IN THE Cl.£K SUPREME COU~T OF VIRGINIA'

ffDI? ............... ~~ )

SUPREME COURT OF VIRGINIA

AT RICHMOND

RECORD NOS. 911318, 911319, 911320 (S.C.C. Case No. PUE900023)

VIRGINIA COMMITTEE FOR FAIR UTILITY RATES, JEAN ANN FOX

AND THE DIVISION OF CONSUMER COUNSEL OF THE OFFICE OF THE ATTORNEY GENERAL,

Appellants,

v.

VIRGINIA ELECTRIC AND POWER COMPANY, AND THE STATE CORPORATION COMMISSION OF VIRGINIA,

Appellees.

SUPPLEMENTAL APPENDIX OF VIRGINIA ELECTRIC AND POWER COMPANY

This Supplemental Appendix contains unpublished authorities cited in the Brief of Appellee Virginia Electric and Power Company.

November 25, 1991

Evans B. Brasfield Richard D. Gary Hunton ' Williams Riverfront Plaza-East Tower 951 E. Byrd Street Richmond, VA 23219-4074 (804) 788-8200

Charles K. Trible Kendrick R. Riggs virginia Electric and Power company P. o. Box 26666 Richmond, VA 23261 (804) 771-3000

counsel for Appellee Virginia Electric and Power company

CONTENTS

Authority Supplement

Application of Appalachian Power Company, Case No. PUE860015, Report of Glenn P. Richardson, Hearing Examiner (February 4, 1987) A

Application of Virginia Electric and Power Company, case No. PUE880014, Report of Glenn P. Richardson, Hearing Examiner (Nov. 10, 1988) B

Portions of Rules Governing Utility Rate Increase Applications (adopted by State Corporation Commission in Commonwealth of Virginia at the Relation of the state Corporation Commission. Ex Parte: In the matter of adopting revised rules governing Financial Operating Reviews and utility rate case filings, 1984 sec Ann. Rep. 375) c

Application of Virginia-American Water Company, Case No. PUE910028, Preliminary Order (May 10, 1991) D

Application of Southwestern Virginia Gas Company, Case No. PUE910024, Order Granting Motion (May 13, 1991) E

·"'

i

Supplement A

• SCC-62. ·I"r co~iROL CENTS -~n-~!J.. .... ...,'-'.

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~ I 0 2 I COMMONWEALTH OP VlllGINIA

STATE CORPOll.AnON COMMISSION

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APPLICA~liEer-t~ r-:-i 4: 12

APPALACHIAN POWER COMPANY

For an expedited increase in rates

CASE NO. POE860015

REPORT OF GLENN P. RICHARDSON, BEARING EXAMINER

February 4, 1987

HISTORY OF THE CASE

Pursuant to an order of the Commission dated April 30, 1986, this application for an expedited rate increase came on for hearing on September 4 and 5, 1986. A transcript of the hearing is filed with this- repqrt. Post-hearing briefs were filed by the parties on or before October 23, 1986.

Counsel appearing were John L. Walker, Jr., Esquire, and B. -Allen Glover, Esquire, for Appalachian Power Company C"Apco")J James C. Dimitri, Esquire, and Anthony Gambardella, Esquire, for the Division of Consumer Counsel, Office of the Attorney General, A. c. Epps, Esquire, and Charles P. Midkiff, Esquire, for the Old Dominion Committee for Fair Utility Rates ("Committee•), Fielding L. Williams, Jr., Esquire, for Celanese Corporation' and Kenworth E. Lion, Jr., Esquire, for the Commission's Staff. Numerous letters opposing the increase were filed with the Clerk of the Commission.

Proof of public notice was received at the hearing as Exhibit A.

Apco's last general rate case was concluded by Commission order dated October 7, 1983, in Case No. POE830037. 1983 SCC Ann. Rep. 497. In that case, Apco was allowed to place rates into effect designed to produce approximately $29.9 million in additional gross annual revenues. The Commission found that Apco's cost of equity was between 15.0 and 16.0%, and authorized a 16.0% return on equity given the superior performance of Apco•s generating units during the test period. The increase was de­signed to produce an 11.67% return on rate base.

Apco•s application in this case, filed on March 14, 1986, seeks an expedited rate increase of $32,783,084, representing an increase in operating revenue of approximately 6%. The increase is designed to produce an 11.40% rate of return and is based on

the 16.0% return on equity authorized in Apco•s last general rate case. The proposed increase in base rates will be partially offset by a reduction of $11,978,897 in Apco•s fuel factor, on an annual basis, resulting in a net increase of $20,804,187. Apco filed proposed tariffs allocating the increase by an.equa1 per­centage (10.76%) across-the-board increase to the non-fuel por­tion of each customer class.

After reviewing the application, the Staff concluded that Apco•s proposed tariffs, which allocated the increase to each class on an equal percentage basis, did not comply with Rule II(3) of the Commission's Rules G9verning Utility Rate Increase Applications. Accordingly, Apco was directed to reallocate its proposed increase to each customer class in the same proportion as the increase allocated each class in Apco•s 1983 rate case. The Staff, for example, required Apco to allocate 8.14083% of the current increase to its small general service (SGS) schedule since 8.14083% of Apco•s 1983 rate increase was allocated to that schedule. Apco complied with the Staff's request by filing re­vised tariffs on March 31, 1986.

Motions to Dismiss the application were filed by the Attorney ·· General and the Commission's Staff on March 28 and March 31, 1986,

respectively. The motions claimed that Apco had experienced a substantial reduction in its cost of equity since its last rate case thereby preventing it from seeking expedited relief under Rule II. The Attorney General further argued the American Elec­tric Power (8 AEP•) operating companies, of which Apco is a member, are currently seeking FERC approval of an agreement to equalize each ~perating company's investment in extra-high voltage trans­mission facilities. Apco•s payments under the agreement, accord­ing to the Attorney General, should be investigated in the context of a general rate case, rather than an expedited proceeding.

On April 30, 1986, the Commission entered an order denying the Motions to Dismiss and awarding Apco interim rate relief of $29,370,412, for service rendered on and after May 1, 1986. The Commission determined that, while it was denying the Motions to Dismiss, it was concerned with Apco's currently authorized 16.0% return on equity. ~he Commission therefore allowed Apco•s cost of equity to be fully litigated in this case. The Commission further noted, in response to the Attorney General's motion, that the AEP Transmission Equalization Agreement had no revenue impact in this case.

PREBEARING MOTIONS

Apco•s application generated a virtual barrage of pre-hearing motions seeking to address a host of new issues in this expedited rate case. The first such motion was filed by the Committee on May 20, 1986, seeking authority to address four rate design issues. The Committee further requested that Apco's application be

2

converted to a general rate case if the rate design issues were found to be beyond the scope of an expedited rate case.

On June 18, 1986, I entered a Ruling authorizing the Com­mittee to present evidence on two rate design issues. First, the Committee was allowed to address the Staff's revenue allocation methodology requiring Apco to reallocate its proposed increase to each customer class in the same proportion as the increase allo­cated to each class in Apco•s 1983 rate case. Second, the Com­mittee was allowed to present evidence on whether the proposed rates were consistent with the rate design objectives approved in the 1983 rate case. On the other hand, I denied the Committee's request to challenge the underlying cost allocation methodologies of the rates because Rule II(3) appears to preclude such an inquiry in an expedited rate case. I also denied the Committee's request to convert the application to a general rate case because the Committee failed to demonstrate or even allege how circum­stances have so significantly changed since Apco's 1983 rate case to warrant a complete realignment of Apco's rates.

The next dispute arose on July 7, 1986, when the Attorney General filed a motion requesting leave to present evidence on Apco's test year capacity equalization charges incurred under the_ AEP Interconnection Agreement. In support of its request, the Attorney General claimed that Apco•s capacity equalization charges increased from $33.8 million in 1984 to $74.8 million during the test year. Given the magnitude of the increase, amounting to an increase exceeding 100%, the Attorney General sought to investi­gate Apco•s capacity equalization charges and propose a normali­zation adjustment, if warranted.

Apco filed a response to the Attorney General's motion on July 17, 1986, arguing that its capacity equalization charges are beyond the scope of an expedited rate case. Apco further argued that the Commission is preempted from examining its capacity charges under the •filed rate doctrine• recently reaffirmed by the o. s. Supreme Court in Nantahala Power and Light Co. v. Thornburg, 54 O.S.L.W. 4676, _ U.S. _, (June 17, 1986).

On July 22, 1986, I entered a Ruling granting the Attorney General leave to address Apco•s capacity equalization charges. I found the increase in charges between 1984 and the test year appeared to represent a •significant change in circumstances• requiring further investigation. I took under advisement Apco's federal preemption argument finding •[i]t would be premature to rule on Apco•s jurisdictional argument without having the benefit of all the facts relating to Apco's capacity equalization charges spread on the record.• July 22, 1986, Bearing Examiner's Ruling at p. 2.

The final area of dispute arose on July 29, 1986, when the Staff filed a letter advising the Commission that the Staff would present evidence on three new accounting issues: (1) a proposed

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adjustment to remove deferred taxes from rate base and capitali­zation, (2) a new cost rate to be assigned the investment tax credits (ITC) and a proposed interest synchronization adjustment on a portion of rate base supported by ITCJ and (3} an adjustment to eliminate the accrual of AFODC. Apco filed a Motion to Exclude the Staff's testimony on these issues on August a, 1986.

On August 22, 1986, I advised the parties that I was taking Apco's Motion to Exclude under advisement pending conclusion of the hearing. If granted, Apco•s motion would have excluded a major portion of the Staff's case. Due to this drastic effect, and the general advisory role of the Examiner in every case, I thought it inappropriate to rule on Apco•s motion prior to the hearing. The Staff's testimony was therefore admitted, subject to Apco•s exclusionary motion.

SCOPE OF AN EXPEDITED RATE CASE

As the numerous pre-hearing motions once again demonstrate, the permissible scope ~fan expedited rate case continues to be a hotly contested issue. I cannot recall a recent expedited case in which the nature~· scope and proper focus of this ·type of proceeding has been so seriously questioned or extensively argued­as it was in this case. It is therefore appropriate to discuss what I believe to be the proper scope of an expedited rate case prior to ruling on the motions and addressing the substantive issues raised in this case.

The history of the expedited rate case rules can be traced to the passage of House Joint Resolution No. 348 in 1979. 1979 Va. Acts, 1365. The resolution required the Commission to imple­ment a more efficient procedure for investigating the earnings of utilities on an annual basis. The express purpose of the resolu­tion was to promote gradual rate increases in an effort to avoid the •rate shock• associated with large, infrequent rate increases during periods of double-digit inflation.

The Commission was directed by the resolution to simplify its procedures and design a program to review utility earnings on an annual basis. The General Assembly further recognized that the Commission would be faced with a large number of such increases on an annual basis. In order to streamline the handling of the annual review, the resolution authorized the Commission to impose reasonable limits on the issues that could be raised in such cases. A utility, for example, could not request a rate increase exceeding increases in the cost of living. The resolution also authorized the Commission to sever major issues from the review, such as rate design, construction needs and load projections. Again, the express intent of the legislature was to impose reason­able limits on the issues raised by interested parties so that a large number of increases could be considered by the Commission on an annual basis.

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With regard to investor-owned electric utilities, the Com­mission initiated its Financial Operating Review ("FOR") procedure by a January 4, 1980 letter to the utilities from the Commission's General Counsel. The letter described the financial and ac­counting information each utility had to submit to be considered for expedited rate relief. Utilities were further advised that the Commission would not consider a change in a utility's rate design or its authorized return on equity under the FOR program. The letter's guidelines were continued in effect until August 31, 1982, when the Commission formally proposed rules designed to implement the resolution in Case No. POE820056, 1982 SCC Ann. Rep. 629.

