ML20153F976
| ML20153F976 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 01/08/1988 |
| From: | Steinberg D UTAH POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML20153F598 | List: |
| References | |
| NUDOCS 8805110109 | |
| Download: ML20153F976 (36) | |
Text
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ir Exhibit B F
UNITED STATES OF AMERICA t
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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PREFILED TESTIMONY OF DENNIS P. STEINBERG i
l 8805110109 880509 PDR ADOCK 05000344 l
T DCD k
p-t.
Exhibit No. 10 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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PREFILED TESTIMONY OF DENNIS P. STEINBERG ON BERALF OF PACIFICORP, UTAH POWER & LIGHT COMPANY PC/UP&L MERGING CORP.
I January 8, 1988 1
5-t
SUMMARY
OF TESTIMONY OF DENNIS P. STE!NBERG ISSUES ADDRESSED 1.
Power supply benefits resulting from the merger.
2.
Coal supply arrangements for Pacific Pover's and Utah Pover's plants.
CONTENT AND CONCLUSIONS Savings in generation investment and resource acquisition costs result from two factors.
Postponement and reduction of new capacity purchases are possible because of peak load diversity, reserve sharing and increases in available capacity.
Second, new energy resources are postponed beyond the 1993-94 time frame required by Pacific Power in the absence of the marger.
Construction of new generating resources required by Utah Power in the absence of the merger is avoided by increases in less expensive firm purchases.
The costs of advancing construction of additional transmission facilities are subtracted from these savings.
Savings in power system operations (Net Power Cost) result from more efficient dispatch of generating resources, displacement of higher-cost purchased power, and the ability to make additional wholesale sales at enhanced sale margins.
C 2-COAL SUPPLY ARRANGEMENTS Pacific Power has an interest in five existing coal-fired I
generation projects located in Washington, Montana and Wyoming.
The coal supply for each plant is described.
Utah Power has an interest in four existing coal-fired generation projects.
The coal procurement activities of the merged company will not differ from the current activities of the individual companies.
The overall objective vill continue to be to provide safe and reliable electric service at the lowest reasonable cost to customers.
Preference vill not be given to affiliated coal suppliers.
The merged company's coal arrangements and ownership interests vill not have any measureable effect on either the availability of coal to other utilities or on wholesale power competition.
Four of the five coal-fired power plants in which Pacific Power has an interest are jointly owned with wholecale power competitors and those competitors also wholly own or partially own and control the attendant coal supply.
The coal for Pacific Pover's wholly-owned coal-fired generating plant, Dave Johnston, is supplied by Pacific Power's Dave Johnston mine and through outside unaffiliated purchases.
None of the merged company's wholesale power competitors purchase coal from the Dave Johnston mine.
PacifiCorp's NERCO subsidiary sells coal to Platte River Power Authority (PRPA) under a flexible coal supply contract.
La
.o
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3 No wholesale power competitors of the merged company purchase coal from interests owned by Utah Power.
The merged company, including affiliated coal interests, would control less than 6 percent of the contro11esd, uncommitted coal reserves in the western coal market.
1
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i I
l l
f l
l t
y D.
P. Stoinbdrg t 1
9.UESTION 2
Please state your name, business
- address, and 3
present position.
4 ANSWER 5
My name is Dennis P.
Steinberg.
My business 6
address is 920 SW sixth Avenue, Portland, Oregon 97204.
My 7
present position is Director of Power Planning with Pacific 8
Power & Light Company (Pacific Power or Company).
9 QUESTION 10 Please summarize your education and business ex-11 perience.
12 ANSWER 13 I
received a
Bachelor of Science degree in 14 Electrical Engineering from Northrop University in 1972.
In 15
- addition, I
have taken courses from the University of 16 Southern California and General Electric Company in the area 17 of Power System Analysis.
From 1972 to 1978 I was employed 18 by Southern California Edison Company as a
Generation 19 Planning Engineer.
I was employed by Pacific Power in 1978 20 as a Power Resource Engineer, advancing to a Senior Power 21 Resource Engineer in November of 1980, to Power Resource 22 Planning Supervisor in January,
- 1983, to Power Resource 23 Studies Manager in
- July, 1984, to Power Planning and 24 Analysis Manager in May, 1985, and to my present position in 25 October, 1987.
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,C D. P. Stoinborg f 1
QUESTION 2
What are your present duties?
3
_ ANSWER 4
As Director of Power Planning, I am responsible 5
for the activities of the Power Planning and Analysis 6
Department, Power Contracts Department, and the Wholesale 7
Power Marketing Department.
I am also responsible for the 8
preparation of power resource and power cost information 9
used in retail rate filings.
10 QUESTION 11 What activities are performed by the Power 12 Planning and Analysis Department?
13 ANSWER 14 The activities of that department include the 15 performance and evaluation of long-range load / resource 16 studies using computer programs which simulate the operation 17 of Pacific Power's system under different operating 18 conditions.
The purpose of these studies is to identify 19 the most cost-effective future power supplies and operating 20 strategies for the Company's customers, i
21 QUESTION 22 Have you previously testified in regulatory j
23 proceedings?
24 ANSWER 25 Yes.
I have testified in regard to many power 26 planning and operation matters in Wyoming, Oregon, Washing-
D. P. StoinbDrg ?
1
- ton, Montana, California, and before the Federal Energy 2
Regulatory Commission.
3 QUESTION 4
What is the purpose of your testimony?
5 ANSWER 6
The purpose of my testimony is to discuss 7
currently estimated power supply benefits of the merger.
I 8
will also discuss the merged company's coal supply arrange-9 ments and any attendant effects those arrangements may have 10 on wholesale power competitors.
With regard to merged 11 system power supply benefits, these benefits include savings 12 in three areas that have been more generally described in l
13 Mr. Boucher's testimony.
The first is savings in new 14 resource investments or purchased power costs to meet the 15 merged system's future capacity and energy requirements, as 16 compared with the costs of meeting each individual system's 17 requirements without a merger.
Second is savings in future 18 power system operating costs from the more efficient 19 dispatch of the merged system's resources.
The third source 20 of power supply benefits is additional net revenues from 21 both nonfirm and firm wholesale sales that the merger makes 22 possible.
23 QUESTION 24 Mr. Steinberg, do you have an exhibit in connec-25 tien with your testimony?
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~S D. P.-StOinb3rg t r
1 ANSWER 2
- Yes, I have Exhibit No.
11 which consists of 3
Schedules 1 through 5.
4 QUESTION r
5 Was the exhibit prepared under your direction and 6
supervision?
j 7
ANSWER t
8 Yes, it was.
9 QUESTION 10 Please describe the information shown in Sched-t 11 ule 1 of Exhibit No. 11.
j f
12 ANSWER 13 Schedule i summarizes annual savings in all the, j
14 areas studied by year over the next five years.
Savings are 2
15 summarized in two categories.
The first category is the 16 savings in generation and resource acquisition costs, offset I
17 in part by costs of advancing transmission investment.
In 18 the second category are savings in power system operations j
19 that result from the merger, identified as Net Power Cost i
20 Savings in the schedule.
Included in tne Net Power Cost i
21 Savings are revenues from both nonfirm and firm wholesale i
?
22 sales.
(
23 00ESTION 24 How were savings in generation and transmission 25 investment and resor:ce acquisition costs shown in 26 S w < d., 1 es'.irated7-I t
1
\\
D. P. Stoinborg :
1 1
ANSWER 2
The details of this estimate are summarized in 3
Schedule 2 of Exhibit No.
11.
This schedule shows the 4
annual costs associated with new capacity resource and 5
energy resource acquisitions and new transmission invest-6 ments by operating year from 1988-89 through 2006-07.
These 7
data are shown for Utah Power, for Pacific Power, and for 8
the merged system.
