20161021Harvey Direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR
AUTHORITY TO INCREASE ITS RATES
FOR ELECTRIC SERVICE TO RECOVER
COSTS ASSOCIATED WITH THE NORTH
VALMY POWER PLANT.
CASE NO. IPC-E-16-24
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
TOM HARVEY
1 Q. Please state your name, business address, and
2 present position with Idaho Power Company ("Idaho Power" or
3 "Company") .
4
5
A. My name is Torn Harvey and my business address
is 1221 West Idaho Street, Boise, Idaho 83702. I am
6 employed by Idaho Power as the Resource Planning and
7 Operations Director in the Power Supply Department.
8
9
10
Q.
A.
Please describe your educational background.
I have a Bachelor of Business Administration
in business management from Boise State University. I also
11 attended the University of Idaho's Utility Executive Course
12 in 2011.
13 Q. Please describe your work experience with
14 Idaho Power.
15
16
17
A. I was hired by Idaho Power in July 1980 to
work in the Plant Accounting Department. I continued
working in the accounting area through 1985. From 1985
18 through 2009, I was the Fuels Management Coordinator and
19 then was promoted to the Joint Projects Manager. In April
20 2015, I was promoted to my current position, Resource
21 Planning and Operations Director. My current
22 responsibilities include supervision over Idaho Power's
23 jointly owned coal assets, integrated resource planning,
24 cloud seeding program, river engineering, strearnflow
25 gaging, and operations hydrology.
HARVEY, DI 1
Idaho Power Company
1 Q. What is the purpose of your testimony in this
2 case?
3 A. The purpose of my testimony is to discuss the
4 prudence of investments made at the North Valmy power plant
5 ("Valmy") that have added to the associated plant balances
6 since the Company's last depreciation rate update became
7 effective on June 1, 2012, and to inform the Idaho Public
8 Utilities Commission of necessary future investments at the
9 plant to ensure Valmy continues to be available for
10 reliable load service through the end of 2025 . My
11 testimony also presents Valmy's current position in the
12 Company's generation portfolio and the results of an
13 analysis performed by Idaho Power that supports the
14 proposed depreciable life at Valmy reflecting an end-of-
15 life date as of December 31, 2025.
16
17
Q.
A.
Please describe the Valmy plant.
Valmy is a coal-fired power plant that
18 consists of two units and is located near Winnemucca,
19 Nevada. Unit 1 went in service in 1981 and Unit 2 followed
20 in 1985. Idaho Power owns 50 percent, or 284 megawatts1
21 ("MW") (generator nameplate rating), of Valmy. NV Energy
22 also has 50 percent ownership and is the operator of the
23 Valmy facility. Idaho Power and NV Energy work jointly to
24 make decisions regarding any environmental investment,
1 For planning purpo ses, Idaho Power uses the ne t dependable
ca p a b ility of 262 MW.
HARVEY, DI 2
Idaho Power Company
-----------------------------------------------
1 plant retirement, or conversion . The plant is connected
2 via a single 345 kilovolt transmission line to the Idaho
3 Power control area at the Midpoint substation. Idaho Power
4 has the northbound capacity and NV Energy has the
5 southbound capacity of this line.
6 Coal for the plant is shipped via railroad from
7 various mines in Utah , Wyoming, and Colorado. The power
8 plant uses a variety of emissions control technologies,
9 including state-of-the-art fabric filters that remove more
10 than 99 percent of particulate emissions. Additionally , a
11 Dry Sorbent Injection ("DSiu) system has been installed on
12 Unit 1 to reduce acid gas emissions and flue-gas scrubber
13 technology is utilized on Unit 2 for the reduction of
14 sulfur dioxide emissions.
15
16
I . VALMY OPERATIONS AND INVESTMENTS SINCE 2011
Q. Company witness Matthew Larkin states in his
17 direct testimony that the current depreciable life at the
18 Valmy plant reflects a 2031 end-of-life for Unit 1 and a
19 2035 end-of -life for Unit 2. What resource planning
20 analyses did the Company prepare based on the 2031 and 2035
21 end-of-life assumptions for Valmy approved in the last
22 depreciation study?
23 A. A 2031 end-of-life for Unit 1 and a 2035 end -
24 of-life for Unit 2 was used in the Idaho Power prepared
25 Coal Unit Environmental Investment Analysis for the Jim
HARVEY , DI 3
Idaho Power Company
1 Bridger and North Valmy Coal-Fired Power Plants ("2013 Coal
2 Study") . This analysis guided Idaho Power's Valmy-related
3 decisions until the preferred p o r t folio selected as part of
4 the 2 015 Integrated Resource Plan ("IRP") concluded that a
5 2025 end-of-life assumption for Valmy would provide a more
6 favorable economic outcome as compared to the previous
7 operating life assumptions.
8 The analysis performed for the 2013 Coal Study
9 examined future investments required for environmental
10 compliance at existing coal units and compared those
11 inv estments to the costs of two alternatives: ( 1)
12 replacing such units with combined cycle combustion turbine
13 units or (2 ) converting the existing coal units to natural
14 gas. The 2013 Coal Study was inc luded as an exhibit to my
15 testimony in Case No. IPC-E-13-16.2
16 Q. What was the result of the analysis for Valmy
17 in the 2013 Coal Study?
18 A. At the time the study was prepared, it was
19 determined that continued operati o n of Unit 1 until 2031
2 0 and Unit 2 through 2035 was economi c , with the only notable
21 env ironmental investment required at Valmy being to install
22 OSI for compliance with the Mercury and Air Toxic Standards
23 ("MATS") regulation on Unit 1. Valmy is not subject to the
2 Idaho Power 's Application for a Certificate of Public
Convenience and Necessity for the Investment in Selective Catalytic
Reduction Controls on Jim Bridger Units 3 and 4 .
HARVEY, DI 4
Idaho Power Company
1 Regional Haze Best Available Retrofit Technology ("RH
2 BART") regulations; therefore, no additional controls were
3 required for compliance with the RH BART regulations.
4 Idaho Power concluded that installation of the OSI system
5 was a low-cost approach to retain a diversified portfolio
6 of generation assets for customers and that continued
7 operation of Unit 1 would provide fuel diversity, helping
8 to mitigate risk associated with natural gas prices. Thus,
9 the Company continued to include Valmy in its generation
10 portfolio for the 2013 IRP and future resource planning.
11 Q. Please describe the operations of Valmy as
12 identified in the preferred portfolio analyzed in the 2013
13 IRP.
14 A. Although Idaho Power analyzed ceasing
15 operations at Valmy in 2021 and 2025 as part of the 2013
16 IRP, the preferred resource portfolio included continued
17 operations of the Valmy coal facility in full compliance
18 with environmental regulations through the 2013 IRP
1 9 planning period (2013-2032). Consistent with the
20 assumptions appl ied in the 2013 Coal Study, continued coal
21 operations were expected to require advanced financial
22 commitment in 2012 for the installation of OSI emission
23 control systems, approximately three years prior to their
24 installation and operation .
