ML20153F668
| ML20153F668 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 02/24/1988 |
| From: | Boucher R UTAH POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML20153F598 | List: |
| References | |
| NUDOCS 8805110020 | |
| Download: ML20153F668 (62) | |
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Exhibit B r
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UNITED STATES OF AMERICA BEFORE THE NUCLEAR REGULATORY COMMISSION IN THE MATTER OF THE
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EXHIBIT B to Facility APPLICATION-OF PACIFICORP
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Operating License No. NPF-1 FOR CONSENT TO THE TRANSFER )
Indemnity Agreement No. B-78 OF LICENSES
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REBUTTAL TESTIMONY OF RODNEY M.
BOUCHER I
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Exhibit 207 y
b UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Utah Power & Light Company
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PacifiCorp
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Docket No. EC88-2-000 PC/UP&L Merging Corp.
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REBUTTAL TESTIMONY OF RODNEY M. BOUCHER ON BEHALF OF UTAH POWER & LIGHT COMPANY PACIFICORP PC/UP&L MERGING CORP.
February 24, 1988
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SUMMARY
OF REBUTTAL TESTIMONY OF RODNEY M. BOUCHER ISSUES ADDRESSED 1.
Competition in the Bulk Power Markets A.
Criteria for Evaluating Merger 1.
Idaho Power Witness Hughes, p. 9 (Ex. 84)
B.
Appropriateness of Merger Conditions 1.
Idaho Power Witness Hughes, p. 78, (Ex. 84) 2.
UMW Witness Russell, p. 17, (Ex. 20)
C.
Selection of Generation and Transmission Markets 1.
Idaho Power Witness Hughes, pp. 27-23, 42 (Ex 84)
D.
Efficiency of Buy-Sell Transactions 1.
Idaho Power Witness Hughes, pp. 32, 54, 47-58 (Ex. 84) 2.
UMW Witness Russell, pp. 18-19, (Ex. 20)
E.
Viability of Pacific Intertie 1.
Idaho Power Witness Hughes, pp. 33, 37 (Ex. 84)
F.
Merged Company's Ability to Control Market 1.
Idaho Power Witness Hughes, pp. 27-28, 33, 38-39,48-49 (Ex. 84)
G.
Assessment of Proposed Conditions 1.
Idaho Power Witness Hughes, p. 78 (Ex. 84) 2.
UMW Witness Russell, p. 17 (Ex. 20) 2.
1980 Transmission Services Agreement between Idaho Power and Pacific Power A.
Contract Disputes are not Merger Issue 1.
Idaho Power Witness Crowley, p. 25 (Ex. 69)
B.
Violation of TSA i
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R. M. Bouchor 2
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Idaho Power Witness C r'o w l e y, pp. 26, 32-33 (Ex. 69)
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2.
Idaho Power Witness Collingwood, p. 11, (Ex. 67) 3 3.
Idaho Power Witness Casazza, pp.
8, 13, 16, 51 (Ex. 51)
C.
Need for Additional Transmission 1.
Idaho Power Witness Crowley, p. 26 (Ex. 69) 2.
Idaho Power Witness Casazza, pp. 6, 24 (Ex. 51)
D.
Dynamic Scheduling and Overlay 1.
Idaho Power Witness Collingwood, pp. 10-12 (Ex. 67) 2.
Idaho Power Witness Casazza, p. 33 (Ex. 51)
E.
Integrated System Operation 1.
Idaho Power Witness Casazza, p. 16, (Ex. 51) 3.
Changes in Operation Due to Merger A.
Adverse Affect on Idaho Power System 1.
Idaho Power Witness Collingwood, p. 3 (Ex. 67) 2.
Idaho Power Witness Casazza, pp. 6, 8 (Ex. 51)
B.
Loop Flow 1.
Idaho Power Witness Casazza, p. 28 (Ex. 51)
C.
Proposed Transmission Additions 1.
Idaho Power Witness Casazza, p. 28 (Ex. 51) 4.
Alternatives to Merger A.
Contracts and Pooling 1.
UMW Witness Russell, p. 41 (Ex. 20) 5.
Integrated Service Areas A.
Reasonableness of Wheeling Policy 1.
UAMPS Witness Lim, p.18 (Ex. 49)
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CONTENT AND CONCLUSIONS Criteria for Evaluatina Merger The selected criteria distorts the relationship of the WSCC transmission system in relation to WSCC power markets.
Appropriateness of Mercer Condition
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The proposed merger conditions address National Policy issues that are unrelated to the merger and cannot~be settled in this proceeding without unfairly impacting the merging companies' ability to compete.
The proposed canditions are unacceptable.
Efficiency of Buv/ Sell Transactions Buy / sell transactions are a normal efficient and prudent utility practice employed by numerous utilities including some of the intervenors.
Viability of Pacific Intertie The Pacific Intertie is a traditional and viable transmission path for surplus Northwest Bulk Power whose viability and dominance is overlooked by the selection of transmission and generation markets.
Merged Comoany's Ability to Control Markets The merged company's market share and transmission system are dominated by much larger competitors and have little, if any, impact on market price.
Assessment of prooosed Conditions t
The proposed conditions will not accomplish the intended results, many of which are unreasonable and unrelated to the merger.
The proposed conditions would only advantage one or two other utilities and are self-serving.
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V R. M. Boucher 4
i Contract Disputes are not a Merger Issue The 1980 TSA disputes between Idaho Power and Pacific Power are not related to the merger.
The intervenors are using the merger process to obtain contract changes.
Violations of TSA Pacific Power has not violated the TSA and does not intend to after the merger.
Need for Additional Transmission The existing TSA and the proposed additions by the merged company are adequate to achieve the merger benefits.
Dynamic Schedulina Dynamic scheduling under the TSA was agreed to by Idaho Power and Pacific Power and is not impacted by the merger.
Dynamic Overlav Dynamic Overlay is a natural extension of the parties' intent to install automatic generation control at the Jim Bridger plant and does not adversely impact the Idaho Power system.
Integrated System Ooeration
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Pacific Power has operated an integrated system for years and the merger provides even greater integration.
The negotiation of the TSA was intended to provide such integration.
Adverse Affect on Idaho Power The merger will not adversely effect the Idaho Power system or other systems.
Changes due to merged system operations will be either insignificant or positive on other systems.
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R. M. Bouchar 5
Looo Flow The merged system operation will not significantly change loop flow in the WSCC system and will not adversely affect Idaho Power or other neighboring systems.
Proposed Transmission Addition The proposed transmission additions are adequate to achieve merger benefits and will not adversely impact neighboring systems.
Alternatives to Merger Contracts or Pooling alternatives cannot achieve all of the benefits of the merger and would take too long to achieve.
Integrated Service Areas The proposed wheeling policy is reasonable for wheeling services between Integrated Services Areas and will speed up requests for wheeling services within Integrated Service Areas.
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R. M.
Boucher 1
3 1
OUESTION 2
Please state your
- name, business address and 3
present position.
4 ANSWER 5
My name is Rodney M.
Boucher.
My business address 6
is 920 SW Sixth Avenue,
- Portland, Oregon.
I am Vice 7
President and Assistant to the President with Pacific Power 8
& Light Company (Pacific Power).
Until January 13, 1988, I 9
was Vice President of Power Systems.
10.
OUESTION 11 Are you the same Rodney M.
Boucher who sponsored 12 direct testimony in this proceeding?
13 ANSWER 14 Yes, I am.
15 OUESTION 16 What is the purpose of your rebuttal testimony?
17 ANSWER 18 I
will address the testimony of intervenor 19 witnesses Hughes, Crowley, Collingwood,
- Casazza, Russell, 20 and Lim in the following areas:
21 1.
Competition in the western interconnected 22 system bulk power market.
23 2.
The 1980 Transmission Services Agreement 24 between Pacific Power and Idaho Power.
25 3.
Change in system operation due to the marger.
26 4.
Contract / Pooling Alternative.
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Bouchar 2
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5.
Integrated Service Access.
2 QUESTION 3
Will you offer any exhibits in connection with 4
your testimony?
5 ANSWER 6
Yes.
I have one
- exhibit, Exhibit No.
- 208, 7
consisting of 13 Schedules.
8 SECTION 1 - Competition in the Western Interconnected System 9
Bulk Power Market 10 OUESTION 11 Do you have any general conclusions regarding Dr.
12 Hughes' testimony (Exhibit 84) in this proceeding?
13 ANSWER 14 Yes.
Dr. Hughes' definitive conclusions (Exhibit 15 84, pages 3,
- 4) are unsubstantiated.
He relies almost 16 exclusively on the testimony of other Idaho Power company 17 (Idaho Power) and Montana Power Company (Montana Power) 18 witnesses (Exhibit 84, pages 29, 34-35, 37-39, 51-52, 67, 19 70-71, 76, 90).
The testimony of the Montana Power and 20 Idaho Power witnesses is also unsubstantiated.
21 OUESTION 22 Do you agree with Dr. Hughes' selection of the 23 criteria for evaluating competitive aspects of the merger 24 (Exhibit 84, page 9)?
25 ANSWER 26 No.
Dr. Hughes has restricted his analysis of the
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R. M.
Bouchar 3
1 competitive aspects of the merger to a very narrow focus of 2
the competition between the merged company and just two 3
other utilities,
(Exhibit 84, page 29).
This is hardly a broad-enough focus 5
to make a determination of public interest.
6 OUESTION 7
Do you agree with Dr. Hughes' recommendations in 8
this proceeding (Exhibit 84, page 78)?
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9 ANSWER 10 No.
While certain aspects of Dr.
Hughes' i
11 testimony may be of interest to this Commission, Dr. Hughes' 12 conclusions are unsupported and his recommendations are far 13 beyond the scope of the merger process.
The transmission 14 access question is one of broad national concern and 15 consequences and must be resolved through a more compre-16 hensive and rigorous national policy forum.
17 OUESTION 18 Do you agree with Dr.
Hughes' assessment of 19 transmission paths (Exhibit 84, page 27)?
20 ANSWER 21 No.
Dr.