Also, the differences in these costs 9
between the merged system and the sum of the two separate 10 systems are shown.
The costs associated with new transmis-11 sion investments are based on the information provided in 12 Mr. Boucher's Testimony.
They assume Pacific Power's 13 Firehole-to-Bridger Pump and South Trona-to-Monument 14 additions are advanced from 1989 to 1988, and Bridger-to-J 15 Rock Springs additions are advanced from 1995 to 1989 as a 16 result of the merger.
The new Shute Creek-to-Opal addition 17 is also added in 1989.
These transmission lines are shown i
18 in Schedule 4, page 1, of Mr. Boucher's Exhibit No.
9.
The 19 Bridger System Midline Switching (Treasureton Loop-in) 20 addition is assumed to be required by 1998 for the merged 21 system, in order to meet Utah summer peaks without addition-I 22 al generation, as described by Mr. Boucher.
23 The costs associated with new capacity resource 24 and energy resource acquisitions are also based on the data of l
25 provided in Mr. Boucher's Testimony describing the ef fect 26 the merger on future capacity expansions.
Schedule 2 of l
i 6
5 D. P.
Steinberg 1 1
Exhibit No. 11 quantifies the savings that arise from the 2
difference in future resource requirements as shown in 3
Schedules 21 and 22 of Mr. Boucher's Exhibit No. 9, with one 4
difference.
That difference is an increase in capacity 5
purchase requirements for the merged system of 200 MW, over 6
and above those shown on line 6 of Schedule 21, Exhibit 7
No.
9.,
for 1991-92.
This additional capacity purchase is 8
required as a result of the additional off-system firm sale 9
by the merged system, which I will describe in more detail 10 below.
Il Two major savings from the merger are evident from 12 Schedule 2.
- First, new capacity purchases arc postponed 13 and
- reduced, due to the peak load diversity, reserve 14 sharing, and increases in available capacity described by 15 Mr. Boucher.
- Second, new energy resources are postponed 16 for several years beyond the 1993-94 time frame required by 17 Pacific Power in the absence of the merger.
In addition, 18 the construction of new generating resources required by 19 Utah Power in the absence of the merger is avoided by 20 increases in less-expensive firm purchases.
Subtracted 21 from these savings are the costs of advancing the construc-22 tion of transmission facilities already planned without the 23 merger plus additional transmission construction required to 24 realize additional merged system power supply benefits.
25 The net effect is an increased cost in 1988-90, due to 26 transmission advancements, with substantial savings
5 D. P. Stoinborg 1 1
1 thereafter.
2 The net present value of these savings is about I
i 3
$352 million over the 20-year horizon, as indicated in 4
Schedule 2.
The annual cost effects of the merger for 1988-5 92 are shown on line 1 of Schedule 1, after conversion to a 6
calendar-year basis.
The assumptions used to calculate contained in the workpapers accompanying 7
these savings are 8
my testimony.
9 QUESTION 10 Do these savings fully reflect the opportunity to 11 substitute transmission facilities for new generation 12 resources that the merger provides?
13 ANSWER 14 Yes, the savings reflect our best thinking at this 15 time.
The substitution of new transmission and additional 16 purchase power for the construction of new generation occurs 17 in 1998 and beyond.
At that soint, Utah Power's need for 18 new sum.er capacity resources has grown to 413 MW (line 6, 19 Schedule 16 of Exhibit No. 9), or almost 350 MW if supplied
)
20 through firm purchases.
By the year 2006, Utah Power's need i
21 for new summer capacity resources has grown to 1031 MW, or 22 860 MW if supplied through firm purchases.
Because of the 23 many uncertainties inherent in the resource planning 24 process, we cannot be certain at precisely what point in 25 that extended time frame Utah Power would need to construct 26 new generation resources.
- However, the plan we have b
D. P. Stoinb3rg j 1
l 1
described is a reasonable scenario, and the $352 million not 2
present value savings is a reasonable estimate.
Even if 3
there is no long-term need to build new resources, the 4
capacity purchase savings will provide substantial. savings 5
to the merged system's customers.
Just considering the
[
6 savings over the next ten years, the not present value of t
l
)
7 these savings is about $67 million.
These savings are in l
l 8
addition to the Net Power Cost Savings shown on line 2 of
)
j 9
Schedule 1.
10 QUESTION l
I 11 What is the Net Power Cost Savings shown on line 2 l
12 of Schedule 1, and how was it estimated?
i 13 ANSWER i
t 14 Net Power Cost is fuel cost plus purchased power 1
15 cost plus wheeling cost minus sale for resale (firm and r
4 16 nonfirm) revenue.
The Net Power Cost benefits shown in i
17 Schedule 1 were estimated using Pacific Power's power cost i
l 18 model.
The model was adapted by-a team of Pacific Power i
1 i
19 analysts in consultation with Utah Power analysts to 20 simulate either of the power systems operating independent-21 ly, or the coordinated operation of the merged system.
l 22 Modifications made to the model included transfer con-23 straints between Utah Power's and Pacific Power's systems, i
24 and recognition of the diverse wholesale power marketing and l
25 purchase power capability of the merged system.
l 26
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J
5 D. P. Stoinborg '
1 Pacific Power's model simulates, on a monthly 2
- basis, the complex interactions of Pacific
- Power, the 3
Bonneville Powsr Administration (BP A) and other Pacific 4
Northwest utilities, and extra-regionel markets.
It gives 5
consideration to pooling and coordination agreements, j
f 6
intertie constraints (both electrical and institutior.al),
7 resource prices and operational limitations, and hydrologic
[
8 uncertainty.
These complexities have a substantial ef fect 9
on Pacific Power's power costs, and can be expected to have 10 a similar effect on the merged system.
Many of these 11 factors are not easiiy recognized in commercial power cost 12 simulation models.
It was therefore appropriate to adapt 13 Pacific Power's existing model to simulate the merged 14 system.
The same methods were also used to simulate each 15 individual system as well as the merged system.
In that way 16 a consistent comparison could be made, allowing a reasonable 17 estimate of the benefits of the merger.
18 OUESTION 19 Does the model provide reasonable estimates of 20 each individual system's power costs?
21 ANSWER t
22 Yes.
Based on our extensive experience with the 23 model for simulating Pacific Power's system, we believe that 24 the model provides reasonable estimates of that system's 25 power costs.
In the case of Utah Power's
- system, we l
26 verified the model by comparing results with power cost I
l
x D. P. Steinborg.
t l
1 simulations that Utah Power had performed using the models 2
and methods they normally employ for power cost estimating
}
e f
3 purposes.
For the 1988-92 period, the adapted model's i
4 results were within 2% of those estimated by Utah Power for 5
sales and purchases, within 0.2% of the Utah Power estimates l
6 for fuel burn expense, and within 0.5% of the Utah Power 7
estimates of the Net Power Cost.
[
t 8
QUESTION 9
Please describe the results of the power cost 10 simulations.
11 ANSPE_R 12 The results are summarized in Schedule 3 of f
13 Exhibit No. 11.
This schedule compares Net Power Cost and 14 its major components for the two individual systems, the sum
[
15 of the two individual systems, the merged system, and the I
16 difference between the merged system and the sum of the two l
17 individual systems.
Schedule 4 shows a
comparison of 18 energy requirements and sources of energy for the stand-19 alone and merged company.
Scheduiss 3 and 4 are derived 20 from the more detailed data itemi:ed in Schedule 5 of 21 Ey.hibit No. 11, 22 The total estimated savings in Net Power Cost 23 (line 24 of Schedule 3) amount to about $16.7 million in 24
- 1988, increasing to about $44.2 million in 1992.
