ML20153F656
| ML20153F656 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 02/24/1988 |
| From: | Steinberg D UTAH POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML20153F598 | List: |
| References | |
| NUDOCS 8805110016 | |
| Download: ML20153F656 (35) | |
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,f Exhibit B UNITED STATES OF AMERICA BEFORE THE NUCLEAR REGULATORY COMMISSION IN THE MATTER OF THE ) EXHIBIT B to Facility APPLICATION OF PACIFICORP ) Operating License No. NPF-1 FOR CONSENT TO THE TRANSFER ) Indemnity Agreement No. B-78 OF LICENSES )
REBUTTAL TESTIMONY OF DENNIS P. STEINBERG f
8805110016 880509 PDR ADOCK 05000344 T DCD
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Exhibit 209 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGi* REGULATORY COMMISSION Utah Power & Light Company )
PacifiCorp ) Docket No. EC88-2-000 PC/UP&L Merging Corp. )
REBUTTAL TESTIMONY OF DENNIS P. STEINBERG 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 DENNIS P. STEINBERG ISSUES ADDRESSED I. Merger Benefits A. Additional Firm Sale Benefits Issues Addressed by:
- 1. CREDA Witness Goff Exhibit 118, pp. 5-8
- 2. Nucor Witness Kahal Exhibit 18, p. 11
- 3. FPC Witness Peters Exhibit 36, p. 13 B. Additional Nonfirm Sale Benefits Issues Addressed by:
- 1. CREDA Witness Goff Exhibit 118, pp. 10-13 and pp.15-18
- 2. Nucor Witness Kahal Exhibit 18, p. 13 C. Savings in Nonfirm Purchased Power Costs
- Issues Addressed by:
- 1. CREDA Witness Goff Exhibit 118, p. 14
- 2. PPC Witness Peters Exhibit 36, pp. 15-19 D. Savings in Wheeling Expense Issues Addressed by:
- 1. CREDA Witness Goff Exhibit 118, p. 8
- 2. Nucor Witness Kahal Exhibit 18, p. 13 E. Bridger Turbine Upgrade Requirements Issues Addressed by:
- 1. CREDA Witness Winterfeld Exhibit 125, p. 8 F. Economic Development Costs Issues Addressed by:
- 1. PPC Witness Peters Exhibit 36, p. 18
- 2. CREDA Witness Goff Exhibit 118, p. 20 G. Resource Planning Benefits Issues Addressed by:
- 1. CREDA Witness Goff Exhibit 118, pp. 19-21 Exhibit 124
' ,t og
- II. Effects of Merger on Other Utilities A. Effects on Others' Reserve Requirements Issues Addressed by:
- 1. CREDA Witness Helsby Exhibit 134, p. 25 -
- 2. Idaho Power Witness Casazza Exhibit 51, p. 30 B. Effects on Others' Povea* Sales and Purchases Issues Addressed by:
- 1. PPC Mitness Drummond Exhibit 27, pp. 4-9 CONTENT AND CONCLUSION Power Cost Savinos Estimates Applicants' estimates of power cost savings resulting from the merger used consistent and representative assumptions and methods, and their power cost savings estimates are reasonable.
Intervenors have relied on incorrect assumptions and factual errors in their criticisms of Applicants' power cost savings estimates:
- New firm sale opportunities of the merged company are .
misrepresented
- Increases in nonfirm sales by the merged company are misinterpreted or misrepresented
- Criticisms of the efficiencies from coordinated operation are invalid Economic Development Estimates Intervenors' analysis of economic development benefits from the merger exaggerate or double count the power supply costs for these incremental loads, or fail to account for the revenues offsetting long-range costs.
a .
3 Long-Range Resource Plan Benefits ,
Intervenors' analyses of the resource planning benefits from
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the merger are incorrects
-- The resource options available to the merged system are incorrectly limited All costs and benefits are not accounted for.
Effects of the Mercer on Other Utilities Claims of harm to other parties from the merger are based on faulty assumptions, data, and misinterpretations. The merged company's savings in forced outage reserves will not harm other utilities. Intervernors' estimates of the effects on others' ,
power sales and purchases are greatly exaggerated.
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1 Q. Please state your name.
2 A. Dennis P. Steinberg.
3 Q. Are you the same Dennis P. Steinberg who testified 4
previously in this proceeding?
5 A. Yes.
6 Q. What is the purpose of your testimony.
7 A. The purpose of my testimony is to rebut certain 8
assertions made by intervenors with respect to merged 9
system power supply benefits. Specifically, my 10 .
testimony will address the following areas:
11
- Net power cost savings, as discussed by CREDA 12 vitnesses Goff and Winterfeld, NUCOR witness Kahal,,
13 and PPC witness Peters.
14
- Economic development costs, as discussed by CREDA 15 witness Goff and PPC witness Peters.
16
- Resource plan savings, as discussed by CREDA vitness 17 Goff.
18
- Effect of the merger on other utilities' planning, 19 operations, or costs, as discussed by CREDA vitness 20 Helsby, Idaho Power witness Casazza, and PPC witness 21 Drummond.
22 I. Net Power Cost savinos 23 Q. Did you address the power cost savings resulting from the merger in your direct testimony?
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.a I I presented the results of power cost simulation A. Yes.
2 studies that demonstrated savings resulting from 3
additional firm and nonfirm sales, reduced purchased power and wheeling expenses, and more efficient 5
operation of the merged company's resources. Those 6
studies compared the operations of the merged company 7
with operations of each of Utah Power and Pacific Power, 8
assuming they were not merged, over the 1988-92 period.
9 I believe those studies used consistent and 10
' representative assumptions and methods, an'd that the 11 power cost savings estimates are reasonable.
12 Q. What assumptions did you make about an additional firm 13 sale by the merged company?
14 A. The studies assumed a sale of 50 average MW (aMW) 15 beginning in June of 1988, increasing to 100 aMW in 16 January of 1990.
17 Q. Witnesses Goff, Peters, and Kahal have questioned the 18 likelihood of the merged company's assumed new firm 19 sale. What are their assertions?