25
HARVEY, DI 5
Idaho Power Company
1 Q. Did Idaho Power commit financially and
2 subsequently install the DSI emission control systems
3 required at Valmy?
4 A. Yes. In 2012, Idaho Power committed
5 financially to the OSI investments required on Unit 1 to
6 meet the MATS regulation. Installation of the required
7 emission control systems was complete in the spring of
8 2015.
9 Q. With the DSI emission control system
10 investments completed on Unit 1, are both units at Valmy in
11 compliance with all known environmental regulations?
12 A. Yes. However, subsequent to the 2013 Coal
13 Study, it was determined that because of the existing
14 condition of the scrubber on Unit 2 , the scrubber would
15 need to be upgraded to meet the acid gas portion of the
16 MATS regulation. The scrubber upgrade on Unit 2 was
17 completed in 2015. With existing investments, Valmy is in
18 compliance with all current environmental regulations.
19 Q. Are there any future environmental regulations
20 that could affect Valmy?
21 A. At this time there are three environmental
22 regulations that have the potential to affect Valmy in the
23 future: the National Ambient Air Quality Standards
24 ("NAAQS"), Regional Haze, and the Federal Environmental
25 Protection Agency's Clean Air Act Section lll(d)
HARVEY, DI 6
Idaho Power Company
1 ("11 1 (d) "). All impact areas for NAAQS are in attainment
2 and the state of Nevada is well below the Reasonable
3 Progress glide slope under the Regional Haze regulation so
4 no additional controls are anticipated at this time .
5 Finally , although there is still uncertainty around the
6 effect of final regulation related to lll(d), it is
7 anticipated that Valmy will be able to meet all targets set
8 by the final rule .
9 Q. Idaho Power 's last general rate case used a
10 2011 test year as a basis for plant values , which included
11 $148 million in Valmy-related plant . However, Mr . Larkin
12 indicated t h at current Valmy plant balances as of July 31 ,
13 2016 , are approximately $217 million . Please explain what
14 is driving the approximately $70 million increase in the
1 5 Valmy balances from the 2011 test year to July 31 , 2016.
16 A. There have been a number of investments
17 required at Valmy over the last four and a half years to
18 ensure the plant remains operational in a safe , efficient ,
19 and reliable manner , including investments required to
20 ensure environmental compliance as well as a number of
21 investments for routine maintenance and repair .
22 Q. Have you prepared an exhibit detailing the
23 investments made since the last general rate case?
24 A. Yes . Exhibit No . 4 details the investments
25 made at Valmy since the last general rate case , including
HARVEY , DI 7
I daho Power Company
1 the investment by year and a classification as to whether
2 the investment was for environmental compliance, the safe
3 and economic operation of the plant, or for reliability
4 purposes. Exhibit No. 4 also includes a description and
5 justification for each of the investments.
6 Q. Does Idaho Power perform a review of the
7 planned capital projects prior to any investments being
8 made at Valmy?
9 A. Yes. For all planned capital projects, Idaho
10 Power receives from the plant operator, NV Energy, a
11 description of the project, the factors driving the need
12 for the project, and a recommendation for the work to be
13 performed.
14 Q. Were all of the projects comprising the
15 approximately $70 million in investment that occurred
16 between the 2011 test year and July 31, 2016, necessary for
17 either environmental compliance, the safe and economic
18 operation of the plant, or for reliability purposes?
19
20
A.
Q.
Yes.
Please describe the investments made for
21 environmental compliance since 2011.
22 A. The investments made for environmental
23 compliance include OSI installation and coal pipe
24 replacement on Unit 1, the scrubber upgrade on Unit 2, the
25 coal crusher belt feeder project, dust collector upgrade,
HARVEY, DI 8
Idaho Power Company
1 caustic tank building replacement , evaporation pond liner
2 replacement , bed demineralizer replacement , and the coal
3 combustion residual compliance project.
4 Q. What investments were made for the safe ,
5 reliable , and economic operation of the plant?
6 A . To maintain the safe and reliable operation of
7 the plant, the cooling towers on both units were replaced ,
8 the circulating water lines were recoated , the
9 mechanical/electrical shop was redesigned for increased
10 productivity, and the cathodic protection system was
11 upgraded. In addition, Unit 1 required the replacement of
12 the reheat tube and secondary tube sections of the boiler
13 and the sootblower system . Similarly , it was essential
14 that Unit 2 undergo a rebuild of the bottom ash hydrobin, a
15 burner and primary air duct replacement, a generator phase
16 end turn design betterment project , steam valve hardening ,
17 and a primary superheat lower loop replacement . The
18 capital investments made at Val my since the last rate case
19 were prudent and essential for continued operation of the
20 plant.
21
22
23 Q.
II. VALMY'S POSITION IN IDAHO POWER'S
GENERATION PORTFOLIO
Please describe the preferred portfolio
24 identified in the Company's 2015 IRP as it relates to Valmy
25 operations .
HARVEY, DI 9
Idaho Power Company
1 A. Idaho Power analyzed a variety of retirement
2 dates for Valmy as part of the Company's 2015 IRP. Results
3 consistently indicated favorable economics associated with
4 two significant resource actions: the Boardman to
5 Hemingway ("B2H") transmission line and the early
6 retirement of Valmy. The preferred portfolio selected for
7 the 2015-2034 planning horizon contained both actions in
8 the year 2025, with completion of the B2H transmission line
9 preceding the end-of-year coal plant retirement.
10 Q. What were the factors driving the 2025 Valmy
11 end-of-life in the 2015 IRP preferred portfolio?
12 A. The preferred portfolio selected as part of
13 the 2015 IRP process contained no other resource additions
14 through the end of the 2020s. In addition to the absence
15 of resource needs, the resource sufficiency through the
16 early 2020s shielded the preferred portfolio from risk
17 exposure associated with the following near-term
18 uncertainties identified: planned but yet-to-be-built
19 Public Utility Regulatory Policies Act of 1978 (PURPA)
20 solar facilities, lll(d)'s proposed regulations, the
21 completion date of B2H, and the alignment of Valmy's early
22 retirement date with NV Energy.
23 Q. What was the action plan for Valmy's 2025 end-
24 of-life date as identified in Idaho Power's 2015 IRP?
