KinneylRodney Pickett
System Operations
[phone]
Please explain and provide any analysis showing how the Company determines which
replacement program projects are justified and cost effective in terms of improved reliabilty and
customer service. See Page 21 of Mr. Kinney's testimony staring on line 11.
RESPONSE:
Please see the response to production request No. Staff-095 for a copy of the Company's "Asset
Management Five Year Plan and Budget Summar. Ths plan describes all of the replacement
projects and efforts that the company plans to initiate or continue over the next five years. The
plan describes the cost associated with each project. The plan also discusses the risks associated
with the Company's aging equipment. Ths information is deterined through the collection of
data and associated failure rate analysis.
The information from the Company's "Asset Management Five Year Plan and Budget Sumar"
associated with the replacement projects discussed in Mr. Kinney's testimony on page 21
beginning on line 11, is shown in "Staff PR 103 Attachment A".
.
.
.
Staff_PR_103 Attachment A Page 1 of12
ER 2260 Surge Arresters
Substation Surge Aresters or Lightning Aresters provide protection to several Substation
components. Over time the insulating characteristics degrade. This is especially tre for the
older Silicon Carbide type of Surge Aresters. Avista plans to replace an average of24 per year
on a planed basis out of the approximately 760 in the Substations. The estimated budget by
year for this project is shown in Table 6.
T bl 6 S A R lacement Budget Projectionsae ,ure;e rrester epJ
Capital O&M
Year Costs Costs
2008 $165,000 $39,000
2009 $178,000 $41,000
2010 $195,000 $42,000
2011 $205,000 $44,000
2012 $204,000 $45,000
2013 $226,000 $47,000
2014 $243,000 $49,000
ER 2275 Substation Fence and Rock
The Substation Rock and Fence AM plan covers the maintenance and replacement of Avista's
164 substations. A vista anticipates an average of 4 Substations wil require repairs to the fence
or rock ground cover in order to keep the public out and maintain the insulating properies of
the
Substation Rock. A vista also anticipates that 5 Substations each year wil need to be completely
resuraced with new rock. See Table 7 for the projected budget needs.
T bl 7 F d R k R air and Replacement Budget Projectionsae,ence an oc eo
Capital O&M
Year Costs Costs
2009 $49,000 $49,000
2010 $53,000 $53,000
2011 $58,000 $58,000
2012 $63,000 $63,000
2013 $63,000 $63,000
.
.
.
StafCPR_I03 Attchment A Page 2 of 12
ER 2278 Distribution Reclosers
The Distrbution Recloser AM Plan covers the Low Voltage Breakers and Reclosers installed in
the substations and out on the varous feeders throughout our system. Switchgear or metal
clad
circuit breakers used in the distrbution system are not covered by ths program and are included
in the Switchgear AM plan. Reclosers and Low Voltage Circuit Breakers provide isolation and
protection to a feeder or a portion of a feeder and in the case of a Recloser, they provide
restoration of a momentar fault. Our system has --15 Substation Reclosers or Low Voltage
Circuit Breakers and -145 Feeder Reclosers. From Figure 9, we can see that only a small
portion of our RecloserslLow Voltage Circuit breakers, but as shown in these figues, a
signficant portion of our Reclosers wil become:: 40 years old and begin to reach their end of
life.
For substations, we have been maintaining Reclosers for several years and have an ongoing
maintenance program for them. The curent program attempts to perform maintenance on these
devices once every 10 years, but due to resources constraints, it has not always been achieved.
The change to the maintenance proposed here is to go to a 13 year maintenance cycle on the
older Vacuum style Reclosers and on all of the Oil style Reclosers. We wil continue to
refubish Reclosers as they fail or come into the shop for other reasons. However, the older
Reclosers, usually older than 45 years old, that no longer can be refubished wil require
inspection every 5 years until they are replaced. As an additional par of the program, 60 old
style Reclosers wil be replaced on a planed basis because they are old, sparepars are no longer
available and have reached their end of life. The planed replacements include 6 per year over a
5 year period. The new style of Vacuum type Reclosers canot be refurbished but can only have
the mechanical linkages lubricated and a few components replaced, so their maintenance cycle is
recommended to be 5 years. Over the next 10 years we anticipate the following pars use based
on this program:
. 35 refubished Reclosers
. 5 new Reclosers
. 60 Planned Replacements
.
.
.
StafCPR_I03 Attchment A Page 3 of12
Figure 9, Substation Reclosers & Low Voltage Circuit Breaker Age Prof'ile
- 30 Recloser must be replaced due to prove Safety and Unreliability issues
15% ~ 40 Years Old
8.00%
7.00%
co¡ 6.00%
'3
go 5.00%
D.
~ 4.00%
Õ
1:
~
CDD.
3.00%
2.00%
1.00%
0.00%
,.
1\f
1\
V1
1\ f\ ,
V '\\,\/\,\ /'
i
o 10 20 30 40
Age (Years)
50 60 70 80
For the Feeder Reclosers, no maintenance or planed replacement is recommended over the next
10 years. Feeder Reclosers are not easily accessible as in a substation, so any maintenance on
them is equivalent to a planed replacement. Our analysis indicates that any planed
replacement program is not cost effective for our customers. Furer analysis wil be perormed
to ensure this is the correct approach, but until information is available, no change in our curent
approach is recommended. Over the next 10 years we anticipate the following parts use based
on this program:
. 15 refurbished Reclosers
. 7 new Reclosers
StafCPR_I03 Attachment A Page 4 of 12
.Figure 10, Feeder Reclosers Age Profile
14%;: 40 Years Old
12.00%
c:10.00%
0¡
'3 8.00%Q.0i:
eã 6.00%Õi-Õ-4.00%c:
CD
CJ"-
CDi:2.00%
0.00%
0 10 20 30 40 50
Age (Years)
60 70 80.
This program wil use existing resources and reflects a slight drop in the labor requirements. On
average, we wil need 1,800 man-hours from Substation Electrcians, 60 man-hours from Relay
Techncians, and 90 man-hours of Linemen's time each year to manage Reclosers. The budget
requirements for Substations is in Table 8 and for Distribution, the budget is in Table 9.
T bl 8 S b R i B dae,u station ec oser u 12ets
O&M
Year Capita Costs Costs
2009 $351,000 $93,000
2010 $362,000 $95,000
2011 $376,000 $87,000
2012 $389,000 $91,000
2013 $405,000 $74,000
.
.
.
.
Staff PR 103 Attchment A Page 5 of 12
T bl 9 D' t 'b ti R I B dae,IS ri u on ec oser u u!ets
O&M
Year Capital Costs Costs
2009 $35,000 $3,000
2010 $36,000 $3,000
2011 $37,000 $3,000
2012 $41,000 $4,000
2013 $44,000 $4,000
Ths program is only a small change from our curent program and only reduces our maitenance
requirements by a small percentage. The benefits of the program come in the out years as the
system begins to age further and stars to really benefit our customers out in 2014. Compared to
our curent case, it has an Internal Rate of Retu to our customers of8.8% due to their avoided
costs associated with power outages and durations.
ER 2280 Substation Circuit Switchers
Substation Circuit Switchers are used like Circuit Breakers in a Substation to provide isolation
and protection for Substation Transformers and are located on the High Voltage side of the
transformer. Some Circuit switchers are used to control capacitor bans in larger substations that
provide voltage support on the system. They are normally located on smaller and more rual
types of substations except when they are used to control capacitor bans.
Figue 11 shows the age profile for our approximately 120 Circuit Switchers used thoughout our
system.
.
.
.
Staff PR 103 Attchment A Page 6 of12
Figure 11, Substation Circuit Switcher Age Profile
29% ? 30 Years Old
2% ? 40 Years Old
Substation Circuit Switchers
40
35
."30.!"i 25-
U).5 20i.
CI.c 15E::Z 10
5
0
0 5 10 15 20 25 30 35 40 45 50
Age (Years)
Our revised plan is to perform periodic testing, inspection, and maintenance on the Circuit
Switchers to ensure their timing of operations are within specifications, lubricate the mechanical
linkages, and identify when a Circuit Switcher must be replaced. Circuit Switchers are also
inspected as par of the month Substation Inspection Program that identifies when a Circuit
Switcher's Interrpter does not have enough SF6 gas for futue operations and must be replaced
or refilled with gas depending upon the design. The program outlines an inspection program that
is time based and varies with the age of the Circuit Switcher. The inspection cycle vares from
11 years for a new one and reduces to a 5 year cycle for the oldest circuit switchers. This wil
result in approximately 20 Circuit Switcher Inspects per year. Based on the inspections, we
anticipate that 2 Circuit Switcher Interrpters wil need to be replaced each year, and two new
Circuit Switchers wil be needed to replace old ones over then next 10 years.