The final rules, adopted on December 4, 1984, incorporated many of the limits previously set forth in the General Counsel's letter. Rule II(3), for example, provides that •[a]llocation methodologies and rate design objectives are determined by the Commission in general rate cases,• thereby precluding the exami­nation of major r~te design issues in a FOR. The rules also provided that a utility is prevented from requesting a change in the return on equity- authorized in its most recent general rate case. Thus, the necessity for reasonable limits in such cases was recognized by the General Assembly when passing the resolution, by the General Counsel's 1980 letter implementing the program, and the Commission's orders adopting the program in Ca~ No. POE820056 and revising the rules in Case No. POE850022. In short, everyone has recognized that if the program is to remain effective, reasonable limits must be imposed on case participants.

Although the program has been in effect for almost seven years, the permissible scope of such cases continues to stir heated debate. Apco takes the position that an expedited rate case is a limited issue rate vehicle that is fundamentally dif­ferent from a general rate case. In its view, an expedited rate case represents an alternative to a general rate case and is designed primarily to be a financial review of a utility's earnings using the ratemaking standards established in its most recent general rate case. An expedited rate case was never intended, according to Apco, to be a proceeding in which all or even most ratemaking issues could be reexamined and changed to the detriment of the utility. Accordingly, Apco argues that the accounting adjustments approved in its 1983 general rate case must be applied in this expedited case when evaluating the reasonableness of the proposed increase. Ratemaking standards and accounting adjustments inconsistent with those approved in its

1 The rules w~~e renamed by the Commission on December 4, 1984, in Case No. POE820056. The FOR program is now called an expedited rate case, • ••• the latter being the refined successor to FOR~· 1984 sec Ann. Rep. 375, 376.

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1983 rate case must be rejected on the basis they are beyond the scope of an expedited proceeding.

Apco therefore argues the Staff's testimony proposing new adjustments removing deferred taxes from rate base and capitali­zation, eliminating the accrual of AFODC and Staff's adjustment to reflect a new cost rate for ITC and additional interest syn­chronization on a portion of rate base supported by ITC must be striken. It claims these adjustments are inconsistent with the adjustments approved in its 1983 ease and are beyond the scope of an expedited proceeding.

Apco finally argues it would be extremely unfair to limit a utility on the issues it can raise in an expedited rate case while allowing.other parties an unrestricted right to address any issue they desire. Such an interpretation, according to Apco, will cause the death of expedited rate cases as a viable alternative to a general rate case.

The Staff, Attorney General and Committee, of course, take a position diametrically opposed to that advanced by Apco. They argue the expedited rules only limit the issues a utility can raise in an expedited case. Other interested parties are free to raise any issue they desire in an expedited case. In their view, imposing limits on other interested parties would violate their procedural due process rights and would prevent the Commission from fulfilling its duty of establishing just and reasonable rates as required by Virginia Code §56-235.2 and the Constitution of Virginia.

Finally, the Staff claims that its interpretation is not unfair to a utility. The opportunity for expedited rate relief is of considerable benefit to a utility because it allows a utility to place its rates into effect 30 days after the filing of its application. If a utility desires the benefits of prompt rate relief, a price may be exacted for the privilege. The "price" paid by a utility is that it is precluded from changing its cost of equity, altering its rate design or proposing any new accounting adjustments inconsistent with those approved in its prior general rate ease.

After reviewing the rules and the arguments of counsel, it appears the confusion in this area can be traced to the termin­ology of the expedited rules. Although the rules expressly limit the issues a utility can raise, they are silent on whether other interested parties are subject to the same limitations. This Rsilencen has caused several parties to believe that no limits can be imposed on anyone other than the utility. Commissioner Lacy noted this problem in terminology in a recent expedited rate case. She suggested the rules need to be revised to address this

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issue and remove any ambiguities. 2 This is ·a suggestion that I wholeheartedly endorse since it would clarify, once and for all, the appropriate scope of an expedited· rate case. For the moment, however, I am faced with the problem of making a recommendation on what I believe to be the appropriate scope of such cases.

It has always been my opinion that reasonable limits can, and indeed must be placed on all parties if an expedited rate case is to remain a viable alternative to a general rate case. Why parties continue to argue that no limits can be imposed on anyone other than the utility, after almost seven years of operating under the program, is a mystery to me. The limited· nature of such cases has been consistently recognized and sanc­tioned by the General Assembly, the Commission, and the Virginia Supreme Court of Appeals.

The necessity for such limits were first recognized in the General Assembly's resolution requiring the Commission to imple­ment a more efficient procedure for investigating utility earn­ings. Bouse Joint Resolution No. 348 limited rate increases to amounts not exceedfng increases in the cost of living. It fur­ther authorized the Commission to consider major ratemaking issues, such as rate design, const·ruction needs and load projections, in _ separate proceedings.

The limited nature of such cases was further recognized in the General Counsel's letter first implementing the FOR program, as well as the formal rules and regulations adopting and amending the program by the Commission in Case Nos. PUE820056 and POE850022. Although the rules have been amended over the years to incorporate changes in policy or statutory law, the guiding philosophy behind the program has remained the same since its very inception. Simply put, the philosophy of the program is that such reviews are limited issue rate vehicles designed primarily to review a utility's earnings using the standards approved in its most recent general rate case. The limited nature of such cases has been affirmed over and over again since the program's inception.

In Vepco•s 1980 FOR, for example, the Commission explained the limited scope of such cases as follows:

The Commission agrees with the Bearing Examiner that limits must be established for FOR proceedings if FOR is to be a workable concept. We do not find FOR to be an appro­priate proceeding for litigation of all

2 See Lacy, dissenting, Application of Columbia Gas of Virginia. Inc., Case No. POE850053, Appeal pending before Virginia Supreme Court.

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issues which would be properly considered in a general rate case. Both our experience to date with FOR and our understanding of the Bouse Joint Resolution mitigate against our acceptance of POR as a forum for consideration of every issue disposed of by the Commission in prior rate cases. Application of Virginia Electric and Power Co., 1980 SCC Ann. Rep. 459, 460.

Moreover, recent expedited cases decided by the Commission have reaffirmed the limited nature of such cases by refusing to consider certain issues deemed beyond the scope of review. See Application of Virginia Natural Gas, Case No. POE850036, Interim Order dated February 4, 1986, Application of Columbia Gas of Virginia, Case No. POE850053, Interim Order dated April 8, 1986, Appeal pending before Virginia Supreme Court. (Both cases ex­cluded certain rate design issues from consideration in an expedited rate case.)

. Finally, I find it· significant that the Virginia Supreme Court has reviewed and endorsed the limited nature of such cases. In explaining the scope of a POR and distinguishing the program from a general rate case, the Court made the following observation in Westyaco y. Columbia Gas, 230 Va. 451 (1986):

Furthermore, the present proceeding is not a general rate case but one for expedited rate relief. Columbia's application for expedited relief was filed pursuant to the Financial Operating Review (FOR) program, established by the Commission in response to Bouse Joint Resolution No. 348 passed by the General Assembly in 1979. 1979 Va. Acts, 1365. Concerning FOR proceedings, we have said:

The [FOR] program is designed to insure stability in utility rates by providing for an annual review of the financial condition of utilities. As part of the program, a utility may ask for an increase in rates. In doing so, certain findings made by the Commission at the utility's last general rate case, such as the cost of equity. rate design. and some accounting adiustments, are held con­stant. The FOR, therefore, differs from a general rate case, and the utility retains the option of filing for a general rate increase. (Emphasis added.)

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Roanoke Gas v. Corporation Comm., ·225 Va. 186, 188, 300 S.E.2d 785, 786 (1983). Bence, the issues are limited in a proceeding brought under the FOR program, and, consequently, different rules apply. (Emphasis added.)

The basic problem I have with the view advocated by Staff, Attorney General, and the Committee is the attempt to convert this case to a general rate case for all parties except Apco. The parties argue they are entitled to raise any issue they desire in much the same manner as in a general rate case, while limiting Apco in the issues it can raise. Not only is this approach fundamentally unfair to Apco, but it ignores the fact that an expedited case has always been intended to be a financial review using the standards established in a utility's most recent general rate case. If such standards are continually subject to attack, requiring the utility to once again defend the Commis­sion's prior decision on ·a particular issue, and if the utility is precluded from~roposing any adjustments to offset the loss of any revenue resulting from a change in standards, the procedure will have little or-no value to a utility.

A second concern I have with unrestricted approach is that it fails to recognize the considerable benefits which accrue to the ratepayer from such cases. Although no consumer likes in­creased electric bills, I think it's safe to say that expedited cases generally result in lower rate increases than general rate cases. In Apco•s case, for example, it did not propose any increase rel•ting to its participation in the AEP Transmission Agreement because it was prevented from doing so under the expe­dited rules. As a result, Apco•s decision to file an expedit'd rate case may have saved Virginia consumers literally millions of dollars w~ch Apco would have expected to recover in a general rate case. This is why I believe it is so important to preserve the integrity of the expedited rules.

I would hasten to point out, however, that my view of the rules is not identical to Apco•s suggestion that past decisions in a general rate case will always be controlling. No utility should be allowed to prevent the consideration of issues merely by its choice of filing an expedited, rather than general rate case. Circumstances may have changed since a utility's most recent general rate case making it necessary to reexamine an issue previously decided. To give a quick example, the economy has improved since Apco•s 1983 rate case when the Commission

3 Onder the agreement, as filed with FERC, Apco bas com­mitted itself to a plan, which, if implemented as proposed by the AEP companies, will obligate Apco to pay approximately $22 million each year to Indiana and Michigan Power Co. and Kentucky Power Co.

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approved a 16.0% cost of equity. As a result, the Commission allowed Apco•s current cost of equity to be addressed.

Apco•s assertion that prior ratemaking standards must always control is erroneous. In certain conditions, issues must be reexamined in light of current conditions. Furthermore, accep­tance of Apco•s argument would prevent the Commission from ful­filling its duty of establishing just and reasonable rates as required by Virginia Code 556-235.2.

I believe the confusion in this area can be eliminated if two simple rules are kept in mind when evaluating an expedited rate case. First, issues of first impression, never specifically considered in a prior general rate case, will always arise and must be dealt with on their merits. Summarily excluding evidence on issues of first impression without an opportunity for hearing may violate a party's procedural right of due process. Vepco y. State Corp. Com~ 226 Va. 541 (1984). The Commission must, in my opinion, allow issues of first impression to be addressed in an expedited rate_ case.

On the other hand, issues previously considered and addressed in a prior rate case should not be relitigated by any party in a­subsequent expedited case absent a substantial change in circum­stances requiring a reexamination of the issue. Accordingly, issues relating to cost of equity, rate design and a whole host of other issues customarily decided in general rate cases should not be relitigated in an expedited rate case in the absence of a compelling need to do so.

Finally, there appears to be no violation of a party's due process rights by limiting the introduction evidence on previous­ly decided issues. Due process only requires a reasonable "opportunity•, not an absolute, unrestricted right to present evidence and be heard. The parties have had one opportunity to present evidence when the issue was first decided in the utili­ty's prior rate case, and will have yet another opportunity in its next general rate case. There is no due process requirement that the parties be furnished a third opportunity to challenge an issue previously decided absent a substantial in circumstances requiring a reexamination of the issue. Absent such a change, however, previously decided issues should not be relitigated in an expedited case. It would be inefficient, unnecessary and totally at odds with the philosophy of the financial review to allow an unrestricted opportunity to review previously estab­lished standards during such a limited hearing.

