20090702Bokenkamp Rebuttal.pdf

esIDA~POR~
An IDACORP Company
BARTON L. KLINE
Lead Counsel
July 14, 2009
VIA HAND DELIVERY
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
P.O. Box 83720
Boise, Idaho 83720-0074
Re: Case No. IPC-E-09-03
LANGLEY GULCH POWER PLANT
Dear Ms. Jewell:
Enclosed for filing in the above matter are nine (9) copies each of the corrected
redacted rebuttal testimonies of Karl Bokenkamp and Vernon Porter. One copy of each of
the redacted testimonies has been designated as the "Reporter's Copy." Also, a disk
containing Word versions of all of Idaho Power Company's rebuttal testimonies is enclosed
for the Reporter and has been marked accordingly.
The enclosed redacted version has been corrected to correlate to the pagination
and line numbering contained in the confidential versions of Mr. Bokenkamp's and Mr.
Porter's rebuttal testimonies. Please substitute the enclosed redacted version with the
version previously filed. Please note, the exhibits previously provided with the testimonies
have not changed and should be attached to the versions enclosed herein.
Also enclosed for filng are nine (9) copies of Idaho Power's Certificate of Service
indicating service of the corrected rebuttal testimonies on the Intervenors.
Very truly yours,0t~
Barton L. Kline
BLK:csb
Enclosures
cc: Intervenors (w/encls. testimonies)
P.O. Box 70 (83707)
1221 W. Idaho St.
Boise, 10 83702
RECEIVEDCERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 14TH day of July 2009 I sem~Jg4rU ~ 9: 13
correct copy of IDAHO POWER COMPANY'S CORRECTED REDACTEDI~¡ril1~,L('
TESTIMONY OF KARL BOKENKAMP AND VERNON PORTER uPbrlllitÊ~r.mŠSfON
named parties by the method indicated below, and addressed to the following:
Commission Staff
Scott Woodbury
Deputy Attorney General
Idaho Public Utilities Commission
472 West Washington
P.O. Box 83720
Boise, Idaho 83720-0074
Industrial Customers of Idaho
Power and Northwest and
Intermountain Power Producers
Coalition
Peter J. Richardson, Esq.
RICHARDSON & O'LEARY PLLC
515 North 2th Street
P.O. Box 7218
Boise, Idaho 83702
Dr. Don Reading
Ben Johnson Associates
6070 Hil Road
Boise, Idaho 83703
Snake River Allance
Ken Miler
Clean Energy Program Director
Snake River Allance
P.O. Box 1731
Boise, Idaho 83701
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Idaho Irrigation Pumpers
Association, Inc.
Eric L. Olsen
RACINE, OLSON, NYE, BUDGE
& BAILEY, CHARTERED
P.O. Box 1391
201 East Center
Pocatello, Idaho 83204-1391
Anthony Yankel
Yankel & Associates, Inc.
29814 Lake Road
Bay Vilage, Ohio 44140
Idaho Conservation League
Betsy Bridge
Idaho Conservation League
71 0 North Sixth Street
P.O. Box 844
Boise, Idaho 83701
Northwest and Intermountain
Power Producers Coalition
Susan K. Ackerman
9883 NW Nottage Drive
Portland, Oregon 97229
Community Action Partnership
Association Of Idaho
Brad M. Purdy
Attorney at Law
2019 North 1th Street
Boise, Idaho 83702
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~~
RECE'VEO
700' JUl \ 4 AM 9: , \
iDAHO PllBLlC;. N
UT\UT\ES COMMlSSiO
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR A
CERTIFICATE OF PUBLIC CONVENIENCE
AND NECESSITY FOR THE LANGLEY
GULCH POWER PLANT.
CASE NO. IPC-E-09-03
IDAHO POWER COMPANY
DIRECT REBUTTAL TESTIMONY
OF
KARL BOKENKAMP
INFORMTION SUBJECT TO THE
PROTECTIVE AGREEMENT
HAS BEEN DELETED FROM THIS DOCUMNT
1 Q.Would you please state your name, business
2 address, and present occupation?
3 A.My name is Karl Bokenkamp and my business
4 address is 1221 West Idaho Street, Boise, Idaho. I am the
5 General Manager of Power Supply Operations & Planning at
6 Idaho Power Company.
7 Q.Are you the same Karl Bokenkamp that
8 submi tted direct testimony in this proceeding?
9 A.Yes I am.
10 Q.What is the purpose of your direct rebuttal
11 testimony in this proceeding?
12 A.My testimony will respond to the allegations
13 of Intervenor witnesses that Idaho Power does not need the
14 Langley Gulch project in 2012. I will also address certain
15 aspects of Staff and Intervenor witness testimony
16 concerning the 2012 Baseload Request for Proposals ("RFP")
17 and the evaluation of the proposals received.
18 Q.Please summarize why Idaho Power selected
19 the Langley Gulch proj ect as the winner of the 2012
20 Baseload Resource RFP.
21 A.The Langley Gulch proj ect was selected for
22 one primary reason - the value it provides to Idaho Power's
23 customers.
BOKENKAMP, DI REB 1
Idaho Power Company
1 Langley Gulch was the top scoring combined cycle
2 project and the net present value ("NPV") of its 20-year
3 revenue requirement provides considerable savings to
4 customers. Even under conservati va assumptions, the NPV of
5 its 20-year revenue requirement is approximately $ 95
6 million less than that of the next closest combined cycle
7 proj ect. This conservative scenario is presented in Staff
8 Exhibit No. 113 and it uses Langley Gulch's full Commitment
9 Estimate, which it may not spend, and excludes Langley
10 Gulch's terminal value.If Langley Gulch's terminal value
11 is considered, Staff Exhibit No. 114 shows the NPV of its
12 20-year revenue requirement is approximately $160 million
13 less than that of the next closest bidder.