- Hughes, by casually disregarding the 22 Pacific Intertie and ignoring the Rocky Mountain to Desert 23 Southwest and the Desert Southwest to California / Southern 24 Nevada markets, has narrowed his focus to only a sliver of 25 the actual WSCC transmission paths (Exhibit 84, pago 28).
26 Dr.
Hughes would have this commission believe that Utah
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R. M.
Bouchar 4
1 Power's ownership of the 600 ' MW Pinto-Four Corners line 2
relative to the 5200 MW Ar. zona Interconnection with 3
California will soraehow operate to allow Utah Power to 4
control the California and Desert Southwest market prices 5
for bulk power and will block Northwest producers, who have 6
access to the Pacific Intertie, from the California market 7
(Exhibit 84, pages 33, 37).
Furthermore, while the Desert 8
Southwest has been an important historic market to Utah 9
Power and the Rocky Mountain utilities, the recent addition 10 of the three Palo Verde nuclear units has largely reduced 11 the significance of that uarket.
Additionally, it is 12 important to recognize that the Desert Southwest market has 13 not been and is not today a significant market for Northwest 14 utilities.
I can only conclude, therefore, that Idaho Power 15 and Montana Power are using the merger proceeding as an 16 opportunity to obtain access to new markets thereby 17 upsetting existing competitive relationships.
18 OUESTION 19 Do you have any comments on Dr. Hughes' selection 20 of the bulk power markets (Exhibit 84, page 42)?
21 ANSWER 22 Yes.
While I generally agree that the relevant 23 bulk power markets include one consisting of California and 24 southern Nevada, Dr.
Hughes has ignored other potential 25 customers such as Puget Sound Power & Light Company (PSPL),
26 which are accessible to all Northwest entities including
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1 Idaho Power ari Montana Power.
Certainly if_ Idaho Power's 2
and Montana Power's claims that they are low-cost Northwest 3
producers are valid, they should have the inside track 4
unless, of course, that market is not sufficiently lucra-5 tive.
From our discussions with PSPL, it would appear that 6
the PSPL power requirements could use up much of the Idaho 7
Power and Montana Power surplus.
Neither Pacific Power or 8
Utah Power _ have any control over Idahr
'ower and Montana 9
Power's access to PSPL.
10 OUESTION 11 Do you agree with Dr. Hughes that Southern Nevada 12 is isolated (Exhibit 84, pages 33, M -3 9, 49)?
13 ANSWER 14 No.
Nevada Power is strongly interconnected with 15 the Los Angeles Department of Water and Power at McCullough, 16 the California Department of Water Resources at Reid-17 Gardner, and Southern California Edison Company at Mead and 13 Hoover, all of which entities have shares of tne Pacific 19 Northwest-Pacific Southwest Intertie.
Nevada Power is also 20 strongly connected to Western Area Power Administration at 21 Mead and Hoover.
None of these interconnecting parties have 22 been willing to deliver Northwest energy to Nevada Power 23 except in a buy-resell mode.
To order the merged company to 24
- wheel, without so ordering other interconnected entities 25 with which the merged company competes, would be discrim-26 inatory and unfair.
Such an order could allow others to use
R. M.
Bouchor 6
1 the merged company's transmission system to dispose of their 2
surplus power leaving the merged-company without the 3
parallel opportunity to dispose of its power.
4 OUESTION 5
Do you agree with Dr. Hughes' conclusion that low-6 cost producers within the Northwest would be excluded from 7
California markets as a result of the merger (Exhibit 84, 8
pages 17-18, 22, 48-49)?
9 ANSWER 10 No.
Throughout Dr. Hughes' testimony he stressos 3
11 the importance of being able to make firm sales to the 12 California and southern Nevada markets, and implies that 13 low-cost producers in the Northwest can of fer lower-priced 14 firm long-term sales arrangements.
In my experience, being 15 a low-cost producer is generally relevant only in a nonfirm 16 market.
It is unreasonable to assume that just because a 17 utility has production costs that are competitive in the 18 nonfirm market, it would be willing to offer long-term 19 power sales arrangements based on production costs of its 20 lowest-cost resources.
If a utility were to enter into such 21 an arrangement, it would incur the wrath of its state 22 regulators and cuctomers by selling the low-cost generation 23 on a long-term basis to another utility while retaining 24 higher-cost generation to the detriment of its own rate-25 payars.
In the case of Idaho Power and Montana Power, I 26 would cxpect the prices of any long-term firm power sales
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R. M.
Boucher 7
1 arrangement to be ditimately based on the fully-distributed 2
cost of their highest-cost resources, such as the Valmy 3
generating plant of Idaho Power and Colstrip generating 4
plant of Montana Power.
Since those resources are compar-5 able to the highest cost resources owned by either of the 6
merging companies, the claims that the merger will prevent 7
the marketing of low-cost resources to California and 8
Southern Nevada is baseless.
Furthermore, the production 9
cost of Idaho Power's Valmy generation is substantially 10 higher than any of the merging companies' mine-mouth coal 11 generation as shown in Exhibit 208, Schedule 2.
12 QUEST.LQE 13 Do you agree with Dr. Hughes' assertion that the 14 merged company will have strong incentives not to buy lower-15 cost power from other utilities such as Montana Power and 16 Idaho Power (Exhibit 84, pages 22, 54, 57-58)?
17 ANSWER 18 No.
As stated many times in the Applicants' 19 testimony in this proceeding, the merged company intends to 20 operate all of its generation and transmissicn facilities as 21 a single system, with the objective of achieving at the 1
22 lowest net power cost.
Therefore, the Applicants will 23 purchase from other utilities when such purchases will f
24 reduce net power cost.
As indicated on pages 63-64 of his 25 Exhibit 84 Dr.
Hughes assessed the relative costs of 26 production facilities of Northwest entities and concluded
R. M. Bouchor 8
1 that the merging companies' resources generally had higher 2
production costs than the Idaho Power / Montana Power.
3 resources.
Therefore, if Northwest low-cost producers are 4
really low-cost producers, the merging companies will have 5
every incentive to purchase power f rom those entities in 6
order to displace their higher-cost thermal resources.
Only 7
by doing so can the merging companies minimize net power 8
cost.
Furthermore, for the merged company to do otherwise 9
would not be in the interest of its customers and would 10 impede the merged company's goal of maintaining its competi-11 tive position and stabilizing prices for its customers, 12 OUESTION 13 Is the intended operating scenario of the merged 14 company cost effective?
15 ANSWER 16 Yes.
While I am not an economist by education, I 17 do know what cost savings mean to our customers.
Dr. Hughes 18 goes to great lengths to hypothesize the impacts on the low-19 cost producers' customers and on the potential California 20 purchasers' customers, but totally ignores the impact of his 21 suggestions on customers of the merging companies (example, 22 Exhibit 84, pages 23, 58).
It seems unreasonable to me that 23 his conclusions of economic inefficiency could be reached 24 without consideration of the merging companies' customers.
25 OUESTION 26 On page 24 of his Exhibit 84, Dr. Hughes suggests
R. M.
B:uchcr 9
1 that Utah Power has historically purchased lower-cost power 2
from Northwest entities and resold it at a higher price to 3
California and Desert Southwest customers and suggest this 4
practice is somehow improper.
Do you have any comments on 5
that practice?
6 ANSWER 7
I find it hard to believe that Dr. Hughes would 8
find the practice of displacing higher-cost thermal 9
resources with lower-cost resources anythirg other than the 10 normal and prudent operation of an interconnected utility.
11 Furthermore, Dr. Hughes implies that Utah Power can control 12 the price in the California market even with its limited 13 ability to access that market.
Dr.
Hughes chooses to 14 ignore that, because of the availability of excess gener-15 ating capacity elsewhere, the nonfirm market in California 16 is and will continue for some time to be a buyers' market 17 where the price is dictated by the buyers' alternative 18 purchase opportunities out of the Northwest via the Pacific 19
- Intertie, the Desert Southwest, and various suppliers 20 generation within California itself.
Dr. Hughes would have 21 one believe that only the initial producer and the ultimate 22 buyer would have any right to enjoy the economic benefits of 23 a transaction when there are intervening utilities and that 24 any other practice is monopolistic.
25 OUESTION 26 Do you agree with Dr. Hughes' characterization of
R. M.
Boucher 10 1
such transactions as a masked wheeling charge (Exhibit 84, 2
page 54)?
3 ANSWER 4
Absolutely not.
To the extent that power 5
purchased from the Northwest producers is purchased at a 6
price less than the cost of producing the same amount of 7
power from a utility's their own thermal resources, such 8
transactions are merely the displacement und subsequent 9
sale of higher-cost resources.
Additionally, to the extent 10 that the subsequent sales price does not exceed the fully 11 distributed cost of those displaced thermal resources, then 12 the practice is common practice among utilities and well 13 within all reasonable regulatory expectations.
14 OUESTION 15 Do you agree with Dr. Hughes' characterization of 16 such a practice as a mechanism to avoid FERC regulation of 17 transmission profits (Exhibit 84, page 54)?
18 ANSWER 19 No.
The FERC has for many years endorsed the 20 split savings concept as a
pricing basis for economy 21 transactions.
Furthermore, it has been well documented in 22 the Applicants' testimony in this proceeding, that revenues 23 from such transactions by Utah Power flow directly back to 24 reduce not power cost and therefore the customers' cost.
25 Dr. Hughes attempts to characterize gains from these types 26 of transactions as "profits,"
thereby falsely implying that
R. M. Boucher 11 F
1 the revenues would flow to the stockholders.
o 2
OUESTION 3
Is Utah Power the only utility that engages in 4
simultaneous buy / sell transactions?
5 ANSWER 6
No.
My Exhibit 208, Schedule 2, consists of pages 7
extracted from the January 1988 Intercompany Pool (ICP) log 8
sheet.
It shows that at least Idaho Power and Montana Power 9
also engage in that practice.
I am aware of many other 10 utilities that engage in simultaneous buy-and-sell trans-11 actions.
12 QUESTION 13 Do you have any comments regarding what Dr.
14 Hughes' characterizes as Pacific Power's "Power Supply i
15 Business Plan," (Exhibit 84, page 88) which is included in 16 Dr. Hughes' Exhibit No. 90?
17 ANSWER 18 Yes.
What Dr.
