ML20153F717
| ML20153F717 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 01/08/1988 |
| From: | Reed F UTAH POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML20153F598 | List: |
| References | |
| NUDOCS 8805110030 | |
| Download: ML20153F717 (26) | |
Text
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)s Exhibit B g.-
UNITED STATES OF AMERICA
.BEFORE THE NUCLEAR REGULATORY COMMISSION IN THE MATTER OF THE-
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EXHIBIT B to Facility APPLICATION OF PACIFICORP
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Operating License No.-NPF-1 FOR CONSENT TO THE TRANSFER )-
Indemnity Agreement No. B-78 OF LICENSES
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4 x
PREFILED TESTIMONY OF FREDRIC D.
REED t
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8805110030. 880509-PDR ADOCK 05000344 T
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Exhibit No. 3 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. EC38-2-000 s
PC/UP&L Merging Corp.
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PREFILED TESTIMONY OF FREDRIC D. REED ON BEHALF OF UTAH POWER & LIGHT COMPANY, PACIFICORP, AND PC/UP&L MERGING CORP.
4 January 8, 3988 1
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SUMMARY
OF TESTIMONY OF FRSDRIC D.
REED ISSUES ADDRESSED 1.
Description of PacifiCorp.
2.
Expected post-merger corporate organization.
3.
'Quantification of expected effect of the merger on costs of UP&L and PP&L.-
.4.
Financial effects of the merger.
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5.
Effect of the merger on prices of UP&L-and PP&L.
1 6.
Effect of the merger on meaningful regulation by state commissions.
7.
Production and use of co'al by the merged companies.
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,y CONTENT AND CONCLUSIONS Description of PacifiCoro In 1984, the name Pacific Power & Light Company was changed to.Pacificorp to reflect the corporation's diversification in electric service, telecommunications (Pacific Telecom, Inc.) and mining (NERCO, Inc.).
PacifiCorp continues to conduct its electric business under the name "Pacific Power & Light Company."
During 1986, Pacificorp had earnings of approximately $230 million on revenues of approximately $2 billion.
During 1986, about S2 percent of PacifiCorp's operating revenues were derived 6
from Pacific Power, 24 percent from NERCO and 24 percent from Pacific Telecom.
In 1986, PacifiCorp entered a fourth line of business -- financial services.
Pacific Power has more than 670,000 customers in six states, covering a 63,000 square mile service territory.
Service is provided to more than 240 communities through three regional offices and 54 district offices.
Each region is managed by a
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vice president who has primary responsibility for establishing pricing and customer relations policies and for controlling operating costs.
The organizational structure and commitment to
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decentralized management will not change as a result of the merger.
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- e 3, Under average water conditions, 66 percent of Pacific Power's generation comes from thermal plants and 16 percent from 7
hydroelectric plants.
The balance is obtained through purchase.
Post-Mercer Orcaniization s
Following the merger, Utah Power & Light Company (Utah Power) will operate as a separate business unit of PacifiCorp and continue to do business under the name "Utah Power & Light Company."
Utah Power will have a separate board, a committee of the PacifiCorp Board of Directors, with delegated authority over annual constructior. budgets, purchase and disposition of utility property; personnel policies and compensation, research and development and policies and practices concerning customers.
Three persons who are members of the Board of Directors of Utah i
Power immediately prior to the effective date of tue merger and are presently residing in the Utah Power service territory are expected to be elected to the Board of Directors of the merged corporation.
The headquarters of the Utah Power division of the merged corporation will remain in Salt Lake City.
Effect of the Mercer on Costs The substantial savings in net power costs are described in detail in the testimony of Mr. Boucher and Mr. Steinberg.
Savings in other areas such as auditing, data processing,
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4 inventories, insurance, legal, shareholder relations and power plant maintenance scheduling are expected to be even greater.
Consolidated opercating benefits for the period 1988 through 1992 are expected to total approximately $505 million.
Financial Effects The merger is expected to result in a reduction in external funding requirements from needs today, which are not substantial.
This is the result of anticipated reductions in construction
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requirements and in operating expenses.
The utility operations of the merged company are expected to generate sufficient a
internal funds to fund most ongoing construction requirements.
The merger is expected to produce a compsny that is at least as financially strong as the sum of its premerger parts and, therefore, bonds ratings should reflect that streng,.h.
Changes in bond ratings in either direction are not expected to be a significant factor in evaluating the economies of the merger.
In the near term, the merger will not affect the cost of capital because the embedded cost of capital will not taange.