Ths work wil be performed by our own workforce since it is performed inside our existing
substations. Table 10 shows the Capital and O&M Budget projects for the work. The resources
needed are 600 man-hours of Electrcian and 200 man-hours of Rela.y Technician support to
complete on average each year.
The benefits of this program come from several areas. The program is anticipated to save
~$45,000 anually in O&M costs and ~$16,000 in Capital costs durg the first 10 years by
reducing the number of unplaned outages and extending the life of the existing equipment.
Compared to the current case, the planed maintenance case has an Internal Rate of Retu of
10% and saves our customers ~$180,000 in avoided costs due to outages.
.
.
.
Staff_PR_103 Attachment A Page 7 of12
T bl 10 C' 't S 't h B d t P . tionsae,ircUl Wi c er U life roiec
5 Year Budaet
Year Capital O&M
2009 $67,000 $104,000
2010 $0 $108,000
2011 $0 $112,000
2012 $0 $116,000
2013 $0 $120,000
ER 2294 System - Batteries
This budget item covers the replacement and maintenance on all Substation batteres. The range
of batteres covers from 24 vdc to 125 vdc and can be located in battery rooms or specific
equipment. We analyzed not only the capital budget needs, but also the O&M Budget needs to
develop the budget requirements shown in Table 14, Substation Battery Budget Projections.
However, a decision was made to put the analysis on these batteries on hold until a batteryan
was in place, and testing batteries, before going ahead with any recommendations. So, the
current budget requirements wil be based on historical spending levels adjusted for inflation
until furter analysis has been completed.
T bl 14 S b ti B tt B d P . tionsae,u sta on a ery U llfet rO.jec
O&M
Year Capital Costs Costs
2009 $106,000 $181,000
2010 $115,000 $187,000
2011 $156,000 $193,000
2012 $113,000 $200,000
2013 $95,000 $207,000
ER 2425 Substation High Voltage Fuse Replacements
About 60 of our smaller substations use power fuses to provide protection for substation
transformers instead of relays. Of these 60 substations, 18 have High Voltage Power Fuses that
are no longer rated to handle the currently available maximum fault curents and 14 of this group
average about 50 years old and no longer have spare pars. Approximately, 21 % are more than
40 years old. Four of the substations have a fault duty curent that exceeds all types of fuses and
must be replaced by a Circuit Switcher.
Figure 15 shows an estimated age of the Power Fuses based on the age of the substation.
Based on Avista's analysis, Power Fuses should also be replaced every 40 years, because they
become uneliable and not supported with spare pars. The Power Fuse AM Plan wil replace an
average of 5 fuse installations each year until 18 underrated Power Fuses are removed from the
system. Those requirng a Circuit Switcher will be replaced at the end of the replacement of the
StafCPR_I03 Attchment A Page 8 ofl2
.18 underrated Power Fuses. Once all of the underrated fues have been replaced, A vista wil
continue to replace the remaining as they reach approximately 40 years of age or are no longer
supported with spare pars.
Figure 15, Power Fuse Age Profie Estimate
6-"
CD-5CO
E.--
U)4CD-".!3ñi-
U)c:2~
CD.Q
1E.::Z
0
.
Power Fuse Age Profile
18 Power Fuses are installed in systems 21%;; 40 Years Old
that exced their fault capacity
~-_..
Ti niIIn I~ ~ ~~~~~~~~~~~~~~
Age (Years)
.
.
.
Staff_PR_103 Attachment A
Figure 16, Power Fuse Cumulative Cost Projections
Page 9 of12
80000000
70000000IIco~ 60000000
CD
i 50000000..
8 40000000
CD::~
'5
E::o
30000000
20000000
10000000
0 r-..ID m C'r-C;ID m C'r-iñ ID0..0 0 N N C'C'oq oq ID00000000000NNNNNNNNNNNNN
Year
- Power Fuse - Base
Case
- Power Fuse - Planned
Case
-- Power Fuse -
Optimized Case
The resources required to complete the work is shown in Table 13, Power Fuse Replacement
Capital Budget Projections. The labor resources require are listed below:
. Substation Engineer - 50 man-hours
. Substation Electrician - 210 man-hours
. Linemen - 60 man-hours
For installng and removing the mobile substation anually to support the work, Avista projects
we wil use the following additional resources:
. Electrcians - 600 man-hours
. Communications Techncian - 20 man-hours
. Equipment Operator - 75 man-hours
. Substation Engineer - 60 man-hours
The benefits of this program includes improved reliabilty due to replacing these unreliable
Power Fuses with new and more reliable fuses and greatly reducing the risk of damaging the
Power Transformer the fuse tres to protect. A vista estimates that the plan wil save our
customers approximately $55,000 per year in avoided costs due to power outages caused by
Power Fuse failure. Figure 16 shows the cumulative cost benefit of the planed replacement
program.
.
.
.
Staff PR 103 Attchment A Page 10 of12
Table 13, Power Fuse Replacement Capital Budget Projections
Capital
Year Costs
2009 $297,000
2010 $275,333
2011 $253,571
2012 $237,875
2013 $220,556
ER 2449 System - Replace Substation Air Switches
This program covers the planed and unplaned replacement of Substation Air Switches. Air
Switches used in the Transmission System located outside of a substation are covered by ER
2254 discussed above. The analysis used for this budget item was an earlier model and wil need
to be updated in the futue ifthe need arises. However, we anticipated that the use of an
integrated Substation analysis wil provide futue direction on what should be done to replace
Substation Air Switches. The integrated approach wil more accurately reflect the best
opportty to use a planed approach since our switches are best replaced when the substation is
rebuilt or undergoing a major upgrade. Table 15, Sub Air Switches Projected Budget, provides
the basis analysis and estimated needs to address Ai Switches that fail each year.
T bl 15 S b Ai S 't h P 'ected Budgetae,u r wi c es ro
Year Capital Costs
2009 $114,000
2010 $122,000
2011 $140,000
2012 $156,000
2013 $157,000
ER 2416 System - Porcelain Cutout Replacements
A program was implemented in 2007 and scheduled to be completed in 2008 to replace all of the
Chance cutouts in the system. This program should address the immediate issues with the
broader category of Porcelain Cutouts. However, we anticipate the other styles of porcelain
cutouts to star failing prematuely in the near futue and have seen some early indication of this.
However, until mòre data is gathered, we plan on monitoring the data and develop a new plan in
the futue when the information warants another look.
StafCPR_103 Attachment A Page 11 of12
. ER 2254 Transmission Air Switches
The transmission air switches have been replaced at a steady but modest pace durng recent
years. The average capital expenditue has averaged about $100,000 per year durg the past 3
years. Ths translates to changing or refubishing 3-4 switches per year. The curent 115kV Air
Switch inventory consists of370 operational units.
There are some switches also installed on the 230kV and 60kV systems, however, the
preponderance of Air Switches are installed on the 115kV system.
80 air switches are being fit with grounding platforms for worker safety durng 2008. During
this process a new worm gear handle is installed and disconnecting whips are adjusted.
Operating pivot joints of the switch mechansms are not affected by this work. In short, the 2008
work is safety related, not switch mechansm related.
Avista has an inventory listing of Transmission Air Switches that lists the location and type of
switch. Information regarding age of the equipment is not complete but a general age profile can
be observed.
.115kV Air Switch Age Profile
10
5
o
~Ç) ~O: ~'ò fblö ~Ç) ~l: ~A" fbÇ) fbO: fblö fbOJ 2)1) 2)~ 2)'ò ~" ~l:~~~~~~~~~~~~~~~~
Year Installed
Information
regarding
equipment age
is for 298 of 370
total air switches.
As of 5/29/2008
35
30
25
~:ø 20c
tV
:: 15a
.At this time, there is not a distubing trend in Air Switch failure. However, as seen in the age
profie, a bow-wave of aging switches wil begin to approach during the coming decade.
.
.
.
StafCPR_I03 Attchment A Page 12 ofl2
Transmission outage cause tracking is being improved at this time. The improved information
wil allow tracking of failure trends for the air switch population.
A VISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
. JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
AVU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-l 04
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04/14/2009
Scott Kinney
Scott Kinney/Rodney Pickett
Transmission Operations/Elec. Eng.
[phone]
REQUEST:
Please provide the level ofO&M expenses incurred for the Company's distrbution asset
management program for the years 2004 though 2008. What anual distrbution O&M
expenditues, in excess of those for asset management, were incurred for the years 2004 though
2008?What were the anual distrbution O&M expenditues prior to the Asset Management Plan
for the years 2000 though 2003?
RESPONSE:
.
Prior to 2005, the Asset Management Expenses were not isolated from other expenses, so are not
readily available for 2004.
Table 1 shows the Distrbution Asset Management actual anual O&M expenditures (system)
broken down into major areas for the years 2005-2008.
Table 2 shows the actual anual Total O&M (excluding the amounts provided in Table 1 for Asset
Management) expenditues (system) for the years 2005-2008.
Table 2 Other O&M Distribution Ex enses for 2005-2008 (System).
Response to Staff Request No. 349
Page 2
Table 3 shows the actual anual Total O&M expenditues (system) for the years 2005-2008
. (combining Tables 1 & 2).
Table 3
":jj~çtì.a1\fQ(!!~n05:j. .*F~l:tQaljfQt¡'~nn~l A!!~iâì.âl;¡fôrj2nn"AK;~tyalfQ(1~ØØai(t
$21,239,624 $22,569,058 $22,486,704 $26,064,830
Table 4 shows the actual anual Total O&M expenditues (system) for the years 2000-2004.
$14,032,377 $15,849,519 $14,320,185
Table
Please see attachment "StafCPR _104 Attachment A - Asset Mgmt Dist Exp.xls" for detal of the
above tables.
.
.
.
.
.
Asset Management - O&M Electrical Distribution Expenses
Total for Avista
Elect Dist Ops Elect Dist Maint Elect Dist
Source Year FERC 580-589 FERC 590-599 Total
Discoverer 2008 12,666,551 13,398,279 26,064,830
(FERC Form not
completed)
FERC Form 1/30 2007 10,586,452 11,900,252 22,486,704
p.322
FERC Form 1/30 2006 9,942,254 12,626,804 22,569,058
p.322
FERC Form 1/30 2005 10,746,520 10,493,104 21,239,624
p.322
FERC Form 1/30 2004 10,114,406 8,993,627 19,108,033
p.322
FERC Form 1/30 2003 8,790,007 7,749,109 16,539,116
p.322
FERC Form 1/30 2002 7,833,894 6,486,291 14,320,185
p.322
FERC Form 1/30 2001 7,413,641 8,435,878 15,849,519
p.322
FERC Form 1/30 2000 5,226,901 8,805,476 14,032,377
p.322
StafCPR_104 Attachment A - Asset Mgmt Dist Exp.xls
DistAsset
Mgmt Dist
(Pickett)Balance
5,921,445 20,143,385
5,261,325 17,225,379
4,824,721 17,744,337
4,351,161 16,888,463
Page1 of 1
.
.
.
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
AVU-E-09-01 I AVU-G-09-01
IPUC
Production Request
Staff-l 05
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/14/2009
Scott Kinney
Liz Andrews
State & Federal Reg.
[phone]
Isn't the Network Management plan described on page 36 of Mr. Kinney's testimony for the city of
Spokane directly assigned to the Washington electrc jursdiction? Ifnot, why not?
RESPONSE:
Yes, as shown in Ms. Andrews workpapers section PF9-4, the 114,000 was directly assigned to
Washington.
.
.
.
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-l 06
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/14/2009
Don Kopczynski
Jason Thackston
State & Federal Reg.
[phone]
Has the Company applied for federal funding under the American Recovery and Reinvestment Act?
If not, why not? If so, please descrbe the amount of fuding sought and the proposed purpose.
RESPONSE:
The recently enacted federal stimulus package contains many tax-related and funding provisions that
may be beneficial to existing and potential projects at Avista. We are currently evaluating those
provisions and developing a plan to take advantage of the opportnities in the stimulus package
where appropriate, but that evaluation is not yet complete. We have retained a consultat, Booz &
Company, to assist the Company in that regard. The stimulus package encompasses transmission
projects, wind generation, and energy effciency measures, all of which are included in our curent
and proposed projects. Avista wil continue to examine the possibilities to paricipate in the federal
stimulus package and wil provide updated information as it becomes available.
.
.
.
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
AVU-E-09-01 I AVU-G-09-01
IPUC
Production Request
Staff-l 08
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04117/2009
Don Kopczynski
Amanda Reinhardt
Customer Service
[phone]
In response to Staff Production Request No. 24, Avista reported its actual servce level in
December of 2008 was 66.10%. Please explain the reason( s) for the low servce leveL.
RESPONSE:
Durng December 2008, the Coeur d' Alene area experenced approximately 85 inches of snowfall
in a two-week perod. The heavy snowfall increased electrc outage calls, and in addition in some
cases agents were unable to make it to work for their scheduled shifts due to heavy snowfalL.
Overall, higher than expected call volumes for the available agents staffed resulted in a negative
impact to service level for December 2008. In December 2008 the Company experienced 6,456
CSR outage calls, nearly double the number of outage calls compared to December 2007.
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-l 09
REQUEST:
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04114/2009
Don Kopczynski
Amanda Reinhardt
Customer Serce
[phone]
For the year 2008 please provide by month the number of e-mails received by the Customer
Service Center.
RESPONSE:
Customer emails received each month.
Jan 3809
Feb 2973
Mar 3208
Apr 2548
May 3108
Jun 2703
Jul 2553
Aug 2254
Sep 2360
Oct 2239
Nov 1834
Dec 1957
Total 31546
.
.
.
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
A VISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-110
DATE PREPARD:
WITNESS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/20/2009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
Please provide Cost of Service results based on the Company's filing with the following change:
increase all Residential class coincident peak allocators by 10%.
RESPONSE:
Please see attached Excel worksheet labeled "Staff PR 110 Attachment A". Please note that
increasing the Residential class coincident peak without changing any other schedules caused the
Idaho total system peak to exceed the recorded Idaho total system peak for the test perod.