DISCUSSION

Although this case generated substantial argument concerning the permissible scope of an expedited rate case, there appear to be relatively few issues to be resolved in this case. The major

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issues concern: (1) abnormal test year flood expenses; (2) al­lowance for funds used during construction (APUDC); (3) test year capacity equalization charges; (4) removal of deferred taxes from rate base and capitalization; (5) an appropriate cost rate and additional interest synchronization for investment tax credits CITes); (6) cost of equity; and (7) allocation of the proposed increase among Apco•s customer classes.

1. Flood Expense

In November of 1985, a flood occurred in Apco•s service area exceeding the 100-year flood plain. As a result of the flood, Apco was required to incur approximately $1.2 million in costs to restore customer service. Of this total amount, $1.1 million was allocated to Apco•s Virginia jurisdictional opera­tions. The incremental flood cost (after removing normal payroll) amounted to $796,444.

-Staff accounting witness Smith proposed an adjustment to

amortize the flood costs over a three-year period. ·Be contended the flood was an abnormal occurrence which is not expected to recur in the foreseeable future. Be therefore proposed an ad­justment to amortize the flood costs over a three-year period consistent with the Commission's ratemaking treatment of similar items of an unusual or nonrecurring nature. Acceptance of the Staff's adjustment would reduce Apco•s test year expenses by $530,962.

While acknowledging the flood.was unusual, Apco believes it should be allowed to claim the entire flood cost as a test year expense for three reasons. First, Apco said the flood cost was a relatively small amount and allowing the entire amount to be expensed would not significantly impact its revenue requirement. Second, Apco contended the expense was incurred for service restoration which directly and immediately benefited its custo­mers. Since the costs related to service restoration, Apco argued the ratemaking treatment should be different from that afforded other abnormal and nonrecurrinq expenses. Finally, Apco claimed that allowing the entire cost as a test year expense is not unfair to ratepayers since the Commission will examine Apco's operations on the basis of its next Annual Information Filinq for the year 1986. This after-the-fact review will ensure that Apco's rates are reasonable, even if all flood costs are allowed in cur­rent rates. If the annual review demonstrates excessive rates, Apco claims its rates can be later reduced.

There is no question that the November 1985 flood was an abnormal and unusual event not likely to recur in the foreseeable future. The flood exceeded the 100-year flood plain, and this fact alone illustrates how rare a flood of this maqnitude occurs.

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In past cases, the Commission has normalized test year expenses caused by extraordinary or nonrecurring events. In Apco's 1978 rate case, for example, the Commission amortized the costs associated with a fire at Apco's Amos generating plant, holding that "· •• it would be inappropriate to set rates based upon the entire amount of this extraordinary expense." Applica­tion of Appalachian Power Company, 19.79 sec Ann. Rep. 201, 205-06. Similarly, rate case expenses are traditionally amortized over a two or three year period even though these expenses occur much more frequently than a 100-year flood. Bow flood costs which are incurred once every 100 or so years should be treated any dif­ferently from rate case expenses is a mystery to me.

I therefore find the Staff's adjustment to amortize the flood costs over a three year period is reasonable. It would be inappropriate to establish current rates based on test year expenses that are not likely to recur during the period new rates are in effect. The Staff's proposal is therefore accepted for purposes of this report.

2 •. Proposed Elimination of AFUDC

Staff witness Peterson proposed an adjustment to eliminate the booking of AFODC as income in order to allow Apco to earn a full cash return on CWIP. Apco's AFtJDC accrual for the test period, after certain undisputed accounting adjustments, amounts to $309,784.

In support of his adjustment, Peterson said the Commission has approved the discontinuance of AFUDe for several other utili­ties operating in Virginia, such as Potomac Edison and Virginia Electric and Power Company. See Application of Potomac Edison Electric Company, 1982 sec Ann. Rep. 524: and Application of Virginia Electric and Power Company, 1981 SCC Ann. Rep. 238, 241. In these cases, the Commission held that elimination of AFODC improves the financial condition of a utility and is in the best interests of the ratepayer. Pinally, Peterson claimed the current case is the ideal time to implement this policy for Apco given its relatively low level of current construction.

The Committee and Attorney General opposed the elimination of AFODC for Apco. The Committee argued that AFODe should be eliminated only when a utility demonstrates that it is experi­encing financial difficulty. In its view, the elimination of AFODC should be viewed as a financial tool designed for use only in those cases where a utility's financial condition needs im­mediate improvement. The Committee further points out that neither Apco nor the Commission's Staff submitted any evidence indicating that Apco•s financial condition requires such an extraordinary measure. The Committee therefore a~gues that, lacking any evidence of a financial need by Apco, the consumer should not be required to pay for the elimination of AFODC.

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APUDC, of course, is a subject very familiar to the Commis­sion. Inclusion of AFUDC as "above the line• income presented no problems in the early 1970s·when there was a moderate level of construction. Later, however, when construction programs in­creased and APUDC likewise increased, the necessity for ceasing its accrual became apparent.

Judge Shannon was the first Commissioner to suggest the accrual of AFODC should be eliminated in a series of dissents in the late 1970s. See Shannon, dissenting, Application of Appalachian Power Company, Case No. 19723, 1977 SeC Ann. Rep. 158, 169-70; Application of Potomac Edison Company, Case No. 19810, 1978 SCC Ann. Rep. 118, 123-24; and Application of Appalachian Power Company, Case No. 19984, 1979 sec Ann. Rep. 201, 212-13. In support of his position, Judge Shannon claimed that many benefits would accrue to the utility and ratepayers by the elimi­nation of APUDC. Such benefits included increased coverage ratios for the purpose of issuing debt, improved bond ratings, and improvements in-the ~uality of earnings through better internal cash flow. .Elimination of APUDC would also .reduce the amount of outside financing which otherwise would be necessary for capital improvements and lower the utility's capital costs to the benefit of both the utility and Virginia ratepayers.

Although Judge Shannon was the sole champion of this cause for a number of years, the Commission finally reversed its long­standing policy on APUDC beginning in Vepco•s 1981 general rate case where the Commission held that "[w]e are convinced the rate­payers will be the beneficiaries of the elimination of APUDC." 1981 SCC Ann. Rep. 238, 241. The Commission's position on APUDC has remained unchanged over the years as evidenced by Virginia Power's most recent general rate case where the Commission stated: "We fully agree with the Bearing Examiner that total elimination of the accrual of AFODC is in the best interest of both the ratepayer and the Company. With the small amount of APUDC being accumulated in recent periods, ending such accrual would be a logical extension of our policy. • • ." (Emphasis added.) Case No. POE840071, Final Order dated May 16, 1986, at p. 10.

Although I agree with the Committee that elimination of APODC is a financial tool to improve a utility's earnings, I am not entirely convinced that AFODe should be eliminated only in those cases where a utility demonstrates an urgent need for its removal. It appears to me that the Commission's policy is to cease the accrual of AFODC because it will be benefit ratepayers by improving cash flow and reducing capital costs. These benefits will be realized regardless of the financial condition of the utility.

In conclusion, I find the Commission's past decisions on AFUDC represents a clear policy common to utility ratemaking which should now be implemented for Apco given its relatively small

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amount of AFODC. The Commission bas previously stated that expedited rate cases should be flexible enough to incorporate the Commission's current position on issues common to utility ratemaking. For this reason, I find the Staff's adjustment to eliminate the accrual of AFODC for Apco should be approved and Apco•s Motion to Exclude evidence on this issue should be denied.

3. Capacity Equalization Charges

Apco is a member of the AEP system and participates in the AEP Interconnection Agreement. Onder the agreement, a central dispatching office schedules the output of each company's generating units, controls the transmission of power between the AEP operating companies, and regulates off-system sales. The purpose of the agreement is to achieve the most reliable and economical power supply for the AEP system as a whole.

The agreement prescribes a formula, known as the member load ratio (MLR), to al}ocate capacity settlement payments to and from each company and to determine each company's share in profits from off-system sales. The MLR is calculated monthly, and is derived by dividing each company's peak demand in the previous 1~ months by the sum of all the operating companies' peak demands during the previous 12 months. Apco•s average MLR for the test year was .32641, resulting in total capacity equalization charges of $74,803,599. Its share in off-system sales totaled $53,517;000.

The Attorney General and Committee claimed that Apco•s test year capacity equalization charges were distorted by abnormally cold weather occurring in January, 1985. The abnormal weather caused Apco to hit a new internal peak of 5,464 MW on January 21, 1985. This, in turn, caused Apco•s capacity equalization charges to increase for the following 12 months under the agreement. The effect of the abnormal weather and record peak was not eliminated from Apco•s capacity equalization charges until after the close of the test year in February, 1986.

The Attorney General and Committee argued that Apco•s test year capacity equalization charges should be normalized to elimi­nate the effects of abnormal weather. They claim that failure to make a weather normalization adjustment will cause excessive capacity equalization charges to be embedded in Apco•s future rates, needlessly increasing the ratepayers• electric bills. Both parties therefore proposed adjustments to remove the effects

. of the January, 1985 abnormal weather.

The Attorney General's witness, Alexander F. Skirpan, examined Apco's actual and projected MLRs and capacity equalization payments from 1981 through 1990. Sis examination revealed that the abnormal weather in January, 1985, caused Apco•s monthly MLR to increase from .30867 in January of 1985 to .32874 in February, 1985. This increase in Apco•s MLR caused its test year capacity equalization

14

charges to more than double the amount incurred in 1984 ($33,797,000 v. $74,804,000). Be said failure to weather normalize the MLR would allow Apco to recover more revenue than needed to cover a normal level of capacity equalization charges.

Skirpan further claimed that AEP itself had recognized that abnormal weather distorted the MLRs for several of its operating companies during 1985. In support of this contention, Skirpan referred to a recent case decided by the Ohio Public Utilities Commission where Henry Fayne, an AEP Service Corporation employee, proposed an adjustment to Ohio Power Company's MLR to remove the effects of abnormal weather. Mr. Fayne testified as follows before the Ohio Commission:

In January 1985 the AEP System experienced severe and abnormal weather conditions in various parts of its service territory, which significantly distorted the peak demands of several of the operating compa­nies. Bec~use the MLR is calculated each month based on each company's peak demand in the previous twelve months, the effect of the abnormal January 1985 weather conditions will not be eliminated until February 1986. (Exh. No. JWV-6)

Interestingly enough, the abnormal weather had just the opposite effect in the Ohio rate case since Ohio Power, unlike Apco, is a •surplus• member of the AEP system. In other words, Ohio Power receives capacity equalization payments from AEP "deficit" companies such as Apco. Cold weather therefore caused Ohio Power to receive larger settlement payments during the test period than it would otherwise receive during normal weather conditions. Relying on Mr. Fayne•s testimony, the Ohio Commis­sion found that abnormal weather distorted the MLR of Ohio Power. The Commission therefore normalized the company's MLR when calcu­lating Ohio Power's capacity settlement payments. The MLR ad­justment had the effect of reducing Ohio Power's test period revenues and increasing its revenue requirement. Be Ohio Power Company 76 PUR 4th 121 (1986).

Since AEP admitted that abnormal weather distorted the MLRs of AEP members, Skirpan recommended that Apco•s MLR also be weather normalized to reflect a normal, on-going level of capacity equalization charges which can be expected to be incurred when the rates approved in this case are in effect. Be recommended that Apco•s MLR be adjusted to the January, 1985 level of .30867 when determining a normal level of capacity charges. Ose of the January, 1985 MLR would produce "normalized• capacity equalization charges of $55,642,777, or approximately $19 million less than the amount actually incurred during the test period. On a jurisdic­tional basis, Skirpan's proposed MLR would reduce Apco•s operating expenses by $8,036,240, and reduce its jurisdictional revenues by

15

$1,217,090, to reflect a smaller share in off-system sales profits resulting from a normalized MLR.