25
HARVEY, DI 10
Idaho Power Company
1 A. The 2015-2018 action plan recognized in the
2 2015 IRP included ongoing permitting, planning studies, and
3 regulatory filings associated with the B2H transmission
4 line during all four years, and indicated, in 2016, Idaho
5 Power would work with NV Energy to synchronize depreciation
6 dates and determine if a date could be established to cease
7 coal-fired operations. This filing will synchronize
8 depreciation rates between the two companies.
9 Q. How have changes in market energy prices in
10 recent years impacted the value of Idaho Power's surplus
11 energy or "off-system" sales?
12 A. In 2011, the average price Idaho Power
13 recei ved for off-system sales was $22.71 per MW compared to
14 2015 when the average price Idaho Power received for off-
15 system sales was only $11.82 per MW. Moreover, year-to-
16 date 2016, Idaho Power's average price for off-system sales
17 is only $8.76 per MW.
18 Q. How does the decrease in the average price for
19 off-system sales impact Valmy operations?
20 A. The significant decrease in market prices has
21 resulted in a decrease in the number of hours Valmy
22 operates economically, as the dispatch cost is now
23 typi c ally higher than the market price. The following
24 chart details the decrease in Idaho Power's capacity factor
25 at Valmy over the last eight years as a result of the
HARVEY, DI 11
Idaho Power Company
1 decrea s e in market prices . NV Energy is experiencing a
2 similar trend in its share of Valmy generation .
3
4
5
Year Idaho Power's
Dispa tched
Capacit y Factor
2008 7 6%
2009 7 2%
2010 6 4%
2011 2 9%
2012 2 7%
20 1 3 4 9%
2014 4 1 %
2015 1 5%
Rather than a resource used to generate off-system
6 sales , Idaho Power has been relying on Valmy to meet the
7 Company 's peak energy needs , preserving the balanced
8 portfolio needed to reliably serve Idaho Power customers
9 during all types of system conditions. For example , when
10 extreme cold weather or extreme hot temperatures occur in
11 the West raising market prices , Valmy is available to
12 provide reliab l e energy and capacity to serve I daho Power 's
13 customers . Absent Valmy's generation , the Company woul d be
14 required to rely on market purchases on non-firm
15 transmission , which may not be available to serve the load .
16 Q. If Valmy is currently being used to he l p Idaho
17 Power reliably serve load , why is the Company proposing a
18 2025 end-of-life?
19 A . As shown in the preferred portfolio of Idaho
20 Power 's 2015 IRP , the economics of Valmy's operation are
HARVEY , DI 1 2
Idaho Power Company
1 impacted in the long term, as new resources such as B2H or
2 other operating facilities are available to maintain the
3 balanced portfolio required to serve load reliably.
4 Q. Absent B2H, is it feasible to discontinue
5 operations prior to 2025?
6 A. No. As previously stated, Idaho Power relies
7 on Valmy to meet peak energy needs and to preserve the
8 balanced portfolio needed to reliably serve customers
9 during all types of system conditions. When extreme cold
10 weather or extreme hot temperatures occur in the West,
11 Valmy is providing reliable energy and capacity to serve
12 customers . The Company's peak-hour load and resource
13 balance analysis included on page 96 of the Company 's 2015
14 IRP demonstrates that Idaho Power would have peak-hour
15 capacity deficits beginning in 2020 if Valmy were retired
16 in 2019. A copy of the 2015 peak-hour analysis is provided
17 as Exhibit No. 5. As can be seen in Table 7.5 of Exhibit
18 No. 5 under the line labeled "Valmy Retire Units 1 and 2
19 Year-End 2019," peak-hour deficits without Valmy generation
20 capacity grow from 24 MW in 2020 to 236 MW by 2024.
21 Q. Please provide an example of how Valmy is
22 currently being used to balance Idaho Power 's portfolio and
23 reliably serve customers.
24 A. In the summers of 2015 and 2016, Idaho Power's
25 loads exceeded 2900 MW, resulting in market purchases
HARVEY, DI 13
Idaho Power Company
1 between 300 to 500 MW to cover load while Valmy was
2 economically displaced by the market purchases and
3 operating at minimum levels. As the temperatures and load
4 continued to rise , wind generation decreased and Idaho
5 Power was unable to import additional market purchases to
6 cover the load due to transmission constraints . During
7 these hot afternoon time periods, Valmy was dispatched at
8 or near capacity. Another example occurred in the fall and
9 winter of 2014 and 2015. Valmy was dispatched during the
10 Langley Gulch power plant maintenance outages as Fall
11 Chinook spawning flows restricted hydro generation and
12 there was not sufficient transmission capacity to reliably
13 serve load with market purchases. Idaho Power will
14 continue to rely on Valmy during similar circumstances in
15 the future as load increases in the Company's service
16 territory and until the addition of new resources that are
17 available during peak hours or can provide additional
18 transmission capacity.
19
20 Q.
III . CESSATION OF VALMY OPERATIONS
Have Idaho Power and NV Energy agreed to a
21 date to cease coal-fired operations at Valmy?
22 A. No. However, Idaho Power and NV Energy
23 continue discussions working towards a mutually agreed upon
24
25
closure date . Synchronized depreciation dates for
HARVEY , DI 14
Idaho Power Company
1 ratemaking purposes will help in establishing a date to
2 cease coal-fired operations.
3 Q. In his testimony, Company witness Mr. Larkin
4 discusses the use of a 2025 depreciable end-of-life date by
5 NV Energy for both units at the Valmy plant. Would it be
6 feasible for Idaho Power to continue to utilize Valmy
7 beyond 2025 if NV Energy was no longer an ownership
8 partner?
9 A. No. If NV Energy establishes a closure date
10 of 2025, Idaho Power's continued utilization of Valmy
11 beyond 2025 would require negotiation with NV Energy to
12 modify or terminate the existing Agreement for the
13 Ownership of the North Valmy Power Plant Project
14 ("Ownership Agreement"). In addition, the Agreement for
15 the Operation of the North Valmy Power Plant Project
16 ("Operation Agreement") would require nullification as it
17 identifies NV Energy as the operator of Valmy. Absent the
18 acquisition of a new operating partner or Idaho Power
19 acquiring or developing the skills and experience to
20 operate a coal-fired plant, it would be impractical for
21 Idaho Power to continue operating the plant after 2025
22 without NV Energy.
23 Q. Has Idaho Power performed any additional
24 analyses associated with the Valmy end-of-life date since
25 the 2015 IRP was completed?
HARVEY, DI 15
Idaho Power Company
1 A. Yes. In 2016, Idaho Power assessed the
2 continued use of the 2025 end-of-life assumption for Valmy
3 using an updated evaluation of the present value revenue
4 requirement of operating period alternatives.
5 Q. How did the Company analyze the potential
6 revenue requirement impact of modifying the Valmy end-of-
7 life date?