.Sumc AVISTA UTILITES Idaho Jurisdiction
Scenario: Company Base Case Cost of Servce Baic Summary Eleric Utilit 04/14/09
Producton Reques No. 110 For the Twelve Months Ended Sepember 30, 2008
(b)(c)(d)(e)(I)(g)(h)(i)OJ (k)(I)(m)
Residential General Large Gen Extra Larg Extra Large Pumping Stree &
System Servce Service Servce Gen Servce Service Potlatch Servce Area Lights
Description Total Sc 1 Sch 11-2 Sch21-22 Sch25 Sch 25P Sch 31-32 Sch 41-49
Plant In Servce
1 Prouction Plant 373,731,000 138,942,810 36,972,139 73,982,991 31,642,573 85,147,493 5,872,60 1,170,390
2 Trasmission Plant 160,359,00 58,72,33 15,728,701 31,903,621 13,68,081 37,249,093 2,551,931 523,237
3 Distribution Plant 391,018,00 197,358,427 61,571,178 91,36,302 10,733,997 2,156,60 8,513,166 19,32,328
4 Intgible Plant 39,605,00 16,03,426 4,176,826 7,454,248 3,019,615 8,040,146 628,001 250,738
5 General Plant 61,178,00 32,708,147 7,96,651 9,311,830 2,80,388 6,412,870 958,328 1,016,786
6 Total Plant In Servce 1,025,891 ,00 443,767,146 126,414,496 214,016,992 61,88,652 139,00,20 18,524,030 22,281,481
Accm Deprecati
7 Producton Plant (146,687,00)(54,231,518)(14,46,60)(29,091,729)(12,454,350)(33,661,475)(2,315,83)(466,491)
8 Transmission Plat (55,nO,00)(20,422,581)(5,470,162)(11,095,510)(4,757,68)(12,954,570)(887,516)(181,973)
9 Distribuon Plant (121,422,00)(60,62,702)(17,696,227)(28,258,437)(3,147,094)(689,459)(2,423,039)(8,585,042)
10 Intangible Plant (6,504,00)(3,237,529)(801,147)(1,056,459)(354,274)(863,215)(102,251)(89,126)
11 Genera Plant (26,764,00)(14,30,079)(3,484,793)(4,073,716)(1,226,857)(2,805,466)(419,247)(444,821)
12 Tota Accmulated Deprecon (357,147,000)( 152,823,409)(41,917,937)(73,575,851 )(21,94,263)(50,974,205)(6,147,88)(9,767,453)
13 Net Plant 68,744,00 290,943,737 84,496,559 140,41,141 39,940,390 88,031,999 12,376,147 12,514,028
14 Accmulated Deferre FIT (94,m,00)(40,511,780)(11,392,984)(19,364,622)(5,88,715)(13,611,805)(1,670,08)(1,840,00)
15 Miscellaneous Rate Bae 2,967,00 651,523 231,893 766,114 337,485 919,450 51,551 8,984
16 Total Rate Base 5n,434,00 251 ,083,480 73,335,468 121,842,63 34,392,160 75,339,643 10,757,614 10,683,00
17 Revenue From Retail Rates 220,252,000 86,358,00 27,841,000 46,634,00 14,497,00 37,941,00 4,139,00 2,842,00
18 Other Operating Revenues 32,90,000 12,414,853 3,33,758 6,568,693 2,704,405 7,184,160 526,387 170,744
19 Total Revenues 253,160,00 98,n2,853 31,179,758 53,202,69 17,201,405 45,125,160 4,665,387 3,012,744.Operating Expnses
20 Production Expense 132,634,00 47,872,437 12,90,991 26,511,83 11,395,160 31,365,640 2,135,763 449,178
21 Transmission Expnses 8,348,00 3,056,979 818,808 1,66,845 712,160 1,939,120 132,849 27,239
22 Distribuion Expnses 9,626,00 4,628,565 1,334,788 2,266,359 325,069 68,90 183,439 818,875
23 Customer Accnting Expense 3,484,00 2,571,225 566,133 159,263 37,127 96,155 44,220 9,878
24 Customer Information Expenses 1,537,000 68,374 167,00 256,61 108,399 291,626 22,862 4,274
25 Sales Expses 235,00 78,937 21,975 48,021 20,867 60,270 3,995 934
26 Admin & Genera Expeses 21,605,00 11,239,590 2,798,404 3,454,03 1,029,200 2,36,246 347,08 372,437
27 Tota O&M Expnse m,469,00 70,134,107 18,611,102 34,356,815 13,62,982 36,185,963 2,870,216 1,682,815
28 Taxes Oter Than Income Taxes 8,751,00 3,582,203 1,012,146 1,819,537 595,874 1,442,572 153,490 145,178
29 Other Income Related Items (106,00)(44,248)(11,217)(20,122)(8,17)(20,286)(1,492)(218)
Deprecation Expse
30 Prouction Plant Deprecation 9,335,00 3,497,987 927,63 1,843,042 787,198 2,104,851 145,697 28,587
31 Transmission Plant Deprecation 3,232,00 1,183,536 317,00 64,010 275,719 750,747 51,434 10,56
32 Distribuion Plant Deprecation 10,048,00 4,965,162 1,601,384 2,459,029 30,220 51,900 226,182 438,121
33 General Plan Depreation 4,867,00 2,602,08 633,705 740,80 223,102 510,174 76,240 80,89
34 Amortizatin Expense 2,256,00 83,552 223,154 446,623 191,027 514,120 35,456 7,069
35 T otaf Depreciation Expense 29,738,00 13,087,324 3,702,891 6,132,504 1,783,267 3,931,792 535,00 56,213
36 Incoe Tax 6,445,00 1,316,2n 1,92,52 2,433,945 23,931 388,032 265,938 94,354
37 Total Operating Expnses 22,297,00 88,075,66 25,237,442 44,722,68 16,022,638 41,928,074 3,823,161 2,487,342
38 Net Income 30,863,00 10,697,189 5,942,316 8,480,014 1,178,767 3,197,086 842,226 525,402
39 Rate of Return 5.34%4.26%8.10%6.96%3.43%4.24%7.83%4.92%
40 Return Ratio 1.00 0.80 1.52 1.30 0.64 0.79 1.46 0.92
41 Interest Expense 19,055,00 8,285,615 2,420,030 4,020,739 1,134,922 2,486,166 354,995 352,533
File: 1009 Elec Case / Elec COS PR110 / Sumcot Exhibit Page 1 of 3
.
StafCPR_110 Attachment A.xls Page 1 of 3
Sumct AVISTA UTILITIES Idah Junsdcton
Scenano: Company Bae Case Revenue to Cost by Functional Component Summary Elecne Utilit 04/14/09
Production Reque No. 110 For the Twelve Month Ended September 30, 200.(b)(e)(eI (e)(I)(g)(h)(i)Ol (k)(I)(m)
Residential Genera LargeGen Extra Larg Extra Large Pumping Stree &
System Service Servce Servce Gen Servce Servce Potlatch Servce AreaUght
Desnption Tota Sch 1 Sch 11.12 Sch 21.22 Sch25 Seh 25P Sch 31.32 Sch41.49
Functional Cost Components at Current Return by Schedule
1 Producton 135,477,62 47,773,63 14,169,323 28,285,871 11,142,452 31,327,049 2,323,208 456,081
2 Trasmission 16,120,216 5,440,508 1,987,485 3,711,38 1,167,456 3,445,549 316,33 51,496
3 Disnbuion 43,403,590 19,869,717 8,225,301 10,672,291 1,06,649 567,419 1,085,276 1,916,937
4 Common 25,250,572 13,274,137 3,458,891 3,96,450 1,120,442 2,60,982 414,183 417,486
5 Total Current Rate Revenue 220,252,00 86,358,000 27,841,00 46,63,00 14,497,000 37,941,00 4,139,00 2,842,00
Expressed as $/kWh
6 Production $0.038 $0.04113 $0.0438 $0.03995 $0.03547 $0.03451 $0.03952 $0.0318
7 Transmission $0.0062 $0.0068 $0.0015 $0.00524 $0.00372 $0.00 $0.00 $0.0075
8 Distnbuon $0.01245 $0.0171 $0.02544 $0.01507 $0.0034 $0.003 $0.01846 $0.13944
9 Comm $0.00724 $0.01143 $0.01070 $0.0060 $0.00357 $0.00286 $0.00705 $0.0337
10 Total Current Melde Rates $0.06316 $0.07435 $0.0810 $0.06587 $0.04614 $0.04179 $0.07040 $020674
Functional Cost Components at Uniform Current Return
11 Production 136,108,108 49,141,470 13,244,269 27,203,573 11,691,897 32,175,149 2,191,163 460,588
12 Transmission 16,382,662 5,999,215 1,60,88 3,259,351 1,397,590 3,805,57 260,711 53,455
13 Distnbuion 42,44,209 21,910,502 6,551,38 9,260,974 1,271,753 596,130 875,38 1,978,08
14 Common 25,317,020 13,537,338 3,295,867 3,852,861 1,160,343 2,653,38 396,518 420,705
15 Total Unifonn Current Cost 220,252,00 90,588,526 24,698,400 43,576,759 15,521,583 39,230,124 3,723,775 2,912,83
Expressed as $/k