Over the long term, it is expected that the cost of new securities will be lower than would be case without the merger.
Some dilution of common equity is expected upon the merger, but the effects will be transitory.
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-s-Effect on-Prices Prior to the merger, and in recognition of increased competition, Pacific Power had committed to not increasing its retail rates for the foreseeable future.
A' major merger that would yield operating efficiencies and allow a spreading of fixed costs over a larger customer base was a crucial element in the price stability policy.
In regard to Utah Power, Pacifico'rp is committed to an immediate two percent retail price reduction after the merger and a total price reduction of at least five to ten percent during the next four years.
Utah Power's firm wholesale customers will enjoy price reductions from the power supply related merger benefits reflected in the fuel adjustment clause.
Initially, retail and wholesale prices will be derived from a separate cost of service study for the operations of each division.
Developing prices on a single-utility basis would necessitate price increases for Pacific Power's existing customers, an unacceptable result.
The merged company cannot at this time propose detailed principles for intercompany allocations, especially with respect to the common benefits l
expected to flow from the merger.
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Effectiveness of Reculation.
The operation of two divisions in seven states _will not undermine the effectiveness of regulation or increase the
. potential for misallocation of costs.
PacifiCorp and its regulators already successfully deal with electric operations in six states and nonelectric operations that account for nearly
- half of total income.
The merger vill add a seventh retail jurisdiction -- Utah -- and substantially reduce the relative contribution of nonelectric operations.
Except for the proposed corporate miqration of PacifiCorp from Maine to Oregon, which will result in this Commission no longer approving PacifiCorp's i
securities issuances,'the merger will not result in a reduction in the present regulatory authority of any commission.
In regard to the Utah Commission, it is inconceivable that the merged corporation would be inattentive to the concerns of a regulatory body overseeing well in excess of $500 million in revenues and
$1.5 billion of rate base.
The operations of PacifiCorp have been significantly diversified for approximately ten years.
During that time, f
Pacific Power has not had significant difficulties with the six state commissions that regulate it in regard to subsidization l
issues.
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4 7-gpal Issues No. substantial changes are anticipated in the way Utah Power and PacifiCorp, through its subsidiary, NERCO, Inc. produce coal.
No plans have been made to' transfer the ownership or operation of Utah Power's coal mines to NERCO.
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I Q.
Please state your name, business address and occupa-1 tion.
2 A.
My name is Fredric D.
Reed.
My business address is 3
4 920 SW Sixth Avenue, Portland, Oregon 97204.
I am a 5
Seni r Vice President of Pacific Power & Light Company 6
(Pacific Power or the Company).
7 Q.
Please summarize your education and prior employment, d
8 I graduated from Pennsylvania State University with a A.
9 Bachelor's Degree and Master's Degree in Business 10 Administration in 1961.
I was subsequently employed 11 in various positions in the railroad industry until 12 employed by Pacific Power in 1969 as Manager of g
Economic Analysis and Budgets.
I was elected Control-14 lec of the comp.nv in 1974 and a Vice President in,
1979. I assumed my present position in 1986.
15 Q.
What are your responsibilities as Senior Vice Presi-16 dent of Pacific Power?
77 A.
18 I am responsible for treasury functions, financial services, budgeting, financial analysis, financial 19 Planning, revenue requirements and information ser-20 vices.
21 I report to the President of the Company.
Q.
Have you previously testified in regulatory proceed-22 ings?
g A.
Yes, I have testified on numercus occasions in all six 24 25 states waere Pacific Power provides electric service.
Q.
What subjects will you address in your testimony?
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My testimony will cover the following subjects:
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(1)
A description of PacifiCorp and its sub-sidiaries.
3 4
(2)
A description of the expected post-merger 5
corporate organization.
6 (3)
A quantification of the expected'effect of 7
the merger on the costs of Utah Power and Pacific 8
Power.
9 (4)
A discussion of the financial effects of the 10 merger.
(5)
A discussion of the effect of the merger on u
12 prices of Utah Power and Pacific Power.
b 13 (6)
A discussion of the effect of the merger on 14 the effectiveness of state regulation.
15 (7)
A discussion of various issues related to 16 the production and use of~ coal by the merged company.
Q.
Are you sponsoring any exhibits?
77 A.
Yes.
I am sponsoring Exhibit No.
4, which consists of 18 Schedules 1,
2, 3 and 4.
Schedules 1 and 2 are from gg 20 Company records.