20 A. Mr. Goff asserts that an actual purchaser has not been 21 identified and negotiations have not taken place to 22 secure the sale (Exhibit 118, p. 5). Mr. Kahal makes 23 similar assertions (Exhibit 18, p. 11). Dr. Peters 24 asserts that only a "generic sale is assumed" and there 25 is no evidence offered as to the reasonableness of the 26 Page l l
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assumption (Exhibit 36, p. 13).
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Q. What is the basis for your assumption of the additional
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firm sale?
4 A. My direct testimony did not identify a specific 5
purchaser, but I can elaborate to some degree on the 6
likelihood of the firm sale. Representatives from 7
8 Pacific Power and Utah Power have held serious and fruitful negotiations with utilities in the Southwest 9
and Northwest. Based on those negotiations, we believe 10 the prospects are very good for consummating a firm sale 11 upon completion of the merger, and that the assumed firm 12 13 sale in my prefiled testimony is reasonably 14 representative of what our negotiations will produce. -
15 To describe specific details of our negotiations could seriously compromise confidential business information.
16 17 We believe several other utilities are competing for these sales. Both the timing and services offered are 18 critical, given this competition.
19 i
Q. Are there other measures of the reasonableness of the 20 new firm sale assumption?
21 A. Yes. The wholesale marketplace is currently supporting 22 comparable firm sales. As I indicated in my direct 23 testimony bqfore this Commission, the prices we assumed are in line with prices Pacific Power will receive for 26 its sale to Southern California Edison (SCE) and Utah Page 2
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- 4 1 Power from its sale to Nevada Power. The size of the 2
assumed firm sale is also in line with the size of 3
already consummated sales.
.4 Q. Do some intervenors also question whether there is a 5
market for such a firm sale?
6 A. Yes, Mr. Goff, on behalf of CREDA, (Exhibit 118, p. 8) 7 questions whether a market exists at Four Corners, where 8
the new firm sale was assumed to occur in the power cost 9
studies of my direct testimony. This is based on his 10 .
assumption that Utah Power would already be making a 11 sale to this market if it existed, or that such a 12 planned firm sale would have appeared in Utah Power's 13 pre-merger load and resource plan.
14 Q. Does this disprove the existence of a firm sale market 15 at Four Corners?
I 16 A. No. Whether or not Utah Power planned to m6ke such a 17 firm sale, there is no reason an uncertain commitment 18 would have been divulged in a firm load and resource 19 plan. His assumption also ignores the improved ability of the merged company to complete such a sale, as t 21 discussed in Mr. Boucher's direct testimony (Exhibit 8, 22 ep. 36-41).
Q. Why does Dr. Peters object tc the power cost benefits of the new firm sale?
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A. He asserts (Exhibit 36, p. 18) that the sale "apparently 2
derives from the ability of the merged companies to 3
dominate transmission facilities." As Dr. Landon's
.4 rebuttal testimony indicates,' Dr. Peters' conclusions on 5
market dominance are faulty.
6 Q. Do you disagree with the results of Dr. Peters' analysis 7
of the new firm sale benefits shown in Exhibit 42, pages 8
5-6?
9 A. I do not disagree with his estimate of the effect of 10 .
removing the firm sale. Using Pacific Power's power 11 cost model, he apparently duplicated the sensitivity 12 study I provided in my workpapers and discussed in my D .
I direct testimony (Exhibit 10, p. 14) showing the same 14 4
effect. As I just indicated, I disagree with his 15 premise in removing the firm sale benefits. I provided 16 the sensitivity study estimate, since the firm sale 17 contract is not yet signed; he provided the study 18 because he erroneously concludes that the benefits are 19 not attributable to the merger.
20 Q. Witnesses Goff and Kahal questioned the estimates of 21 increased nonfirm sales attributable to the merger.
22
- What are their criticisms?
23 A. Mr. Goff asserts that an incorrect analysis was used to 24 quantify the increased sales (Exhibit 118, pp. 10 and
- 15) and that invalid price assumptions vete used 26 Page ;
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(Exhibit 118, p. 12). Mr. Kahal admits he has no basis 2
for challenging the price assumptions used, but reminds -
3 us that the magnitude of benefits attributable to sales 4
is dependent on prices assumed (Exhibit 18, p. 13).
5 Q. What was the basis for nonfirm price assumptions used in 6 '
your studies?
7 A. Nonfirm wholesale power prices used in the power cost ,
8 model studies were based on estimates of competing oil 9
and gas-fired generation costs and on both companies' 10 .
experiences in power marketing; they are in line with 11 current prices and trends. The assumptions were 12
- identical between the simulations for the merged and 13 unmerged companies, with the exception of prices assumed 14 for Utah Power's Four Corners and Nevada markets. Prices 15 for these markets were one mill /kWh higher for the 16 merged system than for Utah Power unmerged. This price premium is based on the merged system's ability to offer more valuable services to these markets as compared to 19 Utah Power without the merger. Premium service can mean 20 more reliable nonfirm sales, extended or block sales, 21 and more sales during peak hours. The price premium is (
22 l a reasonable assumption, as illustrated by the two j 23 mills /kWh premium that BPA receives for assured delivery of nonfirm energy. For reference, I have provided that ;
portion of BPA's 1987 Nonfirm Energy Rate Schedule as
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Exhibit 210, Schedule 1.
2 Q. Mr. Goff asserts that this increased price assumption is 3
incorrect. What is the basis for his contention?
4 A. He claims that the "merger will have a net adverse 5
affect on the merged companies' ability to assure 6
delivery of nonfirm power during the next nine years" 7
(Exhibit 118, p. 13). This claim is based on the fact 8
that Utah Power requires additional firm capacity 9
purchases in the winter beginning in 1996-97, while the 10 .
merged company needs additional vinter capacity 11 beginning in 1991-92, 12 Q. Does that comparison support his contention? ,
13 A. No. He has not described any relevant measure of the 14 relative reliability of the merged and unmerged 15 companies at any point in time. Mr. Goff's use of firm 16 resource requirements as an indicator of nonfirm power 17 supply reliability is mistaken. Independent of nonfirm IS power marketing considerations, the merged system will acquire additional firm power supplies as required to 20 meet its firm load requirements.