14 The selection of a combined cycle proj ect will help
15 to provide the up and down regulation necessary to
16 integrate intermittent resources as well as provide the
17 Company with an option to reduce its C02 emissions by
18 shifting generation from its coal-fired resources to a
19 natural gas-fired resource.
20 Q.ICIP and Irrigation Pumpers Association
21 witnesses assert that the Company's load forecasts do not
22 accurately reflect current depressed economic conditions
23 and, as a result, they recommend that the Commission wait
24 until after the 2009 IRP has been acknowledged to see if
BOKENKAMP, DI REB 2
Idaho Power Company
1 Langley Gulch is actually needed in 2012. ICIP witness Dr.
2 Reading even recommends the Company completely restart the
3 RFP. Are their recommendations reasonable?
4 A.No. I think they are recommending a very
5 risky strategy. Based on the Company's current forecasts
6 of loads and resources, an additional resource such as the
7 Langley Gulch project is needed in 2012. To illustrate
8 this need, I have included Exhibit No. 10.
9 Q.What does Exhibit No. 10 show?
10 A.Exhibi t No. 10 is a current average energy
11 and peak-hour load and resource balance. It shows that
12 even with Langley Gulch in service in July of 2012, a
13 significant average energy deficit exists. Exhibit No. 10
14 uses the May 2009 load forecast, the most recent estimates
15 of peak-hour contributions from the Irrigation Peak
16 Rewards, A/C Cool Credit and Commercial DSM programs,
17 updated levels of firm import capability from the Pacific
18 Northwest, and wholesale firm energy purchases capable of
19 being delivered to Idaho Power's east side. As shown on
20 Exhibit No. 10, Idaho Power is still projecting significant
21 peak-hour deficits during July 2009 through July of 2012 of
22 166 MWs, 40 MWs, 132 MWs, and 18 MWs (assuming Langley
23 Gulch is on-line in July 2012) , respectively. From an
24 average energy perspective, using the May 2009 load
BOKENKAMP, DI REB 3
Idaho Power Company
1 forecast, the aforementioned assumptions regarding DSM,
2 firm import capacity from the Pacific Northwest, and east
3 side purchases, Idaho Power is still proj ecting average
4 energy deficits during July 2009 through July of 2012 of
5 365 aMWs, 368 aMWs, 421 aMWs, and 285 aMWs (assuming
6 Langley Gulch is on-line for July 2012), respectively.
7 Q.In your prior response you mentioned the May
8 2009 load forecast. Was the decision to proceed with
9 Langley Gulch based on a May 2009 load forecast?
10 A.No, as noted in my direct testimony, a
11 baseload resource was identified in the preferred
12 portfolios in both the 2004 and 2006 IRPs. A natural gas-
13 fired baseload resource was included in the 2008 IRP
14 update. Clearly, load growth has declined since those
15 forecasts were made. However, Idaho Power has prepared a
16 number of updated load forecasts since the 2006 IRP and
17 2008 IRP update were published. Recent economic conditions
18 prompted the Company to revise its load forecast in
19 December of 2008 and then again in May 2009. The December
20 2008 revision looked at residential and commercial loads.
21 The most recent revision, performed in May of 2009, updated
22 the forecast loads for special contract customers as part
23 of preparing the next load forecast, which is expected to
24 be completed in late summer 2009.
BOKENKAMP, DI REB 4
Idaho Power Company
1 Exhibi t No. 10 does not include the recently
2 acquired flexibility to reduce Hoku's loads by 39 MW
3 between June 15, 2012, and August 15, 2012. If the Company
4 includes this flexibility, the proj ected peak-hour deficit
5 in July of 2012, without Langley Gulch, is 279 MW (318 MW
6 deficit + 39 MW reduction from Hoku). The average energy
7 deficit in July of 2012, without Langley Gulch, is 497 aMW
8 (536 aMW deficit + 39 aMW reduction from Hoku) .
9 Q.ICIP witness Mitchell and Irrigator witness
10 Yankel indicate that the Company can cover summer 2012
11 deficits with additional wholesale purchases. Is that
12 true?
13 A.It is important to remember that to serve
14 the 279 MW deficit without Langley Gulch, any imports from
15 the Pacific Northwest in excess of the projected firm
16 network transmission set-aside of 114 MW would be on non-
17 firm transmission.If Idaho Power's other transmission
18 customers use their transmission rights during July of
19 2012, then any time Idaho Power imports more than 114 MW
20 from the Pacific Northwest, it is using transmission
21 capacity that is intended for Transmission Reliability
22 Margin ("TRM") and Capacity Benefit Margin ("CBM").
23 Although this transmission is sold on a non-firm basis,
24 when Idaho Power uses this transmission capacity, it is
BOKENKAMP, DI REB 5
Idaho Power Company
1 using the transmission capacity intended to (1) provide
2 reasonable assurance that the transmission system will be
3 secure under a reasonable range of uncertainty in system
4 conditions and (2) ensure access to backup generation from
5 interconnected systems to meet generation reliability
6 requirements commencing at the end of any hour that a loss
7 of generation occurs in.In other words, Idaho Power is
8 using its reserves. If the Company was importing more than
9 114 MW from the Pacific Northwest during a July 2012 peak-
10 hour and simultaneously lost a Jim Bridger unit, it would
11 already be using some of the transmission that was intended
12 to ensure transmission system reliability or to replace the
13 lost Bridger generation using market purchases.