Hughes characterizes as Pacific 4
i 19 Power's business plan was in reality a "white paper" that 20 was created for the sole purpose of investigating the feas-21 ibility of various potential changes in the internal 22 restructuring of Pacific Power.
It was aimed at increasing 23 the financial accountability of hypothetical power supply 24 and the distribution operating divisions, thereby creating 1
i 25 greater incentives for improved operations and efficiency.
t 26 As indicated in the last paragraph of the Executive Summary 7
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BouchOr 12 1
of that document, "a power supply entity is an evolutionary 2
concept that needs serious consideration before major 3
corporate restructuring is contemplated.
It is not clear at 4
this time what the best relationship is between power supply 5
and distribution functions of Pacific Power".
6 OUESTION 7
Has that "business plan" been adopted by Pacific 8
Power's management?
9 ANSWER 10 No.
11 OUESTION 12 Has Dr. Hughes adequately, addressed the Pacific 13 Intertie as a market path for Idaho Power and Montana Power?
14 ANSWER 15 No.
Dr. Hughes tends to gloss over the Pacific 16 Intertie as a transmission path for Montana Power and Idaho 17 Power, as being too restrictive to warrant consideration for 18 either firm or nonfirm transactions (Exhibit 84, page 37).
19 OUESTION 20 Have Idaho Power and Montana Power made signif-21 icant use of the Pacific Intertie in the past?
22 ANSWER 23 Yes.
During the period between 1982 anct 1986, 24 Idaho Power and Montana Power made annual sales over the 25 Pacific Intertie averaging 421,726 MWh and 372,894 MWh 26 respectively.
Exhibit No. 208, Schedule 3 of this testimony
R. M. Bouchor 13 1
shows the Pacific Intertie use during the period 1982 2
through 1986, for all users of the Pacific Intertie.
3 OUESTION 4
Was the Pacific Intertie fully utilized during
.5 this period from 1982 through 1986?
6 ANSWER 7
No.
Additional sales could have been made 8
utilizing this facility.
9 OUESTION 10 Considering the testimony of witnesses Crowley, 11 Miller and Durick, do you believe the Pacific Intertie will 12 be a viable path under Bonneville's proposed Long Term 13 Intertie Access Policy (LTIAP)?
14 ANSWER 15 Yes.
After numerous public meetings and viewing 16 comments from affected parties within the Pacific Northwest, 17 Bonneville has proposed significant changes to both the 18 firm and nonfirm access conditions contained in the initial 19 draft of the LTIAP.
Those changes, which are summarized in 20 Exhibit No. 208, Schedule 4, show that the future use of the 21 Pacific Intertie under tne LTIAP can be expected to be 22 essentially the same as historical usages.
Therefore, it 23 is reasonable to expect that both Idaho Power and Montana 24 Power will continue to have nonfirm access to the Pacific 25 Intertie in accordance with historic allocation practices 26 and firm access which has not been previously available.
In
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fact,. depending upon the load resource balance of Idaho 2
Power and Montana Power and the diminishing surplus of other 3
Pacific Northwest utilities, it is entirely possible that 4
Idaho Power's and Montana Power's access to the Pacific 5
Intertie during most periods of the year could be con-6 siderably in excess of historic averages.
Exhibit No. 208, 7
Schedule 5 contains the results of a series of studies done 8
by the Pacific Northwest Utility Conference Committee 9
(PNUCC) regarding the monthly probability of the Pacific 10 Intertie being available for nonfirm transactions.
The 11 specific study was conducted for the year 1990 based on the 12 Northwest Regions' load and resource projections.
This 13
. study shows that by 1980, there is a very high probability 14 that the Intertie will be in conditions 2 or 3 during most 15 of the year.
Condition 3, which is unconstrained access for 16 Northwest utilities, is shown to have a probability of a
17 occurrence ranging from a minimum of 38% in February to a 18 maximum of 98.5% in August.
Condition 2, which is a formula 19 allocation pro rates to each Northwest utility' desired 20 access, if shown to have a probability of occurrence ranging 21 from 0% in August to 57.5% in February.
it is clear that 22 there will be ample opportunity for nonfirm sales using the 23 Pacific Intertie.
24 OUESTION 25 Is firm transmission access available on the 26 Pacific Intertie?
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ANSWER 2
Dr. Hughes dismisses access under the LTIAP as 3
uncertain and risky (Exhibit 84, page 88), notwithstanding 4
the fact-that both Montana Power and Idaho Power have 5
Exhibit B allocations under the policy which may be used to 6
consummate firm sales with California utilities.
In fact, 7
Montana Power's
- witness, Mr.
Miller on page 3
of his 8
testimony (Exhibit 64) indicates tha*.
he is virtually 9
certain that he will receive at least 105 MW of firm 10 Intertie access to consummate a sale with the Los Angeles 11 Department of Water & Power in California.
It is inter-12 esting to note that BPA has given Pacific Power zero Exhibit 13 B allocation under the LTIAP, because Pacific Power has 14 invested in its own access path to the California utilities.
15 It is ironic to note that if the recommendations of Dr.
16 Hughes were adopted, and the merging companies were required 17 to grant Montana Power and Idaho Power transmission service 18 that resulted in access to California utilities, under the 19 rules of Bonneville's LTIAP, they would lose their Exhibit 20 B allocations to the extent that such new access exceeded 21 these Exhibit B allocations under the LTIAP.
As shown in 22 Exhibit 208, Schedule 6,
which is a copy of the Exhibit B 23 from BPA's latest draft
- LTIAP, Idaho Power has been 24 allocated 87 MW of firm Intertie access and Montana Power 25 has been allocated 105 MW.
R. M. Bouchor 16 1
OUESTION 2
can you explain why BPA has selected the specific 3
MW values in Exhibit B?
4 ANSWER 5
BPA has calculated the Exhibit B numbers to equal 6
each utility's existing regional firm energy surplus using 7
data furnished by Northwest utilities to regional planning 8
groups such as the PNUCC.
BPA has indicated that it 9
belit.ves such firm energy surplus amounts are reflective of 10 each Northwest utility's firm access needs.
11 OUESTION 12 On page 37 of Exhibit 84, Dr. Hughes implies that i
13 Pacific Power has some degree of control over Northwest 14 utilities' ability to access the Pacific Intertie.
Is this 15 correct?
16 ANSWER 17 No.
Both Idaho Power and Montana Power are 18 directly interconnected with the Bonnevilla Power Admin-19 istration and have direct access to the Intertia Via those 20 interconnections.
21 OUESTION 22 Has Idaho Power been a consistent advocate of firm 23 market access?
24 ANSWER 25 No.
In meeting to discuss Bonneville's Interim 26 and Near-Term Intertie Access Policies which preceded the
R. M. B:uchar 17 1
LTIAP, Idaho Power argued that nonfirm access to the Pacific 2
Intertie should have a priority over firm access.
Pacific 3
Power and others argued that firm access to the Intertie 4
should have a priority over nonfirm.
j 5
OUESTION 4
.6 Given the testimony of the witnesses in this 7
proceeding, has Idaho Power Company changed its -focus 8
regarding access to the California market?
9 ANSWER 10 Based on this testimony, yes.
Despite its 11 position of being a
low-cost producer in the Pacific 12 Northwest, and the substantial mark-up by Idaho Power on
~ 13 nonfirm sales associated with existing hydroelectric 1
14 facilities, Idaho Power has apparently decided that such 15 margins were not sufficient and has elected to focus on 16 apparently more lucrative longer-term firm sales.
It is 17 obvious that both Montana Power and Idaho Power have elected 18 to attempt to use the merger proceeding as a vehicle for 19 access to new markets.
l 20 OUESTION 21 On page 60 of Exhibit 84, Dr. Hughes argues that 22 operation of the merged system resources will create a l
23 higher nonfirm market price in California.
Do you agree?
24 ANSWER 25 No.
Dr. Hughes' argument would only be valid if 26 the merged company were the only seller or the dominant
r R. M.
Bouchar 18 1
seller to California. Dr. Hughes ignores the fact that the 2
merged company will own only a small share of market access 3
capability and he fails to recognize that the merged 4
company will face intense competition from the Desert 5
Southwest, from the Pacific Northwest, and from California 6
utilities' own resources.
It is completely unreasonable to 7
assume that the limited access to California-owned utilities 8
by the merged company through the Desert Southwest would 9
allow the merged company to control the market price.
In 10 re.ality, the California nonfirm market is, and will continue 11 to be for the foreseeable future, a buyer's market where the 12 price will be a function of the buyer's avoidable cost or 13 the price set by the much larger competitors for that 14 market.
Dr.
Hughes then asserts that the purchasing 15 practices of the merged company would be a form of waste 16 caused by the substitution of the merged company's higher-17 cost resources for Idaho Power and Montana Power's lower-18 cost resources.
In fact if the low-cost producers will sell 19 to the merged company at a price which will allow displace-20 ment and resale of its more-expensive resources, then for a 21 given market, the operation of the total resources for the 22 merged company and the low-cost producer would be exactly 23 the same.
In that event, the real issue is the sharing of 24 the revenues associated with the total transaction since 25 the sale price to California would be the same regardless of 26 who was the producer.
I.
R. M. BouchOr 19
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QUESTION 2
On page 67 of Exhibit 84, Dr. Hughes indicates
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3 that Montana Power has resources other than Colstrip 4 that 4
it will seek to market once it has sold all of the Colstrip 5
4 capacity.
Do you agree with this?
6 ANSWER 7
This conclusion seems to be at odds with the load 8
and resource data submitted by Montana Power to the ICP Load 9
and Resource Committee.
According to this data, which is t
10 enclosed as Exhibit No. 208, Schedule 7, Montana Power will l
11 be substantially in load resource balance once it has 12 disposed of its Colstrip 4 capacity and energy.
13 OUESTION 14 On page 75 of Exhibit 84, Dr. Hughes implies that 15 Montana Power and Idaho Power are low-cost producers of 16 firm bulk electricity based on the premise that a low-cost 17 seller is characterized by low operating
- costs, ample 18 capacity availability, and ability to expand capacity 19 through low-cost increments to the system.