Schedules 3 and 4 were prepared un-33 der my direction and supervision.
PacifiCom 22 Q.
Please describe the operations of PacifiCorp.
23 24 PacifiCorp is a diversified electric utility, which A.
was originally formed in 1910 as "Pacific Power &
25 26 Light Company."
In 1986, PacifiCorp had earnings of 2
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approximately $230 million on revenues of approxi-2 mately $2 billion.
PacifiCorp has grown to be one of 3
the largest investor-owned electric utilities in the 4
Northwest, with more than 670,000 customers in six 5
states.
In 1984, the firm changed its name to 6
Pacificorp to reflect its diversification'and 7
broadened operations in electric service, telecom-8 munications and mining.
PacifiCorp continues to con-9 duct its: electric utility business under the name 10 "Pacific Power & Light Company."
11 Q.
Please describe the operations of PacifiCorp's prin-12 cipal subsidiaries.
73 A.
PacifiCorp is the owner of approximately 90 pe.rcent of 14 NERCO, Inc. and 87 percent of Pacific Telecom, Inc.
15 NERCO, Inc. is engaged in the mining of coal and pre-l clous metals and the exploration and development of 16 17 minerals, precious metals and oil and gas in several 18 regions of the United States and Canada.
Pacific 79 Telecom, Inc. provides local and long distance tele-20 phone and other communication services in Alaska and l
21 1 cal telephone service and access to the long dis-tance network in seven other Western states and 22 Wisconsin.
Pacific Telecom, Inc.'s long lines car-23 24 rier, Alascom, Inc., provides intrastate and inter-25 state long distance communications within Alaska and l
26 aetwaen Alaska and the rest of the world through 3-Page l
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satellite and terrestrial facilities.
During 1986, 2
about 52 percent of PacifiCorp's operating revenues 3
were derived from Pacific Power, while NERCO and 4
Pacific Telecom each contributed approximately 24 per-5 cent.
6 In 1986, Pacificorp entered a fourth line of 7
business--financial services.
PacifiCorp is the owner 8
of PacifiCorp Credit, Inc. and PacifiCorp Finance, 9
Inc.
PacifiCorp Credit is prirarily engaged in the 10 leasing of capital and business equipment and lending 11 against receivables and inventories.
PacifiCorp 12 Finance is engaged in providing equity investments in 13 leveraged lease transactions.
14 Schedule 1 of Exhibit No. 4 is a chart showing s
15 the entire family of PacifiCorp companies.
Schedule 2 16 f Exhibit No. 4 is a map showing the geographic scope 17 of their operations.
18 All four of PacifiCorp's major business segments 19 have separate management and boards of directors.
20 They operate as separate businesses ultimately 21 accountable to the Chairman and Chief Executive Of-22 ficer and President of PacifiCorp, the Corporate 23 Policy Group and the PacifiCorp Board of Directors and 24 shareholders.
i 25 Q.
Please describe Pacific Power's operations.
26 4
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Pacific Power provides electric service to more than
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2 240 communities through three regional offices and 54 3
district offices located throughout a 63,000 square 4
mile service territory.
The geographic distribution 5
f its retail electric operating revenues during 1986 was oregon--56 percent, Wyoming--21 percent, 6
7 Washington--14 percent, California--5 percent, Montana--3 percent, and Idaho--1 percent.
Pacific-8 Power's retail service territory is depicted on 9
10 Schedule 1 of Exhibit No.
2, attached to the testimony of Mr. Topham.
In addition, Pacific Power has sub-33 12 stantial wholesale cales, principally to California utilities.
During 1986, total electric revenues were i
13 14 approximately $1.1 billion, of which approximately
$128 million was derived from wholesale sales.
Under 15 16 average water conditions, approximately 66 percent of 77 PacifiCorp's energy requirements are supplied by 18 thermal plants and 16 percent by hydroelectric plants.
gg The balance of approximately 18 percent is obtained 20 under long-term purchase contracts (principally from hydroelectric facilities), interchange contracts and 21 22 ther purchase arrangements.
The company has now terminated all involvement in nuclear projects, except 23 f ra 2.5 percent interest in the Trojan facility 24 which has been in successful operation since 1976.
25 26 The Company also purchase substantial quantities of 5-Page
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firm capacity and nonfirm energy from the Bonneville 2
Power Administration (Bonneville).
3 Pacific Power employs approximately 4,100 of the_
4 total 10,600 people employed by Pacificorp.
5 Q.
How does Pacific Power respond to customer needs in-6 its large and diverse service territory?