21 The more appropriate measure of power supply reliability 22 is the internal reliability of the merged system as 23 compared to that of the individual companies under any specific load / resource situation.
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J-e I Have you performed any studies addressing internal power Q.
2 supply reliability?
3 A. Yes. A summary of such studies is provided as Exhibit 4
210, Schedule ?.. The supporting studies are voluminous, 5
and are not included in my workpapers because they were 6
provided to all parties in response to FERC Trial Staff 7
Request SE 2-30. The study results indicate a 8
substantial Ancrease in supply reliability due to merged 9
system operation.
10 .
Q. Does Mr. Goff also question the usefulness and 11 cost-effectiveness of merged system resources to provide 12 increased nonfirm power supply reliability?
13 A. Yes. Specifically, Mr. Goff questions the usefulness 14 and cost-effectiveness of Pacific Power's peak capacity 15 purchase contract with BPA to provide i.ncreased nonfirm 16 supply reliability (Exhibit 118, p.13). He claims that 17 the contract "only provides for capacity purchases 18 during heavy load hours" and "any use of capacity 19 purchased under BPA's Schedule CF-87 rate for a duration 20 which exceeds eight hours on a monthly basis results in 21 additional charges," which would reduce the claimed 22 benefits.
23 Q. Has Mr. Goff correctly described the terms and 24 conditions associated with Pacific Power's use of the 25 firm capacity purchase from SPA, and that purchase's 26 Page ,
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1 role in providing increased nonfirm supply reliability?
2 A. No. First, it is the entire merged system's resources, 3 not just the BPA capacity contract, that helps provide 4 more reliable nonfirm sales. While BPA peak is a major 5 and important part of the merged resource mix, the 6 company's hydro resources with their attendant storage 7 and other system resources are equally important to 8 overall system reliability.
9 Second, with regard to the BPA capacity contract, Mr.
10 Goff apparently misunderstands the contract terms and 11 the current wholesale power rate schedule, CF-87.
12 Pursuant to Pacific's contract, we can schedule B deliveries of capacity from BPA in any hour, peak or ,
14 off-peak, up to the contract demand. The contract 15 demand is currently 1027 MW. Mr. Goff's description of 16 the extended peaking surcharge in BPA's CF-87 rate 17 schedule is misleading. A careful reading of the rate 18 schedule, provided in Mr. Goff's Exhibit No. 121, 19 indicates there is no limit to the number of hours that 20 capacity can be scheduled, and there is no peaking 21 surcharge as long as the demand duration during any peak 22 day does not exceed eight hours. Demand duration is 23 defined in the rate schedule as the total energy 24 scheduled during a day's peak hours divided by the 25 contract demand. Pacific Power can therefore schedule 26
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1 at least 8,216 MWh (8x1027) during each and every day of i i
2 .a month without incurring the-peaking surcharge, which j 3 Mr. Goff claims would offset any nonfirm price premium.
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j Therefore, Mr. Goff's assertions of impaired usefulness' .l 5
and cost-effectiveness of this resource are also y incorrect. 3
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7 Q. Has Pacific Power ever incurred the extended peaking l 8
surcharge for its use of BPA peak capacity? .
9 i A. No. The extended peaking surcharge was first included in .
10 BPA's firm capacity power rate schedule in' 1979. In the 11 ensuing nine years, Pacific Power has never incurred the i 12 peaking surcharge. During this same period, Pacific has u
provided reliable nonfirm and block sale services to t
14 numerous wholesale customers.
s 15
- Q. Please summarize your discussion of nonfirm sales price l 16 j
assumptions. ;
- 17 A. The price assumptions used in estimating merger benefits (
) 18 are reasonable when compared with current prices in 'the
) ;
i 19 marketplace. The merged company's improved reliability ;
20 and resource diversity will allow it to provide premium ,
21 i
nonfirm service when requested and justifies at least a j
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22 one mill /kWh price premium for the sales made to Utah l 23 Power's traditional markets. Mr. Goff's claim that the f 24 merger "vill have a net adverse affect" on the ability j
25 to assure d.elivery of nonfirm power is invalid. His i
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conclusion that price premiums can only result from 2
control over transmission, not premium. service, is not ,
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based in fact.
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'4 Q. Mr. Goff (Exhibit 118, p. 10) asserts that Utah Power's i 5
nonfirm sales over the Pacific Intertie (Intertie) were L 6
understated by your studies. What is the basis of his 7
contention?
8 Mr. Goff simply asserts thate since Utah Power could A. ,
9 '
have nonfirm access rights to the Intertie, that sales over the Intertie should have been assumed'in our :
11 analysis.
12 Q. Has Utah Power ever made nonfirm sales over the D .
Intertie, in actual practice?
14 A. No. Utah Power has never made Intertie sales, and the B
6 power cost model simulations are therefore realistic. !
16 Although Utah Power could gain some Intertie access !
17 under certain conditions, there are severe constraints :
2 on its ability to economically utilize such rights in i
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actual practice. Utah Power is not directly connected 20 to BPA, and would currently incur about 6 mills /kWh for j 21 wheeling and losses to make Intertie sales. This makes :
22 such sales uncompetitive, assuming that transmission >
23 paths to BPA vere even available. Mr. Goff also suggests that Utah Power could overcome such impediments 25
' through contractual arrangements, which I discuss later ;
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1 in my testimony.
2 Q. You stated that Mr. Goff also criticizes the analytical 3
methods used to estimate nonfirm sales benefits. What
.4 are his criticisms?