Mark Drazen, the witness for the Old Dominion Committee, also proposed an adjustment to normalize Apco•s capacity equali­zation charges. Be said there are two methods to do this: (1) weather-normalize Apco•s 1985 peak, which he admitted would be a large undertaking requiring information which was not readily available, or (2) weather normalize Apco•s MLR. Be opted for the second method, as did the Attorney General's witness Skirpan.

In order to weather normalize Apco•s MLR, Drazen examined Apco•s monthly MLRs from 1981 through May, 1986. Based on his analysis, he concluded that a normal MLR for Apco, excluding the effect of abnormal weather, would be in the range of .30700 to .31700. Using the low end of his MLR range of .30700 would produce normalized capacity equalization charges of $53.8 million, or approximately $21 million less than the amount incurred during the test year. Og a jurisdictional basis, Drazen•s adjustment would reduce Apco•s operating expenses by $8,793,000 and reduce its revenues from off-system sales by $1,332,000.

The upper end of Drazen•s MLR range of .31700 would produce normalized capacity equalization charges $64.6 million, or ap­proximately $10.2 million less than incurred during the test year. On a jurisdictional basis, a .31700 MLR would reduce Apco•s test year expenses by approximately $4,265,000 and reduce its revenues from off-system sales by approximately $644,000.

Apco, of course, argued that the entire amount of test year capacity equalization charges should be allowed when establishing rates. In defense of its position, Apco denied that abnormal weather was the sole reason for the increase in charges between 1984 and the test period. John w. Vaughan, the president of Apco, claimed that $18-$20 million of the increase in capacity charges resulted from the Rockport I Coal Generating Plant being placed on line by Indiana and Michigan Electric Company. Be further testified many other factors such as changes in load and customer mix could affect Apco•s MLR. Be finally admitted, however, after heated cross-examination, that weather was the primary factor causing the large increase in Apco•s capacity equalization charges between 1984 and the test period.

Apco•s brief restated its earlier position in its Motion to Exclude that its capacity equalization charges are beyond the scope of an expedited rate case. Apco further claimed that a MLR adjustment had been proposed in its prior rate cases but the Commission rejected each and every attempt to do so. In Apco•s 1982 FOR, for example, Apco sought to adjust its MLR to reflect a new internal peak which occurred outside the test period. The Commission rejected the MLR adjustment on the basis it was beyond

16

the scope of an FOR proceeding.4 A year later, in its 1983 general rate case, Apco sought to adjust its

5off-system sales to

reflect losses in system sales realizations. The Commission rejected the adjustment, holding that the entire amount beyond the test period should be deducted from the amount requested.6 In short, Apco argues these prior rate cases demonstrate that an adjustment to its MLR is inappropriate under the legal prin­ciples previously established by the Commission.

Second, Apco argues the record contains inadequate evidence to support an adjustment to its MLR. Apparently, Apco•s argument here is that the proper and preferred method to weather normalize its capacity equalization charges would be to normalize Apco•s 1985 peak demand, rather than focusing solely on its MLR. To weather normalize Apco's peak is a large and complicated under­taking requiring a consideration of many factors, such as a potentially abnormal increase in retail and system sales revenues due to the weather, variations in system pool transactions be­tween the AEP companies, and other variable operating and main­tenance expenses that-would likewise be affected by abnormal weather. Apco claims that focusing solely on its MLR ignores the importance of these other variables, all of which should be considered when weather normalizing its capacity equalization charges.

Finally, Apco argues the Commission lacks jurisdiction to reduce its capacity equalization charges because the AEP Inter­connection Agreement was approved by FERC. Citing Nantahala Power and Light Co. v. Thornburg, 54 o.s.L.w. 4676, _u.s.__ (June 16, 1986), Apco argues the Commission is federally preempted under the "filed rate doctrine• from adjusting its capacity equalization charges. FERC is the only forum that can alter Apco•s capacity equalization charges.

As can be seen, this one issue generated the most debate during the hearing. Although the parties have submitted volumi­nous evidence and argument on this issue, it appears to me that a relatively simple ratemaking concept is at issue. First, should

4 Case No. POE820030, Interim Order dated May 28, 1982, 1982 SCC Ann. Rep. 6031 Final Order dated February 23, 1983, 1983 SCC Ann Rep. 360.

5 Case No. POE830037, Final Order dated October 7, 1983, 1983 sec Ann. Rep. 497.

6 Interestingly enough, a corresponding adjustment to reduce Apco's test year capacity equalization charges was not proposed in the 1983 rate case.

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the Commission normalize test year revenues and expenses to eliminate the effects of abnormal or.nonrecurring events? And second, is the Commission federally preempted from weather nor­malizing costs that are incurred under an agreement approved by PERC? Since acceptance of Apco•s preemption argument would pre­clude the Commission from examining the merits of this issue, the preemption argument will be addressed first.

In Nantahala, the North Carolina Utilities Commission (NCOC) rejected a PERC-approved allocation scheme in favor of an alter­nate method more favorable to North Carolina ratepayers. As a result, the NCOC allocated more low cost entitlement power to Nantahala Power, reduced the company's overall revenue require­ment, and limited the company's ability to recover all of its wholesale power costs under an agreement approved by PERC. The NCOC decision was affirmed by the North Carolina Supreme Court as a proper exercise of state ratemaking authority.

In reversing the North Carolina decision, the u.s. Supreme Court held the •filed rate doctrine• prevents a state from de­claring a PERC-approvea rate unjust and unreasonable. Onder that doctrine, PERC alone has the exclusive jurisdiction·over whole­sale power rates. The reallocation of low cost •entitlement power• by the NCUC, contrary to the allocation method prescribed by PERC, was a direct and unlawful intrusion into PERC's exclu­sive jurisdiction over wholesale power rates in violation of the Supremacy Clause of the o.s. Constitution. In analyzing this decision, however, it's extremely important to remember that NCOC's allocation method was directly contrary to that approved by FERC. As a result, Nantahala would not fully recover its wholesale power costs under the NCOC decision. The u.s. Supreme Court held that such a •trapping of costs• is prohibited.

Although it bas always been difficult to draw a clear line separating federal and state regulation in the area of PERC­approved wholesale power rates, I am not convinced that the Supreme Court's decision in Nantahala preempts the Virginia Commission from establishing a level of capacity equalization charges repre­sentative of normal conditions. There are several reasons why I believe Nantahala is not applicable under the facts developed in Apco•s case.

First, the Attorney General and Committee are not contending that Apco•s test year capacity equalization charges should be reduced because the interconnection agreement is unjust and un­reasonable. Nor are they attacking the method for allocating capacity costs among the AEP companies (MLR) on the basis that it is unreasonable. Were this the case, Nantahala would clearly preempt the Commission from reducing Apco•s capacity charges. A state commission has no authority to find a wholesale power rate unreasonable or authority to change a PERC-approved allocation formula. See also AEP Generating Company, Docket No. ER 84-579-005, 36 PERC, §61,226 (August 20, 1986). However, this is not

18

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what the Attorney General and Committee are contending. To the contrary, they freely admit that the Interconnection Agreement is reasonable and benefits Apco•s customers. What the Attorney General and Committee seek is to establish a level of capacity equalization charges, using the PERC-approved Interconnection Agreement and MLR, which can reasonably be expected to recur during the period the rates approved in this case are in effect. Therefore, the Nantahala decision is clearly distinguishable from the facts developed in Apco•s case. In the North Carolina case, the Commission and state supr~me court ignored the PERC-approved rate and substituted its own rate using a different allocation formula. This is not the remedy sought in Apco•s case however.

Second, one of the .primary concerns of the Supreme Court in Nantaha!a, was that NCOC's allocation method would not allow the Company to fully recover its wholesale power costs. Such a Rtrappinq of costs• is not allowed. The proposals in Apco•s case, however, will allow Apco to fully recover its capacity equalization charges under ·the interconnection agreement under norma! weather conditions. Normalizing the MLR would merely prevent Apco from over-recovering its capacity costs under the agreement based on the· abnormal weather conditions occurring on one single day during the test year. The Virginia ratepayers would therefore be protected from paying excessive rates designed to recover abnormal capacity charges incurred during the test year.

Third, although Nantahala constitutes a strong reaffirmation of the Rfiled rate doctrine•, it cannot be interpreted to require that a state commission must always accept, without further in­quiry, a PERC-approved wholesale power rate. Indeed, the Court suggests that a state may indeed deviate from a PERC-approved wholesale power rate where lower cost power is available else­where or where the utility•s decision to purchase the higher cost power is imprudent. Finally, the Court held that a decrease in rates would be appropriate on an express findina that costs of obtaining power had decreased, or that other costs of operation had declined. Id. at 4680 (emphasis added).

Finally, one of the critical problems with the NCOC decision was the lack of an express finding that Nantahala•s cost of power had decreased. The NCOC only found that Nantaha!a should have obtained more low cost power than it was allocated under the PERC order. Given the absence of a finding that lower cost power was available to Nantahala, the o.s. Supreme Court held the NCOC and state supreme court decisions cannot stand the preemptive force of PERC's decision. In Apco•s case, however, the Attorney General and Committee argue that Apco•s cost of purchase power will decrease under the agreement since the abnormal weather is not expected to recur during the period the rates approved in this case are in effect. · ·

For the foregoing reasons, I am unable to conclude that Nantahala preempts. the Commission from adjusting Apco•s test year

19

capacity equalization charges if it appears that Apco•s capacity costs will be substantially less than the capacity costs incurred in the test period. Indeed, Nantahala appears to support such an adjustment if abnormal weather distorted Apco•s capacity equaliza­tion charges and a decrease in capacity costs can be expected in the future.

Saving found that Apco•s capacity costs can be adjusted to remove the effects of abnormal weather, it is now necessary to address the merits of the proposals by the Attorney General and Committee. For purposes of discussion, the following chart (Exh. No. JWV-4) shows Apco•s historic and projected annual MLRs and ca­pacity equalization payments under the AEP Interconnection Agreement:

MLR Capacitv Charges

1981 .29728 $22,608,000

1982 .32114 47,080,000

1983 .3091Q- 35,509,000

1984 .30572 33,797,000

1985 .32641 74,804,000

1986 .31711 66,008,000

1987 .31128 53,881,000

1988 .31686 65,616,000

As the above chart illustrates, Apco•s capacity costs more than doubled between 1984 and 1985. Although $18-20 million of the increase is attributable to bringing on-line Rockport No. 1, I find the balance of the increase was caused primarily by abnor­mally cold weather. Virtually all the witnesses, even John vaughan, the president of Apco, admitted the large increase in capacity costs between 1984 and 1985 was caused primarily by abnormal weather. Even Apco•s own service company, AEP Service Corporation, acknowledged that abnormal weather distorted the MLRs of the AEP companies in 1985, and has gone on record for surplus companies, such as Ohio Power, proposing an adjustment to test year MLRs to remove the effects of weather. Of course, for "deficit companies,• such as Apco, no MLR adjustment has been proposed. Surely, the AEP companies cannot be allowed to argue inconsistent treatment of essentially the same item under similar circumstances merely to increase the revenue requirements of each company.

I therefore find that Apco•s test year capacity equalization charges are distorted and not representative of the level of charges that can be expected during the period the rates approved

20

in this case are in effect. The parties in this case have reco~­mended using an MLR ranging between .• 30800 and .31700. Obviously, a .30800 MLR will not produce sufficient revenue to cover a normal level of capacity costs. Apco•s MLR beginning in February of 1986 decreased to .31513 and then increased to .31703 in March, 1986. It remained at this level until August, 1986, when it again dropped to .30991. Accordingly, use of a .30800 MLR will not produce suf­ficient revenues to allow Apco to cover a normal, on-going level of capacity charges. For this reason, the lower MLR is rejected.