7 A.
We have divided the Company's operations into three 8
regions.
Each region is managed by a vice president 9
who has principal responsibility for establishing 10 pricing and customer relations policies and for con-11 trolling operating costs.
Each region is in turn 12 divided into a number of districts, each of which has 13 a manager who is 2' 'orded substantial autonomy in 14 responding to local customer needs.
15 Q.
Will the merger changs Pacific Power's organizational 16 structur.e and commitment to decentralized management?
A.
No.
The Company believes decentralization is crucial 37 18 to understanding unique requirements of customers and 39 effectively responding to them.
20 Post-Mercer Orcanizatior!
21 Q.
Following the merger, how will the. present operationc 22 f Utah Power be integrated into PacifiCorp?
l 23 A.
Following the merger, Utah Power will operate as a 24 separate business unit of Pacificorp and continue to d
business under the name "Utah Power & Light Com-25 I
26 pany."
Like Pacific Power, Utah Power will have a l
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separata board and will be afforded the same benefits 2
and treatment as other business units in the family of 3
PacifiCorp companies.
Utah Power will play a key role 4
in defining PacifiCorp strategy through representation 5
n the Corporate Policy Group and PacifiCorp's Board.
6 The merger agreer. ant provides that three persons 7
who are members of the Board of Directors of Utah 8
Power immediately prior to the effective date of the 9
merger, and one person residing in the Utah Power ser-j.
10 vice territory, will be elected to the Boar'd of Direc-11 tors of the merged corporation.
Thereafter, the 12 merged corporation is to seek further representation 13 of qualified persons residing in the Utah Power ser-14 vice territory for its Board of Directors with the aim 15 f eventually having a prorata representation from 16 Utah Power's service territory.
7 The merger agreement also provides that the head-18 quarters of the Utah Power division of the merged cor-19 poration will be in Salt Lake City.
20 Q.
Y u indicated that a Utah Power "Board" would be 21 f rmed similar to the existing Pacific Power "Board."
3 How does the Pacific Power Board operate?
23 A.
The Pacific Power Board is technically a committee of 24 the PacifiCorp Board of Directors.
Its membership 25 consists of five persons who are members of the 26 PacifiCorp Board of Directors and four others.
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3 Pccific Power Board has been delegated authority over annual con'struction budgets, purchase and disposition 2
3 f utility property, personnel policies and conpensa-
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4 tion, research and development and policies and prac-5 tices concerning customers.
The PacifiCorp Board of 6
Directors has retained direct responsibility for mat-7 ters that affect the corporation as a whole, such as 8
auditing and financing.
9 In order to insure appropriate coordination of 10 the activities of the two electric divisions, it is 11 expected'that the President of the Utah Power division 12 will be a member of the Pacific Power Board and that 13 the President of Pacific Power will be a member of the 34 Utah Power Board.
15 Effect on Costs 16 Q.
How will the merger affect the operating costs of Utah Povar and Pacific Power?
77 18 The merger will result in a significant reduction in A.
39 operating costs.
20 Q.
In general, why are cost savings expected?
A.
Mr. Boucher and Mr. Steinberg will testify in detail 23 22 concerning expected savings in net power costs.
In 23 general, these savings can be expected for the follow-24 ing reasons:
25 (1) the merger will provide diverse access to ex-26 isting and new whclesale markets, facilitating the 8
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3 profitable disposition of available power supplies; 2
(2) the merger will enhance the ability of both 3
companies, through expanded interconnectic.., to take 4
greater advantage of low-cost power supplies which-are 5
available in the short term, but which likely will not 6
be available in the long tera absent an early commit-7 ment to those power supplies; 8
(3) because Pacific Power is a winter-peaking 9
utility and Utah Power is a summer-peaking utility, 10 there are sube antial b'enefits to be gained from the diversity of the systems; gg 32 (4) the merger will reduce system operating costs
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through the integrated economic dispatch of genera-33 tion; and g4
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(5) the merger will reduce system raserve 15 16 requirements and improve system reliability because of 77 expanded transmission interconnections.
18 Whilu the expected savings in net power costs are gg substantial, we expect total savings in other areas to 20 be even greater.
23 Q.
Have expected cost savings been quantified?
A.
Yes.
In advance of the merger PacifiCorp and Utah y
e Power had to rely on published financial informatic and had limfted time and ability to precisely estimate 2
potential merger savings.