5 A. Mr. Goff r.laims that the power cost model studies "have 6
arbitrarily constrained UP&L's thermal generation when 7
modeling UP&L operating as a separate company below the 8
level used when modeling UP&L as a merged company" 9
(Exhibit 118, p. 15). He further asserts that this 10 understates nonfirm sales that could be made by UP&L 11 without the merger and overstates the merger benefits 12 (Exhibit 118, p. 16). In support of his contentions he 13 performs alternative projections of Utah Pover's nonfirm 14 sales without the merger (Exhibit 122).
15 Q. Are there errors in Mr. Goff's analysis?
16 A. Yes. His characterization of the model results 17 contained in my direct testimony is incorrect and his own analysis is misleading with regard to merger benefits.
20 Q. Please explain.
A. First, with regard to the alleged inconsistency between the unmerged and merged simulations, Utah Power generation in the unmerged case was not constrained more severely than in the merged system simulation. In fact, just the opposite is true. My exhibit 210, Schedule 3 Page 12-7
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compares the total energy generating caeability of Utah !
2 Power's units, as determined using the production factor 3 These values and thermal maintenance model inputs. ,
indicate the units were constrained more severely under 5
merged system operation than under unmerged operation by 6
1 about 218,000 MWh/ year, on average. The lower total I 7
energy availability from Utah Power generating units for 8
^
the merged system simulation was used to reflect a ,
9 slightly heavier reliance on these units for load ,
10
< control after the merger.
11 Mr. Goff's erroneous conclusion is based on his '
examination of the results of the power cost studies, 13 not the input constraints. Because Utah Power 14 generating plants produced more energy in the merged 15 system study than in the unmerged study, he incorrectly ;
16 concludes that the model unfairly constrained the l 17
' operation of these generating plants.
18 ;
Q. Were Utah Pover's generating units constrained by model 19 logic from making nonfirm sales in the unmerged 20 simulations, but not so constrained in the merged r 21 simulations, as Mr. Goff implies?
22 i A. No. All economic sales to available markets, as well l 23 j
as purchases and displacements were allowed in the i 24 unmerged simulations, just as in the merged system .
25 simulation. Utah Pover's generating units ran higher in i
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the merged simulation, in spite of the more severe 2
availability inputs, because of increased oportunities 3
for displacement, wholesale power market diversity, and
.4 the new firm sales. -
5 Q. Why do you believe Mr. Goff's analysis is misleading?
6 -
A. Notwithstanding the fundamental error in Mr. Goff's 7
assumptions I just described, he failed to include the 8
cost of generation to make the sales he assumed could be 9
made. In so doing, he substantially overstated the 10 .
implied'effect of his assumptions on merger benefits.
11 Q. Do intervenors raise any questions regarding the 12 purchased power assumptions of the merged system model?
13 A. Yes, Mr. Goff and Dr. Peters are both critical of the 14 nonfirm purchase results.
15 Q. What are Mr. Goff's criticisms?
16 A. Mr. Goff (Exhibit 118, p. 14) maintains that the lover 17 cost perchases assumed in the merged system study should 18 have been included in the unmerged Utah Power simulation 19 as well. He states that Utah Power is directly 20 connected with Deseret Generation and Transmission 21 Cooperative (Deseret), and that contractual arrangements 22 could be made to wheel other low cost purchases through 23 Western Area Power Administration (WAPA) facilities.
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Q.- Were any such purchases recognized in the power cost t
2 studies? i l- 3 A. Yes. Contrary to Mr. Goff's assumption, the nonfirm j .4 i purchase inputs to the unmerged Utah Power simulation -,
! 5 implicitly included substantial purchases from Deseret, . -\
based on Utah Power' actual operating experience. '
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i With regard to other power supplies which Mr. Goff
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l alleges could be made available through arrangements
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with either WAPA and/or Pacific Power absent the merger, .
j- 10
<- theinabilityofUtahPowertorelyonWAPk'ssystemis .
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' of Mr. Tucker.
4 discussed in the rebuttal testimony !
12 j Utah Power's ability to rely on transmission services i l
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i provided by Pacific Power would depend on speculative' l 14 future transmission service and resource coordination !
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agreements. ,
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. Q. What.is the'effect of those low-cor.t purchases on the !
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j merged system benefits?
- 18 A. I have quantified those benefits on line (6) of Exhibit 19 I l 210, Schedule 4. This exhibit also demonstrates that 20 i- Mr. Goff's estimate (Exhibit 118, p. 19) of joint [
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- dispatch benefits, net of low-cost power purchase i 22 l benefits, is incorrect.
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- Q. Do you agree with Dr. Peters' assertions with regard to f 4 24 nonfirm purchases? f
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A. No. Dr. Peters (Exhibit 36, p. 15) claims that power 2
cost model results in my direct testimony suggest 3
inefficient resource operations, because the merged 4
studies show a reduction in hydro generation and 5
secondary purchases and an increase in thermal 6
generation, as compared to the unmerged results. This 7
misrepresents model results in several ways.
8 Q. Do the model results indicate significantly less hydro 9
generation by the merged system?
10 A. No. Hydro generation by the merged and unmerged systems 11 is virtually identical. Th3 1,217 MWh difference 12 between syss.em hydro generation results over the five 13 year study, amounting to 0.005 percent of total hydro 14 generation, arises from the sto. age decisions made in the model's simulations. In some years there is an 16 increase and in some a decrease, but the changes are in 17 any event minute.
Q. Hov do nonfirm purchases and thermal generation change between the merged and unmerged systems?
20 A. Nonfirm energy purchases by the merged company are lover 21 by less than 2% over the five year period, ccmpared to the unmerged simulations. Total thermal generation increases 1.9% over the same period with the merger.
24 Dr. Peters implies that the increase in thermal generation is due to the need to replace nonfirm Page 16-
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I purchases and hydro generation. Dr. Peters fails to 2
observe that increases in thermal generation by the 3
merged system are primarily a result of increases in 4
economic wholesale sales by the merged system, which 5
reduce overall total power supply costs.
6 Q. Dr. Peters suggests that the merged system's 7
substituting thermal generation for purchases may be 8
inefficient, because those purchases could be derived 9
from hydro generation. Does this demonstrate 10 inefficiency?