14 As a point of reference, if we average the Company's
15 hourly imports from the Pacific Northwest during the month
16 of July 2007, on average Idaho Power's imports from the
17 Pacific Northwest for hours 7 through 22 averaged over 400
18 MW. Peak import levels exceeded 700 MW.
19 Q.In Mr. Yankels' testimony on behalf of the
20 Irrigators, he argues that the 115 average MWs of network
21 set-aside for firm purchases is meaningless because the
22 Company's new forecasts included planned peak energy
23 purchases from the Pacific Northwest ranging from 441 to
BOKENKAMP, DI REB 6
Idaho Power Company
1 670 MWs in 2013. Is Mr. Yankel correctly interpreting the
2 transmission available to Idaho Power in the summer?
3 A.No.It appears that Mr. Yankel may not
4 understand the difference between the firm and non-firm
5 transmission capacity available to Idaho Power.In fact,
6 the discrepancy Mr. Yankel has identified further
7 reinforces the Company's need for the Langley Gulch
8 resource to be available during Idaho Power's peak-hours in
9 2012 and 2013.
10 The FERC has established strict rules for
11 determining available transmission capacity. Under those
12 rules, Idaho Power's transmission business unit determines
13 the amount of firm transmission Idaho Power's Power Supply
14 business unit can expect to receive to serve its network
15 loads. This is Power Supply's "network set-aside." The
16 minimum amount of network set-aside for firm purchases for
17 2012 is 114 MW and that is expected to occur in July. The
18 amount of set-aside Power Supply receives from the
19 Transmission business unit will vary from month to month
20 depending on the Company's forecast need for transmission
21 and available transmission capacity.
22 The amount of network set-aside shown in Exhibit No.
23 10 as "Firm Pacific NW Import Capability" is the Company's
24 most current estimate of its future network transmission
BOKENKAMP, DI REB 7
Idaho Power Company
1 set-asides from the Pacific Northwest. To avoid confusion,
2 an identical amount of firm Pacific Northwest import
3 capability is listed for both the Average Energy and Peak-
4 Hour load and resource balances. Any imports from the
5 Pacific Northwest in excess of the listed firm Pacific
6 Northwest import capability will be on non-firm
7 transmission. These imports will be using transmission
8 capacity intended for (1) system reliability and/or (2) to
9 replace energy from unplanned generator outages, such as
10 loss of a unit at Jim Bridger. This is the amount of firm
11 transmission that Power Supply expects to receive from
12 Idaho Power's Transmission business unit for importing
13 power purchases from the Pacific Northwest. This
14 transmission set-aside provides a firm path to import
15 energy from the Pacific Northwest. The load and resource
16 balance assumes that energy will be available to purchase
17 in the Pacific Northwest.
18 Q.If Langley Gulch is not in-service in July
19 of 2012, then how much energy would the Company need to
20 acquire to maintain the load and resource balance?
21 A.The average energy load and resource balance
22 indicates that 650 aMW would be needed. During the peak-
23 hour, 432 MW is necessary.
24 Q.How do you compute those deficit amounts?
BOKENKAMP, DI REB 8
Idaho Power Company
1 A.The 650 aMW is composed of 114 MW of imports
2 from the Pacific Northwest plus 251 MW to replace Langley
3 Gulch, which is shown as on-line in July of 2012 in Exhibit
4 No. 10, plus an additional 285 MW to cover the remaining
5 deficit shown on the average energy load and resource
6 balance. The 432 MW needed during peak-hour is composed of
7 114 MW of imports from the Pacific Northwest plus 300 MW to
8 replace Langley Gulch plus 18 MW to cover the remaining
9 deficit shown on the peak-hour load and resource balance.
10 Q.Why is the proj ected deficit less during the
11 peak-hour?
12 A.The peak-hour load and resource balance
13 assumes that Idaho Power's existing natural gas-fired
14 peaking facilities are in operation and contributing 416
15 MW.
16 Q.Would the peaking resources contribute
17 anything to reduce the July average energy deficit?
18 A If the peaking resources are assumed to be
19 in service, then they would reduce the energy deficit.
20 However, from an economic perspective, they are typically
21 the last resources to dispatch. If the peakers were
22 operated for half of the month, they would provide
23 approximately 200 aMW of energy. This would reduce the
BOKENKAMP, DI REB 9
Idaho Power Company
1 amount of energy needed to maintain the load and resource
2 balance from 650 aMW to approximately 450 aMW.
3 Q.Does this mean that Idaho Power will still
4 need to import large amounts of energy to meet its
5 proj ected deficits?
6 A.Yes. Without Langley Gulch, but with the
7 assumption that 200 aMW of energy is provided by the
8 peaking resources, the July 2012 needs are 450 aMW of
9 energy, and 432 MW during the peak-hour. Considering the
10 39 MW of Hoku flexibility available in July of 2012, the
11 average energy requirement is reduced from 450 aMW to 411
12 aMW and the peak-hour requirement is reduced from 432 MW to
13 393 MW. With a network transmission set aside of 114 MW
14 for firm imports from the Pacific Northwest, that leaves an
15 additional 297 aMW to be imported to meet the average
16 energy need and 279 MW to meet the peak-hour need. If
17 energy to meet these needs is imported from the Pacific
18 Northwest, it will be imported on non-firm transmission,
19 utilizing transmission capacity typically reserved for TRM
20 and CBM discussed earlier.