Since then, representatives of the two companies have been able to exchange a
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great deal of information, and there has been an ongo-2 ing effort to better quantify expected merger savings.
3 Mr. Steinberg's testimony describes the results of ef-4 forts by Utah Power and Pacific Power representatives 5
to quantify power supply savings.
In addition, we 6
have had an opportunity to further study the other 7
major areas of potential benefit resulting from a con-8 solidation of operations.
Schedule 3 of Exhibit No.
9 4, which was prepared under my direction and supervi-10 sion, sets forth the most current estimates of con-gg solidated operating benefits for the period 1988 32 through 1992.
While these estimates reflect an in-3 13 creasing understanding of benefits available from the 14 merger, I eweet a continuing process of refinement as 15 we gain experience as a merged company and understand 16 additional opportunities for increase.d efficiencies.
77 Q.
What is the source of these savings that are expected?
A.
Even though it is contemplated that Utah Power and 18 19 Pacific Power vill operate as separate divisions, a 20 consolidation of certain duplicative functions or programs within functions, such as auditing, data 21 g
processing, inventories, insurance, leaal, shareholder relati ns and power plant maintenance scheduling, 23 24 should produce substantial savings after the merger is 25 fully implemented.
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Q.
Can you provide examples of how these savings could be 2
achieved?
3 A.
Yes.
In regard to casualty and property insurance, 4
for example, the incremental cost of adding the elec-5 tric operations of Utah Power to Pacific Power's ex-6 isting policies will be approximately $5 millioti an-7 nua31y, as compared to the v13 million Utah Power now g
pays for generally comparable coverage.
9 In the group welfare plan benefits area, approxi-10 mately $1 million in administrative costs can be saved' 31 annually because it appears that Pacific can make Lse 12 of the same mutual insurance companies use by Utah b
13 Power to administer its claims.
14 Q.
Will there be a reduction in employment levels as a 15 result of the consolidation of functions?
A.
Yes.
While no layoffs are expected as a result of the 16 17 morger, we expect to achieve a total force reduction 18 of at least 940 positions over the next five years, as 39 employee attrition occurs, resulting in an annual 20 savings of approximately $53 million.
21 Financial EffecE' 22 Q.
How will the merger affect external financing require-23 ments?
A.
The present external financing needs of both Utah 24 25 Power and Pacific Power are not substantial.
The 26 merger is expected to result in a further reduction in 11 -
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cxternal funding requirements.
This is the result of 2
anticipated reductions in construction requirements 3
for the merged companies and the anticipated reduction f
Perating expense due to consolidation and combina-4 5
tion of certain administretive functions.
6 The net effect of the reduced cash needs and im-7 proved operational results will be an improvement in 8
cash flow measures, particularly the ratio of cash 9
Coverage of Construction Expense.
The utility opera-10 tions of PacifiCorp Oregon are expected to generate 33 sufficient internal funds to fund nearly all ongoing 12 construction requirements.
Future external financings 33 are expected to be primarily for the purpose of i
34 recapitalization or refinancing existing security,is-15 sues.
This will allow Pacificorp oregon opportunities 16 to maintain and improve its capital structure by ex-37 ploiting capital market conditions to reduce the total 18 cost of capital and improve financial statistics.,
19 Q.
What dividend policies and payout ratios are expected 20 for the merged company?
A.
Historically, PacifiCorp has maint ined dividend 21 22 policies that are characterized by stability and cur-23 rent needc: of investors.
As shown on Schedule 4 of 24 Exhibit No.
4, on average payout ratios have been near 25 70 percent of uarnings fo'; Pacificorp.
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Pacificorp's policy with regard to its common 2
dividend has been to maintain a dividend payout ratio that is approximately equal to the average for the 3
4 diversified industries in which it is engaged.
In-creases in the common dividend were declared when sub-5 6
'stantial earnings growth justified an increase.- As 7
PacifiCorp's business activities have become more divercified, its dividend payout ratio has declined 8
9 slightly, reflecting the growth of its nonelectric 10 utility earnings and the lower payout ratios associ-ated with those in'dustries.
gg 32 Immediately after the merger, PacifiCorp expects t
maintain its current $2.52 annual divjdend.
i 13 14 Prospectively, the dividend payout ratio will reflect 15 the blended payout ratios of the various operating 16 segments.
Post merger, approximately 70-80 percent of PacifiCorp Oregon's earnings will be from electric 17 18 utility operations, hence the payout ratio is expected gg to be close to the electric utility industry average.
Q.