After considering the evidence, I find that it is appro­priate to use a .31700 MLR for the purposes of this case. This MLR produces capacity charges of $64,634,500, and reduces Apco•s off-system sales profits by $1,536,000. On a Virginia jurisdic­tional basis, a .31700 MLR will decrease Apco•s operating expenses by $4,265,000, and reduce operating revenues by $644,000, for a net reduction in expenses of $3,621,000.

Finally, I believe it's important to note that Apco is not harmed by this recommendation. A .31700 MLR is consistent with the MLRs actually experienced by Apco in 1986, and exceeds its projected MLRs for 1987 and 1988. Apco should therefore receive sufficient revenues to cover all of its capacity equalization charges under the interconnection agreement. On the other hand, if an adjustment is not made to remove the effects of abnormal weather, the rates of Virginia consumers will be needlessly in­creased to cover the excessive and abnormal level of capacity charges incurred during the test period.

4. Remoyal of Deferred Taxes from Bate Base and Capitalization

Apco•s capital structure for ratemaking purposes, as shown on Schedule 3 of its application, includes $170,529,043 of ac­cumulated deferred income taxes and $73,221 of customer advances for construction. In accordance with the instructions to Schedule 3, and consistent with the Commission's past ratemaking treatment of these capital items, Apco included deferred taxes and customer advances in its capital structure as cost-free capital.

Staff witness Peterson claimed that including Apco•s de­ferred taxes in Apco•s capital structure as cost-free capital results in Virginia jurisdictional customers receiving the benefit of approximately 41% of the cost-free capital, although over 71% is directly allocable to Virginia. The disparity is caused primarily by the different accounting methods prescribed by the Virginia and West Virginia Commissions to account for liberalized depreciation.

In Virginia, for example, the Commission authorized Apco in 1975 to account for liberalized depreciation using the tax normalization method. 1975 sec Ann. Rep. 186, 191-92. Onder tax normalization, taxes for ratemaking purposes are determined on the basis of straight-line depreciation, while liberalized

21

..

depreciation is used for federal tax purposes. The difference between the taxes that are payable under straight-line deprecia­tion and the taxes payable under liberalized depreciation are placed in a deferred account and amortized over the useful life of the qualifying asset. According to witness Peterson, the accumulated deferred taxes allocable to Virginia under the nor­malization method amount to $121,131,174.

In West Virginia, on the other hand, the Commission required Apco to account for liberalized depreciation for a number of years using the •flow through• method of accounting. Flow through uses the actual amount of tax paid as a result of liberalized deprecia­tion for both ratemaking purposes and federal income tax purposes. In other words, the benefits of liberalized depreciation are flowed through to ratepayers immediately rather than deferred and amor­tized over the life of the asset. As a result of West Virginia's use of the flow through method, Apco's deferred taxes allocable to West Virginia amount to $49,397,869.

According to P~terson, the different accounting methods prescribed by the Virginia and West Virginia Commissions present no insurmountable problems for ratemaking as long as-deferred taxes are not included in Apco•s capital structure and removed from rate base. However, he claims that in Apco•s case the inclusion of deferred taxes in capitalization deprives Virginia ratepayers of a considerable benefit. This occurs simply because although over 71% of the deferred taxes are allocable to Virginia, only approximately 41% of rate base is allocated to the Virginia jurisdiction. Since rate base and capitalization, at least theoretically, are supposed to match dollar for dollar, Virginia customers only receive the benefit_of 41% of the cost-free capital.

To remedy this problem, Staff witness Peterson proposes to remove deferred taxes from Apco•s capital structure as cost-free capital and reduce rate base by a corresponding amount. Staff further proposes to remove customer advances as cost-free capital with a corresponding reduction to rate base. Acceptance of these two proposals would reduce Apco's rate base by $121,204,395, and lower Apco•s revenue requirement by approximately $9 million.

Apco vigorously opposed the Staff's proposals. It initially filed a Motion to Strike Peterson's testimony arguing his proposals were beyond the scope of an expedited rate case. As previously explained, however, I decided to take Apco•s motion under advise­ment. The Staff's evidence on this issue was therefore received subject to the motion.

On brief, Apco renewed its argument that the Staff's proposal should be rejected. It cited four reasons why the Commission should reject the Staff's adjustment. First, Apco argued that a review of its five general rate cases since 1975, as well as each of its FORs during that period, reveals that the Commission has consistently included deferred taxes and customer advances as

22

cost-free items in Apco•s capital structure. Second, Apco argued the instructions to Schedule 3 explicitly require a utility to include an entry for cost-free items as a part of its capital structure when filing for expedited or general rate relief. Third, Apco argued that in neither the recent Potomac Edison rate case (Case No. P0£850029) nor the recent Virginia Power (Case No. PU£840071) rate case did the Staff propose or.the Commission adopt an adjustment to remove these cost-free items from the utility•s capital structure, even though these proceedings were general rate cases. Finally, Apco argues such an adjustment has never been proposed by the Staff nor adopted by the Commission in any general or expedited rate case involving an electric utility in Virginia. Accordingly, Apco claims that approval of the Staff adjustments would reverse a long-standing Commission policy. such major policy changes, according to Apco, should only be considered in general rate cases or a generic proceeding.

After reviewing this issue, I am concerned with the Staff's proposal for a number of reasons. First, although the Staff attempted to frame ~his issue as one of first impression, my review of Commission decisions since 1970 reveals that numerous proposals have been made in past rate cases to remov~deferred taxes from rate base. Virtually all of the past decisions have rejected proposals to remov' deferred taxes from rate base and a uti1ity•s capital structure. Past Commission decisions there­fore support Apco•s position on this issue.

In Commonwealth Gas Distribution•s 1972 general rate case, for example, the Commission rejected a proposal by Reynolds Metals to deduct deferred taxes for rate base. 1973 SCC Ann. Rep. 173, 176-77. A similar proposal was made in C&P Telephone Company•s 1974 general rate case where several interveners claimed that deferred taxes should be deducted from rate base. The Commission once again rejected the proposal stating •[w]e don•t agree with this contention. We believe these amounts should be included in the capital structure and assigned a zero cost.• 197 4 SCC Ann. Rep. 111, 118. Three years later in C&P 1 s 1977 general rate case, the proposal was again made by certain agencies of the u.s. government. In rejecting the proposal to remove deferred taxes from rate base, the Commission stated the following: •The Commission does not accept these proposed adjust­ments. Deferred income taxes • • • are treated in the capital structure by the Commission.• 1977 SCC Ann. Rep. 139, 145. Accordingly, it appears to me that the Commission•s existing

1 In fact, the only case I have found that accepted an adjustment to remove deferred taxes from rate base is Case No. PU£820041, Application of Roanoke Gas Company, 1982 SCC Ann. Rep. 620. In the Roanoke case, the Commission accepted, without comment, the Staff•s proposal to remove deferred taxes from rate base. Furthermore, the adjustment was accepted only in the context of a general rate case.

23

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•policy• is to include deferred taxes in rate base and capitali­zation as cost-free capital.

The second concern I have with the Staff's proposal is the attempt to change "policy• in the context of an expedited rate case. According to the Staff, it plans to propose a change in treatment of cost-free capital for all utilities in an effort to move toward a ratemaking capital structure containing as few non­investor supplied items as possible. Although I don't question the Staff's right to propose changes in Commission policy in a general rate case or generic case, I do question the decision to alter an existing Commission policy in the context of an expe­dited rate case. In my opinion, major changes in policy should only be considered after careful and thoughtful deliberation of the issue with input from all parties to be affected by such a change. The abbreviated filing schedule in an expedited rate case precludes such a review.

Finally, I cannot ignore Schedule 3 of the rate case rules which require a utility to include cost-free capital in its capital structure. The-staff's proposal would be directly con­trary to the requirements of Schedule 3. Moreover, if the pro­posal is accepted, it will result in a basic injustice to Apco . since its revenue requirements will be reduced by a substantial amount while not affording Apco the right to propose any new adjustments to offset this reduction.

For these reasons, I find the Staff's adjustment to remove deferred taxes from capitalization and rate base should be re­jected at the present time. The purpose of any expedited rate case is to review a utility's financial performance using a set of standards approved in a utility's most recent general rate case. One of Apco•s preapproved "standards• is that deferred taxes and customer advances should be included in Apco's capital structure as cost-free capital. This standard has also been consistently used for all electric utilities subject to the Commission's jurisdiction. I therefore find that deferred taxes and customer advances should remain in the capital structure as cost-free capital at the present time, subject to reexamination of this issue in Apco's next general rate case.

5. Investment Tax Credits

In 1971, Congress reenacted the investment tax credit ("ITC") in order to stimulate investment in new plant and equipment. 26 o.s.c. §538, 46. In order to provide an incentive to purchase new plant, utilities were granted a credit against their federal income tax for qualifying property placed in service. Section 46(£) provides three methods by which a utility may account for the credit. In Case No. 19474, Apco was ordered by the Commis­sion to account for the credit using the ratable flow through method prescribed by §46(f)(2). Onder this method of accounting,

24

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Apco•s tax expense reflected in its cost of service is reduced by a ratable portion of the ITC. The unamortized balance of ITC is included in Apco's capitalization and assigned a cost equal to the overall return. In other words, while the full amount of the credits reduced Apco•s federal income tax in the year it was utilized, for ratemaking purposes the credits are deferred and amortized over the life of the property.

There are two issues relating to ITC which must be addressed in the case: (1) the ITC cost rate, and (2) Staff's additional interest synchronization on a portion of the rate base funded by ITC. Both issues relate to recently amended IRS regulations published on May 22, 1986.

In past rate cases, the Commission has simply assigned ITC a cost rate equal to the overall cost of capital. It was pre­viously thought that assigning a cost rate less than the overall cost of capital could be deemed an impermissible •rate base reduction• under S46(f)(2) of the Code, causing a forfeiture of the credit. Likewtse, no interest synchronization adjustment was made on any of the r~te base funded by ITC since it ~ould have been deemed an impermissible •reduction in cost of service" under §46 (f) (2). This would have also caused a loss of the credit.

The prior IRS regulations were ambiguous and of little help when addressing an appropriate ITC cost rate or permissibility of making an interest synchronization adjustment on a portion of the rate base funded by the ITC. Accordingly, prudence dictated a cautious approach in past rate cases, for the consequences of an error in the construction of the Internal Revenue Code would be the total loss of an extremely valu·able tax benefit for both the utility and ratepayers.

When Apco filed its application in this case, it assigned ITC a cost rate equal to its weighted cost of capital and did not propose an interest synchronization adjustment on a portion of the rate base funded by ITC. Not only is its treatment consis­tent with its last general rate case, but it is consistent with the ratemaking treatment approved for all regulated utilities operating in Virq~nia.

Staff witnesses Peterson and Tanner, however, proposed two adjustments to implement new IRS regulations adopted on May 22, 1986. 51 Fed. Reg. 18,775. Briefly stated, the new regulations prescribe a new method for calculating the ITC cost rate and allow the synchronization of interest on a portion of the rate base funded by the ITC.

Staff witness Tanner calculated Apco•s ITC cost rate using the new method prescribed by the IRS regulations. Essentially, the new regulations provide that the cost rate assigned to the unamortized balance of ITC may not be less than the overall cost of capital, determined on the basis of a weighted average, for

25

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the capital that would be provided if the credit were unavailable. 26 CPR 51.46-6 (b) (3) Cii) (A). Por the purposes of determining the composition of the capital structure had the credit been unavail­able, the regulations provide that it may be assumed that •such capital (i.e., the unamortized ITC balance) would be provided solely by common stockholders, preferred stockholders and long­term creditors in the same proportions and at the same rates of return as the capital actually provided to the taxpayer by such shareholders and creditors.• 26 CPR Sl.46-6(b) (3) (ii) (B) (2).