21 Q.Doesn't Idaho Power typically import energy
22 from the Pacific Northwest in the summer?
23 A.Yes. The fact that Idaho Power typically
24 imports a considerable amount of purchased energy from the
BOKENKAMP, DI REB 10
Idaho Power Company
1 Pacific Northwest illustrates two points:(1) the
2 considerable reliance that Idaho Power is placing on the
3 availability of market purchases to serve its load and (2)
4 the degree to which Idaho Power is hoping to use non-firm
5 transmission to serve its customers during summer months.
6 Neither of these points are posi ti ve.
7 Q.On pages 30 and 31 of his testimony, Mr.
8 Yankel asserts that the 115 average MW transmission
9 limitation is an artificial construct used to justify the
10 need for Langley Gulch. What is your response?
11 A.Again, I do not think Mr. Yankel understands
12 the issue. The 115 MW (114 MW for July 2012 in Exhibit No.
13 10, the current analysis) of network transmission set-aside
14 is the amount of firm network transmission from the Pacific
15 Northwest that Idaho Power expects to receive during July.
16 This is a very real limitation until additional in-bound
17 transmission capacity from the Pacific Northwest is added
18 to Idaho Power's system. This does not mean that Idaho
19 Power cannot import more than 114 MW in July, but it does
20 mean if more that 114 MW is imported from the Pacific
21 Northwest during July, it will be on non-firm transmission.
22 The Company will be using its reserves (TRM and/or CBM and
23 taking the chance that it will not need to use these
24 reserves if it loses a generating unit, or a fire knocks
BOKENKAMP, DI REB 11
Idaho Power Company
lout a transmission line, or if loop flow limits
2 transmission capacity from the Pacific Northwest.
3 Q.On page 33 of Mr. Yankel' s testimony, he
4 notes that the Company's Irrigation Peak Rewards program
5 could become so successful that Idaho Power will become an
6 energy limited utility rather than a peaking limited
7 utility. Is that a reasonable conclusion?
8 A. As indicated on Exhibit No. 10, on a
9 planning basis, the Company's average energy deficits
10 already exceed its peak-hour deficits for July and August.
11 If the Snake River baseflows continue to decline, Idaho
12 Power's energy position will further deteriorate. And, if
13 as a result of future carbon legislation Idaho Power is
14 required to reduce the output of its coal-fired facilities
15 to reduce C02 emissions, Idaho Power's energy position will
16 deteriorate even more.
17 It would be great if the Irrigation Peak Rewards
18 program became very successful. But even if it achieves
19 the levels shown in Exhibit No. 10, the program would not
20 eliminate or defer the need for Langley Gulch in 2012. For
21 July 2012, Exhibit No. 10 includes 188 MW of DSM and energy
22 efficiency program contributions above the amount forecast
23 for July of 2009, bringing the total DSM/energy efficiency
24 forecast for July of 2012 to 432 MW. If an additional 200
BOKENKAMP, DI REB 12
Idaho Power Company
1 MW of DSM from the Irrigation Peak Rewards program was
2 added, the 416 MW peak-hour contribution from the peaking
3 resources and 114 MW peak-hour contribution from Pacific
4 Northwest imports could be reduced (but not altogether
5 eliminated), leaving additional firm transmission capacity
6 and/or combustion turbine capacity available to improve
7 reliabili ty and serve customers in the event of an
8 unplanned outage at one of Idaho Power's generation
9 facili ties, or a transmission system outage. Recent
10 transmission outages due to wildfire certainly show that
11 such outages are not hypothetical.
12 Q.In a footnote on the bottom of page 6 of Mr.
13 Yankel' s testimony, he notes that his testimony addresses
14 Langley Gulch as an energy resource rather than a peaking
15 resource. Is that a valid assumption to make?
16 A. Yes, I think Mr. Yankel' s assumption is
17 reasonable. While Langley Gulch is expected to operate as
18 an energy resource, following load and providing additional
19 up and down regulation capability to assist with
20 integration of intermittent resources such as wind
21 generation, the project is definitely needed during summer
22 peak-load hours.
23 Q.In his testimony, Mr. Yankel states that the
24 2008 updated IRP and the 2006 IRP are essentially
BOKENKAMP, DI REB 13
Idaho Power Company
1 "worthless. "(Page 9, line 14.) Are those the only load
2 forecasts the Company has considered in deciding to
3 continue to pursue Langley Gulch in light of changed
4 economic conditions?
5 A.As noted previously in my testimony, the
6 load forecast used to prepare the 2006 IRP and the August
7 2007 load forecast are not the only load forecasts Idaho
8 Power has considered in light of the changed economic
9 conditions. As shown in Exhibit No. 10, a load and
10 resource balance using the May 2009 load forecast, the need
11 for an additional resource in 2012 is apparent.If future
12 load forecasts indicate reduced loads in 2012, then the
13 Company will be well positioned to reduce its historic
14 reliance on energy imported from the Pacific Northwest
15 using non-firm transmission. By adding the resource in
16 2012, the Company is also better positioned to (1)
17 integrate intermittent generation resources, such as wind
18 generation, and (2) respond to carbon legislation with an
19 option to reduce its C02 emissions by shifting coal -fired
20 generation to natural gas-fired resources.
21 Q.At page 28 of Mr. Yankel' s testimony, he
22 states that the Company's 2009 IRP as well as its December
23 2008 and May 2009 updated forecasts indicate that Langley
BOKENKAMP, DI REB 14
Idaho Power Company
1 Gulch will operate at a capacity factor of 91 percent. Is
2 this statement correct?