Please summarize such information as may now exist 20 concerning the bond rating effects of the merger.
21 A.
Absent a merger, it is expected that there would be no 3
material change in the current bond ratings of 23 PacifiCorp or Utah Power.
Bond ratings are the 3
Product of a reasoned, but subjective determination by 25 rating agencies.
Therefore, no "hard" information on 26 Page 13
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future bond ratings is available.
The prospect of a 2
merger creates uncertainty for rating agencies until 3
they are able to determine whether regulators will in-4 pose burdensome preconditions on the merger and until 5
they determine whether the companies are successful in 6
achieving their statcd intentions.
We expect the 7
merger will produce a company that is at least as 8
financially strong as the sum of its premerger parts, 9
and that bond ratings will reflect that strength.
10 Mr. colby's testimony describes projected results of f
11 operations for the merged electric operations,. We do 32 not expect changes in bond ratings in either directiert i
13 to be a significant factor in evaluating the econ' mica o
14 of the merger.
15 Q.
What effect on cost of capital will the merger have, 16 particularly in light of the diversified nature of 17 Pacificorp?
18 A.
The merged company will have a single capital struc-g9 ture and one set of other financial measures.
In the 20 near term, the' merger will not affect the cost of l
21 capital.
This is because the embedded cost of capital 22 will not change.
Over the long term, it is expccted 23 that the cost of new securities will be lower than 24 would be the case without the merger.
25 of course, pursuant to state laws governing pub-26 lic utilities, funds raised through the issuance of Page g,
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4-7 debt, preferred or common equity by PacifiCorp Oregon 2
can only be used.for utility purposes.
Also, it 3
should be noted that historically PacifiCorp has filed 4
rate case applications that incorporate a comparable 5
e mpany analysis relative to the cost of common equity 6
that effectively excludes any effect caused by its 7
diversified operations.
This practice is not expected 8
to change.
9 It is expected that there will be some ailution 10 of common equity upon merger, but the effects will be gg
' transitory and over time will be managed to the bene-12 fit of shareholders, customers and the company.
73 Pricina Issqg.g 14 Q.
What effect will the merger have on the wholesale and 15 retail prices paid by the customers of Pacific Power 16 and Utah Power?
A.
In recognition of the greatly-increased competition we 77 18 face, prior to this merger proposal, Pacific Power 79 committed to not increasing its retail prices for the 20 f res.seable future.
Pacific Power intends to maintain 21 stable prices as a result of our concerted efforts to 22 control costs, encourage economic development in its 23 service territory and aggressively pursue sales and 24 marketing programs.
A major merger that would yield 25 perating efficiencies and allow us to spread fixed 26 d~
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costs over a larger customer base is a crucial element 2
in the price s!. ability strategy.
3 In regard to Utah Power, PacifiCorp is committed 4
to an immediate two percent retail price reduction 5
after the merger and a total price reduction o* at 6
least five to ten percent during the next four years.
7 Mr. Colbly's testimony discusses the effect on Utah 8
Power's firm wholesale customers' prices which will 9
result from the power supply related merger benefits.
10 As such, as merger savings are captured, Utah Power's gg firm wholesale tariffs will be adjusted accordingly.
12 Q.
Will the Pacific Power and Utah Power divisions charge i
g3 the same prices?
74 A.
No.
At least initially, retail and wholesale prices 15 will be derived from the separate costs of service for 16 the operations of each electric division.
The current t
77 utility assets of Pacific Power and Utah Power will be l
gg assigned to the two divisions, respectively.
gg Q.
In light of Mr. Boucher's testimony that generation 20 and transmission facilities will be operated on a 21 "single utility" basis, would it not be more appropri-22 ate to establish prices for the two divielons on a 23 single-system basis?
24 A.
No.
While that approach might be more a'ppealing from 25 a theoretical perspective, it would produce an un-26 16 -
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g reasonable result and would not permit us to proceed i
2 with the merger.
3 Q.
Please explain.
B A.
Largely as a result of Pacific Power's' access to rela-4 i
5 tively low-cost hydroelectric. generation in the 6
Pacific Northwest, Pacific Power's generating costs 7
are significantly lower than Utah Power's.
At least 8
in the near term, developing prices on a single-
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9 utility basis would necessitate price increases for 10 Pacific Power's existing customers--something we will gg not do.
It would appear unreasonable in any event to i
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' Pursue a policy that would cause the merger to in-3 33 crease prices for some 60 percent of the customers of f
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14 the merged company.
