ML20153F682
| ML20153F682 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 01/08/1988 |
| From: | Boucher R UTAH POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML20153F598 | List: |
| References | |
| NUDOCS 8805110023 | |
| Download: ML20153F682 (57) | |
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[ 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
.?OR CONSENT TO THE TRANSFER ) Indemnity Agreement No. B-78 OF LICENSES )
PREFILED TESTIMONY OF RODNEY M. BOUCHER l
8805110023 880509 PDR ADOCK 05000344 i T DCD l _
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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. ) , _
b PREFILED TESTIMONY OF RODNEY M. BOUCHER ON BEHALF OF ,.
PACIFICORP, i UTAH POWER & LIGHT COMPANY PC/UP&L MERGING CORP.
k January 8, 1988 l
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SUMMARY
OF TESTIMONY OF RODNEY M. BOUCHER ISSUES ADDRESSED
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- 1. The existing generation and transmission systems of the merging companies.
- 2. The load and resource diversity that will result from the l merger and the benefits resulting therefrom.
u 3. Changes in the operation and planning of the existing systems needed to realize the benefits of the merger.
- 4. The wholesale power marketing diversity that will result from the merger and the benefits resulting therefrom.
- 5. The generating and transmission resources and loads in the Western Systems Coordinating Council.
- 6. The role of the merging companies in the wholesale market.
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CONTENTS AND CONCLUSIONS-Existinc_ generation and Transmission Systems Pacific Pover and Utah Power both operate fully integrated electric systems in~their respective service territories. Their planning and operations are centrally coordinated. Both companies have offered and are furnishing extensive transmission services to other utilities. The control areas of the two companies are currently interconnected through a 230 kV ,
transmission line. The companies have extensive plans to further integrate <the two systems by the construction of new transmission L
and interconnection facilities.
Load and Resource Diversity There are substantial diversities between Utah Power and Pacific Power that will provide significant planning and operating savings as well as greater flexibility in meeting the needs of customers with maximum efficiency. Most of Utah Power's-capacity is supplied by vestern coal resources, while Pacific Power's location allows it to take advantage of its access to inexpensive hydroelectric resources and resources purchased primarily from the Bonneville Power Administratior.. A similar energy supply diversity exists between the companies.
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.s There is also a diversity in power purchases between the companies, in that most Utah Power purchases are non-firm, while firm purchases are generally dominant in the case of Pacific Power.
The companies experience significant seasonal and annual peak load diversity, with Pacific Power having a vinter peak and Utah Power having a summer peak. Overall generating unit operating efficiencies will improve, peak capacity purchases can be postponed, and significant overall savings vill be achieved.
Capacity requirements of the merged company will also be reduced through a reduction in reserve requirements, because of the increased system reliability that results from a pooling of generating resources.
As a result of these diversities, beginning in the winter of 1989-90 both companies can avoid purchasing new peak capacity, and after 1991 the merger would allow capacity purchases to be reduced by more than 300 mW for several years. Utah Power's otherwise required investments in new generating capacity, beginning in 1998, can likewise be avoided. The merger vill also postpone the need for new energy requirements and resources.
Chances in Operation and Plannino In order to achieve and maximize the major diversity and efficiency benefits, the generating and transmission resources of
( the two power systems will be planned and operated on a
E single-utility basis. These changes will not, however, affect other utilities. The coordination of operations that will take place after the merger will result in a system that is
't integrated, interconnected and coordinated more than is the case with the present separate companies. A number of new transmission facil?. ties and interconnections are planned. These transmission facilities vill, in the merged system, allow capacity requirements to be met without new generation investment that would otherwise be required. They will also enable the company to take better advantage than is presently possible of low cost power supplies that are presently available from other suppliers.
Wholesale Power Marketina Diversity The bulk of Pacific Power's wholesale energy sales in the last four years have been to the California power markets, while Utah Power has made most of its sales to desert Southveet utilities. This diversity, together with the diversity in energy production costs and other operating efficiencies, vill produce enhanced firm and non-firm sales opportunities. The wholesale power market has, in recent years, experienced changes that have made it a "buyer's market," and the flexibility resulting from increased diversity will enable the merged company to provide a greater variety of "packages" of services and thereby make it more competitive. Increased wholesale power sales should result
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_5 from.the companies' ability to maximize use of the merged system's total available market through joint energy supply control, through being more price competitive, through the market access availabls to both companies, and to the improved overall supply reliability of the merged company. The merged company will not, however, dominate wholtsale power markets because of the vigorous competition from other power suppliers with advantages of their own.
Western Systems coordinatino Council A review of the loads and resources of the Western Systems Coordinating Council shows that the merged companies will own and control only a modest amount of the total transmission and that such amount is in reasonable proportion to the size of the merged company.
Wholesale Markets The California market for wholesale power has and is currently undergoing substantial changes. These changes have created a "buyer's market" with intense competition between the Pacific Northwest and the desert Southwest for a smaller and lower-price fuel displacement market in California. This has resulted in selling firms' shifting their marketing focus from short-term non-firm sales to firm sales and to more sophisticated marketing packages. Pacific Power has recently consummated
agreements with Southern California Edison Co. and Sacramento "
Municipal Utility District, and Utah Power has recently entered into an agreement with Nevada Power Co., all of which reflect t
these changes in the California market.
Utah Power's access to the California market is restricted ' '
to short-term non-firm sales at present by reason of transmission limitations. Pacific Power has access to the California market '
through its direct 115 kV interconnection with Pacific Gas and Electric Company and through its interconnections to the' Pacific Northwest-Pacific Southwest Intertie. Pacific Power's use of the Intertie has amounted to approximately 9% of the total Intertie use. . Use of the Intertie may be affected when Bonneville Power 6
Administration adopts a Long-Term Intertie Access Policy to replace the present Near-Term Intertie Access Policy, and Pacific Power's rights to the Intertie may under some conditions be adversely affected.
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1 QUESTION 2 Pleatse state your name, business address and 3 present position.
4 ANSWER 5 My name is Rodney M. Boucher. My business address 6 is 920 SW Sixth Avenue, Portland, Oregon 97204. I am Vice 7 President of Power Systems with Pacific Power & Light 8 Company (Pacific Power or Company) .
9 CUESTION 10 Please summarize your education and prior 11 employment. '
12 ANSWER -
13 I was graduated from Oregon State University in ,
14 1965, with a Bachelor of Science Degree in Electrical ;
15 Engineering, and from Rensselaer Polytechnical Institute in 16 1966, with a Master of Science Degree in Power Systems '
17 Engineering. I am a registered Professional Engineer in the 18 states of Oregon and Connecticut. I was employed by Niagara-Mohawk 19 Power Company in 1965 as an assistant 20 engineer, and from 1966 through 1974 by the United ,
21 Illuminating Company as an engineer, holding various f
22 positions in the treasury, engineering and planning 23 departments. My duties included gener.ation, transmission 24 and distribution planning, economic analysis, load forecast-1 25 ing, computer applications and power system pooling. In
' k 26 January 1975, I was employed by Pacific Power in the power s l
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- 1 resources department with responsibility for power con-2 tracts. From 1979 through 1982, I managed the design 3 engineering department, with responsibility for substations, 4 transmission lines and rights-of-way. In December 1982, I 5 was named Director of Special Projects and in October 1984 6 was elected Vice President.
7 QUESTION 8 As Vice President of Power Systems, what are your 9 responsibilities?
10 ANSWER 11 As Vice President of Power Systems, I am respon-12 sible for planning and operation of Pacific Power's i 13 generating and transmission resources, fuel supply, and all 14 inter-utility transactions related to power supply matters.
15 QUESTION 16 Have you previously testified in regulatory 17 proceedings?
18 ANSWER 19 Yes. I have testified in regard to power 20 planning, wholesale power sales and system operation matters 21 in all of Pacific Cower's state jurisdictions, as well as in 22 Nevada and before the Federal Energy Regulatory Commission.
23 QUESTION 24 What is the purpose of your testimony?
25 ANSWER
( 26 My testimony will address the system operation and
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1 planning aspects of the merging companies in the following i
2 areas:
3 1. The merging companies' existing generation 4 and transmission resources.
5 2. The merging companies' load and resource 6 diversities.
7 3. Changes in operation and planning after the 8 merger.
9 4. Loads, resources and transmission within the 10 Western Systems Coordinating Council (WSCC).
11 5. The merging companies' role in the wholesale
- 12. markets.
13 SU357 TON 14 Will you offer any exhibits in connection with 15 your testimony?
16 ANSWER 17 Yes. ,I have one exhibit, Exhibit No. 9, consist-18 ing of 36 Schedules.
19 QUESTION 20 Are you generally familiar with the Utah Power &
l 21 Light Company (Utah Power) system?