11 A. No. It is the price of such purchases that determine 12 the efficient use of resources, not the ul.timate source D ,
of such purchases. The merged company will certainly rely on its own thermal generation resources rather than purchases, when the incremental costs of such generation are lower than the costs of such purchases. This vill 17 be the case for the merged company's operation, 18 regardless of the purchased power source, just as it is now the case for each of the companies. The merged 20 company'c reliance on its own thermal generation rather than on more expensive purchased power is rational economic behavior and consistent with efficient resource 23 24 E'#8ti ^*
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1 Q. Dr. Peters (Exhibit 36, p. 19) also questions the 2.
validity.of the power cost model's use of fuel costs for 3
dispatch,-because they do not include the operation and 4
maintenance costs of thermal generation. Are 5
incremental O&M costs considered in the model?
6 A. No, not directly. Fev thermal plant O&M expenses are 7
truly variable, or incremental. The overwhelming proportion of OEM costs are related to annual overhauls and plant workforce, and are therefore fixed. The 10 expenses that-could vary in proportion to energy 11 generated, on the other hand, include such items as scrubber reagents, water treatment chemicals, and ash hauling and disposal (offset by revenues from ash sales). These expenses are small and difficult to quantify for relatively small changes in thermal generation and are generally not considered by either company in actual dispatch decisions. They are likely to be in the range of 0.2 to 0.5 mills /kWh. These are minuscule compared with fuel expense, and could amount to only about 50.7 to $1.7 million over the five year period, compared to net power cost savings of $159
!. million from the merger. We did not attempt to
- 23 quantify every conceivable cost nor take credit for every possible benefit.
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1 Q. If incremental o&M costs had been included in the model- l 4
2 dispatch logic, would the purchase or sale results have 3 been different? i
,4 A. No. Overall operations would have been substantially 5
the same as simulated. Incremental o&M costs are well 4
.! within the minimum 2 mills /kWh margin of sale price over 7 !
j fuel cost that the power cost model requires in its 8
nonfirm sales decision logic.
9 Q. Does any other witness misinterpret the thermal ;
10 generation results of your power cost simulations? h II A. Yes. Based on his misinterpretation of the thermal 12 d
generation data in Exhibit 11, Schedule 5, Mr. i 13 '
Winterfeld (Exhibit 125, p. 8) criticizps Mr. Reed a 14 construction savings estimates due to postponement of !
15 j Bridger turbine upgrades. l 16 Q. Why is Mr. Winterfeld's interpretation incorrect?
17 A. Mr. Winterfeld implies that the turbine upgrades are 18 required because the power cost simulations shov 19 l increased generation from Bridger over the 1988-92 [
20 period with the merger. This increased generation is
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] within the capability of the units without turbine :
22 upgrades. The power cost model inputs did not assume j l upgrades to the units for which Mr. Reed included 4
! construction savings, nor did the simulations indicate a I
25 requirement for the upgrades. l l 26 !
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I Q. Witnesses Goff and Kahal questioned the benefits you 2 estimated for wheeling,, expense savings from an exchange 3
arrangement with BPA. Please describe Mr. Kahal's
'4 assertions first.
5 Mr. Kahal considers the estimate a questionable A.
6 assumption and concludes that the subject has not been I
explored with BPA (Exhibit 18, p. 13). He also 8
categorizes the resulting savir.gs as a "pecuniary 9
economy of scale", i.e., a result of increased bargaining strength comparable to wresting' price 11 concessions from suppliers.
Q. Are his criticisms valid? .
A. No. Negotiations have already taken place with BPA over 14 this arrangement, at BPA's request. A detailed proposal 15 from BPA vas provided in response to data requests CREDA 16 3-J-197 and UMW 2-G-33. These responses contained a 17 detailed proposal frem SPA. The proposal could hardly 18 be called an unexplored subject, or an extraction of 19 price concessions from BPA. It represents a true 20 efficiency that can result from the transmission 21 improvements and system integration that the merger 22 allows.
23 Q. What does Mr. Goff allege with respect :o this exchange 24 arrangement with BPA?
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i I A. Mr. Goff (Exhibit 118, p. 8) asserts that the same 2 wheeling service a'nd benefit could be achieved by Utah 3 Power alone, or by way of a three-party contract without 4 the merger.
" 5 Q. Does he suggest practical arrangements to support his 6 contention?
7 A. No. Again, Mr. Goff speculates that merger benefits 8 could be obtained through contractual arrangements.
9 With regard to the specifics of Mr. Goff's proposals, he 10 suggests a completely unworkable arrangement under which Il
- Utah Power we'uld provide the exchange service without 12 .the merger. Because Utah Power lacks an interconnection U with the BPA system, from which BPA must deliver the 14 energy and capacity for the southeast Idaho load, Mr.
15 Goff proposes an arrangement under which Utab Power 16 would serve the southeast Idaho load, and receive 17 equivalent power from BPA to market over the Pacific 18 Intertie. This rests on'the unsupported assumption that 19 Utah Power would always have sufficient power to meet 20 the firm requirement, and a market of equivalent size in 21 California, either firm or nonfirn. He suggests a 22 similar three-party arrangement that similarly ignores 23 resource requirements and power markets?
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-Q. Does the BPA proposal you received mention Intertie 1
2 access as a potential element in the exchange?
A. No. J
.4 Would any'of the assertions made by intervenors with Q.-
5 regard to your estimates of power cost savings cause you 6
to change your estimates?
7 A. No.
II. Economic Development Costs 9
Q. Several intervernors have disputed economic development 10 benefits of the merger testified to by Mr.' Reed, on the 11 grounds that the power supply costs to serve the 12 increased loads vere not accounted for in the 13 evaluation. Do you have any comments on this analysis?