Utah Power's customers will enjoy l
l 15 Price reductions as a result of the merger.
They will 16 not do so at the expense of Pacific Power's customers, j
77 Q.
How long do you plan to establish prices on a separate division basis?
18 A.
The merger itself will produce some convergence of the 39 5
20 Prices of the two divisions.
Mr. Steinberg's studies l
21 suggest additional convergence with the passage of time.
We will monitor the situation and likely f
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23 Propose a change in methodology at such time as doing s
will not materially affect the customers of Pacific 24 l
25 Power or the shareholders of the merged corporation, j
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Q.
How is it proposed that the common benefits that are I
2 expected to flow from the merger will be allocated 3
between the customers of Pacific Power _and Utah Power?
4 A.
Interjurisdictional and intercompany allocations are
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5 among the most complex and controversial areas of 6
utility regulation.
We are not now proposing detailed l
7 principles for intercompany allocations.
We would not-8 wish to propose allocation methods before we have an 9
-opportunity to better understand how the merged firm 10 vill actually operate and until we have an opportunity 13 to consul,t at length with Utah Power's management, 12 this commission, and the seven state regulatory com-g3 missions who have a vital interest in this subject.
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g4 W'e are committed to finding solutions to these alloca-15 tion issues that are fair, consistent with sound i
16 economic and regulatory principles and which will help 1,7 make prices as competitive as possible.
An audit path 18 will be maintained permitting the evaluation of costs I
19 and benefits associated with benefits relative to the s
i 2J Proposed merger.
l 21 Q.
can this. commission properly evaluate the merger I
22 without knowing precisely how cost savings will be al-23 located?
24 A.
Yes.
This commission and seven state commissions, not s
25 the company, will be the ultimate judge as to which 4
26 all cation me:hodologies are reasonable.
If either 18 -
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g Utah Power or Pacific Power-were to propose un-2 reasonable allocation methods in future regulatory 3
proceedings, it is the Pacificorp stockholder, not utility customers,'ho would be at risk.
w 4
5 Furthermore, it should be noted that while inter-6 jurisdictional and interclass allocations will prove 7
to be complex, it may well be that any number of g
potential reasonable allocation methods would produce 9
generally the same result.
This is not to say that 10 allocation is not an important issue, but rather that gg the issue of how benefits will be allocated should not 32 be permitted to overshadow the fact that there will be 13 substantial benefits to all customers independent of 34 what particular allocation methodology is adopted.
In 15 the future, I believe we will develop, on a case-by-16 case basis, allocation methods which are a combination of various indices that best reflect the particular 17 18 e st or revenue element being dealt with.
- However, 19 aven if one were to assume that only one index were 20 used to allocate all cost savings and new revenues, l
21 the outcome may not be materially different.
It is 22 interesting to note, for example, that if one combines 23 the operations of Pacific Power and Utah Power, Utah 24 Power accounts for approximately 41.3 percent of coin-25 cidental peak, 42,0 percent of total energy genera-26 19 -
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a o,.
/
tion, 41.5 percent of megawatt hour sales, 41.9 per-g 2
cent of custome.rs and 43.0 percent of assets.
3 While I hasten to add that I am not suggesting 4
that the above measures are the ones we necessarily 5
intend to use for net merger benefit allocation pur-3 poses, they do suggest that, between the two com-
_7 panies, various indices track each.other quite closely 8
and differences in allocation methods may not produce 9
significantly different outcomes.
10 Q.
Will the operation of the two divisions in seven gg stateu undermine the effectiveness of regulation *or p
increase the potential for misallocation of cc.,sts?
A.
No.
PacifiCorp and its regulators already successful-a 13 14 ly deal with electric operations in six states and 4
15 n nelectric operations that account for nearly half of total income.
The merger will add a seventh retail 16 77 jurisdiction--Utah--and substantially reduce the rela-18 tive significance of nonelectric operations.
g9 Except for the proposed corporate migration of 20 Pacificorp from Maine to Oregon, which will result in this Commission no longer approving PacifiCorp 21 22 securities issuances, che merger will not result in a 23 reduction in the present regulatory authority of any e
i 24 commission.
In regard to the Utah Commission, it is i
25 inconceivable that the merged corporation would be in-26 attontive to the concerns of a regulatory body over-20 -
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l l
.y o,.
, +
- J U
g seeing well in acess of $500 million in revenues and
$1.5 billion of rate base.
l 2
3 The operations of Pacificorp have been sig-
'nificantly diversified for approximately ten years.