22 ANSWER 23 Yes. During the course of my employment with
! 24 Pacific Power, I developed an understanding of the Utah 25 Power system, both through bilateral business dealings with fi 26 Utah Power, and through various utility organizations and
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1 forums, such as the Intercompany Pool and Western Systems 2 Coordinating Council. Since our Companies agreed to merge, 3 I have developed a more detailed knowledge of Utah Power's 4 system.
5 6 EXISTING GENERATION AND TRANSMISSION RESOURCES 7 QUESTION 8 Please generally describe the nature and operation 9 of the companies' existing systems.
10 ANSWER
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11 Pacific Power's geographically diverse system of 12 load areas and resources is fully integrated through an i 13 extensive network of major transmission lines, in excess of 14 250 interconnections, and numerous transmission service 15 agreements with other utilities. Exhibit 2, Schedule 1 of 16 Mr. Topham's testimony, illustrates the geographic location 17 of both Utah Power's and Pacific Power's service areas, and 18 their major transmission lines and generation resources 19 relative to other utilities' major facilities. I am respon-20 sible for the operation and planning of Pacific Power's 21 Generation and Transmission resourcen shown on that map.
22 Pacific Power provides operational control of its system 23 through two control areas, both of which are centrally 24 controlled from its Portland, Oregon, Load Dispatch Office 25 for purposes of efficient day-to-day operation. While A 26 geographically diverse, Pacific Power operates and plans its
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1 generation and transmission resources on a single coor-2 dinated system basis. A copy of Pacific Power's system one-3 line diagrams are included in the workpapers. ,
4 Utah Power's geographically compact system of 5 loads and resources is thoroughly integrated through an 6 extensive network of major transmission lines, numerous 7 interconnections, and a limited number of transmission 8 service agreements with other utilities. Utah Power 9 operates a single independent control area which is i 10 centrally dispatched from its System operations control 11 Center (SOCC) in Salt Lake City, Utah. f 12 QUESTION b
13 Please discuss the degree to which the merging 14 companies have provided transmission services to other i 15 utilities.
16 ANSWER 17 Both Utah Power and Pacific Power provide 18 extensive transmission services to other utilities. '
19 Schedule 1 is a listing of each company's current agreements 20 under which transmission services are provided. As shown in 21 Schedule 2, which is a summary of the services provided 22 under such agreements, Utah Power and Pacific Power have i
23 provided wheeling services during the period 1983 through i 24 1986 averaging about 783 average MW per year for the two !
l 25 companies, with annual services provided by Pacific Power ;
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26 averaging 428 average MW, and for Utah Power 355 average MW. I i
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1 While the amount.of services provided may vary from year to !
2 year, the companies do not expect any significant change in
- 3 such services as a result of the merger. The merged company -
4 will continue to honor all existing agreements for transmis-5 sion services.-
6 QUESTIOJ{
i 7 Please describe the existing control areas of each 8 company.
I 9 ANSWER 10 Both Pacific Power and Utah Power currently 11 control and operate independent multistate control areas. t 12 In general, both companies' control areas are roughly -
- i 13 coincident with their respective service territories and are
14 bounded by their interconnections with neighboring utili- F 15 ties. Within a control area, the controlling utility has 16 the responsibility of operating the controllable generation !
17 to match actual load and schedule requirements on a 18 continuous basis, irrespective of the service responsi- !
19 bility of any particular load within the control area. I 20 Schedule 3 is a listing of both Utah Power's and Pacific 21 Power's existing control area interconnections with other !
22 utilities. ;
23 Because of Pacific Power's geographic diversity, [
24 operational control of generation, major transmission and ;
25 interconnections is more efficiently provided from two loca-l
'( 26 tions. The Load Dispatch Office in Portland, Oregon, ;
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-L 7 1 provides central coordination over the Western Control Area, ;
2 including major generation, transmission and interconnec-3 tions in Oregon, Washington, California, Montana, Idaho, and j 4 the Jim Bridger Project in Wyoming, as well as dynamic 5 overlay Automatic Control Generation (AGC) of the Eastern 6 Control Area. The Energy Control Center in Casper, Wyoming, 7 provides primary control over the Eastern Control Area 8 including major generation, transmission and interconnec-9 tions associated with Pacific Power's Wyoming system.
10 Dynamic overlay AGC is provided from the Portland Load 11 Dispatch Office.
12 Operational control and coordination of the Utah i 13 Power control area, including .najor generation, transmission 14 and interconnections in Utah, Wyoming and Idaho, is provided 15 from the SOCC in Salt Lake City, Utah. ,
16 QUESTION 17 Why is the Jim Bridger Project, which is located 18 in Wyoming, included in Pacific Power's Western Control 19 Area?
20 ANSWER 21 In order to fully integrate the Wyoming system and 22 its extensive coal-fired resources with its western load 23 areas, Pacific Power has entered into a Transmission Service -
24 Agreement (TSA) with the Idaho Power Company (IPC). Under 25 the terms of the TSA, Pacific Power may transfer up to i
- k. 26 1600 MW from its two-thirds share of the Jim Bridger Project ,
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R. M. Bouchor e 1 and its other Wyoming resources through the IPC system to 2 its western load areas. As part of the operational 3 considerations associated with the TSA and the three-party
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4 interconnection agreement between Pacific Power, IPC and 5 Utah Power, Pacific Power's share of the' Jim Bridger Project 6 'and all of the Jim Bridger transmission system were included 4 7 .in Pacific Power's Western Control Area with a direct 8
interconnection to Pacific Power's Eastern Control Area at 9 Jim Bridger. This arrangement- is necessary to satisfy 10 Pacific Power's system integration requirements and provide 11 for dynamic overlay control of its Eastern Control Area from 12 its Western Control Area. The IPC share of the Jim Bridger i 13 Project is in the IPC Control Area.
14 OUESTION 15 Please describe the existing transmission and 16 interconnection facilities between the control areas of Utah 17 Power and Pacific Power.
18 ANSWER 19 The control areas of Pacific Power and Utah Power 20 have been interconnected since 1964, at the Utah Power 21 230 kV Naughton substation in Southwest Wyoming. The 230 kV 22 transmission line connecting the two control areas is owned 23 and operated by Pacific Power and connects, as shown on 24 Schedule 4, page 1, to Pacific Power's Monument switching 15 station which is located 30.2 miles east of Utah Power's
( 26 Naughton substation. While the interconnection facilities
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.s 1 are rated for 380 MW, the operational rating of the 2 interconnectie.1 is limited at times to approximately 200 MW 3 for deliverie s to Utah Power because of Pacific Power's load 4 4 requirement, that are served from these facilities.
5 QUESTION 6 In the absence of a merger, what would the 7 expected future transmission and interconnection planc for j 8 each company be?
- 9 ANSWER 10 This is shown in Schedule 4, pages 3 through 5, t 11 which consists of excerpts from Pacific Power's May 1987 12 five-year Transmission Construction Expenditure Forecast for i 13 the period 1988-1992 in which major transmission projects 14 are identified. This forecast is prepared annually for
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15 budgeting purposes and covers major transmission, substa-16 tion, distribution, control and communication items. A copy 17 of Pacific Power's five-year Transmission Construction i 18 Expenditure Forecast is included in the workpapers.
19 QUESTION 20 Please discuss the major projects included in
, 21 Schedule 4.
j 22 ANSWER i
23 Schedule 4, page 5, identifies tne Eugene-Medford 24 500 kV project. To meet service reliability requirements of 25 Pacific Power's Southern Oregon and Northern Calit'ornia load
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26 areas, an additional transmission source into this area is
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1 required in the early 1990's. The project consists of a 2 500 kV line connecting the Eugene, Oregon area to the 3 Medford, Oregon, area. This line segment will complete a 4 500 kV loop supplying the area.
5 Schedule 4, pages 1 and 2, show the geographical 6 location of the following items: I 7 Items 1, 2, 3. To meet customer load needs and i 8 service reliability requirements in its Wyoming load area,
, 9 Pacific Power is currently converting the Dave Johnston-to-10 Casper 115 kV line to 230 kV. This project is being 11 , developed jointly with the Western Area Power Administra-12 tion. Plans call for this project to extend and connect the f
i 13 Casper area to the Jim Bridger power plant by construction 14 of the Spence-Bairoll-Bridger 230 kV line. Customer load 15 additions near Bairoil have accelerated the timing of this ;
.I 16 project to 1989, 17 Items 4 and 5. The Firehole-to-Bridger Pump and 18 South Trona-to-Monument 230 kV lines are being added to ;
19 maintain service reliability to the City of Green River and j 20 other local loads. ,
j 21 QUESTION !
22 Other than those projects shown in the 5-year r t 23 Forecast Report, did Pacific Power have any other relevant 24 transmission plans, prior to the merger.