These 25 savings reflect the major effects of the merger on power 26 system operation:
more efficient dispatch of generating
n y
D. P. Stoinborg,
g t
resources, displacement of higher-cost purchased power, and i
2 the ability to make additional wholesale sales at enhanced i.
3 sales margins.
I 4
Several results from the simulations stand out as 1
5 significant.
First, the energy sources and uses summarized 6
in Schedule 4 indicate that the merged system increases l
7 thermal generation about 1.5-2%
in each year.
These 8
inersases come about because the merged system is able to 9
decrease secondary purchases up to about 3% and increase 10 wholesale sales in the range of about 7-10%.
Second, with i
11 regard to the Net Power Cost components shown in 12 Schedule 3, purchased power expense is reduced, even in 13 those years when total purchased energy is about the same, i
14 because of the merged system's better ability to access I
15 diverse sources when they are cost-effective.
- Third, 16 wholesale power revenues are increased because of increased j.
l 17 efficiencies.
- Finally, the net effect of all of these 18 changes results in a reduction in Net Power Cost from about l
19 5% to 10%.
These benefits result from relatively modest 20 changes in total system operation, not radical departures j
21 from past practices.
The model input assumptions used to 22 calculate the Net Power Cost Savings, as well as detailed i
23 model output for the merged system and the two individual
]
24 systems, are contained in my workpapers.
1 25 9UESTION i
26 You mentioned that the merged system is expected I
I l
l 5
w-..-
D.P. StOinbcrg,
1 to increase thermal generation over the period simulated.
2 Where do the studies indicate increases in generation occur?
3 p'SWER 4
As indicated in Schedule 5, the increases are 5
spread reughly evenly betwet.n Utah Power's and Pacific I
6 Power's generating units.
As a result of this increase in 7
thermal generation requirements, the merged company's coal 8
consumption is expected to increase over the 1988-1992 9
period by about 1,000,000 tons, 325,000 tons and 290,000 4
10 tons from facilities located in Wyoming, Washington and i
11 Utah, respectively.
12 CUESTION 13 How much of the Net Power Cost savings result from, 14 system operating benefits, as compared to the addit ional 15 firm and nonfirm sales that the merger allows?
i 16 ANSWER j
17 As I previously described, Net Power Cost Savings 18 reflect the combination of many effects of the merger.
The 19 fuel and wheeling expense associated with the additional i
20 firm and nonfirm sales summarized in Schedule 5 are not 21 identified separately in the power cost simulations, so the l
22 wholesale power sales contributions cannot be isolated from l
23 those simulations alone.
We estimate from other analyses i
l 24 contained in my workpapers that Net Power Cost Savings of 25 the mercer due solely to operating efficiencies contribute 26 between about $5 million and about $9 million per year to i
D. P.
SteinbLrg T 1
total New Power Cost savings.
2 QUESTION 3
How were these additional wholesale sales revenues 4
estimated?
5 ANSWER 6
- ?:th regard to nonfirm sales, the ability of the 7
merged system to make additional sales was simulated by the 8
power cost model.
The assumptions we used about the size of 9
wholesale markets were consistent between the simulations of 10 the individual systems and the combined system.
In the case 11 of the unmerged system simulations, the individual systems 12 did not have co.c-effective generating capability to fill 13 those wholesale demands during some time periods.
With the 14 same market size for the merged system, however, additional 15 sales were feasible, due to the load and resource diver-16 sities of the two systems.
17 QUESTION 18 Why have you included an additional off-system 19 firm sale in your benefits analysis?
20 ANSWER 21 As Mr. Boucher discussed in his testimony, the 22 merged system will have mere flexibility to offer marketable 23 energy services with attractive pricing and packaging.
We 24 assumed an additional firm sale of 50 average Kd beginning 25 in June 1988, increasing to 100 average KA in January of 26 1990 can be achieved by the merged system, with prices r
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D. P.
Steinbarg 0 1
similar to those of recent contracts.
Because this f i r.'.
2 sale was not included in the merged system's loads and 3
resources study, as summarized in Mr. Boucher's Testimony, 4
Schedule 23 of Exhibit No.
9, the additional capacity 5
required to complete this transaction through 1992 necessi-6 tates the additional firm capacity purchase in 1991-92 I 7
previously described.
8 QUESTION 9
How would your estimates of Net Power Cost savings 10 be different if the additional firm wholesale sale were not 11 assumed?
12 ANSWER 13 Without the assumed firm sale, Net Power Cost 14 savings would be lower by about $4 million in 1988, and 15 lower by about S22 million in
- 1992, compared with the 16 savings shown on line 2 of Schedule 1.
This estimate is 17 based on simulations without the additional firm sale, as 18 shown in my workpapers.
It reflects both the lower 19 wholesale sales revenue in the absence of the additional i
20 firm sale, as well as the reduction in fuel expense and 21 purchase power expense and increases in nonfirm sales that 22 wou3d~ occur without the firm sale.
Without the firm sale, i
l 23 the savings shown on line 1 of Schedule 1 would also be l
24 higher by about $4 million in 1991 and 1992, reflecting the i
25 lower capacity purchase requirement without the firm sale.
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D. P.
Steinbarg :
1 QUESTION 2
Do you anticipate other savings in Net Power Cost 3
that have not been included in your studies to date?
4 ANSWER 5
Yes.
In addition to the savings that I have 6
already discussed, there is also the potential for addition-7 al system benefits through additional off-system sales and 8
displacement of higher-cost system resources.
Achieving 9
these benefits would involve thermal generating performance 10 higher than we have required on a sustained basis at some 1
11
- units, the implications of which require more stuoy than 12 time has yet allowed.
Further, we have not yet attempted to 13 optimize thermal maintenance schedules to improve wholesale 14 sales or reduce fuel and purchased power expense for the 15 merged system.
Any of these factors could add substantially 16 to the Net Power Cost savings I have already described.
17 QUESTION 18 Do you expect changes in the wheeling expense 19 component of Net Power Cost as a result of the merger?
20 ANSWER 21 Yes.
Schedule 5 indicates changes in two areas.
22 The first is an increase in wheeling expense associated with l
23 an increase in nonfirm wholesale power sales over the l
24 Pacific Intertie.
The second is a reduction in other t
25 wheeling expense associated with expected exchange arrange-26 ments with BPA that the merger allows.
The net savings in 1
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5 D. P.
Stoinbarg
- I wheeling expense increases to about 1.3 million in 1992.
2 QUESTION 3
Please discuss Pacific Power's current coal supply 4
arrangements for its generating plants.
5 ANSWER 6
Pacific Power has an interest in five coal-fired 7
generation projects located in Washington, Montana and 8
Wyoming.
9 In Washington, Pacific Power owns a 47.5 percent 10 interest in the Centralia Generating Plant.
Coal for this 11 facility is supplied through long-term contractual agree-12 ments with the Centralia mine which is jointly owned by 13 Pacific Power and the Washington Irrigation and Development, 14 Company, a wholly-owned subsidiary of The Washington Water 15 Power Company, which also operates the mine.
The Washington 16 Water Power Company, which has a 15 percent interest in the 17 Centralia generation
- facility, is a
wholesale power 18 competitor of the merged company.
19 In
- Montana, Pacific Power owns a
10 percent 20 interest in Colstrip units 3 and 4.
The coal for these 21 generating units is supplied through long-term contractual i
l 22 agreements with the Western Energy Company, a wholly-owned 23 subsidiary of the Montana Power Company.
The Montana Power 24 Company, which has a 30 percent interest in these units, is 25 a wholesale power competitor of the merged company.
26
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D. P. Stoinberg '
1 1
In Wyoming, Pacific Power has an 80 percent 2
interest in the Wyodak Plant, a 100 percent interest in the 3
Dave Johnston Plant, and a 66.7 percent interest in the Jim 4
Bridger Generating Plant.