8 A. To determine the potential revenue requirement
9 impact, Idaho Power analyzed the present value revenue
10 requirement of two operating period alternatives: (1) the
11 2025 end-of-life for both units and (2) the existing 2031
12 and 2034 3 staggered end-of-life assumptions. The operating
13 period alternatives used under the revenue requirement
14 scenarios consisted of the following two components: ( 1)
15 net present value ("NPV") revenue requirement associated
16 with the existing investment, additional run rate capital,
17 fixed operation and maintenance ("O&M") expenses, and
18 forecasted taxes and insurance and (2) the total variable
19 portfolio costs using the AURORA model from the 2015 IRP,
20 updated with the most recent load forecast, natural gas
21 forecast, and Valmy coal price forecast, utilizing the
3 Although the actual current depreciable life of Valmy Unit 2 is
through the end of 2035 , the 2015 IRP planning period did not extend
beyond 2034 ; therefore, this IRP-based analysis reflects a 2034
retirement . Extending the analysis to 2035 would likely result in an
increase in the cost difference .
HARVEY, DI 16
Idaho Power Company
1 resource assumptions from the preferred portfolio. The
2 results of this analysis are presented as Exhibit No. 6.
3 Q. Please describe the results of the revenue
4 requirement impact of the two operating period alternatives
5 presented in Exhibit No. 6.
6 A. Idaho Power's analysis results presented in
7 Exhibit No. 6 indicate that the NPV of the revenue
8 requirement associated with a 2025 end-of-life is $103
9 million less than the revenue requirement of a 2031/2034
10 retirement date.
11 Q. Did Idaho Power conduct updated present value
12 revenue requirement analyses that assessed the economics of
13 ceasing operations sooner than 20 2 5?
14 A. No. While Idaho Power's forecast indicates
15 Valmy is expected to be a necessary, but relatively
16 infrequent, contributor to system reliability, resulting in
17 a low capacity factor between now and 2025, the current
18 Ownership Agreement and Operation Agreement between Idaho
19 Power and NV Energy do not provide for provisions to cease
20 coal-fired operations at the plant if the plant owners do
21 not align on end-of-life dates. In addition, as described
22 in Mr. Larkin's testimony, the rate impact associated with
23 an accelerated depreciation schedule ending in 2019 would
24 be materially higher. In an attempt to mitigate this
25 customer rate impact, the Company has concluded that a 2025
HARVEY, DI 17
Idaho Power Company
-
1 end-of-life date strikes a reasonable balance between
2 reliability, economics , and customer rate impacts.
3 Q. Please describe the routine capital
4 expenditures Idaho Power anticipates will be necessary to
5 safely and reliably operate Valmy through the plant 's end-
6 of -life date of 2025 .
7 A. The incremental investments expected through
8 Valmy's end-of-life are for upgrades and replacements of
9 plant infrastructure required to keep the plant
10 operational, safe, and reliable. Both units are on a
11 three-year outage cycle that requires each unit to be taken
12 down once every three years for unit inspection and
13 selected refurbishment . In 2018 and 2019, the units are
14 scheduled for their next outages so incremental investments
15 are expected to be higher these years . These outages,
16 which should be the last large ones performed, will help
17 ensure the units are operational and can continue to
18 provide reliable service through 2025 .
19 Q. Will Idaho Power perform the same review of
20 future incremental investments prior to any work being done
21 as the review performed for investments made since the
22 Company's last general rate case?
23 A. Yes . The Company will receive a description
24 of the factors driving the need for the project and a
25 recommendation for the work to be performed from the plant
HARVEY, DI 18
Idaho Power Company
1 operator , NV Energy . The estimated cost of each project
2 will then be compared to the expected life of the asset as
3 well as the Valmy end-of-life date to determine prudency of
4 the planned investment . In addition , Idaho Power and NV
5 Energy will work together to identify ways to reduce O&M as
6 both partners prepare for future low production from the
7 plant through its end-of-life .
8
9
Q.
A.
Please summarize your testimony .
Significant changes to the ongoing economics
10 of Valmy operations have occurred between 2010 and 2014 .
11 Market prices have decreased considerably, resulting in a
12 decrease in the number of hours Valmy operates economically
13 as the dispatch cost is now typically higher than the
14 market price. Idaho Power relies on Valmy to meet peak
15 energy needs and to preserve the balanced portfolio needed
16 to reliably serve customers during all types of system
17 conditions . However , Idaho Power's 2016 assessment of
18 Valmy indicated that a 2025 shutdown date is preferable
19 with respect to reliability and revenue requirement
20 impacts . Consistent with the action plan recognized in the
21 2015 IRP , Idaho Power will continue working with NV Energy
22 to synchronize the depreciation date of Valmy and determine
23 if a mutually agreeable date can be established to cease
24 coal -fired operations . It is not the expectation of Idaho
25 Power that any date agreed upon by the Company and its
HARVEY , DI 19
Idaho Power Company
1 operating partner would extend Valmy operations beyond
2 2025.
3 Q. Based on the analysis presented in your
4 testimony, do you believe December 31, 2025, reflects the
5 most reasonable end-of-life assumption for the Valmy plant
6 based on what is known today?
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A.
Q.
A.
Yes, I do.
Does this complete your testimony?
Yes, it does.
HARVEY, DI 20
Idaho Power Company
1 ATTESTATION OF TESTIMONY
2
3 STATE OF IDAHO
4 ss.
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County of Ada
I, Tom Harvey, having been duly sworn to testify
truthfully, and based upon my personal knowledge, state the
following:
I am employed by Idaho Power Company as the Resource
Planning and Operations Director in the Power Supply
Department and am competent to be a witness in this
proceeding.
I declare under penalty of perjury of the laws of
the state of Idaho that the foregoing pre-filed testimony
and exhibits are true and correct to the best of my
information and belief.
DATED this 21 st day of October 2016.
-
Tom Harvey
23 SUBSCRIBED AND SWORN to before me this 21 st day of
24 October 2016.
25
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Notary Public
Residing at: Boise, Idaho
My commission expires: 02/04/2021
HARVEY, DI 21
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-16-24
IDAHO POWER COMPANY
HARVEY, DI
TESTIMONY
EXHIBIT NO. 4
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Project
Unit 2 Cooling Tower
Replacement
Unit 1 DSI Installation
Unit 2 Scrubber Upgrade
Unit 2 Scrubber Alomizer
Upgrade
2011 2012
$80,324 $104,931
$0 $1,661,173
$0 $21,178
$0 $18,148
VALMY INVESTMENTS SINCE LAST GENERAL RATE CASE (CASE NO. IPC-E-11-08)
2013 2014 2015 2016 Total Purpose Project Description/Justification
The Unit 2 cooling tower was operational in 1985 and was designed for a 20 -25 year
life. Safety Metric: The existing cooling lower structure was nearing the end of its
service life and the wood in the tower was deteriorating. Wood supports for access
Safety I ways, piping, and lhe hot deck were rotted and became unsafe. Reliability Metric: The
$113,989 $4,504,556 $2,450,464 $93,878 $7,348,142 cooling tower was operating at 67% of its perfonnance due to degradation of the tower Reliability affecting lhe condensers perfonnance to cool the exhaust from the turbine, causing a
derate in back pressure. O&M Metric: The rotting of the wood structure resulted in an
increase of maintenance costs to replace affected areas.