25 ANSWER l 26 One item which has been in the long-range plan for i I
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1 several years, but still under study and not firm enoagn for 2 the 5-year forecast, is the Bridger System Midline Switching 3 Station. This project involves a 345 kV switching station 4 to be built on the Bridger West 345 kV lines, possibly near 5 Treasureton or Naughton (See Schedu3e 4, Page 1).
6 The purpose of this switching station is to 7 increase the reliability of the Jim Bridger Project 345 kV 8 lines by allo. sing better sectionalizing following line 9 faults, and to increase Bridger West transfer capabilities.
10 QUESTION 11 In the absence of the merger, what are the 12 expected future transmission and interconnection plans for i 13 Utah Power?
14 ANSWER 15 Utah Power has only one significant near-term 16 transmission project, the Southwest transmission line 17 between Utah Power and Nevada Power Company. This transmis-18 sion line is proposed to be constructed with or without the 19 merger and has already received the required regulatory 20 approvals. This project consists of a 137-mile section of 21 345 kV line between Utah Power's Sigurd substation and 22 Newcastle, Utah, and a 32-mile sectic n of 345 kV line 23 between Utah Power's Central substation and the Utah / Nevada 24 state border.
25 These line sections and the necessary sabstations 26 and terminations, combined with the 21-mile section of
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1 345 kV line between Newcastle and Central, Utah, that is 2 currently under construction, will complete the interconnec-3 tion between Utah and Nevada. The cost for this project is 4 estimated to be about $73 million. The transmission line 5 will have a capacity of 400 MW into Southwestern ' Utah and 6 250 itW into Nevada Power.
7 QUEST.g 8 Will the two operating divisions of the merged 9 corporation share power system benefits with the merger?
10 ANSWER 11 YOs. As I will discuss later in greater detail, 12 the power supply benefits of the merged Utah Power - Pacific 13 Power system will be derived from efficiencies and economies i
14 related to resource planning and system operation. The 15 underlying factor giving rise to efficiencies and economies 16 which will be gained through integrated single-utility 17 planning and operations is diversity, as viewed from several 18 perspectives. These perspectives include p.ower supply mix 19 and attendant costs, resource planning, retail load 20 characteristics and wholesale power marketing opportunities.
, 21 Because of its importance, I believe a discussion of 22 diversity is a prerequisite to explaining mergsd power 23 sy;cem benefits.
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1 LOAD AND RESOURCE DIVERSITY 2 QUESTION 3 Please discuss the power supply and resources of 4 the existing systems.
5 ANSWER 6 Pacific Power's generating resources consist 7 mainly of large coal-fired generating units and, to a lesser 8 extent, hydroelectric facilities and power supplies .
9 purchased from other utilities. As shown in Schedule 5, 10 Pacific Power's 1988 total system resource capability is 11 about 5,859 MW, of which 3,073 MW or 52 percent is from 12 coal-fired resources located in Wyoming (2,325 MW),
i 13 Washington (608 MW) and Montana (140 MW) . As further shown 14 in Schedule 5, hydroelectric resources and capacity 15 purchases from the Bonneville Power Administration (BPA) 16 also comprise substantial parts of Pacific Power's capacity 17 resource mix, constituting about 25 percent and 18 percent, 18 respectively.
19 Utah Power.'s generating resources consist almost 20 entirely of large coal-fired generating units. Schedule 6, 21 shows that Utah Power's 1988 total system resource capabil-22 ity is about 2946 MW, of which 2697 MW or 92% is from coal-23 fired resources located in Wyoming (710 MW) and Utah 24 (1987 MW). Utah Power's hydroelectric resources comprise 25 only 118 MW or 4% of its total resource capability.
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1 Schedule 7, contains a list of current generation 4
2 resources owned by Pacific Power - and Utah Power. Also 3 included for each resource is its peak capability, fuel 4 type, normal operating mode, and location. Peak capability 5 information represents what is available to either Pacific 6 Power or Utah Powtr based on their ownership share or 7 entitlement. The differences in hydro resource capabilities 8 shown in Schedules 5 and 6, and the hydro resource capaci-9 ties of Schedule 7, are due to operational constraints.
10 These resources provide substantial capacity 11 diversity between the two systems. As shown on Schedule 8, 12 most of Utah Power's capacity is supplied by the western 3 13 coal resources available to it. Pacific Power's location, on 14 the other hand, allows a more diversified resource mix, 15 taking advantage of its access to inexpensive hydroelectric 16 resources and resources purchased primarily from BPA.
, 17 QUESTION 18 Does the large proportion of Pacific Power's 19 capacity purchases from BPA constitute a continuous energy 20 source for the Company?
21 ANSWER 22 No. Pacific Power's arrangement with BPA in this 23 instance is for capacity only. Energy associated with BPA 24 capacity deliveries to the Company must be returned to BFA.
25 Such energy returns are normally effected using our
( 26 coal-fired generating units. Therefore, from an operational
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1 perspective, BPA capacity is similar to a pumped storage 2 hydro facility. A copy of Pacific Power's firm capacity 3 contract is included in the workpapers.
4 QUESTION 5 Is there diversity between the two systems with 6 respect to energy supply similar to the diversity of 7 capacity resources?
8 ANSWER 9 Yes. Schedule 9, shows the sources of energy used 10 by Utah Power and Pacific Power to meet their respectave 11 total system energy requirements during 1986 based on actual 12 operations. As would be expected, energy supply diversity i 13 between the systems is similar to the capacity diversity, 14 although the relative contributions of each resource type to 15 energy production are different. The higher contribution of 16 Pacific Power's thermal generating facilities to its total 17 energy requirements versus its total available capacity 18 (59.2% vs 52.4%) is largely due to the Company's BPA energy 19 return obligations. In Utah Power's case, thermal resources 20 contributed a smaller fraction to its energy resource mix 21 than to its capacity mix (72.1% vs 91.6%). This illustrates 22 Utah Power's ability to use its geographic location and 23 transmission system to its economic advantage by importing 24 lowe. :ost energy from other sources when available.
25 OUESTION 26 Are energy production costs between the systems
j R. M. Bouchar - 16 1 also diverse?
2 ANSWER 3 Yes. With regard to system fuel costs, Sched-4 ule 10, -illustrates the range of projected 1988 average 5 fuel costs for the major generating plants that Utah Power 6 and Pacific Power bring to the integrated system. These 7 data are only roughly indicative of the-relative incremental 8 costs of these plants in the future, since such costs can 1
9 shift over time depending on such factors as fuel quality 10 and long-term coal-mining plans.
11 QUESTION 12 You have indicated that Utah Power and Pacific l 13 Power have historically relied on off-system generation 14 sources for meeting system load requirements. Please 15 provide recent historical off-system purchase levels and 16 give some general background as to the nature of these 1 17 transactions.
18 ANSWER 19 Schedule 11, contains firm and nonfirm off-system 20 purchase activity for both Pacific Power and Utah Power 21 during the last four years. Firm transactions typically 22 provide both capacity and energy, while nonfirm transactions 23 *ypically
. provide only energy when available.
24 With regard to Utah Power, off-system firm 25 purchases have been made on occasion, but in recent years
\ 26 the majority of off-system purchases have been nonfirm to
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I substitute less expensive purchases, primarily from 2 Northwest hydroelectric generation, for the operation of its 3 own generation.
4 With regard to Pacific Power, off-system firm 5 purchases are generally dominant. This is primarily due tc 6 the Company's long-term purchase agreements that provide a 7 percentage output share of four large Columbia River hydro-8 electric projects, as well as firm power contracts with BPA 9 and other entities that provide capacity and energy. In 10 addition, the Company currently purchases in excess of 1,000 11 MW of firm peaking capacity from the Bonneville Power 12 Administration (BPA). Pacific Power has numerous other i 13 smaller firm and nonfitu purchase arrangements including 14 purchases made under PURPA from qualifying facilities.
15 Pacific Power also purchases substantial amounts of nonfirm 16 energy when available to reduce the operation of more 17 expensive company-owned generation sources similar to Utah 18 Power's practices . A listing of Pacific Power's purchased 19 power contracts is included in the workpapers.
20 OUESTION 21 What circumstances enabled Pacific Power to 22 diversify its capacity resources?
23 ANSWER 24 Pacific Power's ability to construct and purchase 25 hydroelectric resources was due to the Company's advan-
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26 tageous geographic location. Besides participating in the
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1 generation projects identified in Schedule 12, to meet t
2 energy needs, Pacific Power also entered into long-term ;
3 peak capacity agreements with BPA. The Company's initial !
4 peak capacity contract with BPA was executed in 1973, at !
5 which time Pacific Power purchased 200 MW of capacity, our ,
6 current peak capacity agreement with BPA expires in 1991 at a terminal contract demand of over 1,100 MW. Although load 7
8 diversity and other synergies of the merged power systems ;
9 will significantly affect the combined company's total !