16 Proucton $0.039 $0.04231 $0.04096 $0.032 $0.03721 $0.03 $0.03727 $0.0330
17 Trasmission $0.0070 $0.00517 $0.0097 $0.00 $0.0045 $0.0019 $0.003 $0.009
18 Distnbuon $0.01217 $0.01886 $0.02026 $0.01308 $0.005 $0.00 $0.01489 $0.14389
19 Common $0.00726 $0.01165 $0.01019 $0.00 $0.00369 $0.0092 $0.0074 $0.0306
20 Total Current Unifonn Melde Rates $0.06316 $0.077 $0.0763 $0.06155 $0.04940 $0.04321 $0.0634 $0.21189
21 Revenue to Cost Ratio at Current Rates tOO 0.95 1.13 1.07 0.93 0.97 1.11 0.96.Functional Cost Components at Proposed Return by Scheule
22 Proucton 148,00,278 51,743,605 15,195,126 30,588,989 12,428,385 35,073,022 2,501,285 475,865
23 Transmision 21,337,956 7,06,182 2,409,568 4,673,376 1,706,091 5,035,294 391,349 60,098
24 Oistnbution 55,345,280 25,793,194 10,081,64 13,675,732 1,546,700 694,235 1,38,359 2,185,417
25 Common 26,795,486 14,038,019 3,63,663 4,201,903 1,213,825 2,832,449 438,007 431,821
26 Total Propo Rate Revenue 251,485,00 98,637,00 31,326,00 53,140,00 16,895,00 43,63,000 4,699,00 3,153,00
Expresse as $/kWh
27 Production $0.04244 $0.04455 $0.04699 $0.04320 $0.03956 $0.0383 $0.04255 $0.03462
28 Trasmission $0.0012 $0.008 $0.00745 $0.00 $0.00543 $0.00555 $0.0068 $0.0037
29 Distnbution $0.01587 $0.02221 $0.03118 $0.01932 $0.0092 $0.0076 $0.02328 $0.15897
30 Common $0.00768 $0.01209 $0.01126 $0.00593 $0.006 $0.00312 $0.00745 $0.03140
31 Total Propose Melded Rates $0.07211 $0.0892 $0.09 $0.07505 $0.05378 $0.04 $0.0799 $0.22936
Functional Cost Components at Uniform Requested Return
32 Producion 147,899,815 53,532,39 14,411,860 29,536,570 12,689,445 34,855,99 2,376,197 497,348
33 Tranmission 21,280,678 7,79,834 2,087,30 4,233,817 1,815,435 4,943,196 338,658 69,437
34 Oisnbution 55,407,201 28,462,040 8,66,298 12,303,379 1,64,152 686,888 1,169,523 2,476,921
35 Common 26,897,30 14,38,221 3,501,627 4,09,395 1,232,783 2,819,039 421,272 446,970
36'Total Unifonn Cos 251,485,00 104,169,490 28,66,08 50,167,161 17,381,815 43,305,122 4,305,650 3,490,676
Expresed as $/kWh
37 Producton $0.04241 $0.0460 $0.0457 $0.04172 $0.0439 $0.03839 $0.04042 $0.03618
38 Transmission $0.0010 $0.0071 $0.0064 $0.0098 $0.0078 $0.00 $0.0076 $0.0005
39 Oistnbuton $0.01589 $0.02450 $0.0268 $0.01738 $0.003 $0.0076 $0.01989 $0.18018
40 Common $0.0077 $0.01238 $0.01083 $0.0078 $0.00 $0.00311 $0.0071 $0.03251
41 Total Unifonn Melded Rates $0.07211 $0.088 $0.08865 $0.07086 $0.05533 $0.04770 $0.07324 $0.25392
42 Revenue to Cost Ratio at Proposed Rates 1.00 0.95 1.09 1.06 0.97 1.01 1.09 0.90
43 Currnt Revenue to Proposed Cost Ratio 0.88 0.83 0.97 0.93 0.83 0.88 0.96 0.81.File: iO 09 Elee Case / Elec COS PR110 / Sumcst Exhibit Page 2 of 3
StafCPR_110 Attachment A.xls Page 2 of 3
.Sumcst AVISTA UTILITIES Idaho Jurisdiction
Scenario: Compay Bae Case Revenue to Cos By Classnicaon Summar Electri Utilit 04/1410
Production Reques No. 110 For the Twelve Months Ended September 30, 200
(b)(c)(d)(e)(f)(g)(h)(i)OJ (k)(I)(m)
Residenial Genera Large Gen Extra Large Extra Large Pumping Stree &
System Servce Service Servce Gen Serv Seice Potatch Serce Area Ughts
Description Tot Sch 1 Sc 11-12 Sch 21.22 Sch25 Sch25P Sch 31.32 Sch 41-49
Cost Classificaions at Current Reurn by Schedule
1 Energy 112,574,719 36,932,63 11,33,885 24,08,603 9,54,505 28,186,205 2,047,107 44,776
2 Demand 88,013,932 36,139,96 12,549,36 21,919,536 4,943,681 9,753,873 1,732,297 975,219
3 Customer 19,66,349 13,285,397 3,957,755 63,861 6,814 92 359,596 1,422,005
4 Total Current Rate Revenue 220,252,000 86,358,00 27,841,00 46,63,00 14,497,00 37,941,00 4,139,00 2,842,00
Expressed as Unit Cos
5 Energy $IkWh $0.03228 $0.03180 $0.0305 $0.034 $0.03039 $0.03105 $0.03482 $0.03235
6 Demand $lW/mo $10.87 $11.62 $13.04 $11.60 $8.50 $7.11 $12.18 $23.51
7 Customer $1CusVmo $13.62 $11.23 $17.45 $36.52 $47.32 $76.79 $23.29 $952.45
Cost Classifications at Uniform Current Return
8 Energ 113,127,00 37,99,770 10,578,351 23,116,841 10,045,287 29,013,641 1,923,372 449,747
9 Demand 87,455,196 38,63,561 10,723,103 19,912,819 5,467,633 10,215,426 1,497,865 1,00,790
10 Customer 19,669,795 13,956,195 3,39,945 547,09 8,863 1,057 302,539 1,457,296
11 Total Unnorm Current Cos 220,252,00 90,588,526 24,698,400 43,576,759 15,521,583 39,230,124 3,723,775 2,912,832
Expresed as Unit Cos
12 Energy $IkWh $0.03244 $0.0372 $0.03272 $0.03265 $0.03197 $0.03196 $0.03272 $0.03272
13 Demand $IkW/mo $10.80 $12.43 $11.14 $10.54 $9.40 $7.44 $10.53 $2425
14 Customer $ICusVmo $13.62 $11.80 $14.98 $31.67 $60.16 $88.t1 $19.59 $976.9.15 Revenue to Cost Ratio at Currnt Rates 1.00 0.95 1.13 1.07 0.93 0.97 1.11 0.98
Cost Classifications at Proposed Return by Schedule
16 Energy 123,577,80 40,029,861 12,171,706 26,140,872 10,713,870 31,840,925 2,213,978 466,597
17 Deman 105,259,858 43,374,763 14,574,620 26,190,013 6,169,988 11,792,554 2,048,472 1,109,447
18 Cusomer 22,647,33 15,232,376 4,579,673 809,115 11,142 1,521 436,549 1,576,956
19 Total Propoed Rate Revenue 251,485,00 98,637,00 31,326,00 53,140,00 16,895,00 43,63,00 4,699,00 3,153,00
Expressed as Unit Cos
20 Energ $IkWh $0.03544 $0.0346 $0.03764 $0.0362 $0.0310 $0.03507 $0.03786 $0.033
21 Demand $IkW/mo $13.00 $13.95 $15.14 $13.86 $10.61 $8.59 $14.40 $26.74
22 Customer $ICusVmo $15.69 $12.88 $20.19 $46.84 $77.38 $126.77 $28.27 $1,05.23
Cost Classifications at Uniform Requested Return
23 Energy 123,325,286 41,425,408 11,531,978 25,200,799 10,950,859 31,629,189 2,09,762 490,291
24 Demd 105,076,407 46,63,467 13,028,285 24,238,697 6,418,935 11,674,446 1,826,390 1,255,187
25 Customer 23,083,307 16,109,616 4,104,823 727,666 12,021 1,486 382,498 1,745,198
26 Total Unnor Cost 251,485,00 104,169,490 28,665,086 50,167,161 17,381,815 43,305,122 4,305,650 3,490,676
Expressed as Unit Cost
27 Energy $IkWh $0.03536 $0.03567 $0.03567 $0.03559 $0.03486 $0.03484 $0.0367 $0.03567
28 Demand $lW/mo $12.97 $15.00 $13.53 $12.83 $11.04 $8.50 $12.84 $30.26
29 Customer $1CusVmo $15.99 $13.62 $18.10 $42.13 $83.48 $123.87 $24.77 $1,168.92
30 Revenue to Cost Ratio at Proposed Rates 1.00 0.95 1.09 1.06 0.97 1.01 1.09 0.90
31 Current Revenue to Proposed Cost Ratio 0.88 0.83 0.97 0.93 0.83 0.88 0.96 0.81
File: ID 09 Ele Case 1 Elec COS PR11 0 1 Sumco Exhibits Page 30f3.
StafCPR_110 Attachment A.xls Page 3 of 3
.
.
.
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
A VISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-111
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/20/2009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
Please provide Cost of Servce results based on the Company's filing with the following change:
increase all Residential class Non-coincident peak allocators by 10%.