Both units must meet the Mercury and Air Toxics Standard (MATS) 4-16-2015. This
project / scope covers the Hydrochloric Acid (HCI) mitigation to comply with MATS Rule
$624,036 $3,992,239 $495,356 $42,554 $6,815,359 Environmental for the unit to run beyond 4-16-2015. Technology selected was Dry Sorbent Injection
(DSI) -Hydrated Lime is injected in the backend of the boiler lo remove HCI. HCI limit
is .0020 lb/ MMBtu. This project was required for the unit to meet the MATS standard.
The Valmy Unit 2 Dry Flue Gas Desulphurization (DFGD) system began service in
1985. It was based on technology developed and designed by Rockwell International.
The system was not capable of optimum operation. This was due to problems with the
original design, obsolete and worn-out equipment, the complexity of the system design
and a lack of plant staffing to proper1y operate and maintain the system in its current
condition. These problems fell into four main categories: safety issues, environmental
problems, process issues related to the design complexity and a high cost of operation
when compared to more recently designed and built DFGD systems. After started, this
project was modified to increase the S02 removal from the original design of 70% to
roughly 85% to ensure compliance with the Mercury and Air Toxics Standard (MATS).
This project included: 1) the replacement of the Lime Slurry and Recycled Ash Slurry
three way valve with Pinch valves, 2) the replacement of the valves below the inlet
slrainers with new 1-1/2" pinch valves, 3) fabrication and installation of access safety
platfonns missed by engineering but are required for operations and maintenance, 4)
$1,014,212 $2,257,179 $3,062,885 $248,467 $6,603,920 Environmental upgrading the gland seals on the recycled ash and Lime Slurry Pumps, 5) relocating
the two Lime Slurry Pumps for operations and maintenance, 6) replacing the day bin
vibrator, 7) resolving the slurry pluggage issues at the atomizers by extending the hard
piping to the atomizers and replacing the atomizer hoses, 8) replacement of lime and
recycle ash slurry loop pressure transducers and isolation rings, 9) cleaning, inspection
and modification of the atomizer slurry feed systems, 10) cleaning and inspection of
atomizers and slurry distribution wheels, 11) vessel flue gas exit temperature
thennocouple modifications, 12) replacement of all Orbinox valves to Clarkson valves,
13) installing new flushing water strainer, 14) installing pressure gauge isolation seals,
15) tuning of slaking water inlet temperature sparger and controls, 16) refining
Flushing Sequences Logic, 17) installing new level indicators at the recycled ash day
bins, and 18) removing and replace drains at the atomizer deck.
The V2 Scrubber was placed inlo service in 1985, using three (3) separale vessels.
Each vessel contains three (3) spray machines for a total of nine (9) spray machines.
The machines are used for the removal of S02 from the flue gas in order to comply with
the Title 5 mandate. Each spray machine consists of a 300HP water cooled motor
turning at 3600 rpm, coupled lo a 10,000 rpm gearbox with a flex shaft and an atomizer
wheel. The equipment condition deteriorated and became unreliable and inefficient.
Costs to mainlain lhe equipment significantly increased. (12) Atomizer Machines were
$1,355,170 $1,226,229 $3,505,849 ($102,237) $6,003,158 Environmental purchased from Alstom Power. (9) are in continuous use and (3) were purchased as
spares. Along with the purchase of the Atomizers, all (9) turning vanes and Atomizer
Housings and associated controls were replaced. After started, this project was
modified lo increase the S02 removal from the original design of 70% to roughly 85% to
ensure compliance with the Mercury and Air Toxics Standard (MATS). This project was
a complement to the previous project to ensure compliance with the Mercury and Air
Toxics Standard (MATS)
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Valmy Coal Crusher Bell
Feeder Project
Unit 2 Sootblower Syslem
Replacemenl
Unil 1 Cooling Tower
Replacement
Unit 1 Reheal Tube
Replacemenl
North Valmy Dust Collector
Upgrade
Unil 2 Botlom Ash Hydrobln
Rebuild
2011 2012
$0 $378,222
$0 $144,858
$2,974,603 $219,234
$3,165,809 $25,449
$723,834 $922,915
$0 $0
2013 2014 2015
$3,709,529 $46,342 $0
$3,527,234 $79,877 $0
$1,437 $13,197 $0
$0 $0 $0
$987,841 $354,106 $135,968
$0 $83,458 $3,024,866
2016 Total Purpose Project Description/Justification
The crusher tower arrangement and equipment created unnecessary dust generation
which could have caused violations of lhe Nevada Department of Environmenlal
Proteclion dusl elimination requirements. The vibratory feeders were not equipped with
effective seals to the feeder skirtboard, which caused particulale spillage and dust
emissions. The ring-granulator-style crushers generate significant dusl when crushing,
and also acl as a fan to push dust out or lhe skirtboard and headbox openings when
operating empty. Also, the system throughput was compromised due to sizing of the
$0 $4,134,093 Environmental I exisling feeders/crushers; the 400 rating requires bolh feeders /crushers be operated lo
Economic match downstream belt capacily of 800 TPH. Upgrading lhe feeders and crushers to a
higher rate provides additional operaling flexibility. Existing crusher discharge chute
work was not well configured and prone to pluggage. In order lo significantly improve
reliabllily, the new arrangement eliminaled the single flop gate bottleneck present in lhe
currenl transfer arrangement. These upgrades were also required per Nevada
Department of Environmental Protections request for dusl elimination.
The currenl condition of the Unit 2 soolblower system was rated from poor to very poor.
The issues ranged from current overloading to excessive amounts of condensate to
$0 $3,751,969 Reliabilily
excessive slagging (wall slagging). These conditions were contributing to increasing
tube erosion and decreased efficiency due to slagging issues. To ensure reliable
operalions of lhe boiler, lhis project was needed for reliability.
The unit 1 cooling tower was operational in 1981 and was designed for a 20 -25 year
life. Safely Melric: The exisling cooling tower structure was nearing lhe end of its
service life and the wood in the tower was deleriorated. Wood supports for access
Safely/ ways, piping, and lhe hot deck were rotled and became unsafe. Reliability Metric: The
$0 $3,208,471 cooling lower outlet water temperature never mel lhe design parameter thus affecting Reliabilily the condensers performance to cool the exhausl from the turbine, causing high back
pressure. O&M Metric: The rolling of the wood structure was resulting in an increase of
maintenance costs to replace affected areas.