3 A.No. In his testimony, Mr. Yankel adds a
4 footnote that states that the source for the 91 percent
5 capacity factor is Idaho Power's response to Staff's First
6 Production Request in Case No. IPC-E-09-03. The Company's
7 response to Staff's First Production Request, Request No.
8 37, states that the capacity factor for the Langley Gulch
9 project is estimated using AURORA output based upon 2009
10 IRP assumptions. The average capacity factor supplied in
11 the response to Staff Request No. 37 is shown below in an
12 abbreviated form to only include the annual average. As
13 shown below, none of the capacity factors are close to the
14 91 percent amount described by Mr. Yankel.
15
Year Capacity Factor
2012 33%
2013 50%
2014 52%
2015 53%
2016 54%
2017 54%
2018 56%
2019 55%
2020 64%
2021 64%
2022 62%
2023 62%
2024 61%
2025 65%
2026 63%
2027 63%
BOKENKAMP, DI REB 15
Idaho Power Company
Year Capacity Factor
2028 64%
2029 64%
2030 65%
2031 75%
2032 74%
1 Q.On page 29 of his testimony, Mr. Yankel
2 testifies that the Company's 2009 IRP shows Langley Gulch
3 operating at 251 aMW in each month. Is Mr. Yankel
4 confusing availability of the plant with actual operation
5 of the plant when he states that the plant is producing 251
6 aMW in each month of the Company analyses?
7 A.Yes. Mr. Yankel' s interpretation of the
8 data provided by the Company is incorrect. The 251 aMW is
9 not the expected generation; instead it is the amount of
10 energy the Company expects to have available from the plant
11 for planning purposes.
12 Q.Are there other errors in Mr. Yankel' s
13 testimony?
14 A.Yes. In discovery, the Irrigator's
15 requested that the Company re-run its 2008 rate case test
16 year model to assume that Langley Gulch was available in
17 2008. Mr. Yankel used that model run to support his
18 assumption that Langley Gulch, which was not a needed
19 resource in 2008, was used either to displace higher cost
20 purchases or for surplus sales, provided that market prices
BOKENKAP, DI REB 16
Idaho Power Company
1 exceeded the variable operating cost of Langley Gulch.
2 This is the source of his testimony that 88 percent of the
3 Langley Gulch proj ect will be used for surplus sales.
4 Q.Is Mr. Yankel' s comparison of the Company's
5 2009 IRP analysis to the scenario he asked the Company to
6 create, that is, the Company's 2008 test year rate case
7 results adjusted to include Langley Gulch 4 years prior to
8 its need, a reasonable comparison?
9 A.No. The Company has planned for Langley
10 Gulch to be available in 2012. Inserting Langley Gulch
11 into a scenario where 2008 loads and resources are used
12 creates a scenario that is not a realistic representation
13 of when Langley Gulch is needed; therefore, the results are
14 not reflective of what would be expected in 2012 or 2013.
15 Q.On the bottom of page 52 of his testimony,
16 Staff witness Rick Sterling testifies that a simple cycle
17 combustion turbine (" SCCT") was actually the price score
18 winner in the bid evaluation process. He goes on to opine
19 that the reason the SCCT proposal scored well, but was not
20 ultimately selected, was because of the SCCT's low capacity
21 factor. Has Mr. Sterling correctly stated the reasons why
22 the SCCT, even though it was the price score winner, was
23 not selected?
BOKENKAMP, DI REB 17
Idaho Power Company
1 A.He correctly identified one of the main
2 reasons for the SCCT's higher price score. A simple cycle
3 combustion turbine scored well because of its low capacity
4 factor. Another factor contributing to the SCCT's
5 favorable scoring is the lower capital cost of a SCCT when
6 compared to a combined cycle combustion turbine ("CCCT").
7 The combination of the two, low capital cost and the low
8 capaci ty factor, resulted in a high scoring proposal when
9 evaluated with the AURORA model. The AURORA analysis used
10 to develop the price scoring utilized 50th percentile water
11 and load conditions with a 90th percentile peak-hour load.
12 Under these conditions, the SCCT operated at a relatively
13 low capacity factor contributing to its favorable scoring.
14 Considering both the fixed and variable costs of owning and
15 operating a proj ect with all other considerations being
16 equal, a SCCT will be preferred over a CCCT at lower
17 capacity factors and a CCCT will be preferred at higher
18 capacity factors.
19 Mr. Sterling also correctly identified the reason
20 why the SCCT was not selected. Gi ven the Company's need
21 for a generating resource that (1) is capable of operating
22 in a base load manner to cost-effectively supply energy
23 deficits, (2) provides the Company with an option to meet
24 future C02 regulations by shifting generation from coal-
BOKENKAMP, DI REB 18
Idaho Power Company
1 fired to natural gas-fired resources, thereby reducing C02
2 emissions by approximately 0.6 tons/MWh for each MWh
3 shifted, and (3) is expected to be on-line and capable of
4 providing up and down regulation to help integrate
5 intermi ttent renewable resources, SCCT resources were
6 dropped from consideration in the final stages of the RFP
7 process.
8 Q.On page 77, Mr. Sterling discusses his
9 Exhibit No. 113, which shows how the bids in the 2012 RFP
10 would have been evaluated if the Commitment Estimate would
11 have been used to score the Benchmark Resource bid. He
12 concludes that if the Commitment Estimate would have been
13 used as the price of the Benchmark Resource, the Benchmark
14 Resource would not have been declared the winner. Is his
15 conclusion correct?