Is this 20 consistent with your understanding?
[
21 ANSWER 22 Dr. Hughes apparently bases this assertion on the 23 resource plan included in Mr. Crowley's workpapers.
It is 24 impossible to determine from those workpapers whether the 25 planned resources listed in that plan are low cost or high 26 cost.
Mr.
Crowley gives no clue as to the cost of the i
I
R. M. Bsuchcr 20 1
resources in that plan.
In fact, his testimony does not 2
even reference the plan.
I am not aware of what low-cost 3
increments are available to Montana Power and Idaho Power.
4 Based on my understanding, their most recent resource 5'
additions were the relatively high-cost resources of Valmy 6
Nos. 1 and 2 and Colstrip Nos. 3 and 4.
Neither of these-1 7
resources fit Dr.
Hughes' characteristics of low-cost 8
increments.
Furthermore, the Valmy and Boardman coal-fired 1
9 generating plants of which Idaho Power owns a 313 MW share 10 are among the Northwest region's highest operating cost 11 energy sources.
Mr.
Crowley's testimony fails to give 12 enough information to determine the impact of such high cost 13 energy sources on their claim to be a low-cost producer in 14 wholesale sales.
Based on our understanding of the Valmy 15 and Boardman generating plants, we believe tnis production 16 cost to be currently $22-24 per MWh.
Additionally, it is 17 notable that the Idaho PUC has not allowed Idaho Power's 125 18 MW share of Valmy No. 2 to be included in rate base and 19 therefore that cost is not included in the Average System 20 Cost (ASC) comparison in Mr.
Crowley's testimony.
The 21 absence of rate-base treatment of Idaho Power's Valmy No. 2 l
l 22 and Montana Power's Colstrip No.
4 will be a
strong 23 incentive to market these resources.
24 OUESTION i
25 Do you have any comments on Dr. Hughes' suggested 26 remedios to his perceived lack of competition (Exhibit 84, l
i
j{
R. M. Bsuchor 21 1
page 78)?
2 ANSWER 3
Dr. Hughes' assessment of upstream and downstream 4
competition impacts associated with the merger, he failsEto 5
acknowledge that the adoption of his proposed mandated 6
access to the merged company's transmission system would, in 7
fact, merely shift the alleged market control he has given
?
8 to.the merged company upstream to Idaho Power.
His proposed 9
conditions indicate tnat access would be available only to 10 utilities that interconnect with tha northern and of the 11 existing Utah Power system.
A simple inspection of appro-12 priate maps shows that, except for a connection of limited
]
13 capacity with Montana Power, the only utility that directly 14 interconnects with the north end of the Utah Power system is 15 Idaho Power.
Therefore, the result of Dr. Hughes' perceived 16 "fix" would be to concentrate control of access to the 17 Desert Southwest in the hands of Idaho Power and owners of 18 the Four Corners' substation--a position that Utah Power, 19 Idaho Power and such owners of Four Corners currently share, 20 as it relates to access by other low cost Northwest 21 producers.
It could be argued that under such a scenario 22 Idaho Power, as a low-cost producer, would have substantial-23 ly less incentive to purchase from other low-cost Northwest 24 producers than does the merged company.
l 25 OUESTION 26 If Dr. Hughes' proposed 300 MW allocation (Exhibit
R. M. Bouchor 22 1
84, page 84) were adopted by the Commission, would this 2
cause harm to the merged company's operations?
3 ANSWER 4
Yes.
Such an allocation of transfer capability 5
through the Utah Power system would severely curtail the 6
ability of the merged company to utilize its own resources 7
in an efficient manner.
As discussed in Mr.
Tucker's 8
testimony, there is limited transmission capability north of 9
' Ben Lomond.
The 300 MW would limit the merged company's 10 ability to use the enhanced interconnection capability 11 discussed in my direct testimony, Exhibit 8.
Additionally, 12 while Dr. Hughes never clearly comes out and states how the 13 300 MW would be used, it is apparent from his description of 14 what he defines as the bulk electricity market, that such
~
15 use would include seasonal' exchanges, economy transactions 16 in both directions through the Utah Power system, unit 17 contingent sales, emergency capacity arrangements, etc.
A 18 transfer of 300 MW from south-tc-north through the Utah l
19 Power system could impact the ability to operate the Utah 20 Power system in an efficient, reliable manner during certain 21 seasons and also would likely preempt traditional and future 22 economic uses by Utah Power for its customers.
23 OUESTION 24 Please comment on the proposed transmission 25 conditions as described in Dr. Hughes' Exhibit 94 and his 26 summary of such conditions, starting on page 84 of his
J!ch t
R._M. Bouchsr 23 1
testimony (Exhibit 84).
2 ANSWER 3
The proposed conditions are completely inap-1 4
propriate and unacceptable ~to the merging coinpanies.
Dr.
5 Hughes' conclusions as represented by his proposed condi-6 tions are completely arbitrary, unsupported by any factual 7
evidence, have not been shown to be in the public interest, 8
and are narrowly drawn to benefit only one entity, Idaho
[
f 9
Power and to a limited extent, Montana Power.
While Exhibit.
10 No. 94 is attached to,Dr. Hughes' testimony, the conditions 11 in that Exhibit go far beyond the general conditions i
12 discussed by Dr.
Hughes in his testimony.
The imple-13 mentation of the condition in that exhibit would give 14 virtual ownership of 300 MW of Utah Power's transmission 15 system to Idaho Power rather than merely permitting Idaho 16 Power to sell firm power to a buyer for an interim period of 17 time.
18 OUESTION 19 Do you believe that Dr. Hughes' proposed trans-20 mission conditions
- would, in
- fact, encourage as he 21 suggests -- the construction of new facilities by the merged 22 company?
23 ANSWER 24 No.
It is obvious in Condition No.
7 of the 25 preposed merger conditions that the proponents of such 26 conditions have in mind that the transmission charge
i f
R. M. Bouchor 24
~
l 1
associated with the 300 MW allocation would be embedded cost E
2 ra *.e s.
I cannot envision a set of conditions that would be i
3
.a greater disincentive for the merged company to construct j
l 4
additional transmission interconnections to the Southwest.
5 One of the significant public benefits this merger engenders 6
is the development of new transmission to improve the i
7 economics of the interconnected system.
This would be 8
undermined by such a condition.
9 OUESTION 10 Do you have any comments on Mr.
Whitfield l
11 Russell's prepared testimony in this proceeding?
12 ANSWER 13 Yes.
As is the. case with a number of other i
14 intervenor witnesses in this proceeding, Mr. Russell would 15 have this Commission impose Jertain conditions on the merged l
i 16 company related to transmission access (Exhibit 20, page 17 17).
As I have previously testified, I believe that the la imposition of novel transmission requirements on the merging i
19 companies just because they are merging, would be unfair and i
20 would undermine the merged company's ability to compete.
21 Transmission access is an issue of National importance, and i
I 22 will be thoroughly aired before the FERC under its Notice of 23 Inquiry or cther generic proceed $ags.
This proceeding is 24 neither the t 42e nor the p' acc to take on an issue such as 25 transe' m accent. befc.e all et "a
ramifications of such i
l 26 acces
. thoroughly dissum and all consequences t
I 1
i 1
s.
- - - -.w.
i.
R.~M. Bouch0r 25 I
1 are understood.
2 OUESTION 3
In addition to your opposition to Mr. Russell's
^
4 proposed conditions, do you have any specific comments on 5
his recommendations?
6 ANSWER 7
Yes.
On page 17 of his testimony (Exhibit 20),
8 Mr. Russell asserts that his proposed transmission condi-9 tions are intended to address the problems of bulk power 10 marketing in the WSCC region which he characterizes as 11 having extremes of open access on the one hand and "stifling 12 monopoly" on the other hand.
Additionally, he asserts that 13 his conditions are intended to address loop flow problems, 14 which he asserts are mostly the result of utility scheduling 15 practices and the absence of a utility obligation to wheel.
16 Incredibly, Mr. Russell seems to believe that the narrow 17 focusing of his proposed conditions on the merging companies 18 will somehow cure the problems he perceives within the 19 entire WSCC bulk power marketing region.
Mr.
Russell's 20 allegations are completely unsubstantiated.
21 OUESTION 22 Do you have any comments on Mr.
Russell's 23 characterization of marketing arrangements within the WSCC 24 area?
25 ANSWER 26 Yes.
I would like to comment on each of his seven
e q
f I.
R. M. Bouch0r 26 I
1 points, starting on page 18, Exhibit 20, with item 1:
With 2
regard to Mr. Russell's comments on low-cost power trapped 3
in the Northwest, I am confident that Bonneville and most E
4 Northwest utilities will not object if the merger creates a 5
market for such trapped power and will avoid spill on the 6
Columbia River system.
To the extent that such new market 7
will enhance sales by Bonneville or other Northwest 8
utilities, all Northwest ratepayers will benefit.
9 With regard to item 2 on page 18:
It is difficult 10 to understand Mr. Russell's point in this item in that, when 11 BPA has surplus hydro available and is willing to sell it to 12 either Pacific Power or Utah Power, it is only done when all 13 Bonneville preference markets have been satisfied.
Mr.
14 Russell appears to believe that the use of such surpluses to 15 displace higher-cost thermal generation is somehow contrary 16 to the intent of federal law.
I conclude that Mr. Russell l
17 would rather have Bonneville spill such low-cost power 1
18 rather than sell it to either of the merging companies.
19 Page 19, item 3:
Mr. Russell asserts that the I
20 merger will upset existing Northwest patterns for sharing 21 sales to the Southwest over the Pacific Intertie.
The 22 proposed merger will have absolutely nothing to do with how 23 BPA shares sales to California over the Pacific Intertie.
24 Page 19, item 4:
As indicated by Mr. Russell in 1
25 item 3,
those same regional preference entities in the 26 Northwest also have access to BPA's share of the Pacific
.,_--,,,.,.n..-.