Coal for the Wyodak facility is 5
supplied through long-term contractual agreements with 6
Wyodak Fesources Development
- Company, a
wholly-owned 7
subsidiary of Black Hills Power and Light Company.
Black 8
- Hills, which has a
20 percent interest in the Wyodak 9
generation facility, is a wholesale power competitor of the 10 merged company.
The coal supply for the Dave Johnston 11 Plant, the Dave Johnston mine, is owned by Pacific Power.
12 In an effort to further stabilize its power supply costs and 13 power prices, Pacific Power is also purchasing coal from 14 unaffiliated outside suppliers to satisfy a portion of its 15 Dave Johnston coal supply needs.
Coal for the Jim Bridger 16 generating facility is primarily supplied through long-term 17 contractual agreements with Bridger Coal Company, which is 18 one-third owned by Idaho Energy Resources Company, a wholly-19 owned subsidiary of Idaho Power Company, and two-thirds 20 owned by Pacific Minerals, Inc., a wholly-owned subsidiary 21 of NERCO.
- NERCO, the majority of which is owned by 22 PacifiCorp, also sells coal to other electric utilities, 23 which I will discuss later in my testimony.
Idaho Power 24 Company, which owns one-third interest in the Jim Bridger 25 generaticn facility, is a wholesale power competitor of the 26 merged company.
Thri Jim Bridger plant owners also purchase
D.P.
Steinbarg !
I some of their coal supply needs from outside unaffiliated 2
suppliers to help stabilize their power prices.
3 QUESTION 4
Please discuss Utah Power's current ccal supply 5
arrangements.
6 ANSWER 7
As Mr. Topham has previously testified, Utah 8
Power has an interest in four coal-fired generation projects 9
currently available for service located in Wyoming and Utah.
10 In Wyoming, Utah Power owns 100 percent of the 11 Naughton Plant which coal is supplied through exclusive 12 long-term agreement with an unaffiliated supplier, Pittsburg 13 and Midway Coal Company.
14 In Utah, Utah Power owns 100 percent of the Carbon 15 and Huntington generation facilities and about 85 percent of 16 the Hunter plant.
Carbon's fuel requirements are supplied 17 by an unaffiliated supplier, the Valley Camp Coal Company, 18 pursuant to an agreement which expires in 1995.
The coal l
l 19 supply for the Huntington and Hunter plants, the Cottonwood 20 and Deer Creek mines, is owned by Utah Power.
21 QUESTION l
l 22 Will the coal procurement activities of the merged l
l 23 company be different from the current activities of the 24 individual companies?
I 25 ANSWER 26 No.
The overall objective of the merged company
D.
P.
Steinberg,
I will be the same as currently exists for the individual 2
companies.
As such, the objective of the merged company 3
will be to provide safe and reliable electric service at 4
the lowest reasonable cost to customers, both retail and 5
wholesale.
Because fuel costs are the largest operating 6
cost incurred by Pacific Power and Utah
- Power, both 7
companies have pursued fuel procurement strategies that 8
lower or stabilize power prices.
Many of the actions taken 9
by Pacific Power and Utah Power in this regard have already 10 resulted in substantial benefits to their respective 11 customers.
The companies will continue to pursue fuel cost 12 reduction and stabilization strategies subsequent to the 13 merger within the framework of existing contractual 14 arrangements.
15 QUESTION 16 Will preference be given to affiliated coal 17 suppliers for future coal supplies subsequent to the j
18 merger?
19 ANSWER 20 No.
Such is not the case now, nor will it be the i
j 21 case in the future.
As I have already testified, Pacific 22 Power currently purchases coal from unaffiliated suppliers 23 to help meet its fuel needs at the Dave Johnston and Jim 24 Bridger generation facilities, even though Company-owned or 25 affiliated coal supplies are available.
It is likely that 26 Pacific Power will further increase its use of outside coal l
l i
D. P.
Steinborg
- 1 supplies at those plants in the future.
Pacific Power is 2
also in the process of test burning outside coal at its 3
Centralia generation facility in an effort to reduce or 4
stabilize power production costs at that plant.
5 QUESTION 6
What effect will the merged company's various coal 7
supply arrangements and ownership interests have on the 8
availability of coal to wholesale power competitors?
9 ANSWER 10 The merged company's coal arrangements and 11 ownership interests will not have any measurable effect on 12 either the availability of coal to other utilities or on 13 wholesale power competition.
As I have previously te'sti-14
- fied, four of the five coal-fired power plants in which 15 Pacific Power has an interest are jointly-owned with 16 wholesale power competitors and those competitors also 17 wholly-own or partially-own and control the attendant coal 18 supply.
As a result, all of the plant and mine owners have 19 the common interest of low-cost plant and mine operation.
20 This situation will be unaffected by the merger.
The coal 21 for Pacific Power's wholly-owned coal-fired generating 22
- plant, Dave Johnston, is supplied by the Company's Dave 23 Johnston mine and through outside unaffiliated purchases.
24 None of the merged company's wholesale power competitors 25 purchase coal from the Dave Johnston mine.
- Also, no 26 wholesale power competitor of the merged company purchases
D. P.
Steinberg
- 1 1
coal from interests owned by Utah Power.
This situation is 2
indicative of the existing and expected future highly 3
competitive coal supply market in which electric utilities 4
.have many viable coal supply options.
Further, the merged 5
company, including affiliated coal interests, would control 6
less than 6 percent of the controlled, uncommitted coal 7
reserves in the western coal market.
Consequently there is 8
no reason to suspect that the merger would lessen competi-9 tion or restrict access to coal by competitors.
10 QUESTION 11 What do you mean by the terms "controlled, 12 uncommitted" coal reserves?
13 ANSWER 14 The term "controlled" refers to coal reserves that 15 are held by a coal-marketing company through ownership and 16 lease arrangements.
The term "uncommitted" refers to that 17 portion of the controlled reserves that are not currently 18 assigned or dedicated to satisfying existing coal supply 19 arrangements.
20 QUESTION 21 You testified that PacifiCorp's NERCO subsidiary 22 sells coal to other electric utilities.
Are any of these 23 utilities wholesale power competitors of the merged company?
24 ANSWER 25 The only electric utility currently served by 26 NERCO that could be reasonably considered as a wholesale l _.
D. P.
Steinborg,
1 power competitor of the merged company is Platte River Power 2
Authority (PRPA).
It is my understanding that NERCO 3
supplies coal for only PRPA's 250 MW Rawhide 1 unit located 4
in North Central Colorado and that the contract provides 5
PRPA with substantial flexibility.
This situation will not 6
alter any current competitive relationships subsequent to 7
the merger.
8 QUESTION 9
Does this conclude your direct testimony?
10 ANSWER 11 Yes.
12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 GMG#2\\Steinber.900
~.
UNITED STAT 18 OT AMEMCA SEFOM THE FEDERAL INERCY MCULATORY COMMISSION STATE OF ORICON
)
Docket No. EC88-2-00 C0l'NTY OF HULTNOMAH)
)
Af fidavit of Dennis P. Steinberg Dennis P. Steinberg, being first duly sworn, on oath states that he is Director, Power Planning of Pacific Power & lie t Company, whose Profiled h
Testimony was 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 that he would give the answers that are herein set forth and that he adopts the aforesaid answers as his direct testimony in this proceeding.
lN]
V
' 'Dendis f. Stein l
Subscribed and sworn to before me this 6th. Day of January, 1988.
j l
g A
i Notary Public My commission expires May 18, 1989.
+
4 Exhibit No. 11 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.
)
EXHIBITS ACCOMPANYING PREFILED TESTIMONY OF DENNIS P. STEINBERG ON BEHALF OF PACIFICORP, UTAH POWER & LIGHT COMPANY PC/UP&L MERGING CORP.