Although the regulations appear complicated, the actual mechanics of determining the ITC cost rate are not that diffi­cult. All that is required is that Apco•s overall cost of capi­tal be calculated based solely on senior debt and equity. Short term debt, the unamortized balance of ITC, and other cost free capital items, with a few limited exceptions, are removed from the company's capital structure when calculating the ITC cost rate. The resulting overall cost of capital, using the abbre­viated capital structur~, is the cost rate assigned to the ITC under the new regulations. This ITC cost rate is then used in the utility's normal ··capital structure for ratemaking purposes, including all items of capitalization, and an overall cost of capital is derived.

Staff witness Tanner calculated the ITC cost rate using the new method prescribed by the IRS regulations. Ber calculations of the ITC cost rate are shown in Exh. Nos. DLT-27, Schedule 2, p.2 of 2, and DLT-28, Schedule 2, p.2 of 2. Reference is made to these two schedules for an illustration comparing the old and new methods for calculating the ITC cost rate. Based on her analysis, Tanner found that Apco•s ITC cost rate and overall cost of capital would increase under the new method prescribed by the IRS. For example, using her updated cost of equity of 12.5% ·to 13.5%, Tanner found Apco•s ITC cost rate to be 10.90% to 11.30% (Exh. No. DLT-28, Schedule 2, p.2 of 2). Onder the old method, Apco•s ITC cost rate would be 10.10% to 10.47% (Exh. No. DLT-28, Schedule 2, p.l of 2). The new method therefore increases the ITC cost rate, the overall return, and the overall revenue requirement.

The second issue relating to ITC deals with interest syn­chronization. The new regulations provide that an interest syn­chronization adjustment on a portion of the rate base funded by ITC would not constitute an impermissible •reduction in cost of service•, under IRS S46(f)(2). In other words, the new regula­tions allow interest to be calculated as if the entire rate base were financed conventionally in the same proportions as the capital structure. Accordingly, a portion of the rate base funded by ITC is treated as if funded by long-term debt in cal­culating an interest synchronization adjustment.

Staff witness Peterson proposed an adjustment to reduce Apco's income taxes to recognize the additional synchronization

26

allowable under the new IRS regulations. The effect of the adjustment is to reduce Apco•s PIT by an additional $692,336, causing a reduction in its overall revenue requirement of ap­proximately $1.3 million.

Apco did not file any evidence addressing the merits of the Staff's proposed adjustments, nor did it address this issue in any detail in its brief. However, Apco did file a Motion to Exclude the Staff's testimony on these issues contending they were beyond the scope of an expedited rate case. The primary reason cited in support of its argument is that the Staff's ITC adjustments are inconsistent with the treatment afforded ITC in its 1983 general rate case.

I am unable to accept Apco•s invitation to ignore the new IRS regulations when deciding this issue for two reasons. Pirst, the ITC issues were not considered or addressed in Apco•s prior rate case. As previously stated, issues of first impression, not considered in a prior case, must be addressed in a later expe­dited rate case. Secondly, Apco•s argument, if carried to its logical extreme, would require the Commission to ignore all changes in state and federal laws or regulations simply because they prescribe ratemaking standards inconsistent with those ap­plied in a prior general case. In essence, Apco argues for "blind adherence• to past methods irrespective of policy changes caused by new laws, regulations or the ratemaking pro9ess itself. This is a position which I cannot accept.

The expedited rate case rules cannot be so rigid as to prevent the incorporation of newly approved IRS regulations which prescribe uniform ratemaking treatment. The Commission bas al­ways recognized that an expedited rate case should incorporate current decisions on issues common to utility ratemaking. In Vepco•s 1980 POR, for example, the Commission held that, while the POR process should not be a forum for consideration of every issue, it should incorporate changes in policy common to utility ratemaking occurring since the utility's last general rate case. 1980 sec Ann. Rep. 459, 460. Changes in policy can occur by passing new legislation, amending existing legislation, adopting or amending rules and regulations and through the ratemaking process itself. Expedited cases must be flexible enough to incorporate such policy changes.

In this case, it appears the IRS has changed its "policy• on the appropriate ratemaking treatment of ITC since Apco•s last general rate case. I therefore find this existing policy should be incorporated into Apco•s expedited rate case. Apco's exclu­sionary motion on this issue should therefore be denied, and the Staff's adjustments recalculating Apco•s ITC cost rate and addi­tional interest synchronization on a portion of the rate base funded by ITC is accepted.

27

6. Cost of Equity

Three witnesses presented testimony on Apco's current cost of equity. Joseph P. Brennan for Apco, David c. Parcell for the Attorney General, and Donna L. Tanner for the Commission's Staff. The various recommendations for an appropriate cost of equity ranged between 12.5 and 15.5%.

Apco•s witness, Mr. Brennan, used the discounted cash flow (DCP) method and a risk premium analysis to determine Apco•s cost of equity. In forming his recommendation, Brennan gave equal weight to each method and also considered what he perceived as the Commission's policy of •gradualism• established in Case No. PUE850029, Application of Potomac Edison Electric Company, Final Order dated April 2, 1986, (Appeal pending before Virginia Supreme Court).

In his DCP analysis, Brennan used AEP market data as a proxy for Apco and market data from a barometer group of six electric utilities with no nuclear plants under construction. To determine his dividend yields under the DCF analysis, Brennan used a spot market price of stock as of May 15, 1986 and a 12-month average stock price for the year ending April, 1986. Using AEP's spot price of $24.75 and a $2.26 dividend produced a dividend yield of 9.1%. AEP's 12-month average stock price of $23.89 produced a 9.5% dividend yield. Brennan then assumed a 4.7% growth in dividends to develop two additional AEP dividend yields. This produced a 9.5% dividend yield based on the AEP spot price and a 9.9% dividend yield for the 12-month average AEP stock price. Averaging all four dividend yields produced the 9.5% dividend yield that Brennan used in his DCP analysis for AEP (9.1 + 9.5 + 9 .5 + 9. 9 a 3 8 T 4 a 9 .5) •

To develop his growth rate, Brennan used market data from the Institutional Brokers Estimate System (IBES) and Value Line. According to Brennan, IBES projects a 3.9% growth in earnings per share for AEP while Valge Line projects a 5.5% growth in earn­ings. Averaging these two growth rates produced a 4.7% growth rate for AEP which Brennan used in his DCP analysis.

Finally, combining his 9.5% dividend yield and 4.7% growth rate produced a 14.2% cost of equity for AEP. Using a comparable analysis for his barometer group produced an average cost of equity of 13.0\. The following table summarizes the results of Brennan's DCF analysis:

AEP Barometer Group

DIY

9.5% 7.5%

DCP SOMMABY

+ +

28

~

4.7% 5.5%

=

•sarebones• Cost gf Equity

14.2% 13.0%

The second step in Brennan's analysis was to determine Apco•s cost of equity using the risk premium method. This ap­proach essentially attempts to determine the "risk premium• re­quired by equity investors over the returns of debt securities. Theoretically, the •risk premium• is the additional return inves­tors require to invest in common equity versus lower risk debt. Onder this approach, Brennan estimated the prospective cost of a new A-rated utility bond to be approximately 10% and the "risk premium• to be 4.5%. Combining these two values produced a 14.5% cost of equity.

The final step in Brennan's analysis was to average the results produced by his DCF for AEP and risk premium analysis. According to Brennan, the average of the 14.2% DCP and the 14.5% risk premium analysis for AEP indicates a cost of equity rate of 14.4%. Be then rounded this figure to 14.5%, which he states is the bottom of tge range from Apco•s cost of equity (Exh. No. JFB-1 0, p. 4 3).

-The upper end of Brennan's recommended cost of equity for Apco is 15.5%. His method of arriving at a 15.5% cost rate, however, is rather unusual when compared with the methods tradi­tionally used by the Commission in determining a utility's cost of equity.

In Brennan's original prefiled testimony, which was later determined to contain erroneous stock prices, his analysis produced a cost of equity of 14.9% for AEP which he rounded off to 15.0%. Be then added another 50 basis points to the market derived cost rate based upon his conclusion that Apco is more risky than AEP as measured by income volatility. Simply put, Brennan's argument in support of his upward adjustment is that a stand-alone company, such as Apco, is more risky than a group of companies as evidenced by a comparison of historical earnings volatility. In other words, Brennan contended AEP is less risky than Apco because the earnings and losses of the various AEP operating companies tend to offset one another and produce more levelized earnings for AEP. However, a stand-alone company, such as Apco, has a less reliable or more erratic stream of income. Accordingly, Brennan claimed his market derived cost of equity for AEP must be increased because Apco is more risky than AEP.

8 Although I don't question Mr. Brennan's expertise as a cost of capital witness, his mathematics suffer some serious shortcomings. The average of 14.2 and 14.5% is 14.35%. More­over, although Brennan's rounding of the cost of equity from 14.4 to 14.5% appears innocent enough at first glance, a 10 basis point increase in Apco•s cost of equity translates into an additional revenue requirement exceeding $500,000.

29

•

Brennan later discovered, however, that he used an erroneous AEP stock price in his original DCF analysis. As a result, his DCF cost rate for AEP dropped by one percentage point from 15.2% to 14.2%. This error also caused the lower end of his original recommended cost of equity for Apco to drop from 15.0% to 14.5%. Brennan did not, however, recommend that the 15.5% upper end of his range be likewise reduced to recognize his error in stock price. Be offered several reasons for continuing to support a 15.5% cost of equity.

First, he claimed that utility stock prices are unsustain­ably high causing a utility's cost of equity to be understated using a DCF analysis. Brennan therefore said that less reliance should be placed on the DCF model when determining Apco•s cost of equity.

Second, Brennan claimed that the Commission had recently adopted a policy of •gradualism• in recent rate cases when estab­lishing a utility's cost of equity. Onder this theory, Brennan said the Commission's current •policy• is to promote only gradual teductions in a utility's previously authorized retur~ on equity. Citing the Commission's decisions in Potomac Edison, and Virginia Power, Brennan claimed the Commission established a legal princi­ple that a utility's return on equity should be reduced no more than 0.5%. Accordingly, he argued that Apco•s current cost of equity should be reduced to a level no less than 15.5% (e.g., 16.0% - 0.5% =- 15.5%). As to be expected, the Commission's policy of gradualism and Brennan's relative risk adjustment generated most of the controversy and cross-examination at the hearing.

The Attorney General's witness, Mr. Parcell, used the com­parable earnings and DCP methods to arrive at his recommended cost of equity for Apco ranging between 12.5 and 14.0%. In his comparable earnings analysis, Parcell examined the returns of a group of unregulated industrials (e.g., S&P 400) over the past 10 and 5-year periods. The returns on equity averaged between 13.8 and 14.3% over the past 10 years and between 13.4 and 13.7% over the past 5 years.

The second step of his comparable earnings analysis was to compare AEP's risk with that of the unregulated industrials. Parcell concluded that AEP is generally less risky than the S&P 400 indicating a·; lower cost of equity for AEP. Be ultimately concluded that Apco's cost of equity was 13.5-14.0% under this approach.

Mr. Parcell's next approach was to assess Apco•s cost of equity using the ocr·method. Parcell used both historic and prospective market data from AEP Cas a proxy for Apco), Moody's 24 Utilities ("Moody•s•) and a group of comparison companies.

30

•

In his historic DCP analysis, Parcell calculated a range of dividend yields using an average dividend yield for the period 1981 through 1985 and a dividend yield solely for the year 1985. AEP's dividend yield ranged between 10.1 (1985) and 12.3% (5 yr. avg.) 1 Moody's ranged between 9.6 (1985) and 11.1% (5 yr. avg.); and the comparison group ranged between 10.1 (1985) and 11.8% (5 yr. avg.).