,_.-r
-,,-,,,, -.. - -. _ _.,,,,.,,,,. _ _,, _, _ -, ~
R. M. Bouchar 27 i
1 Intertie for sales to California.
2 Page 20, item 5:
Mr. Russell provides no ev!.dence 3
for his allegation regarding wheeling, and attempts to 4
characterize the displacement of higher-cost thermal 5
generation through purchases from the Northwest entities as 6
an unacceptable practice.
7 Pago 20, iteni 6:
Mr. Russell asserts that the 8
proposed new transmission line interconnection with Nevada 9
Power Company (Nevada) will "bypass the loop flow bottlencck 10 at Four Corners."
While Nevada may ultimately extend the 11 345 kV line to interconnect with major California utilities, 12 the initial construction of the Nevada interconnection will 13 not do so.
Additionally, the proposed Nevada intercon-14 nection will be installed with phase shif ting transformers
'15 that will prevent the interconnection from being either 16 contributing to or being affected by loop flow in the 17 interconnected WSCC system.
The proposed Nevada intercon-18 nection, as currently designed, has absolutely nothing to 19 do with the Southern California Edison Company purchasing 20 practicos.
21 Page 21, item 7, Exhibit 20:
Mr. Russell implies 22 that additional interconnections are planned from Utah 23 Power's service areas that will advantage the merged 24 company.
While numerous new transmission lines in the 25 Utah / Nevada / Idaho areas are being discussed by a number of 26 utilities, any such new lines will undoubtedly be a joint
R. M.
Bouchor 28 1
project with participation by a number of entities, not just 2
the merging companies.
3 QUESTION 4
on page 17 of Mr.
Russell's testimony (Exhibit 5
20),
he alleges that the merger will result in some 2
6 unwarranted benefit to the merged company at the expense of 7
its customers.
Is this correct?
8 ANSWER 9
No.
As stated numerous times by the witnesses of 10 the merging companies in this proceeding, the main reason 11 for the merger is to enable the merging companies to 12 maintain control of costs and thereby keep rates to their 13 customers at the lowest possible level.
14 OUESTION 15 De any of the seven attributes which Mr. Russell 16 discusses, starting on page 18, Exhibit 20, have any 17 relevance to the need for imposing the transmission 18 conditions that he has proposed?
19 ANSWER 20 No.
21 OUESTION 22 Do you have any specific comments on Mr. Russell's 23 proposed transmission access conditions?
24
- ANSWEF, 25 Yes.
As with most simple-minded solutions to an 26 extremely complex
- issue, Mr.
Russell's transmission
i R. M. Boucher 29 f
i i
[
l conditions would, in fact, cause moro problems than the t
2 problem he perceives to need a soluticn.
Moreover, his l
3 proposed transmission access conditions would not come 2
4 anywhere close to achieving his stated goa.'.s.
First, while 5
Mr.
Russell generously will allow the merged company to 6
serve its own firm load requirements and customers, his 7
proposed allocation scheme would create chaos among i
l 8
potential buyers and would, in all likelihood, result. in a t
9 very inefficient use of a valuable transmission asset.
Mr.
10 Russell assumes that all buyers wish to purchase the same 11 commodity and that all sellers are capable of supplying that 12 commodity.
In the real world, buyers and sellers in the
[
13 wholesale market have diverse needs and capabilities, such I
]
14 that any simple allocation scheme would be totally unwork-l 15 able.
In addition, Mr.
Russell'J proposed transmission 16 access conditions, while purporting to eliminate the ability l
I 17 of the merged company to accomplish the efficient displace-i 18 ment of more expensive thermal generation and the efficient l
3 19 use of its transmission system would in fact merely shift 20 the ability to accomplish such activities to other entities, j
21 either north of the merged company's system to Idaho or 3
22 south to the entities that own the interconnections on the 23 south end of the Utah Power system.
Mr. Russell's proposed 24 conditions would also preclude any further firm sales by the i
25 merged company, by requiring displacement of those sales by 1
i 26 third-party nonfirm transactions.
Such conditions would be 4
(
R. M. Bouch0r 30 i
i unacceptable to virtually any buyer in the Southwest.
2 OUESTION 3
Do you have any further comments on Mr. Russell's 4*
transmission access conditions?
5 ANSWER 6
Yes.
Mr. Russell, in his proposed transmission 7
access conditions, fails to give any reasons whatsoever why 8
entities that cannot reciprocally provide transmission 9
services for the merged company should gain a favored 10 wheeling and ownership position at the embedded costs of the 11 merged company's transmission system.
One can only 12 speculate that Mr. Russell wishes to encourage the formation 13 of new publicly-owned entities and create encouragement to 14 leave the system of the merged company to the detriment of 15 the merged company's remaining customers.
Additionally, Mr.
16 Rur. sell's adoption of a modified version of Bonneville's 17 proposed Intertie Access policy as a surrogate model for the is merged company's transmission system (Exhibit 20, page 22) 19 is entirely inappropriate.
Bonneville has designed its 20 LTIAP to satisfy its statutory obligations to provide 21 transmission access to all Northwest entities who have paid 22 for the Intertie investment, and to assure itself of the 23 capability of making repayments to the United States 24 Treasury of moneys borrowed.
To assume that such a policy 25 is an appropriate model for transmission access conditions 26 is entirely inappropriate and has no basis in fact or logic.
?^
R. M. BouchOr 31 1
- Finally, Mr.
Russell appears to have taken the role of l
2 public spokesman for the interests of Western utilities and 3
has suggested transmission access conditions to be applied 4
to the merging
- company, knowing full well that such conditions are totally unacceptable and are a thinly-veiled 5
i i
6 disguise to attempt to solve a labor dispute between the 7
United Mine Workers and an affiliate of PacifiCorp.
1980 Transmission Services Agreement between 8
SECTION 2 9
Pacific Power and Idaho Power 10 OUESTION i
11 Please briefly sscribe the of the 1980 Transmis-l 12 sion Services Agreement (TSA) and its basic p,rovisfons, i
13 ANSWER 14 The TSA evolved from Pacific Power's need for 15 east-to-west transmission capabilities in addition to that l
16 which was provided under the 1969 Jim Bridger Project l
17 ownership and operation Agreement.
That Agreement provided 1
l 18 for the transmission of Pacific Power's share of three units I
19 at the Jim Bridger project through the Idaho Power system in i
20 return for allowing Idaho Power to share in project
.l 21 ownership and Pacific Power's ownership of coal, water
[
22 rights and coal reserves at the Jim Bridger project site.
l 23 Pacific Power's need for such additional trannmission 24 capability arose from the joint discission by the project j
25 owners to install a fourth unit at the project and Pacific I
l 26 Power's desire to have the capability to transmit additional
k R. M. Bouchor 32 1
generation from its Pacific Power Wyoming resources, east-2 to-wort through the Idaho Power system to its western load 3
areas.
The TSA was negotiated as an alternative to 4
construction cf Pacific Power's own facilities and repre-5 sents an equitable sharing of the costs of reinforcing the 6
Idaho Power system to accommodate Pacific Power's additional 7
east-west transmission requirements.
8 The 1980 TSA basically provided that Pacific Power 9
would have the right to transfer from east-to-west only up 10 to 1600 MW from its share of the Jim Bridger project output 11 and its Pacific Power Wyoming resources to its energy 12 deficient western load areas.
The agreement also provides 13 that Pacific Power would construct 500 kV transmission line 14 from Pacific Power's southern Oregon load area to Idaho 15 Power's midpoint substation approximately 9u miles from the 16 termination of the Jim Bridger project transmission system.
17 The agreement also provides that Idaho Power would make 18 Pacific Power's east-to-west transfers available to Pacific 19 Power at the existing interconnections near Idaho Power's 20 Snake River hydroelectric facilities and at a new intercon-21 nection at the Idaho Power midpoint substation.
22 A copy of the 1980 Transmission Services Agreement 23 is included as Exhibit 75.
24 OUESTION 25 Do you have any general comments regarding Mr.
26 Crowley's, Mr.
Casazza's and Mr.
Collingwood's testimony
.v.
I R. M.
Boucher 33 1
related to the 1980 Transmission Services Agreement between 2
Pacific Power and Idaho Power?
3 ANSWER 4
Yes.
Messrs.
- Crowley, Casazza and Collingwood 5
argue that several provisions of the TSA will be violated by 6
operations subsequent to the merger.
Operations pursuant to 7
the TSA are not significantly affected by the merger between 8
Pacific Power and Utah Power.
As a result, interpretations 9
of the TSA should not be issues in this proceeding.
Both 10 parties have recourse outside of this proceeding to resolve 11 any such contract issue".
In fact, Idaho Power and Pacific 12 Power are currently attempting to resolve many of these 13 issues entirely independent of the merger.
14 OUESTION 15 What contract provisions do witnesses Casazza, 16 Crowley, and Collingwood contend are violated by operations 17 subsequent to the merger?
18 ANSWER 19 The witnesses assert the following:
20 1.
Pacific Power has insufficient contract rights 21 to achieve merger benefits (Crowley Exhibit 69, page 22 26; Casazza Exhibit 51, pages 6, 24).
j 2')
2.
a.
Pacific Power violates limitation of l
24 east-to-west transfers (Crowley Exhibit 69, l
25 page 32; Collingwood Exhibit 67, pages 15, 1
26 25).
1 1
.I
R. M.
Bouchsr 34
~:
1 b.-
Integrated operation requires! two-way 2
schedules (Crowley Exhibit 69,-
page 33, 3
Casazza Exhibit 51, pages' 8,. 13, 16, 19, 4
24).
5 3.
a.
Pacific Power must schedule in advance 6
(Crowley Exhibit 6'9,
page 34; Collingwood 7
Exhibit 67, page 11; Casazza Exhibit 51, page 8
31).
9 b.
Pacific Power is not permitted to do 10 Dynamic Scheduling by Pacific Power 11 (Collingwood Exhibit 67, pages 10-12, 14; 12 Casazza Exhibit 51, page 33).
13 4.
Unauthorized resources will be transferred 4
14 (Crowley Exhibit 69, page 32; Collingwood Exhibit 15 67, pages 20, 24).
16 OUESTION 17 Does the merged company require services not 18 already provided under the TSA?
19 ANSWER 20 No.
Our analysis of the merger operating 21 requirements for transmission across Idaho Power shows the 22 provisions of the TSA allowing Pacific Power to transfer up 23 to 1600 MW from its Wyoming resources in an east-to-west 24 direction are adequate for post-merger operation.