RESPONSE:
Please see attached Excel worksheet labeled "Staff PR 111 Attachment A"
.Sumct AVISTA UTILITIES Idaho Jurisdiction
Scnario: Company Bae Case Cost of Serv Baic Summary Electri Utilit 04/14/09
Production Request No. 111 For the Twelve Mont Ended September 30, 200
(b)(c)(d)(e)(Q (g)(h)(I)OJ (k)(I)(m)
Resideal General largeGen Extra Lage Extra large Pumping Street &
System Servce Servce Service Gen Servce Servce Potatch Servce Area Lights
Desription Total Sch 1 Sch 11.12 Sch 21-22 Sch25 Sch25P Sch31.32 Sch 41-49
Plant In Serv
1 Production Plant 373,731,00 135,227,560 37,650,169 75,194,994 32,149,197 86,36,517 5,962,243 1,183,321
2 Transmission Plant 160,359,00 57,376,17 15,974,374 32,342,77 13,863,648 37,689,700 2,584,411 527,923
3 Disribution Plant 391 ,018,00 204,237,985 59,358,09 87,128,781 10,731,417 2,150,511 8,186,249 19,224,96
4 Intangible Plan 39,60,00 15,782,495 4,217,405 7,524,89 3,059,635 8,136,208 633,163 251,199
5 Genera Plan 61,178,000 32,729,489 7,924,226 9,225,071 2,838,668 6,95,162 951,491 1,013,891
6 Total Plant In Servce 1,025,891,00 445,353,702 125,124,267 211,416,512 62,642,565 140,835,097 18,317,558 22,201,299
Accm Deprecaton
7 Producion Plant (146,687,00)(52,857,182)(14,716,23)(29,540,070)(12,641,759)(34,111,303)(2,348,989)(471,275)
8 Trasmission Plant (55,770,000)(19,954,410)(5,555,602)(11,248,239)(4,821,529)(13,107,805)(898,812)(183,60)
9 Distribuon Plant (121,422,00)(62,818,00)(16,986,521 )(26,90,257)(3,147,094)(689,459)(2,318,201)(8,55,460)
10 Intangible Plant (6,50,00)(3,227,48)(799,861)(1,053,105)(358,734)(873,920)(101,968)(88,927)
11 General Plant (26,764,000)(14,318,416)(3,466,671)(4,03,761)(1,241,854)(2,841,488)(416,256)(443,555)
12 Tot Accmulated Depreciation (357,147,00)(153,175,500)(41,525,078)(72,785,433)(22,210,970)(51 ,623,975)(6,084,226)(9,741,818)
13 Net Plant 668,744,000 292,178,20 83,599,189 138,631,079 40,431,595 89,211,122 12,233,332 12,459,481
14 Accmulated Deferred FI (94,27,00)(40,535,582)(11 ,307,897)(19,188,697)(5,961,431)(13,793,554)(1,655,938)(1,833,901)
15 Miscelaneo Rate Base 2,967,00 614,403 238,82 778,553 342,393 931,232 52,473 9,124
16 Total Rate Bae 577,434,00 252,257,023 72,530,114 120,220,935 34,812,557 76,34,80 10,629,866 10,634,704
17 Revenue From Retl Rates 220,252,00 86,358,00 27,841,00 46,634,00 14,497,00 37,941,00 4,139,00 2,842,00
18 Other Operaing Revenue 32,90,00 12,131,413 3,38,920 6,653,743 2,746,539 7,285,294 532,626 171,465
19 Total Revenues 253,160,00 98,489,413 31,227,920 53,287,743 17,243,539 45,226,294 4,671,626 3,013,465.Operaing Expse
20 Producton Expnses 132,634,00 46,952,246 13,071,92 26,812,020 11,520,641 31,66,824 2,157,96 452,38
21 Transmission Expnse 8,348,00 2,986,90 831,597 1,683,706 721,716 1,96,058 134,540 27,48
22 Distribuion Expse 9,626,00 4,803,418 1,279,532 2,158,269 324,782 68,229 175,276 816,494
23 Customer Accnting Expenses 3,484,00 2,571,225 566,133 159,263 37,127 96,155 44,220 9,878
24 Customer Inforation Expnses 1,537,00 673,650 169,327 260,612 110,134 295,791 23,169 4,319
25 Sales Exp 235,00 78,937 21,975 48,021 20,867 60,270 3,995 934
26 Admin & Genera Expenses 21,605,00 11,259,647 2,780,752 3,417,875 1,040,290 2,39,870 34,249 371,317
27 Tot O&M Expnses 17,469,00 69,326,023 18,721,240 34,539,765 13,775,557 36,540,196 2,883,414 1,68,805
28 Taxes Oter Than Incoe Taxes 8,751,00 3,572,068 1,007,807 1,809,972 603,30 1,460,404 152,69 144,752
29 Oter Income Related Items (106,00)(41,853)(11,655)(20,903)(8,744)(21,069)(1,550)(226)
Deprecation Expense
30 Production Plant Depreciation 9,335,00 3,397,56 945,96 1,875,801 80,89 2,137,719 148,120 28,936
31 Tramissio Plant Depreciation 3,232,00 1,156,404 321,96 651,861 279,419 759,628 52,08 10,640
32 Distribuion Plant Depreciaton 10,048,00 5,149,33 1,542,270 2,345,252 30,220 51,90 217,450 435,574
33 General Plant Deprecation 4,867,00 2,60,786 630,410 733,898 225,83 516,721 75,696 80,660
34 Amortzaon Expense 2,256,00 816,17 227,239 453,924 194,079 521,45 35,99 7,147
35 Tota Deprecation Expnse 29,738,00 13,123,263 3,667,843 6,06,736 1,80,40 3,987,412 529,350 562,957
36 Income Tax 6,445,00 1,477,894 1,924,083 2,47,268 (28,887)261,247 267,269 96,125
37 Total Operating Expnses 222,297,00 87,457,396 25,30,319 44,836,837 16,147,66 42,228,190 3,831,17 2,486,413
38 Net Incoe 30,863,00 11,032,018 5,918,601 8,450,907 1,095,870 2,998,104 840,449 527,052
39 Rate 01 Return 5.34%4.37%8.16%7.03%3.15%3.93%7.91%4.96%
40 Return Ratio 1.00 0.82 1.53 1.32 0.59 0.73 1.48 0.93
41 Interest Expese 19,055,00 8,324,341 2,393,453 3,967,224 1,148,795 2,519,468 350,78 350,939
File: ID 09 Ele Case 1 Elec COS PRllll Sumct Exhibi Page 1 of 3
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StafCPR_l11 Attachment A.xls Page 1 of 3
.Sumèo AVISTA UTILITIES Idaho Jurisdiction
Scenario: Company Base Case Revenue to Cos By Classifcaion Summar Eleric Utilit 0414/09
Proucton Request No. 111 For the Twele Months Ended September 30, 200
(b)(c)(d)(e)(I)(g)(h)(i)ül (k)(I)(m)
Residential Genera Large Goo Extra Large Extra Large Pumping Street &
Sysem Servce Servce Servce Gen Servce Servce Po1latch Servce Area Ught
Descrpton Total Sch 1 Sch 11.12 Sc21.22 Sc25 Sch 25P Sch 31.32 Sch41.49
Cost Classificaions at Current Return by Schedule
1 Energy 112,436,854 37,043,748 11,349,575 24,125,311 9,473,794 27,948,248 2,050,961 445,217
2 Demd 88,062,09 35,959,011 12,522,024 21,874,215 5,016,661 9,991,870 1,726,66 971,647
3 Customer 19,753,052 13,355,241 3,96,401 63,474 6,545 88 361,373 1,425,136
4 Tot Current Rate Revenue 220,252,00 86,358,00 27,641,00 46,634,00 14,497,00 37,941,000 4,139,00 2,642,00
Expresed as Unit Cost
5 Energ $/Wh $0.034 $0.03189 $0.03510 $0.03407 $0.0315 $0.03078 $0.0349 $0.0339
6 Demand $/W/mo $10.47 $10.51 $13.0 $11.58 $8.63 $7.28 $12.14 $23.42
7 Customer $1ustrn $13.68 $11.29 $17.50 $36.73 $45.45 $73.54 $23.40 $954.54
Cot Classificaions at Uniform Current Reurn
8 Energ 113,127,00 37,999,770 10,578,351 23,116,641 10,045,287 29,013,641 1,923,372 449,747
9 Demd 87,455,196 38,209,791 10,693,070 19,823,371 5,631,342 10,608,391 1,490,017 99,215
10 Customer 19,669,795 13,956,195 3,396,945 547,099 8,663 1,057 302,539 1,457,296
11 Tot Unifonn Current Cost 220,252,00 90,165,755 24,66,366 43,487,311 15,68,293 39,623,089 3,715,928 2,908,258
Expressed as Unit Cos
12 Energ $/kWh $0.0344 $0.03272 $0.03272 $0.03265 $0.03197 $0.03196 $0.03272 $0.03272
13 Demand $//mo $10.40 $11.17 $11.11 $10.49 $9.68 $7.73 $10.48 $24.09
14 Customer $/CusVmo $13.82 $11.80 $14.98 $31.67 $60.16 $88.11 $19.59 $976.09.15 Revenue to Cost Ratio at Current Rate 1.00 0.96 1.13 1.07 0.92 0.96 1.11 0.98
Cost Classifications at Proposed Return by Schedule .