Unit 1 experienced an increase of forced outages to repair failed tubes; 2010 Unil 1
inspection oulage required over 100 pad welds lo patch thin lube wall areas, but lhe
Reliabilily / reheal seclion needed replacemenl during the 2011 outage. Per the NVE Generation
$0 $3,191,257 Economic Engineering inspection -recommendation was to replace all reheat sections otherwise
failures will continue to occur with escalaling frequency up to potentially an average of
one per monlh.
The currenl Valmy coal dusl collection syslems were original inslallalion, circa late
1970's/ea~y 1980's, designed to meet combustible dust control standards of lhat time.
OSHA in 2008 upgraded the standards for combustible dusl control and issued
Instruction CPL 03-00-008 (3/11/2008) that contained policies and procedures for
inspecting work places that create or handle combustible dusls. This program focused
($1,662) $3,123,002 Environmental on specific industries that have frequent combuslible dusl incidents and the National
Emphasis Program is to inspect those facilities thal generale or handle combuslible
dusls which pose a deflagration or other fire hazard when suspended in the air. Along
wilh OSHA's directive and the potential to bum different sources of coal, the old dusl
collection systems needed to be upgraded to meel those requirements.
The Valmy Unit 2 botlom ash dewatering and recycle system was deteriorated and
become unreliable and was at risk of total failure. An inspection by the OEM, Allen
Sherman Hoff was completed in 2010 and repealed in 2012 with bolh inspections
identifying a number of serious issues. ~ lhe plant did not complete the highesl priorily
repairs, lhe system would have become very unreliable and resulted in significant load
($275,518) $2,832,806 Reliabilily / reductions and emergency repair costs. Additional work idenlified after the project Economic started is: concrete foundation repairs, replacing corroded underground electrical
conduits, thickness inspections and repairs to the lower cone sections of two
dewatering bins, additional Non Destructive Examination (NDE) testing, power outage
and weather delays and repairs lo 6 inch and 8 inch knife gate valves.
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Project
Unit 2 Burner Replacement
Unit 1 Sootblower System
Replacement
Unit 1 Secondary Supemeat
Replacement
Unit 2 Primary Air Duct
Replacement
North Valmy Caustic Tank
Building Replacement
Evaporation Pond Liner
Replacement
Mixed Bed Demineralizer
Replacement
Unit 1 Circulating Water Line
Recoat
2011 2012
$0 $693
$0 $118,438
$2,114,142 ($29,440)
$0 $0
$0 $257,820
$774,302 $1,262,317
$0 $30,834
$0 $0
2013 2014 2015
$2,330 $74,157 $2,339,126
$838,112 $1,198,044 ($23,995)
$0 $0 $0
$0 $22,843 $2,212,396
$1,210,585 $368,344 $0
($315,770) $0 $0
$841,661 $796,332 ($35,487)
$0 $48,357 $1 ,199
2016 Total Purpose Project Description/Justification
The Valmy Unit 2 burners were in poor condition and had a history of high failure rate.
Advanced Control Technology burners were installed in 2007. The burner components
were failing due to excessive wear and overheating. The failures induded, the burner
inner barrel, diffusers, igniters, and scanners. In addition to the need of replacement for
$9,732 $2,426,039 Reliability / reliability purposes, there was an average of 21,717 lost MWHs per year from 2007-
Economic 2011 due to burner and igniter issues. This project replaced the burner components
with high wear resistant materials, installed heavy duty igniter tubes, scanners, and new
igniters. Cooling air was supplied to the scanners.
Unit 1 experienced premature boiler tube erosion from the sootblowing activities. The
cause for the erosion was from excessive moisture in the sootblowing medium. The
redesigned system allowed for the extra sootblowing without damage to the boiler
$0 $2,130,599 Reliability tubes. Without a property functioning sootblower system, the potential for an increase
in ash contributes to more accumulation on the tubes reducing the thermal exchange,
which would require more frequent deaning.
This project involved the replacement of the secondary supertleat assemblies in the
Unit 1 Boiler. Since 1998 eighteen (18) documented derates and forced outages have
$0 $2,084,702 Reliability occurred requiring repairs to tube leaks. The Unit 1 boiler inspection conducted in 2008
indicated significant loss in the wall thickness of the tubing and the potential for a
substantial increase in tube leaks.
The North Valmy Unit 2 Primary Air Duct System is part of a system that apportions hot
and cold air flow to the pulverizers for drying and transporting pulverized coal to the
burners in a measured and controlled way. The duct worl<, dampers and expansion
joints have been altered by pulverizer explosions and emergency repairs to return the
($289,625) $1,945,614 Reliability unit to service. This has resulted in misdistribution and control of primary air and has
led to combustion control problems from burner coking to ductwork puffs. Restoration
of the system restored its pertormance and increased reliability of the unit from forced
outages.
This project replaced the building that housed the caustic tanks. In early 2012 the
containment basin in the Caustic Tank Building began leaking. The leaking caustic soda
caused the ground to heave under the building resulting in significant damage to the
Reliability / structure and the associated systems, including the electrical and piping to the caustic
$0 $1,836,748 Safety I tank. The earth was excavated at the heave to alleviate the uplift pressure on the Environmental building. The excavated material was tested with the test results showing an elevated
ph of 12.5 indicative of a caustic soda leak.
The existing pond liner was 30 years old and was exhibiting several areas of
delamination that are indicative of material failure. The condition of the existing liner
$0 $1,720,848 Environmental suggests it has reached the end of its useful life and therefore required a new liner
system to be installed with upgraded materials. This included a double walled liner with
leak detection to ensure environmental compliance.
This project replaced the mixed bed demineralizer and sulfuric acid and caustic soda
tanks. The mixed bed demineralizers were 30+ years old. The su~uric acid tank and
Safety I the caustic soda tanks were reaching the end of their designed corrosion life which
$0 $1,633,341 Environmental involved serious leaks from the tanks. Sulfuric acid and caustic soda were becoming a
higher priced commodity. The entire system needed to be replaced.
The circulating water pipe lining was failing and in need of being relined during an
extended outage. A failure of the lining could result in pipe corrosion and leaks and
could require several days to excavate the line and complete repairs. System leaks
Reliability I required an outage for repair. The cathodic protection system for the plant was replaced
$1,486,158 $1,535,714 Economic in 2013. The poor pertormance of the system before the replacement most likely
resulted in pipe exterior damage. Several other underground pipes have had an
increased failure rate in recent years. A total failure of the pipe would result in a six (6)
month forced outage.