The 25 analysis of the merger operating requirements are discussed 26 in detail in Mr.
Steinberg's prefiled direct testimony
R. M. Bouchsr 35 d
1 (Exhibit No. 10).
Studies of transmission requirements are 2
discussed in Mr. Tucker's testimony (Exhibit 211).
3 Additional studies are included in Exhibit 208, Schedule 9.
4 The merged company will operate within the terms of all 5
existing Utah Power and Pacific Power contracts including 6
the TSA.
If operating experience shows that the estimated 7
merger operating benefits cannot be achieved under existing 8
contracts, these choices are available:
9 1.
Negotiate new contracts 10 2.
Build more transmission, and/or 11 3.
Live with lesser operating benefits and look to 12 other areas to achieve benefit obj ectives.
13 OUESTION 14 Will Pacific Power under any reasonably fore-15 seeable circumstances need to transfer power from west to 16 east?
17 ANSWER 18 No.
Integrated operations require no west-to-east 19 transfers across Idaho Power either before or after the 20 merger.
Pacific Power's western system is and remains 21 energy deficient and will continua to require energy f rom 22 Pacific Power Wyoming resources including Jim Bridger with 23 or without the aerger.
No resource additions are planned 24 for the western system.
The eastern system is energy 25 surplus for the f oreseeable future.
As a result Pacific 26 Power contemplates no transfers from west to east across the g
R. M.
Bouchor 36 t
1 Idaho Power system except for nonfirm transactions under the 2
Intercompany Pool Agreement which must be approved in 3
advance by Idaho Power and for which a separate charge is 4
paid.
5 OUESTION 6
Does Pacific Power schedule transfers under the TSA in advance?
8 ANSWER 9
Yes.
10 QUESTION 11 How does Pacific Power's West System meet its 12 load-following obligation if the east-to-west transfers 13 across Idaho Power change?
14 ANSWER 15 Pacific Power's West Controller automatically 16 signals controllable generation in the west to adjust for l
17 such changes.
18 19
.20 21 22 23 l
24 25 l
l
R. M. Boucher 37 1
OUESTION 2
What is meant by dynamic scheduling?
3 ANSWER 4
Dynamic scheduling is a term of art that is used 5
to describe the process by which each owner's share of 6
actual generation from a jointly owned generating source is 7
electronically made to appear as through such share of 8
generation was locate din the control area of such owner.
9 Such tcheduling is used to relieve the host utility of the 10 burden of automatically compensating for all of the real 11 time variation in actual generation and recognizes that the 12 actual generation is too unpredictable to schedule accurate-13 ly in advance.
14 OUESTION 15 How is dynamic scheduling accommodated within the 16 advanced scheduling requirements of the TSA?
17 ANSWER 18 Pacific Power provides Idaho Power with estimated 19 transfer requirements in advance of the
- hcur, i.e.,
(
20 schedules in advance.
If generation deviates for any I
21 reason in any magnitude, the schedule is adjusted after the 22 hour2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> to match actual transfers.
This process has been in 23 place with respect to the TSA since it became effective in 24 1980 and the practices employed today actually began in 25 1976.
Any variations in Pacific Power Wyoming generation, 26 including Jim Bridger, can effect these transfers resulting
.t
~;
R. M.
Boucher 38 1
in a change (dynamic) to the advance estimated schedule.
2 OUESTION 3
Do you agree with Mr.
Collingwood's testimony 4
(Exhibit 67, page 30) that transfers from east to west 5
cannot be offset by northwest resource operation.
6 ANSWER 7
No..
Pacific Power may use it west resources to 8
serve any customers to which it has access.
To the extent 9
that west requirements are served with west resources, 10 transfers from the east may be reduced.
Nothing in the TSA 11 suggests to the contrary.
12 OUESTION 13 What is dynamic overlay?
14 ANSWER 15 Dynamic overlay is the east-side result of west-16 side load following wh'ich accommodates changes in the east-17 to-west transfers.
The natural consequence of this 18 responsive action is that any failure of Pacific Power 19 Wyoming generation to cover changes in Pacific Power Wyoming 20 load will be covered by west load controllable resources.
21 If the west resources did not respond to the change in 22 transfer to meet the west-load requirements, Idaho Power or 23 other neighboring systems would be required to pick up the 24 difference (control error).
25 OUESTION 26 Does this dynamic overlay cause in any way west-
1 R. M. Bouchar 39 A
1 to-east transfers across Idaho Power?
2 ANSWER 3
No.
If east-to-west transfers
- increase, the 4
controllable generation in the west in adjusted to accom-5 modate service to more west load by east resources.
If the 6
change is a
reduced east-to-west
- transfer, then west 7
resources increase to serve the void left by the reduced 8
east resource service to west loads.
9 OUESTION 10 Would you please provide an example of dynamic 11 scheduling and load following?
12 ANSWER 13 A typical set of conditions is represented in 14 Exhibit 208 Schedule 9,
entitled "Pacific Power & Light 15 Company Dynamic Scheduling / Load.Following Explanation.
16 Three cases, A,
B, and C are provided showing from left to 17 right generation and load in the Pacific Power west system, 18 east-to-West transfers across Idaho Power under the TSA and 19 generation and load in the Pacific Power east system:
20 I.
Case A is the base case with 1200 MW of transfer to 21 the west; 22 II. Case B shows one scenario for just the loss of a 23 single Jim Bridger generator for which Pacific Power has a 24 two-thirds or 333 MW share.
The system response is for 25 primary pickup by the west resources since Jim Bridger is in 26 the west control area.
Pacific Power Wyoming resources may
m's -
R. M.
Boucher 40 1
also respond.
In this example 100 MW is assumed to be 2
picked up in Pacific Power Wyoming and 230 MW in the west.
3 The transfer to the west is reduced to 970 MW; o
4 III.
Case C assumes a 40 MW load char.ge in Pacific 5
Power Wyoming.
It assumes that Jim Bridger generation will 6
pick up part of the load change, in this case, one-half or 7
20 MW.
Twenty megawatts of Jim Bridger is allocated to meet 8
the Pacific Power Wyoming load change.
Transfers west are 9
reduced from 1200 to 1180 MW and west generation picks up 20 10 MW of west load.
11 In both of the change cases, B and C, the dynamic 12 change in schedule due to these changes in transfer will be 13 determined by the timing during the scheduling hour that the 14 change occurred and how long the system took to respond.
15 The actu'al schedule determined after the hour will be the 16 sum of all energy transferred.
If for example, the change 17 from 1200 MW (Case A) to 970 MW (Case B) takes place over a 18 10-minute period in mid-hour, the approximate actual 19 schedule for the hour would be about 1085 MW, the average of 20 the two transfer levels, and a reduction of 115 MW from 21 advance schedule.
In Case C, we would expect unanticipated 22 load increases to take place over longer time periods.
If 23 the 20 MW transfer changed uniformly over a one-hour period, 24 the actual schedule would be 1190 MW, the average over the 25 hour2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />.
This is a change from advance schedule of 10 MW.
R. M.
Bouchar 41 i
1 OUESTION 2
Why is dynamic overlay necessary?.
3 ANSWER 4
Early in the design of the Jim.Bridger Project, 5
Idaho Power and Pacific Power agreed that provisions for 6
automatic generation control (AGC) would be built into the 7
Jim Bridger Project for future use by either or both 8
parties.
See Exhibit
- 208, Schedule 10 which included 9
minutes of meetings and actual control wiring diagrams to 10 implement such dynamic control.
AGC is the term of art used 11 to describe -the automatic real time process of balancing 12 the loads and generation within a control area by adjusting 13 the controllable generations.
Definition of the load 14 control points at the Goshen,
- Kinpoint, and Borah sub-15
- stations, and the 345-230 kV control area interconnection 16' between Pacific Power's eastern and western control areas 17 are also shown.
Idaho Power does not contest that dynamic 18 scheduling of the Jim Bridger Project, both for Idaho Power 19 and Pacific Power, was anticipated and in fact, incorporated 20 under the 1980 Transmission Services Agreement.
Dynamic 21 overlay is the natural consequence of agreeing to locate the 22 Jim Bridger Project in Pacific Power's west control area.
23 This overlay has the same effect as if ACC were implemented 24 on the Jim Bridger Project, both with regard to meeting east 25 side load control needs and with regard to dynamic changes 26 in schedules across Idaho Power.
It would be more expensive
~
~I.
R.-M.
Bouchar 42 I
1, for both Idaho and Pacific Power to install AGC at Bridger, 2
but it would accomplish the same dynamic overlay.
3 OUESTION 4
On Page 10 of Exhibit 67, Mr. Collingwood implies 5
that Pacific Power's use of dynamic overlay control is 6
related to the merger.
How is the overlay control affected 7
by the merger?
8 ANSWER 9
Pacific Power believes that the dynamic overlay 1
10 control is a natural extension of the parties intentions to 11 ultimately have AGC control on the Jim Bridger plant.
The 12 merger has absolutely nothing to do with Pacific Power's use 13 of dynamic overlay since this feature is currently being 14 used and will continue to be used with or without the 15 merger.
However, it is notable that the merger will reduce 16 Pacific Power's need for overlay control since the Utah AGC 17 can assist the Eastern Control Area in meeting control 18 requirements.
19 OUESTION 20 On Page 10 of his testimony, Mr.
Collingwood 21 suggests that overlay control allows Pacific Power to carry i
22 Pacific Power Wyoming operating reserves in its western 23 systems.
Is this true?
24 ANSWER 25 No. Pacific Power's existing rights to schedule up 26 to 1600 MW from its Jim Bridger and Pacific Power Wyoming i
o.
R. M.
Bouchar 43 I
1 resources to its western systems contains no restrictions on 2
changes in schedules; in fact, the dynamic nature of Pacific 3
Power's transfers is implicit in the control arrangements 4
agreed to b'y the parties.