10 capacity needs, I believe BPA peak capacity will continue to [
11 be a substantial and important part of our ultimate resource 12 mix. The availability of capacity to Pacific' Power has i 13 caused its emphasis and focus to be on energy supply ;
14 planning to satisfy its customers' needs, compared to Utah 15 Power's primary focus on capacity planning. A study of BPA 16 peaking capability is included in the workpapers.
17 OUESTION :
18 What accounts for this difference in resource 19 planning emphasis? I 20 ANSWER I
21 Like other utilities throughout the country, Utah 22 Power has had to primarily develop sufficient thetrmal 23 resources to meet its customers' capacity needs due to the l 24 unavailability of less-expensive resource options. With 25 ample coal supplies, the energy from these resources is l 26 limited only by equipment failures and preventivo mainten- y i
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1 ance requirements. In contrast, energy produced from 2 Pacific Power's hydroelectric facilities in the Pacific 3 Northwest is constrained by several additional factors, 4 including precipitation, storage capability, irrigation 5 needs, and recreation and fishery requiremants.
6 QUESTION 7 Please discuss the merged system's peak load 8 diversity.
9 ANSWER 10 Seasonal and annual peak load diversity of the 11 merged system is illustrated in Schedules 13 and 14. The 12 information shown is based on actual 1986 native load data 13 and illustrates the effect of integrating Pacific Power's 14 winter peak load with Utah Power's summer peak load.
15 Pacific Power's winter peaks have historically occurred 16 during the months of November through February while Utah 17 Power's peaks have predominantly occurred 1, . July. Viewed 18 on an integrated basis, the combined system peaked in the 19 winter, and this coincidental peak was substantially lower 20 than the sum of the two systems' noncoincidental annual peak 21 loads. The dif ference, or annual peak load diversity, was 22 436 MW, as shown in Schedule 14.
23 Schedule 15 shows both Pacific Power's and Utah 24 Power's jurisdictional peak load and energy sales informa-25 tion for the years 1983 through 1986, as well as the 26 estimated combined system coincident peak load and energy
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4 1 sales information. The coincident peak load information has !
2 been adjusted to reflect load diversity between the two 3 companies. Also included in Schedule 15 are the individual !
i 4 system's peak load information reflecting off-system sales I 5 at the time of peak load, as well as the individual and 6 combined system's total energy sales.
. 7 QUESTION i
8 How will these load and resource diversities j 9 result in efficiencies and economies of operation?
10 ANSWER 11 Pacific Power anticipates that significant 12 benefits will be derived through its ability to adopt both i 13 joint unit commitment (deciding which generation facilities 14 to make available for use) and dispatch (deciding the extent j 15 to which available resources are actually utilized) . We i 16 believe that these joint operations will allow the merged i
4 17 system to take full advantage of our fuel cost diversities l 18 and improve overall generating unit operating efficiencies,
.i j 19 resulting in significant total fuel cost savings. Our 20 combined ability to take greater advantage of purchased 21 power supplies will also contribute to lower system 22 operating costs. Mr. Steinberg will describe estimates of j 23 these system operation H nefits. +
24 QUESTION 25 How do the many diversities you have discussed J
26 affect future rescurce requirements?
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t 1 ANSWER
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2 By taking advantage of these diversities, the 3 merger will postpone peak capacity purchases that would have 4_ "been needed as early as 1990. Capacity resource needs are 5 also expected to be reduced by. greater reserve sharing 6 through expanded interconnections. As I will discuss later,
,7 expanded interconnections will also facilitate greater 8 utilization of currently available power supplies from third 9 parties.
10 QUESTION 11 What would be each company's expected new resour-12 ces, were they to remain separate companies?
i 13 ANSWER 14 Ea ~.h company's expected future resources are sum-15 marized in Schedules 16 and 17. Schedule 16 summarizes each 16 company's new capacity requirements for both summer and 17 winter peak periods, through winter 2006-7. Schedule 17 18- summarizes each compa.%'s requirement for new energy 19 resources on an annual basis, through operating year 2006-7.
20 These schedules are based on the more detailed load and 21 resource summaries contained in Schedules 18 and 19.
22 QUESTION 23 Please explain the type and timing of Utah <
24 power's expected future capacity expansions summari::ed in 25 Schedules 16 and 17.
26 AN.cWER
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1 Utah Power's new requiremen':s are driven, primarily
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2 by. summer peak loads. Schedule 16 shows purchases of
,3 capacity for the summer season only, beginning in 1990. In 4 that year, an additional 72 MW of capacity are required, in 5 addition ' t'o the 90 MW purchase from Pacific Power already 6 planned. It is- assumed that summer capacity can be 7 purchased from Northwest utilities. Transmission con-8 straints on such off-system purchases recruire new generation 9 to be installed in 1998. In that year, Utah Power plans the 10 installation of a 62 MW combustion turbine (Plann 3d New 11 Generation, line 7), with additional capacity coming from 12 150 MW coal units thereafter. Those coal units also satisfy i 13 the need for new energy resources beginning in 2000-1, as 14 shown in Schedule 17. Timing of these purchases and the 15 associated investments would be delayed by any additional 16 purchases of power from qualifying f acilities under PURPA, 17 over and above those committed purchases shown in Sched-18 ule 18.
19 QUESTION 20 Please explain the type and timing of Pacific 21 Power's expected future capacity expansions summarized in 22 Schedules 16 and 17.
23 ANSWER -
24 Pacific Power's new reque.rements are governed by 25 both winter peak loads and energy needs. Schedule 16 shows x 26 purchases of capacity to meet winter peak requirements,
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-1 beginning in 1990. It is assumed that those capacity 2 purchases could be made from BPA, pursuant to the provisions 3 of applicable BPA rate schedules. Beginning in 1991,
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4 capacity purchases increase substantially, reflecting 5 Pacific's need to replace its current capacity purchases 6 from BPA, which expire in that year. We expect that 7 capacity purchases from BPA will continue subsequent to the 8 current contract expiration; howeves., other capacity ,
9 purchase alternatives are also being considered. Sched-10 ule 16 also shows, on line 17, the capacity matie available 11 by new resources required for firm energy needs, beginning 12 in operating year 1993-94, a 13 T- edule 17 1dentifies the expected sources that 14 can meet .tese energy requirements. The new energy 15 resources were chosen from the range of resource alterna-16 tives summarized in Schedule 20, on the basis of lowest 17 levelized costs. In summary, these sources consist of 18 turbine improvements to existing thermal units, withdrawals 19 of energy from wholesale power customers as is provided in 20 certain power sales agreements, the exercise of options on 21 cogeneration at several of Pacific Power's industrial 22 customers, optional conservation programs, and purchases 23 from BPA as provided for in section 7 (f) of the Pacific 24 Northwest Electric Power Planning and Conservation Act 25 (Regional Act) and in Pacific Power's Power Sales Contract 26 with BPA. A copy of the Regional Act and the Power Sales i
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1 Contract with BPA are included in the. Workpapers. As 2 Schedule 20 indicates, these energy resources have relative-3 ly short lead timeh and need not be committed to at this 4 time. If more cost-effective purchases were to be identi-5 fied, they would, of course, be employed before these 6 resources.
7 8 CHANGES IN PLANNING AND OPERATIpg 9 QUESTION 10 How would you expect the merger to affect the 11 expected future capacity expansions summarized in Schedules 12 16 and 17?
i 13 ANSWER 14 The merger should affect both the type and timing 15 of future resource purchases and investments depicted in 16 Schedules 16 and 17. An illustration of the effects is 17 provided in Schedules 21 and 22. These schedules are based 18 upon the more-detailed load and resource projections for the 19 merged company contained in Schedule 23. Schedule 21 20 summarizes the merged company's expected future capacity 21 requirements, and the type and timing of rescarces that meet 22 those requirements, for both summer and winter peak periods,
- 23 through winter 2006-7. Similarly, Schedule 22 summarizes 24 the merged company's expected future new energy requirements 25 and resources on an annual energy basis, through operating 26 year 2006-7. While the information shown in Schedules 21
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1 and 22 depict a reasonable resource planning scenario, it 2 should be viewed as only an estimate of the changes in
-3 future capacity expansions that could result from the 4 merger. Time has noti yet allowed extensive resource
. 5 planning studies for the merged systen.. The schedules do, 6 however, illustrate the contributions to capacity expansion 7 savings from load diversity and resource diversity.
8 QUESTION 9 Please explain the differences in capacity 10 requirements between the merged system and the systems of 11 the tw unmerged companies.