6 January 8, 1988 i
i l
s Exhibit No.
- ~ [ -
Schtdule l' 4.
i r
Estimated Power Suppy Savings from Merger (Milions of Douars) 1988 1989 1990 1991 1992 (1) Net Savings in New Generation 1.8 2.2 0.2 2.2 8.6 and Transmission Capacity (2) Net Power Cost Savings 16.7 22.4 35.5 40.2 44.2 (3) Total 14.9 20.2 35.3 42.4 52.8 4
Power Planning January 1988
.x Exhibit No. 11 Schedule 2 Total Cost Assedeted with Cepedty. Faergy, and Transenission A44itless (1888)
Fed & Fewer & IJght Cesapeny Hlaheet Merger 19:2 89 1989 90 1990 91 1991 92 1992 95 1993 94 1994 95 1995 96 19%97 1997 98 1998 99 1999 00 200B01 2001-02 2002 03 2003-04 200445 200546 2006 47 (Il Capaasy 0
3.865 4.553 35J10 73.187 77.243 80.789 80.817 95.614 98.605 107.385 517.802 131.829 147.312 168.021 173.549 191.026 219.690 232.436
[2]
Fmr gy 0
0 0
0 0 10355 28.790 40.St4 52.495 94.660 18 3.777 125.515 138.445 195.996 208.407 225.982 275.697 341.9e6 331.802 13)
Tsanwnessum 888 I.485 1.447 I.407 1,369 8.332 2.421 1.142 3,061 2.978 2.898 2.819 2.743 2.fe8 2.594 2.521 2.447 2.374 2.301
[4]
Revernac Roperancma EM 1.352 6500 %.737 74.4 M E8.899 Il2h'4 124.519 151.171 196.244 224.0t4 246.1% 273,0l7 341.975 372.021 403.252 469.170 %4.030 566.539 Utah Fewer & IJght Ceepeny Washeet Merger
[5]
Capeory 0
304 578 1.295 2.I53 3.064 3.190 3.559 4.138 7.766 41.487 71.454 103.454 168.608 198.847 230.572 300.052 330.362 362.344
[61 l'arrgy 0
0 0
0 2.273 4.6 57 7.050 9.559 11,496 14.301 20.976 27.128 33.959 47,040 54.898 63.557 79.285 89.179 100.087 17)
Transassues 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
18; Revesusc Raparrsncms 0
104 575 1.291 4.4%
7 lo t 10.240 13.135 55.634 22.067 62.463 95.552 137.413 215.641 253.744 294.129 379.337 419.341 462.361 Fede'.c Fewer plus Utah Fewer Witheet Merger
[9]
Capeory 0
4.171 5.432 56.621 75J00 80.277 53.979 84.376 99.752 106.371 148.872 189.236 235.293 315.983 359.867 404.428 491p78 550.052 594.781
[10]
Imgy 0
0 0
0 2.273 14.991 35.540 30.819 63.998 10s.962 334.754 152.643 172.404 239.036 263304 290.469 354.982 431.145 431.819 lIll Transenessium 888 I.485 I,447 3,407 3 369 I,332 2.42l 3.142 3.061 2.978 2.898 2,819 2,743 2,668 2,594 2,521 2,447 2,374 2.301
[l2l Reveme Raparuncus 885 5.6%
6.575 55.02
. 31 96.tOO 122.239 137.637 166,905 215.311 256.523 344.715 410.430 557.616 625.765 697.411 545.505 953.571 1.025.900 FacInCery After Merger gl33 C,.ary 0
0 0 47.940 57.243 60.191 68.471 66.779 79.966 87.146 100.438 Ill.2M 133J97 154.6s5 178.55I 202.549 230.113 272306 288.533
{14)
I'nrrgy 0
0 0
0 2.273 11.456 22.372 31.994 41.610 95.013 102.838 119.596 164.619 213.733 257.966 325.125 370.460 455.697 502.704
[ISI T
4,453 6.569 6.398 6.222 6.054 5.893 5,738 5.589 5,444 10,384 13,539 13,180 12.818 12,453 82,103 II.Mt II.427 11,098 10.772 ll6) Revouse Rapanesness 4,453 6.569 6.395 54.162 6TD.D9 96.551 104.361 127.020 192.473 216.105 244.012 330.527 350.571 445.619 539.435 612.000 739.101 795.007 198E 39 1989 90 1990 98 1991-92 1992 93 8993 94 1994 95 1995 96 199497 1997 98 1998-99 1999 00 200E01 2003-02 2002-03 200104 200445 200546 200647 l17] Tesel Net Benente (3.565)
(913) 4H0 3.R66 13.371 19.061 25.657 33.275 39.755 23.535 70.415 100.707 99.603 176.744 177.146 157 V76 236.505 244.469 233.594
[18] Net Present Valene l352,547 ]
ler Il 24%l 1983 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 l19) Tesel Net huelles (1.7R2) (2.239)
(2?6) 2.173 8.685 16.256 22359 29.4t4 36.530 32.851 45.127 55.% I 100.155 135.174 176.945 167.561 197.242 240.459 239.152 I*.
c, l'tmwang Im=ury IVNM
s
[
Exhibit No. 11 Scladule 3 Estanated Net Power Cost Savings from Merger (Thousands of Donars) line 1988 1989 1990 1991 1992 UTAH POWER (1)
Sale for Resale Revenue 56,198 56,882 70,754 79,065 78,121 (2)
Purchased Power Expense 34,951 38,643 45,738 51,622 53,895 (3)
Thermal Fuel Expense 202,568 206,659 212,918 220,172 231,489 (4)
Net Power Cost 181,321 188,420 187,902 192,729 207,263 (line 2 + line 3 -line 1)
PAClFIC POWER (5)
Sale for Resale Revenue 114,224 146,916 145,977 148,825 151,328 (6)
Purchased Power Expense 124,320 142,297 164,183 180,470 190,077 (7)
Thermal Fuel Expense 185,895 204,662 209,409 222,947 233,124 (8)
Wheeling Expense 29,134 32,593 32,275 32,211 33,275 (9)
Net Power Cost 225,125 232,636 259,890 286,803 305,148 (Ene 6 + line 7 + line 8 line 5)
UTAH POWER + PACIFIC POWER (10) Safe for Resale Revenue 170,422 203,798 216,731 227,890 229,449 (11) Purchased Power Expense 159,271 180,940 209,921 232,092 243,972 (12) Thermal Fuel Expense 388,463 411,321 422,327 443,119 464.613 (13) Wheeling Expense.