16 A.No. Although on Staff Exhibit No. 113
17 / / / / / / / shows a higher total price score and total score
18 than the Benchmark Resource, relying only on the point
19 score shown in Exhibit No. 113 is misleading and would have
20 led to a costly mistake if / / / / / / / had been selected.
21 Q.Why do you say reliance only on the point
22 score shown in Exhibit No. 113 would be a mistake?
23 A.If you look at the top paragraph of Staff
24 Exhibit No. 113, it shows the 20-year NPV of the revenue
BOKENKAMP, DI REB 19
Idaho Power Company
1 requirement for the Benchmark Resource using the Commitment
2 Estimate as its cost.It compares that cost to the 20-year
3 NPV of the revenue requirement for / / / / / / / /. The Benchmark
4 Resource is still $ 95 million less expensive for customers
5 than the best alternative bid over the 20-year evaluation
6 period.
7 Q.What else does Exhibit No. 113 show with
8 respect to the comparison between the two bids.
9 A.First, as noted in the text of Exhibit No.
10 113, the terminal value of the Benchmark Resource was not
11 reflected in the scoring shown on Exhibit No. 113. The
12 terminal value is a measure of the remaining economic value
13 of an asset after some number of years, in this instance 20
14 years was used. At the end of a 20-year Power Purchase
15 Agreement ("PPA") or Tolling Agreement ("TA"), the
16 Developer retains the generation asset. Idaho Power might
17 have an opportunity to enter into another PPA or TA, or
18 purchase the asset. However, with a utility-owned
19 facili ty, such as the Benchmark Resource, the utility
20 retains the economic value of the physical asset - a power
21 plant. The RFP Team's evaluation used the book value of
22 the asset to estimate its terminal value. However, if the
23 asset were sold at the end of the evaluation period, the
BOKENKAMP, DI REB 20
Idaho Power Company
1 actual market or economic value of the asset could be
2 higher than the book value.
3 Second, the cost to the Company's customers for
4 imputed debt was not reflected in the results shown on
5 Exhibit No. 113. For further discussion on imputed debt
6 costs, see Staff witness Carlock's testimony at pages 7 and
7 8 and Idaho Power witness Smith's testimony at pages 11 and
8 12.
9 Q.How did the Company's RFP team address the
10 values you discussed in your prior answer in scoring the
11 bids?
12 A.The Company's RFP Team calculated two sets
13 of price scoring for the short-listed proposals. The first
14 set included the as-bid costs without terminal value or any
15 assessment of imputed debt. The second analysis included
16 the terminal value, which is a standard method of capturing
17 end,effects from unequal proj ect lives. The results of the
18 second analysis are shown in Staff Exhibit No. 114. As you
19 can see from Exhibit No. 114, even when you only include
20 the terminal value, the Benchmark Resource will cost
21 customers nearly $160 million less than the closest
22 competing bid.
23 Q.On page 77 of his testimony, Mr. Sterling
24 describes why he thinks the Company chose Langley Gulch
BOKENKAMP, DI REB 21
Idaho Power Company
1 even though his Exhibit No. 113 shows that I I I I I I I I I had
2 the highest point score. Has Mr. Sterling correctly
3 described the Company's rationale for selecting Langley
4 Gulch?
5 A.Wi th one exception, yes.
6 Q.What is that exception?
7 A.I believe Mr. Sterling should have given
8 more recognition to the $ 95 million NPV difference in cost
9 to customers between I I I I I I I I and the Benchmark Resource.
10 Q.In his rebuttal testimony, Company witness
11 Porter describes an agreement to provide an incentive to
12 the Company's EPC contractor to complete the Langley Gulch
13 project in the summer of 2012. I I I I I I I I I I I I I I I I I I I I I I I I II I
14 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I Will this
15 payment adversely affect the cost effectiveness of the
16 Langley Gulch project?
17 A.No.
18 Q.Are there other considerations the
19 Commission should consider in assessing the Company's
20 decision to select the Langley Gulch proj ect.
21 A.There are several other reasons why the
22 Langley Gulch proj ect provides superior value to Idaho
23 Power's customers. Not only is it the lowest cost proposal
24 by at least a $95 million NPV difference in revenue
BOKENKAMP, DI REB 22
Idaho Power Company
1 requirements, there are additional benefits associated with
2 Idaho Power owning the Langley Gulch proj ect. One is
3 flexibili ty in operations and maintenance. As the owner
4 and operator of the facility, Idaho Power will have a high
5 degree of flexibility in scheduling plant operations and
6 maintenance without contractual obligations associated with
7 a PPA or a TA. In addition to the operational flexibility,
8 Idaho Power would also have the ability to use personnel at
9 other Company-owned facilities if Langley Gulch was off-
10 line for an extended amount of time due to market
11 conditions, such as during spring runoff.
12 Another advantage associated with owning the
13 generation facility is the ability for the Company to
14 install cost-effective efficiency upgrades to the facility
15 as they become available. Since Langley Gulch will be a
16 Company-owned facility, the benefits of any efficiency
17 improvements will flow through to customers. If a
18 developer owned the facility and a fixed heat rate tolling
19 agreement was in place, the benefits of efficiency
20 improvements would be retained by the developer.
21 Finally, developing the Langley Gulch proj ect
22 provides the Company with an option to add additional
23 generation facilities at the site at some point in the
24 future.
BOKENKAMP, DI REB 23
Idaho Power Company
1 Q.On page 63 on lines 10-16 Mr.Sterling
2 discusses sub-synchronous resonance ("SSR") .What is SSR?