14 A. Yes. Dr. Peters (Exhibit 36, p. 18) presumes that the 15 power supply costs were omitted from the estimate of 16 benefits in Mr. Reed's testimony, and therefore 17 recommends the incremental loads be included in the 18 power cost model calculations. He provides a study that adds the incremental loads to the base system loads of 20 the merged system, and concludes that these incremental 21 loads will lower power supply benefits by the difference 22 between his study and the study described in my direct 23 testimony. This difference amounts to about $16 24 million in 1992, the last year for which net power cost 25 and economic development benefits were estimated.
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Dr. Peters fails to note that the economic' development 2
benefit estimates in Mr. Reed's testimony already 3
recognized the incremental power costs of the increased loads. This is clearly stated in Mr. Reed's workpapers 4
5 accompanying his direct testimony (pp. 921-923) 6 The supporting his economic development estimates.
7 adjustment to power supply costs recommended by Dr.
8 Peters would therefore double count the power costs.
9 Q. Does any other witness distort the relationship between 10 economic development costs and revenues?
11 A. Yes. Mr. Goff (Exhibit 118, p. 20) added his projection 12 of economic development loads to his analysis of ,
13 long-range power supply benefits over the 1988-2007 14 period. However, Mr. Goff failed to include the 15 revenues that would be associated with his assumed 16 loads. In addition, Mr. Goff included long-range 17 resource requirements and costs associated with the firm 18 wholesale power sale assumed in my 1988-92 power cost 19 estimates. He essumed that the firm sale would extend 20 over this period, and again failed to consider the 21 revenues that the sale would produce.
22 Q. Were the costs and revenues of merger-related economic 23 t
development and firm wholesale power sales included in l 24 l your analysis of long-range power supply benefits?
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k I A. No. Neither the costs nor the benefits were included in 2
my direct testimony. As I discuss in the next section 3 of my testimony, an evenhanded accounting of long-range 4 costs and revenues would not change our conclusions that 5 the long-range resource planning benefits from the 6
merger are substantial. l 7
III. Lono-Rance Resource Plan Benefits 8 Did Mr. Goff criticize your long-range power supply Q.
benefits?
0 A. Yes. He also provided an alternative estimate in Exhibit 11 124.
12 Q. What is your estimate of the long-range power supply 13 benefits of thb merger?
14 A. As I stated in my direct testimony (Exhibit 11, p. 7), I 15 estimated the 20-year net present value (npv) savinos to 16 be about $352 million, compared to Mr. Goff's estimated 17 cost _ of about $176 million. This amounts to a 18 difference of about $528 million between our two 19 estimates.
20 Q. What is the major difference between your estimate and 21 Mr. Goff's estimate?
22 A. As I previously testified, the major difference is the 23 treatment of costs and revenues associated with new 24 economic development and the new firm wholesale power 25 sale. My analysis excludes both the costs and revenues; 26 Page
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I Mr. Goff's analysis only includes costs.
Q. Have you estimated the revenue associated with both 3
economic development and the merged system's new firm 4
power sale?
5 A. Yes. A reasonable estimate of the revenues is between 6
$465 and $513 million npv. The assumptions used to 7
calculate these revenues are included in my rebuttal 8
testimony workpapers.
9 Q. Do these revenue estimates include any costs?
10 '
A. Yes. The revenue estimates are net of additional 11 incremental distribution system costs associated with 12 the economic development load.
D Q. Can these revenues be added directly to Mr. Goff's 14 estimate of resource plan costs?
15 A. I would not recommend that, because Mr. Goff's analysis 16 contains several errors and questionable assumptions.
17 The revenue estimates do, however, give an indication of 18 how distorting a measure his cost estimate is.
19 Q. What are the errors and questionable assumptions you 20 refer to in Mr. Goff's long-range power cost analysis?
21 A. He increases resource requirements by 40 MW, associated 22 with an incorrect Mid-Columbia capacity assumption, and 23 makes inappropriate resource plan assumptions regarding 24 the availability of BPA purchases and other resources 25 available to the merged system.
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l Q. Why does Mr. Goff increase resource requirements by 40 2 '
MW, associated with Mid-columbia generation (Exhibit 3
118, p. 20)?
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A. He-disagrees with the benefit of reduced load following 5
with Mid-Columbia generation, as described in Mr. l 6
Boucher's direct testimony, contending that any 7
increased Mid-Columbia capability would be counteracted 8
by decreased capability at the Utah Power generating 9
plants that would be providing more load following.
10 Q. Why is Mr. Goff's ,40 MW increase in capacity requirement 11 incorrect?
12 A. He confuses long range capacity planning adjustments 13 with operation planning considerations. Pacific Power 14 reduces the Mid-Columbia capacity by 80 MW for resource 15 planning purposes because Mid-columbia generation is the 16 only substantial source of load following available to 17 the company. The operating constraints imposed by this 18 use limit the peak capability of Mid-Columbia 19 generation, making the 80 MW adjustment appropriate. My 20 study assumed that only a 40 MW adjustment would be 21 appropriate subsequent to the merger.
l 22 Q. Does Utah Power's system have similar load following 23 constraints?
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A. No. Utah Power, in contrast to Pacific Power, has 2
Automatic Generation Control (AGC) equipment on each of 3
its large thermal generating units. Normally, Utah 4
Power's system operation requires two units to prov.ide -
5 load following at any time. With this flexibility, Utah 6
Power does not have operating constraints comparable to 7
those on the Mid-columbia generation, and therefore 8
makes no capacity adjustment in its resource plans.
9 With the merger, Mid-Columbia operating constraints will 10 -
not be as severe, because the AGC capability on each of 11 Utah Power's units will be available to provide load 12 following to the merged system. This change will reduce U .
the Mid-Columbia operating constraints, but is not 14 expected to introduce new operating constraints on the 15 Utah Power generating units, because the load following 16 can be provided by more units than are currently 17 employed for load following. Therefore, an additional
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reduction to Utah Power's generating capability, as Mr.
i 19 Goff suggests, need not be made.
l Q. Are there other errors in Mr. Goff's analysis?