16 Energy 123,402,289 40,126,561 12,196,700 26,210,333 10,627,062 31,554,659 2,219,838 467,137
17 Demand 105,343,855 43,217,278 14,531,074 26,114,534 6,257,117 12,078,867 2,039,911 1,105,073
18 Cusomer 22,738,856 15,293,161 4,598,225 815,133 10,820 1,474 439,251 1,580,790
19 Total Proped Rate Revenue 251,485,00 98,637,00 31,326,00 53,140,00 16,895,00 43,635,00 4,69,00 3,153,00
Expresed as Unit Cost
20 Energy $/kWh $0.0338 $0.0355 $0.0377 $0.03702 $0.03383 $0.0376 $0.03776 $0.038
21 Demad $/W/rn $12.53 $12.64 $15.09 $13.82 $10.76 $8.80 $14.34 $26.64
22 Customer $ICustmo $15.75 $12.93 $20.27 $47.19 $75.14 $122.85 $28.45 $1,058.80
Cost Classificaions at Uniform Requested Return
23 Energy 123,325,286 41,425,408 11,531,978 25,200,799 10,950,859 31,629,189 2,09,762 490,291
24 Demand 105,076,407 46,275,178 12,954,66 24,061,529 6,805,38 12,121,99 1,811,63 1,246,00
25 Customer 23,08,307 16,109,616 4,104,823 727,66 12,021 1,486 38,498 1,745,198
26 Total Unifonn Cost 251,485,00 103,810,201 28,591,48 49,989,993 17,568,263 43,752,672 4,290,89 3,481,489
Expresed as Unit Cost
27 Energy $/Wh $0.03536 $0.03567 $0.037 $0.0359 $0.03486 $0.034 $0.03567 $0.03567
28 Demand $/W/mo $12.49 $13.53 $13.46 $12.74 $11.36 $8.83 $12.74 $30.04
29 Customer $1usVmo $15.99 $13.62 $18.10 $42.13 $83.48 $123.87 $24.77 $1,168.92
30 Revenue to Cost Ratio at Proposed Rates 1.00 0.95 1.0 1.06 0.96 1.00 1.0 0.91
31 Current Revenue to Proposed Cost Ratio 0.88 0.83 0.97 0.93 0.83 0.87 0.96 0.82
File: ID 09 Elec Case 1 Eiec COS PRllll Sumco Exhibits Page 30t3.
StatCPR_111 Attachment A.xls Page 30f 3
.
.
.
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
A VU-E-09-01 I A VU-G-09-01
IPUC
Production Request
Staff-H2
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/20/2009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
Please provide Cost of Servce results based on the Company's filing with the following change:
increase all Residential class coincident and Non-coincident peak allocators by 10%.
RESPONSE:
Please see attached Excel worksheet labeled "Staff PR 112 Attachment A". Please note that
increasing the Residential class coincident peak without changing any other schedules caused the
Idaho total system peak to exceed the recorded Idaho total system peak for the test period.
.Sumco AVISTA UTILITIES Idao Juridiction
Scario: Company Base Case Cos of Servce Baic Summary Elecric Utilit 04/14/09
Producton Request No. 112 For the Twelve Months Ended September 30, 2008
(b)(c)(d)(e)(I)(g)(h)(i)0)(k)(I)(m)
Residential General Large Gen Extra Large Extra Lage Pumping Street &
System Servce Serv Servce Gen Servce Servce Potlatch Service AreaUghts
Descripton Tota Sch 1 Sch 11-12 Sch 21-22 Sch25 Sch 25P Sch 31-32 Sci 41-49
Plan In Servce
1 Producton Plan 373,731,00 138,942,810 36,972,139 73,982,991 31,642,573 85,147,493 5,872,60 1,170,390
2 Trasmission Plan 160,359,00 58,722,336 15,728,701 31,90,621 13,68,081 37,249,093 2,551,931 523,237
3 Distributon Plan 391,018,00 204,237,985 59,358,092 87,128,781 10,731,417 2,150,511 8,186,249 19,224,96
4 Intagible Plan 39,60,000 16,076,264 4,163,793 7,429,06 3,019,576 8,040,055 626,076 250,17
5 General Plant 61,178,00 32,982,785 7,878,00 9,142,440 2,80,128 6,412,257 945,38 1,013,00
6 Total Plant In Servce 1,025,891,00 450,96,179 124,100,726 209,586,894 61,877,774 138,99,409 18,182,239 22,181,779
Accm Deprecation
7 Production Plan (146,687,00)(54,231,518)(14,465,608)(29,091,729)(12,454,350)(33,661,475)(2,315,830)(46,491)
8 Transmission Plan (55,770,00)(20,422,581)(5,470,162)(11,095,510)(4,757,68)(12,954,570)(887,516)(181,973)
9 Distributon Plant (121,422,00)(62,818,008)(16,986,521)(26,908,257)(3,147,09)(689,459)(2,318,201)(8,554,460)
10 Intangible Pla (6,504,00)(3,260,347)(793,86)(1 ,042,38)(354,253)(86,164)(101,175)(88,812)
11 Gener Plant (26,764,00)(14,429,227)(3,46,448)(3,999,612)(1,226,743)(2,805,218)(413,582)(443,169)
12 Tota Acmulated Depreciation (357,147,00)(155,161,681)(41,162,602)(72,137,493)(21,940,128)(50,973,886)(6,036,30)(9,734,905)
13 Net Plan 668,744,00 295,60,498 82,938,124 137,449,401 39,937,646 88,025,523 12,145,935 12,44,873
14 Accmulated Deferred FIT (94,277,00)(41,092,604)(11,20,241)(19,00,983)(5,885,474)(13,611,237)(1,642,499)(1,831,962)
15 Miscellaneous Rate Base 2,967,00 650,39 232,254 766,812 337,486 919,452 51,60 8,999
16 Tot Rate Bae 577,434,00 255,358,287 71,96,137 119,209,230 34,38,658 75,333,738 10,555,040 10,623,910
17 Revenue From Retail Rates 220,252,00 86,358,00 27,841,00 46,63,00 14,497,00 37,941,00 4,139,00 2,842,00
18 Oter Operating Revenues 32,908,00 12,440,470 3,330,517 6,552,92 2,704,395 7,184,138 525,169 170,38
19 Total Revenues 253,160,00 98,798,470 31,17,517 53,186,922 17,201,395 45,125,138 4,66,169 3,012,389.Operating Expenses
20 Prodcton Expses 132,634,00 47,872,437 12,903,991 26,511,832 11,395,160 31,365,640 2,135,763 449,178
21 Trasmission Expenses 8,348,00 3,056,979 818,808 1,66,845 712,160 1,939,120 132,849 27,239
22 Distribuon Expenses 9,626,00 4,80,418 1,279,532 2,158,269 324,782 68,22 17,276 816,494
23 Customer Acntng Expenses 3,484,00 2,571,225 566,133 159,263 37,127 96,155 44,220 9,878
24 Customer Information Expses 1,537,00 68,374 167,005 256,461 108,399 291,626 22,862 4,274
25 Sales Expses 235,00 78,937 21,975 48,021 20,867 60,270 3,99 934
26 Admin & General Exnses 21,605,00 11,341,60 2,765,795 3,391,138 1,029,115 2,36,045 342,271 371,032
27 Total O&M Expenses 17,469,00 70,410,975 18,523,237 34,185,828 13,627,610 36,185,085 2,857,236 1,679,028
28 Taxes Oter Than Incoe Taxes 8,751,00 3,626,671 997,842 1,792,159 595,857 1,42,532 151,377 144,562
29 Other Income Related Items (106,00)(44,248)(11,217)(20,122)(8,17)(20,286)(1,492)(218)
Deprecation Expense
30 Productio Plan Deprecation 9,335,00 3,497,987 927,638 1,843,042 787,198 2,104,851 145,697 28,587
31 Trasmission Plant Depreciaton 3,232,00 1,183,536 317,00 643,010 275,719 750,747 51,434 10,546
32 Distributon Plant Deprecation 10,048,00 5,149,33 1,542,270 2,345,252 306,220 51,90 217,450 435,574
33 General Plant Deprecation 4,867,00 2,623,937 626,732 727,324 223,082 510,125 75,209 80,590
34 Amortization Expense 2,256,00 838,552 223,154 446,623 191,027 514,120 35,456 7,069
35 Tot Deprecation Expese 29,738,00 13,293,345 3,636,803 6,005,251 1,783,247 3,931,743 525,246 562,365
36 Inco Tax 6,445,00 1,08,307 1,995,00 2,574,03 24,102 38,434 276,645 97,478
37 Tot Operating Expenses 222,297,00 88,376,049 25,141,665 44,537,150 16,02,398 41,927,509 3,80,013 2,48,215
38 Net Income 30,863,000 10,422,420 6,029,852 8,649,772 1,178,997 3,197,629 855,157 529,174
39 Rate of Return 5.34%4.08%8.38%7.26%3.43%4.24%8.10%4.98%
40 Return Ratio 1.00 0.76 1.57 1.36 0.64 0.79 1.52 0.93
41 Interes Expnse 19,055,00 8,26,681 2,374,776 3,933,83 1,134,840 2,485,971 348,310 350,583
File: 1009 Elec Case 1 Elec COS PR1121 Surncot Exhibits Page 1 of 3
.