29,134 32,693 32,275 32,211 33,275 (14) Net Power Cost 406,446 421,056 447,792 479,533 512,411 (line 11 + line 12 + line 13 line 10)
MERGED SYSTEM (15) Sale for Resale Revenue 187,313 224,512 250,208 265,717 266,772 (16) Purchased Power Expense 154,029 177,033 202,658 224,278 232,092 (17) Thermal Fuel Expense 394,014 414,213 428,346 449,531 470,918 (18) Wheeling Expense 29,009 31,951 31,499 31,199 31,970 (19) Net Power Cost 389,739 398,685 412,295 439,291 468.208 (line 16 + line 17 + line 18 line 15)
MERGED SYSTEM UTAH POWER PACIFIC POWER (20) Sale for Resale Revenue 16,891 20,714 33,477 37,827 37,323 (21) Purchased Power Expense 5,242 3,907 7,263 7,814 11,880 (22) Thermal Fuel E rpense 5,551 2,892 6,019 6,412 6,305 (23) Wheeling Expense 125 642 776 1,012 1,305 (24) Net PowerCost 16,707 22,371 35,497 40,241 44,203 (line 21 + line 22 + line 23 line 20)
POWER PLANNING January 1988
Exhibit No. 11 4,
Schedulo 4 Estimated Not Power Cost Savings from Merger (Thousands of MWH) line 1988 1989 1990 1991 1992 UTAH POWER (1) Not System Load 16,768 16,768 17.096 17,369 17,560 (2) Sale for Rosale 2,597 2,553 2,739 2,832 2,716 (3) Total Requirements 19,365 19,321 19,835 20,201 20,276 (4) Purchased Power 2,239 2,222 2,421 2,670 2,731 (5) Thermal Generston 16,732 16,706 17,020 17,137 17,152 (6) Other Resources 394 393 394 394 394 (7) Total Resources 19,365 19,321 19,835 20,201 20,277 PACIFIC POWER (8) Not System Load 24,519 25.119 25,654 26,785 27,280 (9) Sale for Resale 4,290 5,160 4,761 4,336 4,081 (10) Total Requirements 28,809 30,279 30,415 31,121 31,361 (11) Purchased Power 5,294 5,414 5,794 6.189 6,437 (12) ThermalGeneration 19.014 20,373 20,131 20,440 20,420 (13) Other Resources 4,501 4,492 4,490 4,492 4,503 (14) Total Resources 28,809 30,279 30,415 31.121 31,360 UTAH POWER + PACIFIC POWER (15) Not System Lead 41,287 41,887 42,750 44,154 44,840 (16) Sa's for Resale 6,887 7.713 7,500 7,168 6,797 (17) Total Requirements 48,174 49,600 50,250 51,322 51,637 (18) Purchased Power 7,533 7,636 8.215 8,859 9,168 (19) Thermal Generation 35,746 37,079 37,151 37,577 37,572 (20) Other Resources 4,895 4,885 4,884 4,886 4,897 (21) Total Resources 48,174 49,600 50,250 51,322 51,637 MERGED SYSTEM (22) Not System Load 41,286 41,887 42,750 44,154 44,840 l
(23) Sa's for Rosa's 7,493 8,260 8,177 7,942 7,488 l
(24) Total Requirements 48,779 50,147 50,927 52,096 52,328 (25) Purchased Power 7,301 7,637 8,132 8,886 9,168 (26) Thermal Generaton 36,584 37,624 37,911 38,325 38,263 (27) Other Resources 4,894 4.886 4,884 4,886 4,895 (28) Total Resources 48,779 50,147 50,927 52,097 52,328 j
I l
MERGED SYSTEM UTAH POWER PACIFIC POWER l
(29) Net Systemload 0
0 0
0 0
(30) Sa's for Rosa's 606 547 677 774 691 (31) Total Requirements 605 547 677 774 691 l
(32) Purchased Power 232 1
-83 27 0
l (33) Thermal Generaton 838 545 760 748 693 (34) Other Resources 0
0 0
0 2
(35) Total Resources 605 547 677 775 691 Note. numbers may not add or subtraci proosey, due to rounding l
l DOWER PLANN1NG January 1988 I
i L
Exhibit No. 11 6,
Schedule S Pccp 1 of 6 Merged Model Aterped Utah and Pacific Pacific Power and Utah Power Sese Cese Not Power Cost Anaysis wrm 50 years of hyeo
($)
1988 1989 1990 1991 1992 SPEctAL SALES FOR RESALE mock His 21,739,348 25,948,092 26,224,031 26,513,763 26,817,301 PG&E 6,792,178 6,560,824 6.451,336 6,695,040 7,030,720 Puget Poner 4,727,399 5,163,602 5,730,725 3,568,449 0
SoCafEdson 49,031,020 52,339,833 41,097,714 45,005.027 48,704,821 SAUD 0
0 8,296,594 4,712,347 9.171,547 PP&LeUP&L 0
0 2,830,000 3,235,000 3,608.000 Otur Fem 8,476,050 15.330,000 34,164,000 36,792,000 38,649,600 Nusasm 0
0 17,359,833 26,309,097 26,328,452 Serra Pad:
21,613.026 21,415,106 21,500,354 21,793.122 22,253,496 Secondary Sales 74,934,082 97,754,157 86,553,458 87,093.006 84,207,652 TOTAL SPECIAL SALES 187,313,103 224,511,614 250,200,045 265,718,851 266,771,589 PURCHASED POWER & NET INTERCHANGE Paane Frm 35,427,627 38,103.023 52,282,814 66,650,369 66,580.268 BPA Peak Pwthese 45,763,704 48,486,300 50,282,088 50,910,615 52.796,196 Q F. Contaas. PP&L 34,423,608 45,626,412 47,784,444 48,404,580 49,256,700 UP&L 9am PP&L 0
0 2,830,000 3.235,000 3,608,000 Gan 9mm 0
1,261,000 1,261,000 1,261,000 1,261,000 GSLM 0
308,000 308,000 308,000 308,000 OF Contacas UP&L 7,113,000 12,770,000 14,626,000 14,626,000 14,668,000 Secondary Purctsases 31,289,037 30,478,225 33,283,377 38,882,848 43,614,011 TOTAL PURCH PW & NET INT.
154,028,976 177,032,960 202,657,723 224,278,412 232,092,175 WHEEUNG & U.OF F. EXPENSE BPA lnierte 5,560,604 7,909,925 6,895,749 6,292,218 6,142.656 Oter 23,448,321 24,041,404 24,603,154 24,906.310 25.827,628 TOTAL WHEEUNG & U. OF F. EXPENSE 29.008,925 31,951,329 31,498,903 31,198.528 31,970.284 THT.AMAL FUEL BURN EXPENSE Jrn Brusgar 83,850,307 90,551,520 92,274.171 96,834.105 102.830.223 Or,e Jctosum 43,395,882 44,913,937 46,828,216 48,518.357 51,741,457 Cereuha 41,517,992 51,281,075 53,150,961 57,449,375 57,852.544 Wpduk 13,917,087 14,356,193 15,152,305 16.041,500 16,531,593 Cdsro 6.459,431 6,692.219 6,966.633 7,302,889 7,723.269 Caton 20,853,379 21.477,682 22,015,745 22,688,337 23,361,852 NaugPtn 51,598.459 50,296.833 58,971,640 61,735,913 62.325.722 hrongen 58,919,393 59,066,537 57,761,367 64.083,850 64,470,361 Hunter 69.328,507 71,353,278 70,928,760 70,504,708 77.609.508 kruset 4,173,120 4.223,415 4,296,350 4 372,195 4.471.200 TOTAL FUEL BURN EXPENSE 394,013,556 414.212,689 428,346,153 449,531,230 470,917,7?O NET' POWER COST 389.738,354 398.685,364 412.294,734 439,291,319 468,208,600 l
l t
i Power Planning 1/2,88 16 28 Page 1 ms PD Mer'2ed(a$d l
2 Exhibit No, 11 4
Schedule 5 2 of 6 Merged Model Aferged Utah sad Pect//c Pacific Power and Utah Power Base Case Net Power Cost Energy Anaysis eth 50 years o/ hyde (MW) 1988 1989 1990 1991 1992 NET SYSTEM LOAD 41,286,402 41,886,927 42,749,764 44,154,277 44,839,795 SPECIAL SALES FOR RESALE Sm* H8s 459,901 459,901 (59,901 459,901 459.901 PG&E 250,000 250,000 250,000 250,000 250,000 Pigst Poner 240,901 240,901 240,901 139,893 0
So CalEdson 1,485,373 1,481,314 993.387 993,387 996,108 SMUD 0
0 367,920 367,920 368,928 PP&Le UPAL 0
0 86,300 94,700 104.100 Oter Fem 256,850 434,000 876,000 876,000 878,400 Needa 0
0 432.100 620,700 621,900 Serra Psote 628,800 827,100 827.100 627,100 628,800 Se.ordary Sales 4,170,777 4,762.442 3,844,711 3,512,732 3,179,869 TOTAL SPECIAL SALES 7,492.602 8.259,658 8,177,320 7,942,333 7,488,006 TOTAL REQUIREMENTS 48,779,004 50,146,585 50,927,084 52,096,610 52,327,801 PURCHASED POWER & NET INTERCHANGE PacAc Fem 3,570,755 3.590,419 3,778,825 4,158,944 4,196,278 QF. Cores:ss PP&L 614,880 683,280 700,800 700,800 702.720 UP&L hm PP&L 0
0 85,300 94.700 104.100 Gem Same 0
37,100 37.100 37.100 37,100 GSLM 0
25,900 25,900 25.900 25.900 QF Certacts-UP&L 162,700 274,600 314,500 314,500 315,400 Secondary Purtnases 2.952,409 3,026,005 3,189,734 3,554.215 3,786,072,
TOTAL PURCH PW & NET INT 7,300,744 7,637,304 8.132,159 8,886,159 9,167,570 THERMAL COAL FIRED GENERATCN Jrn Ehsper 8,566.999 8,871,775 8.706,399 8.740,905 8,861,430 Dew Jchnsen 5.371,469 5.217,840 5.226,188 5.169,071 5,241,755 Cenne 2,788.059 3,954,548 4,014,833 4,095,815 3 936,936 Wpdm 1,860,950 1,855,328 1,894,863 1,934,448 1,900,523 Cosrp 864,138 861,567 861.567 861,596 864.142 Caton 952,320 949,241 949,301 949,304 952,311 Neugran 4,116,501 3,803.021 4,326,174 4,466,699 4.359,422 Kntrgon 5,459,822 5.421,766 5.188,261 5.576,546 5.437.667 Hunter 6,454,349 6.540,376 6,595,381 6.382,187 6,561,621 EkndE4 149,040 148,190 148,150 148,210 149.040 TOTAL THERMAL 36,583,647 37,623,652 37,911,117 38,324,781 38.264.846 SYSTEM HYDRO 4,730.365 4,712.877 4.712,710 4,712,641 4,729.400 Draft From Serage (1,861) 7,188 5,534 7,465 (124)
TRCUAN GENERAT)ON 166.109 165,564 165,564 165,564 166.109
.....u...