21 He made a number of changes and assumptions in his A. Yes.
22 merged system plan that were incorrect, and were also
! 23 inconsistent with the Pacific Power and Utah Power
! 24
( resource plans analyzed in my direct testimony. He then l 25 compared the cost of his plan to the costs of the Page * -_ --
1 Pacific Power and Utah Power plans from my direct 2 testimony. The incorrect changes and assumptions made 3 -ty( Mr. Goff include the following:
4 - cost effective cogeneration options were omitted 5 - capacity of Bridger upgrades and conservation were omitted
- SCE contract energy withdrawals were incorrect 7
8
- new generating plant was added in unrealistic increments 9 - BPA purchases were overly restricted 10 Some of these errors tend to understate th6 resource II plan costs, while many of them tend to overstate the 12 costs he has estimated. Taken as a whole, these errors U make it impossible to draw conclusions from his 14 analysis.
0 With regard to the BPA purchase alternative, Mr. Goff Q.
16 (Exhibit 118, pp. 20-21) claims your analysis I
incorrectly assumed that construction of additional UP&L 18 generation plants could be delayed with purchased power 19 from BPA, based on his interpretation of the BPA-NR 20 Please comment on his testimony.
rate schedule.
21 A. Mr. Goff contends that the merged system's ability to 22 purchase BPA-NR power vill be restricted by the fact 23 that some of the merged system's load growth is outside 24 of the Pacific Northwest Region (Region). However, the 25 availability of BPA-NR power to the merged system is a 26 Page M
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I function of both load growth and various changes in 2 resource availability inside the Region, and is 3 determined by each Company's Power Sales Contract with 4 BPA, not by the BPA-NR rate schedule. He has therefore 5 underestimated the availability of BPA-NR power to the 6 merged company.
I We fully expect to have sufficient contractual rights to 8 purchase BPA-NR power in the quantities shown in my 9 direct testimony. For example, in 2006-07 the merged 10 system's regional load is forecast to be 2,670 aMW, as II compared to a 1979-80 load in the Region of 1,978 aMW, a 12 In addition, regional load growth of 692 aMW.
13 reductions in resources previously committed to serving' I4 Regional load can be made under the terms of the Power 15 Sales Contracts when they are no longer available, 16 Mid-columbia rights, Hanford including the loss of 17 Exchange, Hanford Extension, Canadian Treaty Contracts, 18 In combination, the regional load and other resources.
19 growth and energy withdrawal rights vill allow the 20 Company to purchase BPA-NR power in the quantities 21 assumed, should those purchases be the most economical l
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option.
! 23 You have suggested a number of corrections to Mr. Goff's Q.
analysis. Would making these corrections provide an 25 appropriate cost basis for comparing long-term power 26
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I supply costs, including those associated with economic 2 development, with the revenues you have estimated?
3 A. No. Since the revenues I have estimated for economic 4 development include both the short- and long-run 5 revenues, the analysis should also include all short-run 6 costs associated with those loads, to be consistent.
I Q. Have you prepared such a consistent analysis?
8 A. I have analyzed two alternative scenarios, each with the 9 additional firm sale and economic development loads, and 10 each with a consistent treatment of costs' and revenues.
II They employ the same methods and resource alternatives as the plans in my direct testimony, and therefore 13 avoid the numerous errors introduced by Mr. Goff. In one 14 amount scenario, I limited BPA-NR purchases to the 15 In the other scenario, included in my direct testimony.
16 I constrained the BPA-NR purchases to not exceed the 17 levels that were made in Mr. Goff's analysis.
18 These analyses are summarized in Exhibit 210, Schedule 19
- 5. They indicate that long-range resource savings of 20 the merger are in the range of $327 million to $375 21 million, using my BPA-NR assumption, and $256 million to 22 S304 million, using Mr. Goff's assumption.
23 In summary, Mr. Goff's estimate contained in his Exhibit 24 124 included costs of economic development and the new 25 firm sale, but failed to credit their incremental 26 Page l
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1 benfits. The analysis I provided in my direct testimony 2 did not include those costs, because it did not take 3 credit for any of the revenues of those load increments.
4 The long-range benefits of the merger that include both 5 costs and revenues are as summarized in Exhibit 210, 6
Schedule 5.
7 IV. Effects of Merced System Operation 8 and Plannino on Others 9 Have witnesses claimed that other parties will be harmed Q.
10 by the merged company's reduction in capac'ity reserves II in its resource plans?
12 A. Yes. Witnesses Helsby (Exhibit 134, p. 25) and Casazza U (Exhibit 51, p. 30) both contend that any reduction'in 14 reserve levels by the companies will either unfairly 15 cause other utilities' reserve requirements to increase, 16 or will reduce regional reliability.
17 Q. What is the basis for reserve savings incorporated in 18 the merged company resource plan?
19 A. As described in Mr. Boucher's direct testimony and 20 indicated in Exhibit 210, Schedule 2, the merger vill 21 improve the generation reliability of the merged 22 company, and strengthen transmission interconnections.
23 Our estimates of forced outage reserve reductions are l based on preliminary studies only, but as Staff witness 25 Schuppin points out (Exhibit 116, p. 23), the 26 l
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3:
o I preliminary analyses we have conducted use methods 2 recognized in the utility industry. Mr. Schuppin has 3 reached a similar conclusion that the merger will 4 improve system reliabilty.
5 Will this reduction in forced outage reserves cause Q.
6 other utilities' forced outage reserves to increase?
7 A. No. Witnesses Casazza and Helsby presume that the 8 reserve savings must cause others' reserves to increase, 9 because of their misunderstanding of how Pacific Power's 10 capacity planning treats Pacific Northwest' Coordination II Agreement (PNCA) and Intercompany Pool (ICP) Agreement 12 reserve allocations.
U Pacific Power has used as its capacity planning 14 criterion the winter peaking period (November through 15 February) average reserve allocation of the Pacific 16 Northwest Coordination Agreement. Under the ICP II agreement, Pacific Power still complies with its PNCA 18 reserve requirements while maintaining the lower ICP 19 Pacific Power has used the higher reserve allocation.