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Unit 2 Circulating Water Line
Recoat
Mechanical/Electrical Shop
Rebuild
Unit 2 Generation Phase End
Tum Design Betterment
Cathodic Protection System
North Valmy Coal Combustion
Residual Compliance
Unit 2 Steam Valve Hardening
Unit 1 Coal Pipe Replacement
2011 2012
$0 $0
$0 $102,137
$0 $1,420,942
$36,294 $500,521
$0 $0
$0 $0
$0 $0
2013 2014 2015
$0 $28,074 $1,476,360
$1,586,592 ($172,626) ($50)
($133,291) $0 $0
$634,186 ($11,703) $0
$0 $0 $1 ,289,835
$0 $0 $1,116,028
$0 $0 $189,674
2016 Total Purpose Project Description/Justification
The circulaling water pipe lining was failing and in need of being relined during an
extended outage. A failure of the lining could result in pipe corrosion and leaks and
could require several days to excavate the line and complete repairs. System leaks
Reliability / required an outage for repair. The cathodic protection system for the plant was replaced
$18,739 $1,523,174 Economic in 2013. The poor performance of the system before the replacement most likely
resulted in pipe exterior damage. Several other underground pipes have had an
increased failure rate in recent years. A total failure of the pipe would result in a six (6)
month forced outage.
The old maintenance shop complex was comprised of several disconnected areas
which decreased productivity, restricted the ability to provide optimal plant support, and
inhibited the ability to conduct effective staff training. The old welding shop consisted of
a small area between the units enclosed by insulation attached to chain link fencing.
$0 $1 ,516,053 Economic The combined electrical~nstrumentation shop was contained in a small room adjacent
to the business center. The lunchrooms were separate, with the largest used to conduct
safety meetings/training with standing room only. Productive ongoing training could not
be conducted with the entire staff because of inadequate meeting space.
After an investigative analysis of the generator stator end turns, it was determined that
the current phase end-turn connections were too rigid when last rebuilt by REGENCO.
The phase end-turn connections must account for different component expansion rates
$0 $1,287,652 Reliability / and also avoid the potential issues with natural frequency near the electromagnetic Economic exciting frequency forces of 120 hertz. All the generator stator end turns needed to be
resoldered to prevent failure.
The original cathodic protection system was installed during a period from 1981 to
1984. The old cathodic protection system was installed as an upgrade in 1991. The
plant observed an increase in the rate of underground pipe corrosion, which suggested
the existing cathodic protection system failed or was at the end of its useful life. An
evaluation was performed for all five systems and the determination was that the
Reliability/ majority of the depressed sacrificial anodes have been depleted and new anodes
$0 $1,159,298 Economic needed to be installed in order to protect the underground piping, fire lines, and tank
bottoms. It was also determined that there were several new wells put into service
without any cathodic protection. These new well casings needed protection, and
required a complete system for each well. Also, the evaluation proposed that the
majority of the anodes in the condenser water boxes were depleted and need to be
replaced.
The Coal Combustion Residual (CCR) rule was published in the Code of Federal
Regulations on April 17, 2015. Valmy had 180 days to comply with the CCR regulations.
Valmy has taken a proactive approach to addressing the impacts of potential "ash piles"
noted onsite. To continue to be proactive and avoid inadvertently creating CCR
($166,324) $1,123,511 Environmental impoundment, North Valmy needed to place asphalt and concrete at the bottom ash
handling areas of Unit 1 and Unit 2. If this area was not paved, under the CCR rule,
these areas would have been considered an "open dump" and a violation of the
regulation, and may ultimately have lead to the creation of additional CCR
impoundments at Valmy.
Due to high temperatures, the current materials that made up the steam turbine valve
internals were subject to formation of an oxide layer that could eliminate the clearance
Reliability / between the moving and stationary parts. This could have caused the valves to bind $6,720 $1,122,748 Economic and bend, causing a forced outage. The valves were also originally designed for base
load operation. This project helped increase the availability of the valves during high
cycling.
The plant was experiencing considerable erosion on its coal piping that leads from the
pulverizers to the burners. This erosion resulted in coal leaks that were a
housekeeping, dust control (OSHA dust control initiative) and ultimately a fire, health
$921,442 $1,111,116 Safety / and explosion hazard. Identifying and replacing individual sections of piping has been
Environmental performed in the past, which was a short term solution to the problem. A total
replacement of the piping system including wear resistant pipe and a revised support
and hanger system was required.
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Project 2011 2012 2013 2014 2015 2016 Total Purpose Project Description/Justification
From the North Valmy Unit 2, 2009 boiler inspection for the primary superheat section
of the boiler, 36 areas were identified with tubes 50% or less of Minimum Wall
Thickness (MWT) and 68 areas were tubes were 60% or less than MWT. In comparing
2010 inspection report with 2009, sootblower lanes of the primary superheat had lost an
additional 10% of their wall thickness. The inspection reports indicated the potential for
Unit 2 Primary Superheat Reliability / an increase of forced outages. Many of the thinned tubes were replaced in 2010. Follow
$0 $0 $0 $0 $1,057,855 $6,384 $1,064,239 up inspection in 2012 identified a few additional tubes to be replaced. A capital project in Lower Loop Replacement Economic 2013 installed tube shields over the tubes in the sootblower paths. The lower loops
were still exposed to flue gas erosion. The inspection in 2014 indicated the tubes in the
flue gas path continued to deteriorate. The 2015 planned outage created the opportunity
to replace the high wear area tubes with new resistant material.
Pulverizers are utilized to grind coal to fine dust before being transported to burner
fronts. This process wears out roll wheel assemblies, table grinding segments, and the
interior of the pulverizer equipment. Mill overhauls at Valmy have historically been on
an 18 to 24 month cycle. The coal imported to Valmy is high in silica and quartz which
causes excessive wear on pulverizer grinding sections. If the pulverizer condition
Unit 1 Pulverizer '8' Major $623,089 ($42,115) $1,047,583 $438,835 $0 $0 $1,033,696 Reliability / deteriorates the units efficiency is decreased thus increasing the fuel usage and power
Rebuild Economic costs. This project removed and replaced all major components induding roll wheels,
grinding table segments, yoke, classifier and vanes, reject chute, loading cylinders and
cables, labyrinth air seals, pyrite plows, burner shut off valves and seats, rebuill
pulverizer motor, coal feeder belt drive and conveyor reducer and motor, eroded
downspouts and chute, rebuilt lube oil system pumps.
Note: The information presented in this exhibit reflects the total capital spend by specific project, for projects over $1 million, including amounts closed to FERG Account 101 -Electric Plant in Service, FERG Account 107 -Construction Work in
Progress and any FERG Account 108 -Accumulated Provision for Depreciation removals but excluding AFUDC.