With regard to Mr. Collingwood's 5
assertion on reserves, it must be recognized that Pacific 6
Power's transfer's are from Jim Bridger and Pacific Power 7
Wyoming Resources to the west; and, therefore, the operating 8
reserves to cover the loss of Pacific Power Wyoming 9
generation must be in Pacific Power's western load areas to 10 cover the loss of transfers from the east into Pacific 11 Power's western load areas.
Idaho Power entered into the 12 1980 TSA knowing full well how Pacific Power intended to 13 exercise its rights under the 1980 TSA; and, furthermore, 14 Idaho Power has had at least eight years of operational 15 experience with this mode of operation without complaint.
16 OUESTION 17 Does Pacific Power's use of dynamic overlay 18 control impose a burden on the Idaho system?
19 ANSWER 20 No.
Because of the dynamic scheduling of the Jim 21 Bridger plant, which was agreed to by the parties under the 22 1980 TSA, Idaho Power must operate its system to accommod, ate 23 the potential loss of one or more units at the Jiu Bridger 24 plant.
Since Pacific Power owns a two-thirds share of the l
25 plant, the loss of one 500 MW unit could cause a change of l
26 333 MW in Pacific Power's transfers to the west.
The l
4-R. M.
Boucher 44 e
1 dynamic overlay requirement is typically less then 25 MW i 2
around the scheduled flow.
3 OUESTION
+
4 On Page 15 of Exhibit 67, Mr. Collingwood asserts 5
that Pacific Power must move power from its Western area to 6
the' Wyoming-Utah area in order to achieve the merger 7
benefits.
Do you agree?
8 ANSWER 9
No.
Both Mr.
Collingwood and Mr.
Casazza are 10-attempting to convince this commission that Pacific Power's 11 current use of its 1600 MW of transfer
- rights, which 12 includes:
13 1.
The use of Pacific Power's western resources 14 to cover the loss of transferred energy from its 15 Jim Bridger and Pacific Power Wyoming resources; 16 and 17 2.
The displacement of its Jim Bridger and 18 Pacific Power Wyoming and resources and transfers 19 to the west with economical purchases of power in 20 its western systems; and 21 3.
The use of dynamic scheduling and overlay 22 control; 23 will somehow be radically changed by the merger and 24 transformed into a set of new services when absolutely 25 nothing has changed relative to the agreement.
After the l
26 merger, Pacific Power intends to use its 1600 MW transfer 1
I
R. M. Bouchar 45 i
1 rights in virtually the exact same way as oefore.
2 Mr. Collingwood and Mr. Casazza would have this commission 3
believe that because of the merger, Idaho Power must now be 4
compensated under a new contract for exactly the same 5
services that are provided under the existing 1980 TSA.
I 6
must conclude that Idaho Power and Montana Power are using 7
the merger as an excuse to extract concessions from the 8
merging companies by making unsupported allegations that 9
have nothing to do with the merger.
10 OUESTION 11 On Page 6 of Exhibit 51, Mr. Casazza clairs that 12 the merged systems cannot be operated as a "single system" 13 w'thout additional transmissions.
Do you agree?
14 aHSEE 15 That is nonsense.
Pacific Power has been 16 operating a single integrated system for years.
If 17 anything, the merger between Utah Power and Pacific' Power 18 will create an even more integrated system than before.
19 OUESTION 20 On Exhibit 51, pages 4,
7, and 8,
Mr. Casazza 21 asserts that changes will occur as a result of the merger 22 and the associated changes in operation of the merged 23 companies resources.
Do you agree?
24 ANSWER 25 Any change in an interconnected system will cause
h R. M.
Boucher 46 8.
1 changes to occur on the systems of the interconnected 2
utilities.
The point is, are the changes significant and 3
are they beneficial or detrimental to the interconnected 4
system?
Mr.
Casazza has not shown that any detrimental 5
changes occur due to operation of the merged company's 6
system nor has he shown that Pacific Power's use of its 1600 7
MW rights under the 1980 TSA will change.
8 OUESTION 9
Will Pacific Power transfer under the TSA any 10 resources not authorized by the TSA?.
11 ANSWER 12 No.
The TSA provides for transfer of the output 13 of Jim Bridger and Pacific Power Wyoming resources.
Until 14 such time that Idaho Power may agree to provide additional i
15 servid:es, only the output of those resources will be 16 transferred under the TSA.
17 OUESTION 18 How can Idaho Power be assured that no unauthor-19 ized resources are transferred?
20 ANSWER 21 Pacific Power must be able to show that the sum of l
22 the Jim Bridger and its Pacific Power Wyoming resources 23 equals or exceeds the schedule across Idaho Power and that 24 Pacific Power has transmission capacity to deliver such 25 generation to Idaho Power at the specified points.
Idaho 4
26 Power, Pacific Power and Utah Power have conducted studies 4
,.e.
, ~ --
,,._,-,,n.p
._,,,.,,n-.,,,._,..._n n.
n.-,
1 R.' M. Bouchar 47 a
1 to determine the capabilities of the relevant transmission 2
system.
Both'the sum of the generation'and notices of any 3
relevant transmission outages are available to Idaho Power 4
in every hour.
i 5
OUESTION 6
Mr.
Casazza repeatedly states throughout his 7
testimony that two-way service is required for the inte-8 grated operation claimed by the Applicants (example Exhibic 9
51, page 16).
Do you agree?
10 OUESTION 11 No.
Mr.
Casazza argues that the general must 12 always apply to the specific.
He fails to recognize that a f
13 purpose of the TSA was in fact to integrate the west and 14 east areas of the Pacific Power system.
The agreement was 15 entered into in lieu of such additional transmission 16 construction across 90 miles of the Idaho Power system which 17 line.still could be built if necessary.
Pacific Power 18 recognized in entering into this agreement that while two-19_
way transmission was desirable for improved freedom to 20 market power, that as a practical matter, no firm west-to-21 east transfers were going to occur or be needed for a long 22 time, if ever.
The result was that instead of having no 23 agreement and requiring 90 miles of transmission con-24 struction through a
mutually acceptable compromise was 25 reached, the 1980 TSA.
n R., M. Bouchar 48 L
i 1
OUESTION 2
Has Pacific Power operated an integrated system 3
since the construction of facilities provided for in the 4
TSA?
5 ANSWER 6
Yes.
The TSA has proved to be a very adequate 7
integration mechanism.
8 OUESTION 9
Will the merger require any changes in the 10 provisions of the TSA?
11 ANSWER 12 No.
13 SECTION 'l -- Changes in System Operation Due to the Merger:
14 00ESTION 15 Mr.
Casazza (Exhibit 51, pages 6,
8) and 16 Mr. Collingwood (Exhibit 67, page 3),
among others allege 17 that changes in system operation related to the merger will 18 adversely effect Idaho Power and other WSCC systems.
19 Specifically, they are concerned with:
20 a.
Use of the Idaho system; 21 b.
Loop flow; 22 c.
Adequacy of transmission additions; and 23 d.
System control and operation.
24 Do you believe that Idaho Power and other WSCC systems will 25 be adversely affected?
R.
M.
Bouchar 49 1
ANSWER 2
No..
As-I will discuss below, we believe that any 3
such changes will be either beneficial or insignificant.
G 4
OUESTION 5
Will the integration (pooling) of Pacific Power 6
Wyoming resources and Utah Power resources resulting from 7
the merger have any benefit to Idaho Power?
8 ANSWER 9
Yes.
The pooling of the merged company resources 10 on the eastern end of the Idaho system will enhance Idaho 11 Power's use of its west-to-east transmission capabilities.
12 As part of the, ICP, Idaho Power and other ICP 13 members must stand ready to share reserve obligations with 14 other pool members.
Since the majority of the ICP resources 15 are located on the west end of Idaho Power's transmission 16 system, unit outages in either the Utah Power or Pacific 17 Power Wyoming system could require substantial use of Idaho 18 Power's transmission system from west to east.
While such 19 use is an important part of the ICP reserve obligations, 20 there are certain times when such use could restrict Idaho 21 Power's other use of its system.
The pooling of the 22 combined company resources and the transmission additions 23 planned as part of the merger will allow improved coverage 24 by resources available in Wyoming or Utah and will reduce 25 the probable need for ICP resources on the west end of the 26 Idaho Power system.
3 R. M.
Bouchar 50 r
4 1
OUESTION 2
Are there other operational benefits to Idaho 3
Power resulting from the merger?
4 ANSWER 5
Yes'.
Such additional benefits include:
enhanced 6
transfer capability west of Jim Bridger and greater control 7
of power flows on the Jim Bridger transmission system.
8 OUESTION 9
Please explain how the merger increases transfer 10 capability west of Bridger, and why this is significant to 11 Idaho Power.
12 ANSWER 13 The Jim Bridger transmission system is currently 14 limited by operational problems which can occur.following an 15 unplanned outage of one or more of the three 345 kV 16 transmission lines west of Jim Bridger.
When the Jim 17 Bridger transmission system is loaded above 2000 MW, a
18 Bridger unit must.be immediately removed from service 19 (tripped) following a transmission line outage.
While the 20 actual transfer capability of the Jim Bridger transmission 21 system is 2200 MW, both Pacific Power and Idaho Power are 22 reluctant to operate above the 2000 MW.
23 All significant lines added in the interconnected 24 system increase transfer capacity in parallel lines.
The 25 integrating transmission planned by the merged company is no 26 exception.
As discussed in Mr. Tucker's testimony (Exhibit
r..
9 R. M.
Bouchtr 51 is 211), the additional 230 kV lines from Bridger to Naughton -
2 will add approximately 75 MW of transfer capability to the 3
Jim Bridger transmission system.
This will permit Jim
~4 Bridger transmission system -loadings to be raised from 5
2000 MW to 2075 MW and while avoiding unit trips.
6 OUESTION 7
How does Idaho Power benefit from a reduction of 8
Jim Bridger unit trips?
9 ANSWER 10 Idaho Power is a 1/3 owner of the plant.
11 OUESTICN 12 Will the planned Naughton phase shifter benefit 13 the Idaho Power system?
14 ANSWER 15 In several ways.
First, it will insure that the 16 Jim Bridger transmission system will not be encumbered by 17 loop flow from transfers on the 230 kV system.