20 PNCA reserves ( 950 MW versus 539 MW from the 1987-88 21 ICP allocation), largely because of our concern over 22 issues of transmission and the avail ability of capacity 23 from other utilities.
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f 1 Because the merger vill improve internal reliability, 2 Pacific Power's more stringent planning criterion can be 3 relaxed. That is, Pacific can adopt the lover ICP
.4 reserve allocation as its planning criterion with no 5 effect on the ICP or PNCA forced outage reserves 6 allocated to others. Pacific could make this unilateral 7 change with or without the merger, and the merged system 8 resource plan (Exhibit 9, Schedules 16 and 17) assumes 9 this type of reduction. The merger allows such a change 10 without adversly affecting system reliability or 11 burdening other systems.
12 Beyond what is assumed in the merged company resource U plan, the merged company could, within the terms of the.
' 14 PNCA and the ICP, declare ~ resources in such a manner U that would increase other parties allocated reserves.
16 The merged Company's proposed reserve reduction does 17 not require such resource withdrawals.
18 Q. What is your response to Mr. Drummond's assertion 19 (Exhibit 27, p. 4) that the merger ought not be approved 20 because it might reduce sales by other Northwest 21 utilities and BPA?
22 On a philosophical level, I believe that it is important A.
23 to note that virtually anything one utility does is 24 likely to somehow effect another utility or business.
25 In the absence of such relationships, the operation of 26 Page E
L I market forces and societal efficiency gains would be 2 impossible. Mr. Drummond would have us forego the 3 efficiencies of this merger because it miaht cost some
.4 of the PPC members money.
5 Q. Are there benefits to entities other than the merged 6 company from merger-enabled sales?
7 1. . Yes. Mr. Drummond takes a myopic view of lost sales by 8 BPA or others due to the merger. In order for a sale to 9 be lost, somewhere a purchaser has to have' changed 10 suppliers, a result that will only occur in the 11 expectation of a superior product or a better price.
12 Mr. Drummond would have us focus on the disappointed l3 selle'rs and their retail customers, to the exclusion of 14 the satisfied buyers and their customers.
15 Q. Philosophy aside, has Mr. Drummond properly 16 characterized the potential for lost sales by others?
17 A. No, I believe he has substantially overstated the 18 potential. It is notable that two of the entities Mr.
19 Drummond purports to be protecting - BPA and Puget Sound 20 Power and Light Company have not intervened in this 21 proceeding. A third, the Washington Water Power 22 Company, has intervened, but filed no testimony. Jus:
23 as significant, no extra-Regional utility has filed 24 testimony complaining about having to buy lower-cos:
25 power from the merged Company.
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1 Q. Do you expect BPA to suffer a material loss of revenues 2 as a result of the merger?
3 A. No. Mr. Drummond's calculations assume (Exhibit 27, p.
4 7) : (1) All of the merged Company's increased sales 5 will be at the expense of BPA, (2) BPA has no ability 6 to otherwise make up the lost sales at any price, (3) 7 BPA generates power at no cost, and (4) the BPA Public 8 Agency rate lid is not in effect.
9 Even with the benefit of these extraordinary 10 assumptions, Mr. Drummond is only able to demonstrate 11 that the Bonneville rate paid by PPC members will 12 increase by one twentieth of a cent per kilowatt-hour, U three to four years from now.
14 Q. Have you reviewed Mr. Drummond's Exhibit 28, which 15 purports to calculate the "value" of sales to Pacific 16 Power and Utah Power by Idaho Power Company?
17 A. Yes. The calculations performed by Mr. Drummond are 18 meaningless because they deal only with total revenues 19 and do not account at all for the cost of producing the 20 power sold. Absent a consideration of costs, there is 21 no vay to determine how a loss of revenue translates 22 into a loss of net income (if any). Also, as with his 23 BPA calculations, Mr. Drummond assumes that sales 24 formerly made to the merging companies by Idaho Power 13 would not be made to any other party at any price. His 26
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[. 1 A l 2 i L r s 1 assumption that Idaho power would not make any sales to 2 the merged company is also far-fetched, considering that 3 the power cost model simulations (Exhibit 11, Schedule 4 4) indicate the merged company will only reduce nonfirm 5 purchases by less than 2%.
6 Q. Does the merged company expect to continue to buy power 7 from BPA and other Northwest utilities?
8 A. Yes. The power cost model and long range resource plan 9 studies show continued substantial capacity and nonfirm 10 energy purchases from BPA. The only reason the capacity 11 purchases would not be made is if BPA and Pacific cannot 12 come to terms on price - a result I do not expect.
U There will be some reduction in purchases of nonfirm 14 energy from historical levels because of the lower 15 mining costs Utah Power has achieved recently. To the 16 extent the prices demanded by' Northwest utilities for 17 nonfirm are competitive with our other options a 18 substantial level of transactions can be expected.
19 Q. Does this conclude your rebuttal testimony?
20 A. Yes.
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W i I.
F
- 1 g UNITED STATES OF AMERICA ;
BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION 2
3 Utah Power & Light Company )
Pacificorp ) Docket No. EC88-2-000 .
4 PC/UP&L Merging Corporation )
5 AFFIDAVIT OF DENNIS P. STEINBERG s STATE OF OREGON )
7 )ss.
County of Multnomah) 0 Dennis P. Steinberg, being first duly sworn, on oath states that he is Director, Power Planning of Pacific Power &
Light company, whose attached Rebuttal Testimony, Summary and Work Papers were served on all parties to the above-referenced proceeding. Dennis P. Steinberg further states that if asked the questions contained in the text of such testimony, he would give the answers that are therein set forth and that he adopte the aforesaid answers as his, rebuttal testimony in this proceed-16 ing. ,
17 l
18 Ddn is/PI Steinb4~r Subscribed and sworn to before me thf s 22nd day of 20 February, 1988.
/ h .
22 Notary Publip for Oregon My Commission Expires: /2 - / - 9 /
23 24 25 t 26 Page l - AFFIDAVIT OF DENNIC P.
STEINBERG
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