Por his growth component, Parcell used the earnings reten­tion method and examined historic growth rates for each group between 1981 and 1985. This produced an average growth rate for AEP of 0.6%, an average growth rate for Moody's of 3.8%, and an average growth rate for the comparison group of 3.8%. Combining the dividend yields and growth rates produced a cost of equity of 10.7 to 12.9% for AEP7 13.4 to 14.9% for Moody's' and 13.9 to 15.6% for the comparison group. In his final analysis, however, Parcell recommended placing primary emphasis on the low end of each range because he believes the 1985 dividend yields are more appropriate for use in today's financial market.

-Parcell also performed a second DCP analysis for AEP, Moody's

and the comparison group using prospective data. Poe his divi­dend yields, Parcell used the average stock price for AEP, Moody's and the comparison.group for the period January through June, 1986. Current dividends for each group were then increased by .5% of the expected growth rate. This produced a dividend yield of 8.89% for AEP7 8.52%- for Moody's' and 8.92% for the comparison group.

For his growth rates, Parcell used 1986 and 1988-90 growth rates using Value Line projections. This produced a growth rate for AEP of 1.15 to 3.54%; a 3.98 to 4.11% growth rate for Moody's' and a 3.48 to 3.86% growth rate for the comparison group. Com­bining the dividend yields and growth rates produced a "base­line" cost of equity of 10.04 to 12.43% for AEP; 12.50 to 12.63% for Moody's' and 12.40 to 12.78% for the comparison companies. Finally, Parcell did not propose an adjustment for issuance costs or market pressure because AEP has no current plans to issue any new common equity through 1987.

The following chart summarizes the results of Parcell's analysis:

~gmsi,lt!ll Historic P'g§J21!:=ti!:l lsU;:DiDSI DCP DCF

AEP 13.5 - 14.0% 10.7 - 12.9% 10.04 - 12.43%

Moody's N/A 13.4 - 14.9% 12.50 - 12.63%

Comparison Group N/A 13.9 - 15.6% 12.40 - 12.78%

31

After reviewing the various results produced by his analyses, Mr. Parcell found a reasonable cost of equity for Apco ranges between 12.5 and 14.0%. The Attorney General recommended using the midpoint of 13.25% when determining Apco•s overall cost of capital.

The final witness presenting cost of equity testimony was Donna L. Tanner for the Commission's Staff. In her direct pre­filed testimony, Tanner originally found Apco's cost of equity to range between 13.0 and 14.0%. In her supplemental testimony, however, she recommended a 12.5-13.5% cost of equity in recog­nition of the recent increases in the price of utility stock.

Staff witness Tanner used the DCP and risk premium methods to determine Apco•s current cost of equity. For her DCP analysis, Tanner used the market data of AEP as a proxy for Apco and market data from a barometer group of five comparable electric utili­ties. In her original testimony, Tanner used an AEP stock price of $25-$26 and a dividend of $2.26 to arrive at a 8.69-9.04% dividend yield for ASP. She estimated AEP's growth rate to be 4-5%, which resulted in a- cost of equity of 12.69-14.04%. After allowing a 25 basis point adjustment for flotation costs, the DCF model produced a 12.94-14.29% cost of equity.

In her supplemental testimony, Tanner increased the AEP stock price estimate in her DCF analysis to $27-28 given recent increases in price of AEP stock occurring in July and August of 1986. Use of the updated stock price lowered AEP's estimated cost of equity to 12.07-13.37%. After adjusting for flotation costs, AEP's cost of equity increased to 12.32-13.62%.

For her barometer group, Tanner found the expected dividend yields to range from 6.40 to 8.35%. Growth rates ranged from 4 to 7%. Combining the dividend yields and growth rates produced an average cost of equity for the barometer group ranging between 12.46 to 13.07%, with a midpoint of 12.77%. After a 25 basis point adjustment for flotation costs, the range increased to 12.71-13.32%. In Tanner's supplemental testimony, reflecting the increase in utility stock prices, the cost of equity for the barometer group decreased to 12.15-12.67,, with a midpoint of 12.41%.

Ms. Tanner's final analysis used a risk premium method. Using a risk premium of 5% combined with an 8.0% Treasury bond rate produced a 13.0' cost of equity. After adjusting for flota­tion costs, Tanner found the cost of equity to be 13.25% under this approach.

Based on her analyses, Tanner ultimately concluded that a reasonable cost of equity for Apco ranges between 12.5 and 13.5%. The Staff recommended using the upper end of the_range of 13.5% given the superior performance of Apco•s generating units during the test period.

32

As the above summary once again demonstrates, cost of capi­tal witnesses rarely agree on an appropriate cost of equity for a particular utility. This case is no exception. All the cost of capital witnesses do agree, however, that Apco•s current cost of equity is lower than the 16.0% return authorized in its most recent general rate case. Even Apco•s witness Brennan could recommend a cost of equity no higher than 15.5%. Therefore, it cannot be debated that Apco•s authorized return on equity must be reduced.

In making my recommendation in this case, I am placing primary emphasis on the DCP model. Although Apco criticized the use of the DCP model when determining Apco•s cost of equity, I continue to believe that it is a valid tool to assess a company's cost of equity. Apco may be correct in claiming that inflated spot prices may understate a utility's cost of equity under the model. Inflated stock prices do not, however, necessarily render the DCP model useless. The preferable approach, it seems to me, is to simply·avoid-extreme reaction to current, sharply higher stock prices. If the hlgher stock prices appear to be .an aberra­tion, they should be-given very little or no weight 1n the DCP model. On the other hand, if the higher spot prices appear to indicate a continuing financial trend, the DCP model should be revised to incorporate the higher price. Of course, incorporating a sharply higher stock price may cause a reexamination of the DCP growth rate since higher stock prices may be fueled, at least in part, by investors• expectations of greater future growth. I am therefore unable to accept Apco•s invitation to ignore the DCP model when determining its cost of equity. The DCP model has been used by the Commission for decades in determining the cost of equity for public utilities. The method is also flexible enough to eliminate any distortions caused by unsustainably high stock prices.

Having found the DCP model to be appropriate for use in this case, it is now necessary to determine the appropriate data to insert in the DCP model. The necessary inputs are dividend yield (a function of stock price and dividends) and growth rate.

In deciding an appropriate stock price, I believe it is essential to recognize that AEP's stock price has fluctuated by substantial amounts over the past 14 months. On December 3, 1985, for example, AEP's stock traded at $22.62 per share. Eight months later o·n August 20, 1986, just two weeks prior to the hearing, the price of AEP stock had jumped to an all time record high of $31.12 per share. This large increase in stock price caused the Staff to revise its stock price in its DCF analysis thereby lowering it~. recommended cost of equity for Apco from 13.0-14.0% to 12.5-13.5%. Interestingly enough, Apco•s witness Brennan predicted that AEP's stock price was unsustainably high causing the DCF model to understate Apco•s cost of equity. Brennan's prediction was accurate because AEP's stock price

33

plummeted to $26.37 per share on September 12, 1986. Since that time, however, AEP's stock price has rebounded and was selling at $29 per share as of January 14, 1987. A few weeks later, the price once again exceeded $30 per share.

For purposes of any analysis, I find it is appropriate to use an AEP stock price of $25-$26. I believe its appropriate to take a conservative approach in this case given the erratic price levels of AEP stock. Combining this stock price with AEP's current dividend of $2.26, produces a dividend yield of 8.69-9.04%.

The gro~th rates suggested by the witnesses ranged between 0.6% (Parcell - historic DCP) and 5% (Tanner DCP). Apco•s wit­ness Brennan ~ecommended a 4.7, growth rate but noted at the hearing that Value Line had recently projected a 5.5% earnings growth rate for AEP. After considering the recommendations of the witnesses, I find it is appropriate to use a growth rate of 4.25-5.25% for AEP. I firmly believe recent increases in the price of AEP stock is caused, at least in part, by investors• expectations of increased future growth.

Combining the dividend yields and growth rates that I have found proper results in a "barebones• cost of equity for Apco ranging between 12.94 and 14.29%. After allowing a 25 basis point adjustment for flotation costs, as recommended by Staff witness Tanner, AEP's cost of equity increases to 13.19-14.54%. Based on the evidence in this proceeding, the recommendations of the three financial witnesses, and the application of my own subjective reasoning, I find that a reasonable cost of equity for Apco ranges between 13.50 and 14.50%.

Finally, for the purpose of establishing Apco•s overall cost of capital, I believe that Apco should be authorized a 14.50% re­turn on equity. I am making this recommendation for two reasons. First, in Case No. POE850029, Application of Potomac Edison, the Commission indicated that, when determining a public utility's current allowed return on equity, it is desirable to move gradually in the direction of financial trends. This is a policy which I wholeheartedly endorse because large, abrupt reductions in a utility's allowed return on equity can cause a loss of confidence in the stock by current and prospective investors. The legacy of a loss of confidence in utility stock is higher capital costs. Moreover, it is the customers of the utility who eventually shoulder the burden of any higher capital costs.

Second, the Commission has clearly indicated in past cases that it intends to recognize both superior and inferior perfor­mance with tangible rewards and penalties. Public utilities have traditionally been authorized a return on equity in the upper end of a range of equity as a reward for superior generating unit performance. In this case, the evidence clearly reveals that Apco's generating unit performance has been excellent. The

34

equivalent availability factor CEAP) for Apco's generating units ranged from a low of 62.1% to a high of 95.5%. The weighted average BAP for all of Apco•s generaeing units was 80.0%, far above the Staff's 75% target level. As a result, Staff witness Tahamtani recommended Apco•s return on equity be set at the top of the range selected in order to reward Apco for its superior generating unit performance. I share Mr. Tahamtani's belief and find that Apco should be authorized a 14.50% return on equity when establishing its overall return.

7. Reyenue Allocation and Rate Design

Apco originally allocated its proposed rate increase by applying an equal percentage increase (10.76%) to the nonfuel component of each rate schedule. On March 27, 1986, the Staff required Apco to file revised tariffs reallocating its proposed increase to each customer class in the same proportion as each class was allocated in Apco•s 1983 general rate case. As a quick example, assuming ~he residential class was allocated SO% of the proposed increase in 1983, the Staff's method would require that 50% of the current increase be allocated to the residential class. The Staff claims its methodology would move class rates of return closer towards parity.

The Committee's witness, Mark Drazen, testified the Staff's method is inconsistent with the rate design objectives established by the Commission in Apco•s 1983 general rate case. Drazen claimed that in Apco•s 1983 case the Commission accepted the principle that rates should be designed to move toward actual cost. Be further claimed that bad it not been for the economic conditions of residential customers at that time, the Commission would have adhered to its philosophy of designing Apco•s rates based on actual cost. In support of his contention, Drazen referred to the following language of the Commission's opinion in Apco•s 1983 general rate case:

While we generally endorse the philosophy of Mark Drazen, a witness for the Old Dominion Committee for Fair Utility Rates, that rates should be cost­based with each customer class bearing its own costs, a faster move in that direction would cause residential rates to increase even more than Ap­palachian has proposed. OUr failure to accept Drazen's recommended distribution of the rate increase is a recognition of the economic hard times prevalent in much of Appalachian's Virginia service area. 1983 sec Ann. Rep. 497, 499.

Drazen further stated the Staff's allocation method produces results contrary to the rate design objectives established in

35

Apco•s most recent general rate case because it causes the LCP class to move further away from parity. In Apco•s last rate case, Drazen said the LCP class was allocated a larger share of the increase because it was earning a lower return than Apco•s jurisdictional return. A cost of service study prepared subse­quent to the case (Exh. No. BLT-20) demonstrates that Apco•s overall return, after annualizing the new rates, was 11.67% and the class rate of return for LCP was 11.62%. Accordingly, Drazen claims the LCP class is currently earning a retqrn comparable to Apco's overall return. The Staff's method, allocating yet another large increase to the LCP class, would cause the LCP class to move further away from Apco•s overall return contrary to the Commission's objectives of designing rates on cost.