TOTAL RESOURCES 48,779,004 50,146,585 50,927,084 52,096,610
$2.327.801 I
I I
I l
l Po*er P+anrang 1/2'88 16 29 Page 2 ms PD Me*9ed(at) l
Exhibit No. 11 I
i Schedulo 5 4
Na$P$we95 0 l
P:cific 9:wer Sese Case Combined Base Case 8ese Case
- wrth Sopas othyto Sum of Stand Alone we 50)es o/hycro Not Power Cost Analysis
($)
1988 1989 1990 1991 1992 SPECLAL SALES FOR RESALE Mms 21,739,348 25,948,092 26,224,031 26,513,763 26,817.301 PG&E 6,792,178 6,560,824 6,451,336 6,695,040 7,030,720 Puget Power 4,727,399 5,163,602 5,730,725 3,568,449 0
SoCelEdson 49,031,020 52,339,833 41,097,714 45,005,027 48,704,821 SAJO O
O 8,292,594 8,712,347 9,171,547 UmhSees 0
0 2,830,000 3,235,000 3,608,000 Orier Fem 0
0 0
0 0
Nyass 0
0 17,359.833 26,309.097 26,328,452 Surra Paaec 21,613.026 21,415,106 21,500,354 21,793,122 22,253,496 Se<cndary Sales 66,519,007 92,370,189 87,240,054 86,054,938 85,534,631 TOTAL SPECLAL SALES 170,421,978 203,797,646 216,730,641 227.890,783 229,448,968 PURCHASED POWER & NETINTERCHANGE PaolcFrm 35,427,827 38,103.023 52,282,814 66,650,369 66,580.268 BPA Peak Pmhase 45,763,704 48,486,300 50,282,088 50,910,615 52,796,196 QF.Conrads PP&L 34,423,608 45,626,412 47,784,444 48,404,580 49,256,700 PP&L 0
0 2,830,000 3,235,000 3,608.000 Gem Same 0
1,261,000 1,261,000 1,261,000 1,261,000 GSLM 0
308,000 308,000 308,000 308.000 OF Contacts (commrned) 7,125,000 12,770,000 14,626,000 14,626,000 14,668,000 Secxrdary Purchases 36,530,430 34,344,933 40,546,659 46,695,845 55,494,232 TOTAL PURCH PW & NET INT, 159,270,369 180,939,648 209,921,005 232,091,409 243,972,396 WHEEUNG & U. OF F. EXPENSE BPA horse 4,261,935 6,799,391 5,790,732 5,375,421 5,375.915 Criar 24.872,321 25,793,404 26,484,754 26,835,310 27,898.828 TOTAL WHEEUNG & U. Os F. EXPENSS 29,134,256 32,592,795 32,275,486 32,210,731 33,274,743 THERWL FUEL BURN EXPENSE Jm Broper 80,294,665 88,155,503 89,940,936 94.665,711 100.391.429 Dre Joteston 43,395,882 44,913,937 46,828,216 48,518.357 51,741,457 Cerufe 41,827,943 50,544,515 50,521,021 56,418,405 56,735,795 Wpcam 13,917,087 14,356,193 15,152,305 16.041,500 16,531,593 Cosep 6,459,431 6,692,219 6,966,633 7,302.889 7,723.269 Catcn 20,956,394 21,583,541 22.122,721 22,797,104 23,478.812 Na;ghen 50,471.500 51,502.060 58,419,979 59,006,958 59,625.926 Hmangen 58,273,122 58,635,883 58,813,209 65,259,620 67.855.990 Htrer 68,694,121 70,714,356 69,265.688 68,736,500 76.057,181 Ekrdet 4,173.120 4.223,415 4,296,350 4,372,195 4.471,200 TOTAL FUEL BURN EXPENSE 388,463,265 411.321,622 422.327,058 443,119,239 464,612.652 NET POWER COST 406.445.912 421.056.439 447,792,908 479,530,596 512,410.823 l
l l
l Poaer Ptanneg 1/2,38 16 34 Page1 ms PD SA Sum
Exhibit No. 11 4
Schedulo 5 Page 4 of 6 Peelfle Power Utah Power o
Sase Case Combined Base Case Base Case mW 50 pears o(tydro Sum of Stand Alone asW Soyoarothyde Not Power Cost Erergy Analyse (MWH) 1968 1989 1900 1991 1992 41,286h 41,886.927 42,749,784 44,154,277 44,839,795 NET SYSTEM LOAD SPECIAL SALES FOR RESALE assues 459,901 459.901 458,901 480,901 459,901 PG&E 250,000 250,000 250,000 200,000 250,000 PugetPaner 240,901 240,901 240,901 138,893 0
SoCalEdson 1.485,373 1.481,314 903,387 003,387 936,108 54JO O
0 367,920 367,920 368,928 Unh Sales 0
0 86,300 64,?00 104,100 Ohar 8'em 0
0 0
0 0
Neweds 0
0 432,100 420,700 421,900 Serra Panac 428,800 627,100 827,100 627,100 420,000 Secondary Sales 3,822,264 4,654,075 4,043,429 3,813,820 3,367,403 TOTAL SPECIAL SALES 4,887,259 7,713.291 7,500,038 7,147.421 8,797,140 TOTAL REQUIREMENTS 48,173,661 49,600,218 50,249,002 51,321,698 51,636,935 PURCHASED POWER & NET INTERCHANGE Pacdc Firm 3,570,054 3,549,641 3,778,320 4.158,312 4,195.672 Q F. Cortness. PP&L 614,880 683,280 700,000 700,000 702,720 PP&L 0
0 85.300 94.700 104,100 Gem Stan 0
37,100 37,100 37,100 37.100 OSLM 0
25.900 25.900 25.900 25,900 OF Contsen (-,.,.; 4) 162,700 274,600 314,500 314,500 315,400 Secondary Purmeses 3,185,315 3,025,219 3,273,196 3,528,131 3,787,101 TOTAL PURCH PW & NET INT.