4 5
During that time, Pacific Power has not had sig-nificant difficulties with tho'six state commissions 6
7
'that regulate it in regard to subsidization issues, j-8 our regulators have had access to all corporate 9
records necessary to confirm that costs have been ap-10 Propriately accounted for and allocated.
I have no gg reason to expect that the merger will change those circumstances.
12 33 Q.
Are there differences in the manner in which Utah g4 Power and Pacific Power acccunt for wholesale costs 4
15 and revenues for retail ratemaking purposes?
1 A.
Yes.
Utah Power maintains a separate FERC jurisdic-16 l
17 tional account to which it allocates rate base, as l
18 well E.s related expenses and revenues associated with wholesale sales.
In Utah, expenses and revenues asso-79 i
20 ciated with nonfirm sales for resale are generally ac-21 counted for in a retail Energy Balancing Account, 22 t gather with other power costs.
. Pacific Power does not treat wholesale sales as a 23 j
g separate jurisdiction for allocatien purposes and does n t maintain an Energy Balancing Account or other fuel 25 cost adjustment mechanism.
Instead, costs and i
26 I
21 -
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4 t
L_
1 I'
- g' x
",3 m
- 4 ;, '
j revenues associated with sales for resale are allo-
--2 cated to retail jurisdictions.
Firm wholesale tariff 3
sales are allocated to-the state jurisdiction where 4
ths sale is made.
Firm wholesale cont.7act sales and 5
n nfirm sales revenues are allocated to retail juris-6 dictions in the same manner as production expense.
Coal Issues 7
8 Q.
Both Utah Power and PacifiCorp, through its subsidiary
~
9 NERCO, Inc., are major western coal producers.
What 10
- effect will the merger have on coal production of the f
gg two companies?
A.
No substantial changes are anticipated.
Utah Power 12
?
g3 operates several mine-mouth generating plants.
Sub-i t
d g4 stituting fuel for those plants from off-site does not appear' feasible or desirable.
Mr. steinberg's studies i
15 i
i 16 suggest that, if anything, the merger will result in 17 increased production at Utah Power plants and mines I
because of enhanced wholesale power sales op-l 18 portunities.
f
. gg Q.
Subsequent to the merger, will the ownership or opera-j-
20 21 tion of Utah Power's coal mines be transferred to
[
l 22 NERCO, Inc.?-
j i
l A.
No such plans have been made.
NERCO, Inc. is one of
}
23 24 the largest coal companies in the United States with i
25 substantial expertise and a record of low-cost produc-i l
tion.
However, the bulk of its experience is with
[
26 i
22 -
i Page l
l
o g
open-pit mining.
We will explore the.i.ssue of whether 2
there is en appropriate role for NERCO, Inc. in regard to Utah Power's mines.
We would only involve NERCO, 3
4 Inc. in Utah Power's mining operations if doing so ap-5 Pears to be the best and lowest-cost alternative.
Any 6
material change would, of course, be subject to 7
regulatory review.
8 Q.
Does this conclude your direct testimony?
9 A.
Yes.
10 11 12 g3 14 15 16 17 18 19 i
20 21 22 23 24 25 26 23 -
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9L e,*
.g UNITED STATES OF AMERICA BEFORE THE 2
FEDERAL ENERGY REGULATORY COMMISSION 3
4 Utah Power & Light Company
)
Docket No. EC88-2-000 PacifiCorp
)
5 PC/UP&L Merging Corp.
)
Affidavit Adopting
)s Prefiled Testimony of 6
)
Fredric D. Reed 7
g GTATE OF OREGON
)
) ss.
9 County of Multnonah )
10 Fredric D. Reed, being sworn, on oath says that he is the Fredric D. Reed wh9se Prefiled Testimony in the above-13 entitled proceeding accompanies this Affidavit.
12 Fredric D. Reed further states that such Prefiled Testimony is a true and accurate statement of his answers to the 13 questions.therein, that said answers are true and correct to the best of his knowledge, information and belief and that he does J4 adopt those answers as his sworn testimony in this proceeding.
15 F
16 Fredric D.
Reed 17 gg SUBSCRIBED AND SWORN to before me the undersigned Notary'Public this ses day of January, 1988.
19 20 M% - - - /1'bA JM tary Public'for Oregon 21 y commission Expires: __06-09-90 22 f
23 24 l
25 26 pagg - AFFIDAVIT ADOPTING PREFILED TESTIMONY OF FRID3IC D. REED 1
i
_. _ _