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION ·
CASE NO. IPC-E-16-24
IDAHO POWER COMPANY
HARVEY, DI
TESTIMONY
EXHIBIT NO. 5
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7. Planning Period Forecasts Idaho Power Company
Tables 7.5 and 7.6 provide the peak-hour capacity deficits for July and December for the coal futures considered. Darker shading in
the tables corresponds to larger deficits. Surplus positions are not specified in the tables. Because no deficits exist prior to 2020,
the tables include data only for 2020 to 2034.
Table 7.5 July monthly eeak-hour capacity deficits (MW) by coal future with existing and committed supply-and demand-side
resources (90 h -percentile water and 951h -percentile load)
Energy Deficits (aMW) 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
Status Quo
Maintain Coal Capacity
Valmy Retire Units 1 and 2 Year-End 2019
Valmy Retire Units 1 and 2 Year-End 2025
Valmy Retire Unit 1 Year-End 2019 and Unit 2 Year-End 2025
Valmy Retire Unit 1 Year-End 2021 and Unit 2 Year-End 2025
Bridger Retire Unit 1 Year-End 2023 and Unit 2 Year-End 2028
Bridger Retire Unit 1 Year-End 2023 and Unit 2 Year-End 2032
Bridger Retire Unit 1 Year-End 2023 and Unit 2 Year-End 2032,
Valmy Retire Units 1 and 2 Year-End 2025
(24) . ·---,
Table 7.6 December monthly peak-hour capacity deficits (MW) by coal future with existing and committed supply-and demand­
side resources (901h -percentile water and 951h -percentile load)
Energy Deficits (aMW) 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Status Quo
Maintain Coal Capacity
Valmy Retire Units 1 and 2 Year-End 2019 - - -- - -(12) (32) (59) (58) (99)
Valmy Retire Units 1 and 2 Year-End 2025 - -- - - -(12) (32) (59) (58) (99)
Valmy Retire Unit 1 Year-End 2019 and Unit 2 Year-End 2025 -- --- -(1 2) (32) (59) (58)
Valmy Retire Unit 1 Year-End 2021 and Unit 2 Year-End 2025 - - -- --(12) (32) (59) (58)
Bridger Retire Unit 1 Year-End 2023 and Unit 2 Year-End 2028
Bridger Retire Unit 1 Year-End 2023 and Unit 2 Year-End 2032
Bridger Retire Unit 1 Year-End 2023 and Unit 2 Year-End 2032,
Valmy Retire Units 1 and 2 Year-End 2025
Page 96 2015 IRP
2034
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-16-24
IDAHO POWER COMPANY
HARVEY, DI
TESTIMONY
EXHIBIT NO. 6
North Valmy Generating Station
Revenue Requirement of Valmy Operating Period Alternatives
To determine the potential customer rate impact of modifying the depreciable end-of-life assumption at Valmy to 2025,
Idaho Power analyzed the revenue requirement of two operating period alternatives: (1) the 2025 end-of-life for both
units, and (2) the existing 2031 and 2035 staggered retirement assumption. The revenue requirement alternatives
consist of two components:
1. The net present value ("NPV") revenue requirement associated with the existing investment, additional run rate
capital, fixed operation and maintenance ("O&M") expenses, and forecasted taxes and insurance; and
2. The total variable portfolio costs using the AURORA model from the 2015 IRP, updated with the most recent
load forecast, natural gas forecast, and Valmy coal price forecast, utilizing the resource assumptions from
Portfolio P6(b).
When combining components 1 and 2 above, the Company's analysis indicates that the least-cost result is the end-of-life
for both Valmy units at the end of 2025 as compared to 2031/2035, by a differential of approximately $103 million.
Figure 1 below provides a summary of the results, while the detailed NPV cash flow analysis is provided as Appendix A to
this document.
Scenario
2025 Retirement
2031/2034 Retirement
Difference
Figure 1:
NPV Revenue Requirement Analysis Summary
2025 vs. 2031/2034 End-of-Life1
($OOO's)
Component 1: Component 2:
Fixed Cost NPV AURORANPV
$397,342 $4,167,493
$522,715 $4,145,163
($125,283) $22,330
Combined NPV
$4,564,835
$4,667,878
($103,043)
Based on this analysis, from an NPV perspective the net reduction in revenue requirement resulting from a 2025 end-of­
life assumption at Valmy as compared to 2031/2034 is approximately $103 million. When evaluating the 2025 and
2031/2034 scenarios, an end-of-life assumption of 2025 would result in NPV revenue requirement savings as compared
to the existing operating assumption.
1 Although the actual current depreciable life of Valmy Unit 2 is through the end of 2035, the 2015 IRP planning period
did not extend beyond 2034; therefore, this I RP-based analysis reflects a 2034 retirement. Extending the analysis to
2035 would likely result in an increase in the cost difference.
1
Exhibit No. 6
Case No. IPC-E-16-24
T. Harvey, IPC
Page 1 of 2
Appendix A
Idaho Power Company
Valmy Revenue Requirement Comparison
2025 or 2031-2034 Retirement
Forecasted Fixed Costs and Total Power Supply Costs
Discount Rate 6.74%
Fixed Costs
2016 50,578
2017 48,627
2018 49,774
2019 50,410
2020 53,234
2021 52,812
2022 50,506
2023 51,054
2024 50,911
2025 51,204
2026 51,461
2027 51,478
2028 51,240
2029 51,060
2030 49,736
2031 48,160
2032 38,638
2033 37,136
2034 36,366
Total $ 924,384
NPV $522,715.36
Total NPV
NPV difference
for the period 2016-2034
$(000)
6.74% 6.74%
Aurora Fixed Costs
$ 293,380 58,943
$ 332,194 56,520
$ 347,073 57,236
$ 349,001 57,504
$ 330,816 60,062
$ 336,715 58,004
$ 343,726 53,712
$ 357,713 52,135
$ 398,496 50,129
$ 414,280 49,440
$ 426,509
$ 443,502
$ 477,128
$ 493,717
$ 511,211
$ 515,699
$ 530,706
$ 535,206
$ 563,041
$ 8,000,111 $ 553,684
$4,145,162.64 $397,341.99
$4,667,878.00
($103,043)
2
6.74%
Aurora
$ 293,380
$ 332,194
$ 347,073
$ 349,001
$ 330,816
$ 336,715
$ 343,726
$ 357,713
$ 398,496
$ 414,280
$ 434,241
$ 450,235
$ 484,014
$ 500,986
$ 518,893
$ 523,324
$ 535,860
$ 538,971
$ 567,098
$ 8,057,016
$4,167,492.87
$4,564,834.86
Exhibit No. 6
Case No. IPC-E-16-24
T. Harvey, IPC
Page 2 of 2