This reduces 18 the need for generator tripping at Bridger.
Second, when 19 the Naughton intorconnection is not heavily used by the 20 merged
- company, it may be used to unload the Bridger 21 transmission system by using the phase shifter to force 22 Bridger power onto the 230 kV system.
- Third, when the 23 Bridger transmission system loading is near the generator 24 trip setting, the phase shifter can provide more precise 25 control of Bridger transmission system loading which will 26 allow the Bridger transmission system to be more fully
5 R.
M. Bouchsr.
52 1
utilized without fear of exceeding generator trip settings.
2 QILESII_QE 3
Several intervenors, including Idaho Power, are 4
concerned that the merger will create additional loop flows.
5 Will tnis occur?
6 ANSWER 7
No.
Both Mr. Tucker's filed direct testimony 8
(Exhibit 12) and his Exhibit 208, Schedule 8 address loop 9
flow effects of the merger.
Mr.
Casazza has included 10 selected incremental power flow studies in his testimony to 11 show the effect of Pacific Power / Utah Power transfers on 12 loop flow (Exhibit 51, page 28).
13 All of these studies show that the installation of 14 the Naughton phase shifter will ruke diminimus any loop 15 flows caused by operational changes resulting from the 16 merger.
17 OUESTION 18 Do you have further comments on Mr.
Casazza's 19 studies?
20 ANSWER 21 Yes.
The relative magnitudes of loop flow changes 22 resulting from the merger are not shown.
To judge the 23 relative magnitude of any merger-related loop flow changes, 24 one needs to also see the similar changes to loop flow 25 caused by others on the system.
For example, Exhibit 26 No. 208, Schedule 11 shows the incremental effect of an
R. M.
Bouchar 53
-D 1
internal transfer between Idaho Power's Jim Bridger and 2
Brownlee units.
If Mr. Casazza's assertions (Exhibit 51, 3
page 29) that it is established practice in WSCC to base 4
charges for transmission service on incremental scheduled 5
transfers, then Idaho Power should pay Pacific Powcr, 6
Monttaa Power, and others for this internal transfer change 7
since t.Te transmission systems of other parties are used.
8 Exhibit No. 208, Schedule 12 shows the incremental 9
effect on loop flow for a 100 MW schedule from Idaho Power 10 Brownlee units to the Sigurd area.
Exhibit No.
208',
11 Schedule 13 shows the same '~ formation for an Idaho Power 12 schedule from Brownlee to Southern California.
13 OUESTION 14 What do you conclude from these exhibits?
15 bNSWER 16 Loop flow is created by schedules over the 17 interconnected
- system, including the schedules of the 18 intervenors.
Within WSCC there is no requirement to control 19 schedule flows to be actual.
As Mr. Tucker points out in 20 his prefiled direct testimony, WSCC has implemented a
21 procedure to mitigate the effects of loop flow on affected 22 parties (Exhibit 12, page 16).
13 While the merging companies are not required to do 24 so, they are installing the Naughton phase shifter to 25 control actual flows to the desired transfers over the 26 Naughton interconnection between Utah Power and Pacific
c 5
R. M.
Bouch@r 54 1
Power.
2 OUESTION 3
Does the Exhibit 208, Schedule 12 which shows an 4
Idaho Power Brownlee schedule to Sigurd demonstrate anything 5
else?
6 ANSWIB 7
That Exhibit shows that if Idaho Power schedules 8
100 MW from its hydro at Brownlee via Utah Power to Sigurd, 9
30% or 30 MW would act'ually flow over the Pacific Intertie.
10 During periods when the Pacific Intertie is fully loaded, 11 this additional 30 MW wil'1 require curtailments of schedules 12 on the Pacific Intertie.
Intertie transactions would be 13 curtailed.
14 A
similar situation is shown in Exhibit
- 208, i
15 Schedule 13 which shows the incremental flows for'a schedule 16 from Idaho Power Brownlee unit to Southern California.
If 17 this schedule was made through Utah Power to California at 18 Four Corners, a 70 MW added flow on the Pacific Intertie 19 would result.
20 OUESTION 21 Will the merger create incentives for the merged 22 company to reduce major loop flow in both directions?
23 3NSWER 24 Yes, because the merged company will have access 25 on both sides of the major loop, and will therefore wish to 26 minimize loop flow constraints in both directions.
I R.
M.
Bouchtr 55
+,.
1 OUESTION 2
Mr.
Casazza argues (Exhibit 51, page 10) that 3
there may also be merger effects on other systems in 4
additional to the Idaho Power system.
Do you agree and are 5
- these effects positive.
6 ANSWER 7
I agree there are operational ef fects but all are 8
beneficial.
They result from transmission additions planned 9
for the merger.
There are two which I discuss below:
10 a.
The addition of transfer capability out of the
-11 Colorado / Wyoming area.
12 b.
Local reliability improvements to the 13 Southwest Wyoming and Northeast Utah areas.
14 QUESTION 15 How do the planned new transmission facilities 16 affect the Colorado / Wyoming area?
17 ANSWER 18 As Mr.
Tucker explains in Exhibit
Coupled with additions from the 21 Spence and Casper areas being built by WAPA and Pacific 22 Power, this path will strengthen operating characteristics 23 of the Wyoming / Colorado area.
24 OUESTION 25 How will local area reliability be affected by 26 merger transmission additions?
E R. M. Bouchar 56
.D 1
ANSWER 2
The transmission additions have been proposed for 3
several years as a way to increase reliability of service to 4
the loads at Rock Springs, Green River and elsewhere in 5
Southwest Wyoming.
The additions will also increase 6
reliability to loads served by Bridger Valley REA and add 7
support to the Flaming Gor a area.
s 8
Sf&'RION 4 -- Contract / Pooling Alternatives:
9 OUESTION 10 Do you have any comments regarding Mr. Russell's 11 broad statements about the availability of the merger 12 benefits through pooling and/or contracts (example Exhibit 13 20, page 41)?
14 ANSWER 15 Yes.
Mr. Russell states that he has worked on 16 power pooling matters for over 20 years through publica-17 tions, testimony, teaching, and public speaking (Exhibit 20, 18 page 42).
His qualifications do not indicate that he has 19 ever been involved with an extensive negotiation regarding 20 the creation of a power pool.
I was actively involve-d in 21 the negotiations leading to the creation of the New England 22 Power Pool (NEPOOL).
The negotiations related to that 23 agreement took more than 10 years prior to execution and 24 post-execution negotiations continue today more than a
25 decade later.
The NEPOOL agreement is still not achieving 26 all of the desired benefits.
I R. M.
Bouchar 57 1
Both Utah Power and Pacific Power have extensive 2
experience in negotiating both power pooling arrangements 3
and multi-party contracts.
That experience indicates that, 4
to achieve even some of the benefits of the merger, would 5
involve protracted negotiation with other utilities that 6
could take a substantial length of time to accomplish.
Both 7
Pacific Power and Utah Power have intense competitive 8
pressures to deal with, both in wholesale power market and 9
in existing retail market through proposed takeovers by new 10 public entities, competing fuels for industrial customers, 11 and gas and wood heat alternatives for residential cus-12 tomers.
In
- addition, both companies have committed 13 themselves to stabilizing retail rates and cannot afford the 14 time to achieve only a fraction of the proposed merger 15 benefits through the negotiation of power pooling' and 16 coordination agreements.
Furthermore, the non-power-supply-17 related Denefits of the merger are very substantial and are 18 critical to the success of both companies in maintaining 19 their competitive position.
It is the collective benefits 20 of the merger that will allow the merged company to maintain 21 its competitive
- position, and those benefits are not 22 available through contract and pooling arrangements and can 23 only be accomplished by the marriage of the two companies as 24 proposed in this merger.
I e-R. M.
Boucher 58
'e 1
SECTION 5 - Integrated Service Areas 2
OUESTION 3
Mr. Lim claims (Exhibit No. 49, page 18) that the 4
merged company's wheeling policy which provides wheeling 5
only within a compartmentalized area without a case-by-case 6
review is unreasonable.
Do you agree?
7 ANSWER 8
No.
It is reasonable and prudent to review the 9
impacts of a wheeling request on a case-by-case basis.
10 However, when the requested wheeling is completely within a 11 compartmentalized area, the merged company believes that 12 this review would not generally be required.
This is 13 intended to cut the "rad tape" for wheeling within a 14 compartmentalized area.
15 OUESTION 16 What is the basis for the compartmentalized area?
17 ANSWER 18 Within a
compartmentalized
- area, the merged 19 company considers that adequate transmission facilities 20 exist for reasonably expected transmission service requests.
21 OUESTION 22 Does this mean that the system between the 23 compartmentalized areas is not an integrated system?
24 ANSWER 25 No, absolutely not.
For the efficient operation 26 of the merged company system is integrated and has adequate
i
'n
- 1 R. M. Bouchsr.
59 1
transmission for the operation of the merged company.
2 Requests for third-party wheeling which may go beyond the 3
planned capabilities of the merged company must be reviewed 4-on a case-by-case basis.
5 OUESTION 6
Does this conclude your rebuttal testimony?
7 ANSWER 8
Yes.
4 9
1 9
.1 4
l
)
i l.
t 1
l
. - ~ -, -,. _ _,. _. - - _ _. - _, _ _-.___.-._ _.-
I 9'
' h; UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Utah Power & Light Company
)
PacifiCorp
)
Docket No. EC88-2-000 PC/UP&L Merging Corp.
)
)
ss.
COUNTY OF SALT LAKE )
Rodney M. Boucher, being first duly sworn, deposes and says:
that he has read and is familiar with the contents of the foregoing Rebuttal Testimony of Rodney M. Boucher; that if asked the questions contained in said Testimony, the answers and response hereto would be as shown in said Testimony; that the facts contained in said answers are true to the best of his knowledge, information and belief; and that he adopts these answers as his
)
AsjL
/
d Toucher SUBSCRIBED AND SWORN to before me this 22nd day of February, 1988.
,, 1]
\\
/!
i Notary Public N--
My Commission Expires Residing at:
.h :4 f IQ' hMIC
.I ' ' ! !- i. ; R d
.C, i 'd' /
.,