12 ANSWER 13 Two factors contribute to a reduction in net 14 requirements for the merged company. The first factor is 15 the peak load diversity I have already discussed. The 16 -second factor is a reduction in reserve requirements. Each 17 company currently uses a different method of estimating 18 future reserve requirements. While it will take more 19 analysis than time has yet allowed to determine the precise 20 reserve requirements for the merged company, it is safe to 21 say that the merger will significantly reduce those reserve 22 requirements.
23 We know from reliability theory that a pooling of 24 generating resources and diverse loads increases system 25 reliability, and therefore reduces the level of reserves 26 required to achieve the same level of generation reliabil-
l R. M. Bouchar '
b l
1 ity. This benefit of pooling is already recognized in the i
.2 reserve sharing arrangements of the Pacific Northwest 3 Coordination Agreement (PNCA) and the Intercompany Pool ;
4 (ICP). But since the allocation of reserves under both 5 reserve sharing arrangements is made on the basis.of each 6 individual system's relative reliability, the merger would 7 reduce the allocation to the combined system. In ~ simple 8 terms, a pooled operation of Pacific Power and Utah Power 9 generation resources reduces the probability 'that other 10 utilities would need to provide emergency capacity to the 11 merged company; the merged system is more reliable than the 12 individual systems alone. . Consequently, a lower reserve 13 requirement would be allocated to the merged system.
14 The studies we have conducted to date indicate 15 that the merger can reduce allocated reserves in the range 16 of 200 to 500 MW, depending on which optional resources are 17 declared as part o'! the PNCA forced outage reserve alloca-18 tion. For example, if all resources of.the merged comp.any 19 had been used in the 1987-88 PNCA reserve allocation, the 20 merged company would have had a required reserve level of 21 about 1120 MW (critical peaking period average). This can 22 be compared to the sum. of each company's current winter 23 requirement of 1392 MW, as shown in Schedule 24, (4 42 MW 24 plus 950 MW). We have assumed, for preliminary planning 25 purposes, that a 200 MW reduction of required reserves will 26 be realized at a minimum. This reduction is accounted for
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1 in line 4, Reserves Required, of Schedule 21. Copies of the 2 PNCA and ICP agreements and the Forced Outage Reserve 3 Allocations are included in the workpapers.
4 QUESTION 5 Do any other factors contribute to the reduction 6 in required new resources shown in Schedule 21?
7 ANSWER 8 The exhibit recognizes an effective increase in 9 net committed resource capacity (line 5 of Schedule 21) 10 that the merger will allow. An increase in summer capacity 11 reflects the rescheduling of some of Pacific Power's thermal 12 maintenance. In addition, an increase in Pacific Power's 13 Mid Columbia generating capacity of about 40 MW reflects 14 less reliance on these resources for load following that the 15 . merger will allow, as I will discuss later.
16 QUESTION 17 What is the combined effect of the reduction in 18 requirements and increase in effective capacity you have 19 described?
20 ANSWER 21 Line 6 of Schedule 21 shows the new rer- es 22 required by the merged system, line 10 shows the sum of the
?. 3 two separate companies' requirements from Schedule 16, and 24 line 14 shows the difference resulting from the merger.
25 Beginning in winter 1989-90, the merger avoids Pacific 26 Power's purchase of new winter capacity and Utah Power's
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- 1 purchase of new summer capacity. After 1991, the merg're 2 allows capacity purchases to be reduced by more than 300 MW 3 for several years. Utah Power's required investments in new 4 generating capacity, beginning in 1998, are also avoided by 5 the expanded transmission interconnections between the 6 merging companies, which I will discuss later. The expanded 7 interconnections will allow capacity requirements to be met 8 by continued purchases.
9 Schedule 22 compares the merged company's expected 10 future new energy requirements and resources with those for 11 the two companies separately. The merger would postpone the 12 need for new energy resources from 1993-94 to 1997-98. In 13 addition, Utah Power'c investments in coal units, beginning 14 in 1999-2000, can be reduced or avoided to the extent that 15 firm energy purchases from BPA or other possible sources are 16 more cost effective. It is assumed for analysis purposes 17 that those purchases would be made, rather than investment 18 in new generation, as will be discussed by Mr. Steinberg.
19 QUESTION 20 Will operation of the existing systems also be 21 changed after the merger?
22 ANSWER 23 Yes. In order to achieve and maximize the major 24 diversity and e f ficier.cy benefits available to the merged 25 system which will be described by Mr. Steinberg, we expect 26 to plan and operate the generation and transmission
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I resources of the two power systems on a single-utility 2 basis. We will establish arrangements to account for and 3 allocate the operating costs and planning benefits between 4 the two operating divisions.
5 QUESTION 6 Will the existing control areas of the two 7 companies be changed after the merger?
8 ANSWE't 9 Yes. In order to provide for integrated economi-10 cal operation of the merged company's generation and 11 transmission resources as a coordinated system, the merged 12 company intends to combine Pacific Power's Eastern Control 13 Area and Utah Power's Control Area into a single control 14 area which will be centrally controlled from the SOCC. For 15 purposes of planning efficient operation of the L. Ted 16 company's resources (i.e., unit commitment, coordination of 17 off-system sales requirements, system reserve, thermal 18 maintenance, etc.), the merged system's schedule operation 19 will be coordinated through the Portland Load Dispatch 20 Office as is currently the case for Pacific's Eastern 21 Control Area. As is currently the case with Pacific Power's 22 Eastern Control Area, the combined new control area will 23 continue to receive dynamic overlay AGC from the Western 24 Control Area. It is expected, however, that because of Utah
?.5 Power's existing AGC capability, sOch overlay control needs 26 will be substantially reduced.
~
. a.
R.'M. Bouchar~ a 1 QUESTION 2 Will the change in control areas affect other 3 utilities?
4 ANSWER
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5 No. The control area interconnections and control 6 arrangements with other utilities will remain as they 7 currently exist.
8 QUESTION 9 With the changes . you have described, will the 10 merged company be capable of operation as a single, 11 interconnected and coordinated system?
12 ANSWER 13 Yes. The system will be fully integrated and will 14 operate in an interconnected and coordinated fashion. While 15 the Pacific Power service territory consists of some 16 scattered and isolated regions, those regions are tied into 17 the Pacific Power system by direct physical interconnection 18 with Pacific Power facilities, or, in some instances, with 19 the facilities of other power supply entities under firm 20 contracts. As a result, Pacific Power serves all customers 21 in its service territory in a coordinated manner.
22 The Utah Power service territory is not frag-23 mented, and all parts of it are ser.ved by Utah Power 24 facilities.
25 When the two systems are joined by merger, their 26 operation will, as I have illdicated, be consolidated and
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n 1 integrated. The most economic generating units from Pacific 2 Power and Utah Power will be dispatched. Because of modern 3 control facilities and equipment, geographic diversity will 4 not present any problems to this integration.
5- QUESTION 6 What changes will be made to Pacific Power's anc 7 Utah Power's transmission plan after the merger?
8 ANSWER 9 A staged transmission plan has been identified to 10 further integrate the two companies' systems together after 11 the merger. The plan makes use of several elements 12 previously identified as needed for other reasons, and 13 outlines additional elements which could be added later at 14 such time that additional integrating capability is 15 required.
16 QUESTION 17 What elements are required for the first stages of 18 the plan, what are their costs, and what capacity increases 19 do they create between the Utah Power and Pacific Power 20 systems?
21 ANSWER 22 The first elements would involve completing the 23 Firehole-to-Bridger Pump and South Trona-to-Monument 230 kV 24 lines (items 4 and 5 of Schedule 4, page 1) on schedule in 25 1989 (or advance one year to 1988 if physical construction 26 logistics allow). These two segments are twelve and
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o 1 eighteen miles, respectively, and are estimated to cost 2 about $2,228,000 and $3,198,000 in 1987 dollars. These 3 costs are updated from those shown on page 3 of the 5-year 4 plan. These two lines will raise the transfer capability S between the Utah Power and Pacific Power systems to approxi-6 mately 400 MW. In addition, associated capacitor banks are 7 needed. The capacitor bank additions aie estimated to cost 8 about $730,000.
9 QUESTION 10 What new additions are required?
11 ANSWER 12 The next phase would consist of adding a 230 kV 13 line from the Shute Creek substation to Opal, a point on 14 Utah Power's existing Naughton-to-LaBarge transmission line 15 which is presently operated at 69 kV but constructed for 16 230 kV operation (Schedule 4, page 1, item 6) . This line 17 addition (approximately 14 miles) and associated terminal 18 equipment is estimated to cost about $8.0 million and would 19 be constructed in 1989. Also required at this point would 20 be the advancement of a second Bridger-to-Rock Springs 21 230 kV line (Schedule 4, page 1, item 7). This section (34 22 miles) was planned for the mid-1990's to add transmission 23 caoacity and maintain reliability to ac;k Springs and 24 Southwest Wyoming area. Its cost is approximately S7 25 million (including capacitor banks for voltage control), but 26
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1 1 again would be a five- to six-year advancement of a line 2 required'without the merger. These two additions will raise 3 the transfer capability between the Pacific Power's and Utah 4 Power's systems to approximately 530 MW.