StafCPR_112 Attachment A.xls Page 1 of 3
Sumco AVISTA UTILITIES Idaho Junsdiction
Scenano: Compay Bae Case Revenue to Cos by Functonal Component Summary Elecnc Utility 04/14/09
Production Reques No. 112 For the Twelve Monts Ended September 30, 200.(b)(c)(d)(e)(~(g)(h)(i)OJ (k)(I)(m)
Residential General LargeGen Ext Large Extra Large Pumping Street &
System Servce Servce Service Gen Servce Servce Potlatch Serv AreaUghts
Descnption Total Sch 1 Sch 11-2 Sch 21.22 Sch25 Sc25P Sch31.32 Sc41-9
Functional Cost Components at Current Return by Schedule
1 Production 135,559,235 47,547,959 14,261,90 28,484,342 11,142,715 31,327,86 2,337,706 456,745
2 Transmission 16,155,873 5,348,327 2,025,579 3,794,284 1,167,566 3,45,893 32,440 51,785
3 Distnbuion 43,297,68 20,119,943 8,116,54 10,442,950 1,066,361 566,484 1,06,35 1,917,06
4 Common 25,239,213 13,341,77 3,436,967 3,912,425 1,120,35 2,600,784 410,501 416,407
5 Total Current Rate Revenue 220,252,00 86,358,00 27,841,00 46,63,00 14,497,00 37,941,00 4,139,00 2,842,000
Expressed as $/kWh
6 Proucton $0.03887 $0.0409 $0.0411 $0.0423 $0.03547 $0.03451 $0.03976 $0.03323
7 Trasmission $0.0063 $0.0060 $0.0026 $0.00536 $0.0072 $0.0038 $0.00548 $0.0077
8 Distributon $0.01242 $0.01732 $0.02510 $0.01475 $0.00339 $0.00 $0.01817 $0.1395
9 Common $0.00724 $0.01149 $0.0106 $0.00553 $0.00357 $0.0086 $0.008 $0.0309
10 Tot Current Melded Rates $0.06316 $0.07435 $0.08610 $0.06587 $0.04614 $0.04179 $0.07040 $0.20674
Functional Cost Components at Uniform Current Return
11 Prouction 136,108,108 49,141,470 13,244,269 27,203,573 11,691,897 32,175,149 2,191,163 460,588
12 Tramission 16,382,66 5,99,215 1,60,88 3,259,351 1,397,590 3,805,457 260,711 53,455
13 Distnbution 42,44,209 22,578,774 6,337,763 8,84,619 1,271,296 595,051 84,827 1,96,879
14 Common 25,317,020 13,650,972 3,259,600 3,782,775 1,160,236 2,653,135 391,160 419,143
15 Total Unfform Current Cos 220,252,00 91,370,32 24,448,514 43,09,317 15,521,019 39,228,791 3,686,86 2,902,065
Expresed as $/kWh
16 Production $0.0390 $0.04231 $0.0409 $0.0382 $0.03721 $0.0344 $0.03727 $0.03350
17 Transmission $0.0070 $0.00517 $0.0097 $0.0060 $0.0045 $0.0019 $0.0043 $0.00389
18 Distributon $0.01217 $0.01944 $0.01960 $0.01250 $0.0045 $0.00 $0.01435 $0.1432
19 Common $0.00726 $0.0117 $0.0100 $0.0053 $0.00369 $0.00 $0.005 $0.03049
20 Total Current Unfform Melded Rates $0.063t6 $0.07867 $0.07561 $0.06087 $0.04940 $0.0432t $0.0671 $0.2111t
21 Revenue to Cost Ratio at Current Rates 1.00 0.95 1.14 1.08 0.93 0.97 1.12 0.98.Functional Cost Component at Proposed Return by Schedule
22 Proucton 148,095,772 51,451,463 15,307,260 30,83,340 12,428,741 35,074,126 2,519,201 476,63
23 Trasmiion 21,377,410 6,942,854 2,455,703 4,m,521 1,706,240 5,035,762 398,896 60,43
24 Distnbuion 55,231,77 26,143,513 9,94,879 13,373,430 1,546,281 692,865 1,346,49 2,185,359
25 Common 26,780,043 14,09,170 3,619,158 4,150,708 1,213,73 2,832,246 434,454 430,56
26 Total Propoed Rate Revenue 251,485,00 98,637,00 31,326,00 53,140,00 16,895,00 43,635,00 4,699,00 3,153,00
Expressed as $/kWh
27 Production $0.04247 $0.0430 $0.04734 $0.04356 $0.03956 $0.0363 $0.04285 $0.037
28 Trasmission $0.0013 $0.00598 $0.00759 $0.0075 $0.003 $0.00555 $0.0079 $0.0040
29 Distnbution $0.01584 $0.02251 $0.03075 $0.01889 $0.0092 $0.0076 $0.02290 $0.15897
30 Common $0.00768 $0.01214 $0.01119 $0.0086 $0.0038 $0.00312 $0.00739 $0.03132
31 Total Proposed Melded Rates $0.07211 $0.08492 $0.0968 $0.07505 $0.05378 $0.0480 $0.0793 $0.22936
Functional Cost Components at Uniform Requested Return
32 Producton 147,89,815 53,532,395 14,411,860 29,536,570 12,68,445 34,855,999 2,376,197 497,348
33 Transmission 21,280,678 7,792,834 2,087,300 4,233,817 1,815,435 4,943,196 338,658 69,437
34 Distnbuton 55,407,201 29,354,445 8,378,766 11,752,956 1,643,566 685,505 1,127,344 2,464,617
35 Common 26,897,30 14,502,949 3,46,09 4,018,933 t,232,669 2,818,769 415,580 445,310
36 Total Unfform Cost 251,485,00 105,182,623 28,341,024 49,542,277 17,381,115 43,303,470 4,257,779 3,476,712
Expressed as $/kWh
37 Producton $0.04241 $0.0409 $0.04457 $0.04172 $0.04039 $0.03839 $0.04042 $0.0318
38 Transmission $0.00610 $0.0071 $0.00 $0.00598 $0.0078 $0.005 $0.00576 $0.00505
39 Distnbution $0.01589 $0.02527 $0.02591 $0.01660 $0.00523 $0.0076 $0.01918 $0.17928
40 Common $0.0077 $0.01249 $0.01071 $0.00568 $0.00392 $0.00310 $0.00707 $0.03239
41 Total Unfform Melded Rates $0.07211 $0.09056 $0.08765 $0.06997 $0.05532 $0.04770 $0.07242 $0.25291
42 Revenue to Cost Ratio at Proposd Rates 1.00 0.94 1.11 1.07 0.97 1.01 1.0 0.91
43 Current Revenue to Proposed Cost Ratio 0.88 0.82 0.98 0.94 0.83 0.88 0.97 0.82.File: ID 09 Elec Case 1 Elec COS PR1121 Sumct Exhibits Page 20f3
StafCPR_112 Attachment A.xls Page 20f3