7,532,949 7,635,740 8.215.116 8,859.443 9,167.993 THERMAL COAL-FIRED GENERATON Jm anager 8,098,228 8,567,387 8,420,840 8,486,790 8,588.693 Osw Johnsen 5.371,469 5,217,840 5.226,188 5,169,071 5,241,754 I
Comma 2.819,004 3,870,979 3,727,377 3,987,855 3.825.385 W,cdsk 1,860,950 1,855,328 1,494,863 1,934,448 1,900,523 Cdsep 844,138 861,567 861.547 841,596 864.142 l
Cetzn 957,025 953,920 953,913 953.855 957,078 NaugNen 3,978,430 3,874,244 4,271,419 4,198,071 4,101,330 l
Huntrgen 5,316,998 5,319,374 5,386.639 5,804,026 5.677,407 Hrer 6.330,324 6,410,118 6,260,089 6.032,817 6,267,060 Smds4 149,040 148,190 148,150 148,210 149,040 TOTAL THERMAL 35,745,606 37,078,949 37,151,045 37,576,739 37,572.412 SYSTEM HYDRO 4.731,055 4,712,956 4,712,654 4,712,612 4.730.226 Draft Fru ScreGe (2,058) 7,009 5,423 7,340 195 TROJAN GENERATCN 166.109 165,564 165,564 165,544 166.109 TOTAL RESOURCES 48,173.661 49,600,218 50,249.802 51,321,698 51,636,935 l
Power Planrung V2,18 16 34 Page 2 ms PD SA Sum 1
s Exhibit No. 11 Schedulo 5 PEcp 5 of 6 Pacifle Utah Merged Model Merged Utah sad Pacific Difference With Sum of Stand Atene 84srped &dods/ meus Com6ced i
Sese Case Not Power Cost Anahsis wWs 50yous of hytto
($)
1988 1989 1990 1991 1992 SPECIAL SALES FOR RESALE SmMen 0
0 0
0 0
PGAE O
0 0
0 0
Puget Poner 0
0 0
0 0
So Cal Edson 0
0 0
0 0
53 4,10 0
0 0
0 0
PP&LtUP&L 0
0 0
0 0
OrierFrm 8,476,060 15,330,000 34,164,000 36,792,000 38,649,600 Nmeda 0
0 0
0 0
Serra Paate 0
0 0
0 0
Secondary Sales 8,415,075 5,383.968 (646,596) 1,034,068 (1,326,979)
TO% SPECIAL SALES 16,891.125 20,713,968 33,477,404 37,826,068 37,322,621 PURCHAS*D POWER & NET INTERCHANGE Pmkhm 0
0 0
0 0
BPA Peel.Ph 0
0 0
0 0
QF. Cone::ss - PP&L 0
0 0
0 0
UP&Lhm PP&L 0
0 0
0 0
Gem Suas 0
0 0
0 0
GSLM 0
0 0
0 0
QF Conte: s UP&L 0
0 0
0 0
Socordary Purchases (5,241,393)
(3,906,708)
(7.263.282) (7,812,997) (11,880,221)
TOTAL PURCH PW & NETINT, (5,241,393)
(3,906,708)
(7.263.282)
(7,812,997) (11,880,221)
WHEEUNG & U OF F. EXPENSE BPA bierte 1,298,669 1.110.534 1,105.017 916,797 766,741 Cter (1,424,000)
(1,752,000)
(1,881,600) (1,329,000)
(2,071,200)
TOTAL WHEEUNG & U.OF F. EXPENSE (125,331)
(641,466)
(776,563)
(1,012.203)
(1,304.459)
THERMAL FUEL BURN EXPENSE
,Am Brrger 3,555.642 2,396,017 2,333,235 2.168,394 2,438,794 Dese,lonnsen 0
0 0
0 0
Carmes (309,951) 736,560 2,629,940 1,030,970 1,116,749 Wpcw 0
0 0
0 0
Casov 0
0 0
0 0
Catcn (103,015)
(105,859)
(106,976)
(108,767)
(116 060)
Naughtn 1,126,959 (1,205,227) 551,661 2,728,955 2.699,796 Huntngen 646.271 430.654 (1,051,842) (1,175,770)
(1,385 629)
Hunter 634,386 638,922 1,663,077 1,768,208 1,552,327 Eknded 0
0 0
0 0
TOTAL FUEL BURN EXPENSE 5,550,291 2,891,067 6,019,095 6,411,991 6,305.078 NET POWER COST (16,707,558) (22,371,075) (35,498,174) (40 239,277) (44,202.223) l Pe*er Panneg 1/2/88 16 43 Pa9e1 ms Merged Daerence (aq) l L
Exhibit No. 11 Schedule S 5
Pay 6 of 6 Pacif12-Utah Cerged Model Merged Utah and Pacific Difference With Sum of Stand Alone Adorped AbdsImnus Combned 1
Sase Case Not Power Cost Energy Analyss
)
- 80)wr of hyeo (w/H) 1948 1989 1990 1991 1992 NET SYSTEM LOAD 0
0 0
0 0
SPECIAL SALES FOR RESALE Busk>Gs 0
0 0
0 0
PGAE O
0 0
0 0
PugetPw 0
0 0
0 0
so Cad Edson 0
0 0
0 0
SAJO O
0 0
0 0
PP&LtoUPAL 0
0 0
0 0
Otur Fem 256,850 438,000 876,000 876,000 878,400 Newin 0
0 0
0 0
Seva Pozac 0
0 0
0 0
Secondary Sales 348.493 108,367 (198,718)
(101.068)
(187,534)
YOTAL SPECIAL SALES 605,343 546,367 677,282 774,912 690.866 TOTAL REQUIREMENTS 606,343 646,367 677.282 774,912 690,866 PURCHASED POWER & NET INTERCHANGE Peo6e Fvm 701 778 506 632 606 QF.Corwaas PP&L 0
0 0
0 0
UP&LIrom PP&L 0
0 0
0 0
Gem Sasse 0
0 0
0 0
GSLM 0
0 0
0 0
QF Contacas UP&L 0
0 0
0 0
Secondary Pun:hases (232,906) 786 (83,462) 26,064 (1,029)
TOTAL PURCH PW & NET INT.
(232,205) 1,564 (82,957) 26.716 (423)
THERMAL COAL FIRED GENERATION Jm Broper 468,771 304,388 285,559 254,115 272.737 Dre Jornsen 0
0 0
0 0
Cowale (30,945) 43,569 287,456 107,960 111.551 Wyodak 0
0 0
0 0
Caseip 0
0 0
0 0
Catcn (4,705)
(4.679)
(4,612)
(4,551)
(4,767)
Naugten 138,071 (71,225) 54.755 268.628 258.092 Hmirgen 142.824 102.392 (199,378)
(227,480)
(239.740)
Hunter 124.025 130,258 335.292 349.370 294.561 Ek. cool 0
0 0
0 0
TOTAL THERMAL 838,041 544.703 760,072 748.042 692.434 SYSTEM HYDRO (690)
(79) 56 29 (826)
D2 Ffem Sa; rage 197 179 til 125 (319)
TROJAN GENERATION 0
0 0
0 0
TOTAL RESOURCES 605.343 546.367 677,292 774.912 690.866 Power P',anneg 1/2/88 16 43 Page 2 ms Merged D&ence (a%)
- _. _ _.. _