5 QUESTION 6 What- additional transmission ' f acilities might be 7 utilized to further integrate the two systems?
8 ANSWER 9 While not currently planned as part of the staged 10 interconnection plan, the Bridger System Midline Switching 11 station previously discussed could ,be modified to connect 12 into Utah Power's Treasureton substation in order to provide 13 both Bridger system capacity to the west and capacity from 14 the Bridger system to Utah Power's system. The Bridger 15 Switching Station would be a later stage which could be 16 implemented to gain an estimated additional 500 MW of 17 capability from the Bridger-to-Utah Po'ver system, as well as 18 adding several hundred MW of capability to the Bridger west 19 system. This later stage addition could be implemented if 20 the combined system studies identify a need for additional 21 interconnection capability.
22 QUESTION 23 Are there other additions which may be required?
24 ANSWER 25 The 230 kV line additions I have described above 26 provide substantial transfer capability increases. To
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1 control loadings on the new lines and'to control the power 2 split between the Bridger 345 kV system and these 230 kV 3 lines, a phase shifter will be added at-Naughton in Pacific 4 Power's Granger line (Schedule 4, page 1). This will help 5 control the loadings on both transfer paths. The cost of 6 this addition would be approximately $7 million.
7 OUESTION 8 How is the level of investment in transmission and 9 interconnection facilities affected by the presence of a 10 merger?
11 ANSWER ,
12 In that the first stage elements needed to 13 integrate the two companies were already budgeted for other 14 reasons, the level of investment initially will change very 15 little. The additional interconnection capacity between the 16 Pacific Power and Utah Power systems which I have described
'17 above are estimated to cost $22 million.
18 QUESTION 19 To what extent does the merger provide an 20 opportunity to substitute new transmission facilities for 21 new generation resources in the plannit.g of peak capacity 22 expansion?
23 ANSWER 24 Ihe transmission facilities for the merged system 25 I have just described could allow capacity requirements to 26 be met without new generation investments over the planning
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e 1 horizon, as^ summarized in Schedules 21 and 22. The 2~ transmission investments will allow the load diversity and 3 reserve reduction benefits of the merger to postpone or 4 avoid new generation resources, and can also support 5 seasonal capacity exchanges that could reduce future 6 purchases beyond the savings shown in the exhibits.
7 QUESTION 8 How will the transmission plans you have described 9 for the merged system affect operating and resource planning 10 economies?
11 ANSWER 12 Pacific Power, unlike Utah Power, has direct 13 access to relatively low cost power supplies from other 14 utilities located east of Pacific Power's Jim Bridger 15 generation facility. Because of energy transmission 16 limitations west of Jim Bridger, Pacific Power has not been 17 able to take full strategic advantage of these low cost 18 resources. Further, Pacific Power believes that absent an 19 early commitment, these resources will likely not be 20 available for future use. The merging of the systems and 21 expanded interconnections will allow more of this low-cost 22 power to be made available to the merged company, thereby 23 allowing a greater use of all available recources for both 24 long-term power needs and short-term operating efficienc.ns.
25 This will facilitate the attainment of least-cest planning 26 goals and objectives for both divisions, l _
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1 QUESTION 2 Please discuss wholesale power marketing diver-3 sities between the two existing systems.
4 ANSWER 5 As shown in Schedule 25, energy sales to Califor-6 nia power markets have represented about 77 percent of 7 Pacific Power's total wholesale energy sales over the past 8 four years, and less than half that amount for Utah Power.
9 Conversely, Utah Power's sales to desert Southwest utilities 10 have represented about 34 percent of their total wholesale 11 energy sales, and only about 1 percent of Pacific Power's 12 sales.
13 QUESTION 14 Will this diversity lead to wholesale power 15 marketing benefits of the merged power system?
16 ANSWER 17 Yes. Wholesale power sales benefits will ac'crue 18 to the merged system through increased sales margins, and 19 through enhanced firm and nonfirm power sales opportuni-20 ties. Such enhanced opportunities are expected as a re'sult 21 of the merged companies' resource diversity which will make 22 marketable energy available during all seasons of the year.
23 With regard to increased margins, the costs associated with 24 delivering power to wholesale customers will be lower due to 25 the diversity in energy production costs and other operating 26 efficiencies I have described. Sales margins are also
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1 expected to improve due to the combined systems' ability to 2 offer a wider , variety of valuable energy services to 3 existing and potential purchasers, thereby commanding better 4 prices.
5 QUESTION 6 Please explain.
7 ANSWER 8 Over the past several years, Pacific Power, Utah 9 Power and other power suppliers have witnessed a major 10 transition in the wholesale power marketplace. The 11 transition can best be characterized as a transition from'a 12 "sellers market" to a "buyers market" . The cause of this 13 transition was due to the combination of many events. The 14 most notable include substantial amounts of surplus power in 15 the suppliers' systems, the dramatic decline in oil and gas 16 prices, natural gas deregulation and attendant state and 17 federal policies, and the operation of new nuclear, 18 coal-fired and PURPA resources in the purchasers' system.
19 These events have spawned fierce market competition which 20 has suppressed wholesale power sales prices. To support 21 prices tu:d to maintain or increase market share, the 22 packaging of power sales has assumed greater importance.
23 QUESTION 24 How do price and packaging interact?
25 ANSWER 26 While price is certainly a major factor in a
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1 , utility's - purchase decisions, the value of other contract 2 elements such as flexible delivery arrangements, system 3 backup, long-term price stability, length of supply 4 obligation, firmness of supply and other services are 5 frequently of equal or greater importance than the initial 6 price. In fact, these elements to a large extent now are 7 the basis for negotiating wholesale power prices. As a 8 general proposition, the greater variety of these types of 9 energy services a system can offer, the higher the selling 10 price.
=11 I believe that the combined system is well 12 situated to provide the broad spectrum of energy supply 13 services demanded in the wholesale marketplace. The ability 14 of Pacific Power's more extensive hydroelectric system to 15 shape and store energy on a daily and seasonal basis and 16 Pacific Power's access to cost effective capacity resources, 17 coupled with Utah Power's longer-term energy supply from 18 controllable coal-fired generating units, affords the 19 combined system a greater opportunity to realize the market 20 value of its wholesale power. These melded attributes 21 should allow the merged systems to respond to ever-increas-22 ing competition in wholesale power merkets.
23 QUESTION 24 Are increased sales margins important?
25 ANSWER 26 Yes. As Mr. Topham points out in his testimony,
a R. M. Boucher .
7 1 the wholesale power market is highly competitive. As a 2 result, out margins have not been sufficient t.o enable us to 3 earn a reasonable return on a fully-allocated cost basis.
4 Any increase in margins will, therefore, tend to mitigate 5 this deficiency in returr..
6 QUESTION 7 Please discuss the merger's effect on wholesale 8 power sales.
9 ANSWER 10 It is expected that the merged system will be able 11 to effectively compete for wholesale power sales transac-12 tions because of the diverse and complementary generation 13 and transmission resources and the wide variety of market-14 able enetyy services they make possible.
15 The wide variety of valuable energy services that 16 can be offered by the merged system should also facilitate 17 additional firm wholesale power arrangements with California 18 and Northwest utilities in particular. With regard to 19 California, over the past few years, Pacific Power has 20 executed short-term and long-term wholesale power sales 21 agreements with several California utilities generally 22 inaccessible to Utah Power which will likely form the basis 23 for future and expanded arrangements. The formulation and 24 negotiation of these arrangements has enabled Pacific Power 25 to gain a thorough understanding of the needs of these and 26 other California utilities. Similarly, Utah Power's past
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. e 1 and ongoing relati'onships with California utilities through 2 its Intermountain Power Project activities provide the 3 merged syscem with other marketing insights and oppor-4 tunities over existing interconnections, and the. opportunity 5 to participate in possible expanded interconnections.
6 Pacific Power's dealings and many contractual 7 relationships with the Northwest power community are also 8 expected to form the basis for additional firm power sales 9 in the longer term.
10 QUESTION 11 Please discuss the merged systems' expected 12 nonfirm power sales.
13 ANSWER 14 While both Pacific Power's and Utah Power's 15 abil'ities to sell nonfirm power are governed by price 16 consideratiens, Pacific Power's nonfirm market is also 17 constrained by Federal policies. My expectation of 18 increased power sales is based on our combined ability to 19 maximize the use of the merged system's total available 20 market through joint energy supply control (unit commitment, 21 dispatch and maintenance scheduling), through being more 22 price competitive as a result of operating efficiencies.