3 A.SSR is an electrical condition that can
4 cause severe damage to a turbine generator's main rotating
5 shaft.It is caused by the interaction between the
6 electrical resonance of the transmission system and the
7 mechanical resonance of the turbine generator shaft.
8 Q.Wi th that background, is there anything in
9 Mr. Sterling's discussion of SSR that should be clarified?
10 A. Yes, there are a few details that should be
11 clarified. First, the IIIIIIIII amount cited by Mr.
12 Sterling included on line 47 of the Commitment Estimate is
13 intended to cover both the study to see if SSR is an issue
14 and, if it is, the cost of implementing mitigation measures
15 if necessary and station communication costs. The
16 mitigation measures may include a generator tripping scheme
17 to trip the generator if sub-synchronous resonance is
18 detected, or a protection scheme to bypass the series
19 capacitors at Ontario under certain system conditions.
20 Q.On pages 7 and 8 of his testimony on behalf
21 of the ICI P, Dr. Reading argues that the Company's decision
22 to change the forecast of natural gas prices may have
23 eliminated some potentially lower cost facilities from
24 bidding.Is this criticism reasonable?
BOKENKAMP, DI REB 24
Idaho Power Company
1 A.i f bidders with lower cost facilities were
2 interested in the RFP, it seems to me they would have a
3 strong incentive to bid into the process anyway. The same
4 gas price forecast was used to evaluate all proposals so,
5 in that regard, gas price was a neutral factor. Also,
6 bidders were not precluded from bidding multiple
7 technologies, as some bidders did.
8 Q.On pages 9 and 10 of his ICIP testimony, Dr.
9 Reading comments on the way the evaluation team reached
10 consensus on the non-price attributes of the bids and the
11 importance of the non-price attributes in the evaluation.
12 Could you please respond to his criticism?
13 A.That part of Dr. Reading's testimony
14 addressing the importance of non-price scoring is a
15 hypothetical construct that is not very meaningful.
16 Admittedly, non-price scoring is somewhat subjective. As
17 noted in my direct testimony, with less than 2 points
18 separating the non-price scores of the short-listed
19 combined cycle projects, the non-price scores really were
20 not a significant differentiator.
21 Q.On page 16 of his ICip. testimony, Dr.
22 Reading quotes from a letter from TransCanada in which
23 TransCanada explains I I II I I I I I I I I II I I I I I I I I I I I I I I I I I I I I I III
24 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I
BOKENKAMP, DI REB 25
Idaho Power Company
1 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I II I I I I I I I I I I I I I I I I I II I I I I
2 I I I II I I I I I I II I I I I I I I I I I I I I I I I I I I I I II I I I I I I II II I I I I II I I I I I I I
3 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I II I I I I I I I I I I I I I I I
4 11111111111111111111) Do you believe these criticisms by
5 TransCanada are legitimate?
6 A.No. Regarding the first point, the
7 Company's document Response to Questions Raised a t the May
8 8, 2008 Pre-Bid Meeting that was posted on Idaho Power's
9 website, discussed the projected deficit in 2012 and noted
10 this deficit was the principal reason that Idaho Power
11 decided to include a self-build baseload generation
12 resource as one of the al ternati ves to be evaluated in the
13 RFP. With the need for an additional resource in 2012, and
14 no firm assurance at that point that any bids would be
15 recei ved, the Company needed to secure equipment to ensure
16 that a resource could be developed and on-line by 2012.
17 TransCanada's letter confirms the correctness of the
18 Company's decision to secure equipment.
19 This question of equipment transfer was further
20 addressed in response to question No. 3 of the 2012
21 Baseload RFP Questions & Answers document that was posted
22 on Idaho Power's website. The Company indicated that it
23 was not offering the Benchmark Resource equipment to other
24 bidders to maintain its flexibility to select multiple
BOKENKAMP, DI REB 26
Idaho Power Company
1 proposals if agreements with potential new large load
2 customers were finalized during the term of the RFP. The
3 2012 Baseload RFP stated that Idaho Power anticipated
4 acquiring between approximately 250 MW and 600 MW of
5 dispatchable energy. The range in the quantity of
6 dispatchable energy to be acquired was related to the
7 uncertainly associated with potential new large loads
8 locating in Idaho Power's service terri tory. Addendum 1 to
9 the 2012 Baseload RFP, dated June 25, 2008, revised the
10 quantity to approximately 300 MW. Subsequently, by not
11 offering the equipment to other developers before the
12 conclusion of the RFP process, Idaho Power retained the
13 option to use this equipment to build a second plant if new
14 large loads materialized.
15 Q.Did Idaho Power have the contractual right
16 to commit to transfer the equipment?
17 A.No. Mr. Porter addresses the contract
18 issues associated with equipment assignment in his rebuttal
19 testimony.
20 Q.What about TransCanada's stated concern that
21 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I
22 IIIII?
I I I I I I I I I I I I I II I I I I II I I II I I I I I I I I I I I I II I I I I I
24 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I
23 A.
BOKENKAMP, DI REB 27
Idaho Power Company
1 That is simply false. All bidders participating in
2 this RFP had a chance to win. The fact that the Benchmark
3 Resource was ultimately selected was because it had the
4 lowest evaluated cost of the proposals considered in the
5 final evaluation, and because of the value it provides to
6 customers. The costs that the Company incurred to reserve
7 and purchase equipment did not benefit the Benchmark
8 Resource and they did not penalize any of the other
9 proposals. The reservation charges can be compared to an
10 insurance policy premium - in this case, it was the premium
11 the Company incurred to ensure it could have a resource on-
12 line in 2012.