23 Our combined ability to increase sales should also be 24 enhanced through our greater overall supply reliability, 25 which is an important factor considered by nonfirm power 26 purchasers in their decision making process. Reliability,of
, - .y - - - - - - , , - - ~- - - - . --
R. M. Boucher E A 9 1 supply often . determines which utility gets the nonfirm 2 business as well as the ultimate sales price. Mr. Steinberg
, 3 will describe.our estimates of increased wholesale sales the 4 merged company can achieve taking these general factors into 5 account.
6 QUESTION 7 Does this all mean that the merged Company will 8 domi. ate wholesale power markets?
9 ANSWER 10 By no means. We 'till face vigorous competition .
11 from other Northwest utilities with very low prices, desert i
12 Southwest utilities with major transmission interconnec- i 13 tions, and Federal Power Marketing Agencies with significant 14 low-cost surplus resources.
15 16 WESTERN SYSTEMS COORDINATING COUNCIL 17 QUESTION
- 18 -
Please generally describe the regional generation, 19 loads and transmission within Western Systems Coordinating 20 Council (WSCC).
21 ANSWER 22 Schedule 26 is a tabulation showing projected 1988 23 loads and resources by geographic areas as reported by WSCC 24 in the Summary of Estimated Loads and Resources dated April 25 1987. This information is presented to illustrate the 26 summer and winter firm resource capacity capability of each
R. M. Bouchar .'
1 reporting area in excess of firm load requirements, as well 2 as the energy capability of each area during adverse and 3 median hydro conditions. Schedule 27 is'a geographic area 4 representation, of the information contained in Schedule 26 5 where the size of the circle is in approximate proportion to 6 the generating capability within the area. Also shown in 7 Schedule 27 is an approximation of the transfer capability 8 between the regional area representations where the line .
9 width is approximately proportional to the transfer 10 capability, as will be discussed in more detail by 11 Mr. Tucker. Schedule 28 is a summary of the firm transfer 12 requirements between the areas which represents the 13 combination of firm contracts and inter-area joint generat-14 ing unit ownership. The firm transfer requirements shown in 15 Schedule 28 are represented by the darker portions of the 16 transfer capability representations shown in Schedule 27.
17 Schedule 29 is a tabulation of the resource types 18 for the generation shown in Schedule 26 for the various W3CC 19 regions, and Schedule 30 is a graphic illustration of those 20 resources. As illustrated in Schedule 30, the Rocky 21 Mountain and Desert Southwest utilities have predominately 22 coal-fired resources while the Northwest region is dominated 23 by hydro and the California-Southern Nevada utilities hava a 24 heavy concentration of oil- and gas-fired resources.
25 Schedule 31 is a tabulation of the transmission 26 lines within WSCC, comparing the merged company's transmis-
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- x l' sion line ownership with other' areas by' voltage and circuit
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2 miles. As can be seen, the merged company will own and-3 control only -a- raodest amount of the WSCC total transmission 4, and such amount is-in reasonable proportion to the size of 5- the merged company. The competitive aspects of the 6 transmission ownership and resource composition will be 7 addressed by Dr. Landon. A copy of the WSCC load and 8 resource report is included in the workpapers. .
9 10 WHOLESALE MARIGTS 11 QUESTION
- 12 Please discuss the California wholesale markets 13 and the individual companies' role in those markets.
-14 ANSWER 15 The California market has historically been one of
. 16 fuel displacement; i.e., the displacement of higher-cost 17 oil- and gas-fired generation with less-expensive coal-fired 18 or hydro generation through nonfirm or short-term (seasonal)
, 19 firm purchases of power. The California utilities ' have 20 pursued a strategy of constructing major new coal and 21 nuclear generation plants (Mojave, Navajo, San Onofre, Palo 22 Verde, Intermountain Power Project, Diablo Canyon) to 23 accommodate growing load requirements, while displacing 24 their existing higher-cost gas and oil generation with 25 purchases of coal-fired and hydro generation from utilities 26 in the, Rocky Mountain area, Desert Southwest area, and the i L
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1 Pacific Northwest. Typically, such purchases followed a 2 seasonal pattern with major quantities of hydro generation 3 available from the Pacific Northwest during the snow-melt 4
periods in the spring and early summer, followed by ccal-5 fired generation from the Rocky Mountain region during the 6 summer and fall periods, and by coal-fired generation from-7 the Desert Southwest area during the fall, winter and early 8 spring months. Generally, such patterns follow the peak-9 load seasonal diversity between the regions with some 10 variations, depending on the peak-load surplus condition of 11 each region and the snowpack in the Pacific Northwest.
12 actual power flows between the geographic areas shown on 13 Schedule 24 for the years 1985 through 1987 are illustrated 14 in Schedule 32. This information has been summarized from 15 the more-detailed bi-weekly reports published by the USCC 16 Operating Committee. A sample of the bi-weekly report is 17 ' included in the workpapers.
18 Schedule 33 shows total California purchases for 19 1984 from both Pacific Northwest and Desert Southwest 20 sources as published in the October 1986 California Energy 21 Commission's "Electricity Report Six, out-of-state electric-22 ity imports, technical documentation." The companies 23 believe this report is reasonably representative of 24 historical California purchases. As shown in Schedule 33, 25 both companies have successfully competed for a modest 26 share of the California market. Utah Power's access to the
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d 1 California market has been largely restricted to its 2 interconnection at Four Corners where it competes for sales 3 with Desert Southwest utilities as well as with Rocky 4 Mountain utilities with access to Four Corners via the 5 Colorado transmission paths, as will be discussed by 6 Dr. Landon. Until July of 1986, Pacific Power's access to 7 the California market was mainly pursuant to the Bonneville 8 Power Administration (BPA) Near Term Intertie Access Policy 9 (NTIAP) in competition with other Northwest utilities and 10 .BPA. The NTIAP is included in the workpapers.
11 QUESTION 12 Does the merged system anticipate any changes in 13 the future California market or its prospective market 14 share?
1 15 ANSWER 16 As I have already discussed, the California market 17 has and is currently undergoing substantial changes. During 18 this period of change in the California market, the Rocky 19 Mountain, Desert Southwest, and Pacific Northwest areas 20 experienced similar changes with respect to declining load 21 growth which has resulted in significant amounts of surplus 22 power in those regions while their "traditional" California 23 markets ended up with reduced needs and substantially lower 24 fuel displacement prices. The net result of these changes 25 on the market relationship between traditional suppliers and 26 the California market has been to create a "buyer's market"
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- s 1 with intense competition between the regions for a smaller 2 and lower-priced fuel displacement market in California. In 3 order to offset the revenue impacts of lower nonfirm fuel '
4 displacement prices, some utilities (including both Pacific 5 Power and Utah Power) have shifted their wholesale marketing 6 focus from short-term nonfirm sales to firm sales with a 7 longer supply obligation in order to enhance the value of 8 their surplus energy and maintain or improve sales margins 9 and market shares. Despite the substantial changes in the 10 California market, the companies believe that a viable 1.1 market exists for longer-term firm sales to the extent that 12 transmission is available.
13 As a result of the changes discussed above, the 14 merged company believes that future successful firm or 15 nonfirm sales in the California market will require more i
16 sophisticated marketing packages and that the successful '
17 sale will hinge not on price alone but also on such factors 18 as supply reliability, flexible delivery arrangements, 19 recognition of the buyer's alternative fuel supply costs and 20 flexibility for future changes.
21 The merged company believes that Pacific Power's 22 recently consummated agreements with Southern California 23 Edison Co. (SCE) and Sacramento Municipal Utility District 24 (SMUD), as well as Utah Power's recent agreement with Nevada 25 Power Co. are reflective of the changed nature of the 26 California market. A schematic representation of those
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'l agreements illustrating their unique flexibilities is 2 contained in Schedule 34. Copies of the referenced 3 contracts were included in the workpapers.
4 QUESTION 4 5 Please discuss Utah Power's current California 6 market access capabilities and constraints.
7 ANSWER 8 Utah Power is interconnected to the Desert 9 Southwest at Four Corners and Glen Canyon, as well as with a 10 number of California utilities through the Intermountain 11 Power Project at Mona. However, due to transmission 12 limitations beyond Utah Power's interconnection with Desert 13 Southwest and California utilities, which will be discussed 14 in more detail by Mr. Tucker, Utah Power has been restricted 15 to short-term nonfirm sales.
16 QUESTION 17 Please discuss Pacific Power's current California 18 market access capabilities and constraints.
19 ANSWER 20 Pacific Power is currently interconnected to the
- 21 California market through its interconnection with the 22 Pacific Northwest-Pacific Southwest Intertie (the Intertie) 23 at Malin and its direct 115 kV interconnection with Pacific 24 Gas & Electric Company. Pacific Power's current California 25 market access via the Intertie consists of its rights under 26 BPA's NTIAP and a 300 MW firm interconnection right for
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7 1 sales to California utilities at the Malin substation on the 2 Intertie.
3 QUESTION 4 Please discuss the relevant aspet"." of BPA's NTIAP 5 as it applies to Pacific Power and other Northwest utili-6 ties.
7 ANSWER 8 As we understand, current access rights to the 9 California market through the A.C. and D.C. portions of the 10 Intertie is owned or controlled as follows:
11 12 Intertie Rights (MW) 13 14 A.C. D.C.
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TOTAL %
.5 16 BPA 2100 2000 4100 78.85 17 PGE 800 0 800 15.38 18 PP&L 300 0 300 5.77 19 i 20 3200 2000 5200 100.00 21 22 BPA's NTIAP sets forth the terms under which BPA 23 will grant Northwest generating utilities non-assured (non-24 firm) and assured (firm) access to the federally-owned 25 portion of the Intertie for sales to California utilities at 26 tho' California-Oregon border (COB) on the A.C. portion of 27 the Intertie or the Nevada-Oregon border (NOB) on tae D.C.
28 portion of the Intertie. With certain provisions to protect 29 its own marketing and rovenue.needs, BPA has structured the 30 NTIAP to provide (1) limited firm access to Northwest 31 generating utilities based on BPA's determination of such
R. M. Bouchar '
c 1 utility's regional firm energy surplus and (2) nonfirm ;
2 access for Northwest and, in some cases, other utilities 3 based on Intertie loading conditions or California' market 4 requirements.
5 QUESTION 6 Wh.at use has Pacific Power made of the Intertie?
7 ANSWER 8 -Ar shown in Schedule 35, during the period 1982 to 9 1986, Pacific Power's use of the Intertie has averaged 10 approximately 9 percent of the total Intertie use. Prior to 11 July 1986, most of Pacific Power's Intertie access was under 12 the non-assured (non-firm) provisions of the NTIAP. After 13 July 1986, whcn Pacific Power established its interconnec-14 tion rights with California utilities, less than half cf 15 Pacific Power's Intertie use was under the provisions if the 16 NTIAP. Also shown in Schedule 35 is the Intertie usage of 17 other parties.
18 QUESTION 19 Is Pacific Power treated the same as other 20 Northwest utilities under the NTIAP?
21 ANSWER "
22 No. Scific Power is treated differently in two 23 respects: First, BPA has determined that utilities seeking 24 Intertie access must first use their own access rights ,
i 25 before receiving access under the NTIA?. Second, since a 26 portion of Pacific Power's load responsibility is not within l 4
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f R. M. Bouchsr . .
P 1 would result from the merged company's more diverse 2 resources, as I have previously described. It is expected, !
3 however, that BPA will implement its Long-Term Intertie 4 Access Policy (LTIAP) prior to the time that the merger is 5 approved. A copy of the LTIAP is included in the work-6 papers.
7 QUESTION t
8 Please describe how BPA's proposed LTIAP will 9 affect the merged company's use of the Intertie.
10 ANSWER 11 While BPA's final LTIAP could be substantially 12 changed from the current proposal, there are several aspects 13 that may significantly affect the merged company's Intertie 14 use: First, BPA has in numerous ways underscored a "BPA 15 first" philosophy, making any access less certain than under 16 the NTIAP. Second, BPA has given an access advantage to
- 17 the owners of Northwest regional hydroelectric facilities 18 under certain conditions by limiting a utility's access 19 under those conditions to such utility's pro-rata share of 20 the Northwest's total regional hydroelectric capability. As 21 shown in Schedule 36, the merged company's share of the 22 Northwest hydroelectric facilities is only 3.9%, which 23 severely discriminates against primarily thermal-based +
24 systems such as the merged company. Third, it is not clear i
25 how BPA may condition access for those utilities with 26 alternative transmission paths to some Southwest markets.
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R. M. Bouchor .
1 the Northwest region as defined in the NTIAP, BPA's 2 determination of Pacific Power's regional firm energy 3 surplus is reduced, thereby limiting Pacific Power's firm 4 access capability under the NTIAP.
5 QUESTION 6 Does BPA's treatment of Pacific Power under the 7 NTIAP have an adverse impact on Pacific Power's Intertie 8 use?
9 ANSWER 10 Yes. Not all California utility Intertie owners 11 have rights on both the A.C. and D.C. portions of the 12 Intertie. Pacific Power is therefore unable to access some 13 important California markets over the D.C. portion of the 14 Intertie until its A.C. Intertie rights are fully utilized.
15 Additionally, BPA's treatment of Pacific Power's firm energy 16 surplus under the NTIAP effectively prevents Pacific Power 17 from using the NTIAP to market what BPA has determined to be 18 its Northwest regional firm energy surplus.
19 QUESTION 20 How will BPA's NTIAP affect the merged company's 21 use of the Intertie?
22 ANSWER 23 Under certain NTIAP conditions where the Intertie 24 is not fully loaded, the merged company may se able to 25 utilize the Intertie for nonfirm sales to a greater extent 26 than Pacific Power currently can alone. Such greater use
R.-M..Bouchar
- a 1 QUESTION 2 How will the proposed LTIAP affect other Northwest 3 utilities?
4 ANSWER 5 BPA is proposing to make up to 800 MW of firm-6 Intertie access available to Northwest regional utilities 7 which will increase their firm access capabilities.
8 Included in the 800 MW is access for Montana Power Company 9 under section 9 (i) (3) of the Regional Act and provisions for 10 seasonal exchanges with California utilities.
11 12
SUMMARY
13 QUESTION 14 Please briefly summarize your testimony regarding 15 the power supply benefits of the merged system.
16 ANSWER 17 The many and significant diversities that exist 18 between Utah Power's and Pacific Power'r systems provide a 19 unique opportunity to realize substantial economic benefits 20 for our respective customers and shareholders. I believe 21 that the merger will also be beneficial to our respective 22 employees working in the many power supply related areas, in 23 that they will increase the!.r knowledge of different utility 24 system planning and operating procedures and will have 25 opportunities to practice newly acquired skills. The merger 26 will permit us to remain competitive in wholesale power
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R.,M.'BouchOr -
1 markets. ,
2 While our ultimate success in achieving some of ,
3 the envisioned benefits I have discussed will be affected by 4 factors beyond either company's direct control, such as the 5 factors that have given rise to the current "buyer's 6 market," other benefits can be realized regardless of 7 uncontrollable circumstances.
8 The benefits I have described will contribute 9 substantially to the savings and efficiencies from the 10 merger and the retail price reduction plan described in 11 Mr. Rbed's testimony. Experience gained through actually 12 operating as a merged company and the completion of more 13 rigorous system studies will allow us to quantify these -
14 benefits better as part of that plan. I believe that the 15 likely results of detailed studies and experience will be 16 that some anticipated benefits will not be as great as we 17 now believe, while others will be greater. I also believe 18 that other areas of benefit not currently anvitiened will 19 emerge.
20 QUESTION 21 .Gieen the power supply benefits you have 22 described, would you characterize the merger as desirable or i
23 essential?
24 ANSWER 25 Both. The merger is desirable in order to achieve 26 the power supply efficiencies I have described, but also
o e
- - e R. M. Boucher 1 essential to remain competitive in today's electric business 2 environment. As Mr. Topham testified, we are competing 3 with both traditional rivals and new technologies and 4 suppliers in our retail markets. We face stiffer competi-B tion in wholesale markets, as well, from other utilities and 6 federal agencies. Some of these. entities have lower 7 production costs than either Utah Power or Pacific Power 8 standing alone, and control transmission access to wholesale 9 markets. The efficiencies and improved market access that 10 we can achieve through the merger afford us the opportunity 11 to compete more effectively in both retail and .:holesale 12 markets, which will benefit our combined customers.
13 OUESTION 14 Does this conclude your testimony?
15 ANSWER 16 Yes.
17 18 19 20 21
- 22 23 24 25 26 GMG#2\Boucher2.620 .
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UNITED STATES OF AMERICA f
BEFORE THE FEDERAL EFERGY RICULATORY COMMIS$10N STATE OF ORECON ) Docket No. 1C88-2-00
- C0JNTY OF MULTNOMAH) )
Affidavit of Rodney M. Boucher !
i Rodney M. Boucher, being first duly sworn, on oath states that he is Vt:e President of Pacific Power & Light Coinpany , whose Profiled Testimony was served on all parties to the above-referenced proceeding. Rodney M.
Soucher 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.
MPL i
/ /* R cher Subscribed and sworn to before me this 3h_ Day of January,1988.
/ - b d Notary hi,tilic~
~'
My consission expires June 9.1990.
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