13 Q.On page 19 starting on line 11 of his ICIP
14 testimony, Dr. Reading opines that it would not be a
15 prudent business practice for a potential bidder to
16 purchase equipment prior to knowing whether or not it would
17 be successful. If he is correct, how were the two other
18 short-listed bidders, 1IIIIIIIIIIIIIIIIIIIIIIable to bid
19 into the RFP?
20 A.I suppose the answer to that question
21 depends on the bidder, their financial capability, and
22 their view of the future. If a bidder is serious about
23 developing proj ects and they believe equipment prices are
24 low, they might consider purchasing equipment (or reserving
BOKENKAMP, DI REB 28
Idaho Power Company
1 a slot in the manufacturing queue) to ensure equipment
2 availability for future development opportunities to be a
3 prudent business decision. I I I I I I I I I I I I I I I I I I I I I both made
4 the short-list and both already owned equipment they were
5 bidding into the process. Additionally, developers may
6 have existing relationships with manufacturers, providing
7 them access to equipment.
8 Q.If Dr. Reading is correct that independent
9 developers are unlikely to secure equipment prior to
10 winning a bid, doesn't that support the Company's argument
11 that Idaho Power had to move forward and reserve equipment?
12 A.Yes. But more importantly, Dr. Reading's
13 testimony illuminates the principal difference between
14 regulated utili ties and generation proj ect developers.
15 Idaho Power is legally obligated to serve loads so it must
16 act prudently to ensure resources are available even if
17 that means taking some financial risk. Developers do not
18 have that obligation to serve so they can wait to see if
19 their proposal is selected before committing to purchase
20 equipment.
21 Q.On the bottom of page 19, Dr. Reading opines
22 that if the other bidders had known that the proj ect could
23 be delayed six months, the extended deadline may have
24 changed the results of the prices of the bidding process.
BOKENKAMP, DI REB 29
Idaho Power Company
1 Did the Company do anything to address that issue when it
2 extended the on-line date?
3 A.Yes. The Company contacted all of the
4 short-listed bidders to determine the price impact on their
5 proposal if the project was delayed six months from June
6 2012 to December 2012. Both of the bidders responded that
7 delaying the proj ect for six months would not change their
8 pricing.
9 Q.Dr. Reading recommends that the Commission
10 deny the Company's CPCN, complete the 2009 IRP process,
11 develop new rules for conducting RFPs and redo the bidding
12 process. If the Commission accepted Dr. Reading's
13 recommendation, how would that affect the Company's ability
14 to serve future loads?
15 A.I am very concerned that if the Commission
16 accepts the Industrial Customers' recommendation, it could
17 have serious adverse consequences for both the Company and
18 its customers. The ICIP proposal will build substantial
19 delays into a process of acquiring a new baseload resource,
20 which will in turn compromise the Company's ability to
21 provide necessary capacity and energy during 2012 and
22 beyond. If any unanticipated events, such as transmission
23 outages, or generator outages, occur during the period of
24 shortage, load curtailments are certainly possible.
BOKENKAMP, DI REB 30
Idaho Power Company
1 Q.Why do you say that acceptance of Dr.
2 Reading's recommendation would build delay into the
3 resource acquisition process.
4 A.Dr. Reading, in his testimony on behalf of
5 NIPPC, frequently refers to the Oregon Competitive Bidding
6 Guidelines and indicates that the Oregon Guidelines ensure
7 the bidding process is fair for all parties. Although Dr.
8 Reading recommends that the Idaho Commission establish its
9 own guidelines that apply to future resource acquisitions,
10 his testimony implies that the Oregon Competi ti ve Bidding
11 Guidelines provide a good model for the Commission to
12 follow if it determines thatCompeti ti ve Bidding Guidelines
13 are needed in Idaho. I participated in the Oregon
14 Competitive Bidding Guideline development process in Oregon
15 (Docket No. UM 1182). This process was initiated with a
16 filing on December 3, 2004, and concluded with an Order on
17 August 8, 2006, taking over a year and a half to complete.
18 Once the Guidelines are in place, they substantially
19 lengthen the amount of time it takes to conduct an RFP. As
20 Mr. Gale noted in his rebuttal testimony, when PacifiCorp
21 conducted an RFP for a 2012 baseload resource under the
22 Oregon Guidelines, after two and a half years it withdrew
23 the RFP prior to completion of the case.
BOKENKAMP, DI REB 31
Idaho Power Company
1 Based on the Langley Gulch schedule, nearly three
2 years for design and construction will be required after
3 the winner is selected. In my judgment, if the Commission
4 adopts the ICIP's recommendation and we start the process
5 allover again with new bidding guidelines, there will be a
6 considerable delay in the process of acquiring this
7 resource. If it takes a year to develop the guidelines,
8 two years to complete the RFP process and approximately
9 three years for proj ect design and construction, a resource
10 like Langley Gulch would not be on-line and available to
11 serve customer loads before mid-2015.
12 Q.Would that be a problem for the Company and
13 its customers?
14 A.Yes. Idaho Power's load resource balance in
15 2012 is already tenuous. Waiting three to four years to
16 add a baseload resource will increase .those risks
17 substantially. In addition, it will compromise the
18 Company's ability to integrate wind and other intermittent
19 resources if they continue to develop at the pace Idaho
20 Power expects to see.
21 Q.Does that complete your testimony?
22 A.Yes.
BOKENKAMP, DI REB 32
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-09-03
IDAHO POWER COMPANY
BOKENKAMP, 01 REB
TESTIMONY
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