Committee witness Drazen finally claimed the economy in Apco's service area has improved since 1983 and its rate schedules should now be designed to provide for a closer tracking of costs. Drazen therefore updated Apco's 1982 cost of service study to reflect •going level• 1985 costs, and recommended the increase be distributed so that each class is moved closer towards parity (Exh. No. MD-22, Schedules 7 and 11). For increases -less than Apco•s original proposal, Drazen prepared a schedule allocating the increase based on authorized increases of $17 million, $7.8 million and $6.2 million (Ex h. No. MD-23, Schedule 14).

Based on the requested $32.78 million increase, a comparison of the revenue increase allocations proposed by the parties appears as follows:

CQIPAIISQI OP RJYIIPB IBCRBASB !IJJVa~IORS

Class

Residential

Small Gen. Service

Large Gen. Service

Large Cap. Power

Industrial Power

Sanctuary Worship

Outdoor Lighting

UORG MAJOR CUftOMII CLASSBS

($000s)

OJ::iginaJ. ~I:S2J2QSAJ. ReV~§ed P,ggO§Al (eaual ' inc.::ease) (Staff's method)

$15,468 $15,266

4,625 2,669

4,463 5,822

3,554 4,360

4,152 4,450

159 129

361 87

36

Committee's Progosal

$16,242

4,117

4,716

3,595

3,944

167

-o-

There are two facts which must be kept 'in mind when resolving the revenue allocation issue. First, the Commission has consider­able discretion when designing rates to produce the amount of an increase found reasonable. Second, this case is an expedited rate case where the principal focus is an investigation of a company's financial condition and performance during the test year. Cost of service studies are not filed in expedited rate cases because cost allocation and rate design would introduce a level of complexity that is not appropriately addressed in such limited issue rate vehicles. Indeed, Rule II(3) explicitly pro­vides that "[a]llocation methodologies and rate design objectives are determined by the Commission in general rate cases.• The only rate design requirement imposed in such cases is that a utility must allocate its increase to customer classes in a manner •consistent with the Commission's order in the applicant's most recent general rate case." Rule II (3).

The Committee argues that the Staff allocation method is contrary to Rule II(3) because it produces results inconsistent with the principle~ established in Apco's prior rate case. I disagree. The allocation method appears to produce results con­sistent with the rate design objectives established in Apco's last rate case.

First, although the Commission generally endorsed the prin­ciple of designing rates based on actual costs in Apco's 1983 rate case, it is abundantly clear that cost was not the only factor considered by the Commission in Apco's prior rate case. In fact, the Commission explicitly refused to design Apco's rates based solely on cost given •the economic hard times prevalent in much of Appalachian's service area •••• " 1983 sec Ann. Rep. 497, 499. As a result, a smaller percentage of the total in­crease was allocated to the residential class in Apco's 1983 case in an effort to lessen the impact of the increase on economically disadvantaged ratepayers.

The Committee argues that the economy in Apco's service area has now improved and Apco•s rates should now provide for a closer tracking of costs. Although I agree in general that the economic climate has improved, I am not convinced that the economy in southwestern Virginia bas improved to such an extent, especially the Appalachian coal fields, that cost should be the sole or even the primary factor to be used in designing Apco's rates. Indeed, southwestern Virginia appears to remain one of the most economi­cally disadvantaged areas of the Commonwealth. Unemployment remains high in the reg ion and many ratepayers in the area can ill afford a large increase in rates.

The Committee's proposals, on the other hand, would allocate ·a disproportionate share of the increase to the residential class contrary to the rate design objectives established in Apco•s last rate case of lessening the impact of any rate increase on resi­dential customers. In fact, the Committee's proposal would

37

allocate a larger increase to the residential class than the amount originally proposed by Apco under the equal percentage method.

The Staff's method, on the other hand, allocates a much smaller share of the total increase to residential customers. The amount allocated to the residential class by the Staff's method is less than the amount proposed by the Committee or under Apco's original equal percentage method. Implicit in the Staff's method is the same realization that cost should not be the only consideration when designing Apco's rates in this case. Indeed, many factors must be considered in designing rates in­cluding •the cost of providing service, the relationship between classes of customers, value of service, marketability, encourage­ment of efficient use of facilities, broad availability of service and a fair distribution of charges among the users• (emphasis added). Westyaco Corp. v. Columbia Gas of Virginia., 230 Va. 451 (1986) 1 Secretary of Defense v. C&P Telephone Co., 217 Va. 149 (1976).

The second conc~n I have with the Committee's proposal is the attempt to design rates in an expedited rate case based on a cost of service study. Not only has a cost of service study never, to my knowledge, been used to design rates in an expedited rate case, but the Committee's allocation method is based on a 1982 cost of service study updated to reflect 1985 •going level• costs. As the Commission is aware, the manner of developing a cost of. service study and class rates of return is a rather imprecise exercise even with the benefit of an accurate, up-to­date cost of service data. It literally requires the allocation of every asset and expense of the company from the largest gener­ating units to pens and pencils used by meter readers to record usage. Suffice it to say that designing rates based on accurate, up-to-date data is a complicated endeavor. Updating a cost of service study which is over four years old to design current rates is bound to cause inaccuracies given the constant and continuing changes in load, usage patterns and customer mix, all of which affect the current level of revenues and expenses being experienced by any particular class.

Simply put, I have two concerns with the Committee's proposal. First is the attempt to design rates based on a cost of service study in an expedited rate case, thereby increasing the complexity of a case which is designed primarily to review a utility's financial condition. My second concern is the use of an outdated cost of service study which I believe is inherently unreliable.

In past expedited rate cases, the Commission has used three methods to allocate increases: (1) the equal percentage method, (2) a uniform surcharge per Mcf for certain gas companies, and most recently, (3) the Staff's allocation method used to design

38

the utility's interim rates approved in this case. After con­sidering the evidence in this case, I find the Staff's allocation method should be approved. Not only does this method produce rate design results consistent with Apco•s prior general rate case, but it also has the Commission's stamp of approval in two recent expedited rate cases. Application of Soythwestern Virginia Gas Co., Case No. POE860010, Final Order dated August 6, 1986; Application of Virginia Natural Gas, Case No. POE850036, Pinal Order dated June 30, 1986. Finally, the allocation method represents a simple, uncomplicated method of allocating rate increases consistent with the spirit of expedited rate cases. For these reasons, I recommend the Staff's allocation method be used when redesigning rates to produce the lower amount of revenue approved in this report.

liNANCIAL SUMMARY

Based on the above findings, Apco's overall cost of capital is 10.87,, This cost ot capital is derived by incorporating a 14.50' cost of equity, calculating the ITC cost rate.consistent with the requirements of the new IRS regulations and including deferred taxes and customer advances in the capital structure as cost-free capital. It also assumes acceptance of the Staff's nondisputed adjustments, which I find reasonable. Accordingly, I find the following capital structure and weighted cost of capital should be adopted when determining Apco's aggregate revenue re­quirement.

Capital Structure and Cost of Capital

December 31, 1985

Amount llmD COOOsl 1 ~

Short-term debt $ 7,397 0.31 8.90

Long-term debt 1,047,569 43.51 9.48

Preferred Stock 231,554 9 .• 62 11.28

Common Equity 867,136 36.02 14.50

Investment Tax Credits 83,219 3.46 11.71

Cost-Free Capital 170.602 7.08 -o-$2,407,477 100.00

39

Weighted ~

0.03

4.12

1.09

5.22

.41

-o-10.87'

Apco•s revenue deficiency, consistent with my findings, is $16,632,812 calculated as follows:

Reyepae Beggirewept Calaglation

Rate Base

OVerall Cost of Capital

Net Revenue Requirement

Adjusted Net Operating Income

Net Revenue Deficiency

Tax Conversion Factor

Gross Revenue ~eficiency

FINPINGS ANQ BECOMMENPATIONS

$995,050,463

10.87%

$108,161,985

-99,433.468

8,728,517

.524777

$16,632,812

After considering the evidence in this case, I find that:

(1) The use of a test year ending December 31, 1985, is proper in this proceeding,

(2) Company's net operating income - adjusted for the test period is $99,433,4687

(3) 13.50 to 14.50 percent is a reasonable range for Com­pany's cost of equity, and that Company's rates should be de­signed to generate a 14.50 percent return on equity given the superior performance of Company's generating units during the test period,

(4) Company's weighted cost of capital as of December 31, 1985, is 10.87 percent1

(5) Company's year end rate base for the test period is $995,050,4637

(6) Company's rates should be increased to produce $16,632,812, which is the amount necessary to produce a 10.87 percent return on year end' rate base,

(7) Company's interim rate design, which allocates the in­crease to each class in the same proportion as each class was allocated in Company's 1983 general rate case, is reasonable,

40

(8) Company should be directed to file revised tariffs to produce the amount of additional revenues found reasonable herein; and

(9) Rates in effect on an interim basis since May 1, 1986, are designed to collect $29,370,412, in additional annual revenues, which is more than that found reasonable herein on an annual basis. Company's customers are therefore due a refund based on the difference between the interim rates and the rates approved herein for all collections made during the interim per-iod.

I therefore recommend that the Commission enter an order in this proceeding which:

(l) Directs the prompt refund to customers of the excess revenues already collected under the interim rates in effect in this case; ·

-(2) Permits rates calculated in accordance with the findings

. made in this report to be placed into effect on a permanent basis; and

(3) Dismisses this case from the Commission's docket of active cases.

BESPONSES

The parties are advised that any exceptions to this Report must be filed with the Clerk of the Commission in writing, in an original and fifteen (15) copies, within fifteen (15) days from the date hereof. The mailing address to which any such filing must be sent is Document Control Center, P. o. Box 2118, Richmond, Virginia 23216. Any party filing such exceptions shall attach a certificate to the foot of such document that copies have been mailed or delivered to all other counsel of record and to any party not represented by counsel.

Respectfully submitted,

~L Glenn P. Richardson Bearing Examiner

41

Document Control Center is requested to mail or deliver a copy of this Report on February 4, 1987, to John L. Walker, Jr., Esquire, and B. Allen Glover, Jr., Esquire, P. o. Box 720, Roanoke, VA 24004-07207 to Charles F. Midkiff, Esquire, Midkiff & Associates, PC, 115 s. Third Street, Richmond, ~ 232191 A. c. Epps, Esquire, and Louis R. Monacell, Esquire, 1200 Mutual Building, Richmond, VA 232197 to James c. Dimitri, Esquire, and Anthony Gambardella, Esquire, Division of Consumer Counsel, Office of the Attorney General, 101 North 8th Street, Richmond, VA 232197 to Fielding L. Williams, Jr., Esquire, and Walter B. Ryland, Esquire, P. o. Box 1320, Richmond, VA 23210, to Glenn J. Berger, Esquire, 919 Eighteenth Street, N.W., Washington, D. c. 20006, to Kenworth E. Lion, Jr., Commission Counsel, and to the Commission's Divisions of Energy Regulation, Accounting and Finance, and Economic Research and Development.

42

SCC·62

.-.~) :.-;l~! i u~ f~1 3: \2 \~c·J ·--~~ ' APPUCATION OF

a ~l

COMMONWEALTH OP VlllGINIA

VIRGINIA ELECTRIC AND POWER COMPANY

For an increase in base rates

Supplement B {

CASE NO. PUE880014

BEPORT OF GLENN P. RICHARDSON, HEARING EXAMINER

November 10, 1988

HISTORY OF THE CASE

On May 20, 1988, Virginia Electric and Power Company ("Virginia Power" or

"Company') filed an application for an expedited increase in base rates under the

Commission's Rules GovembigUtiiity Rate Increase Applications. The application

proposed rates that would produce additional annual operating revenues of

$96,696,000, based upon the test year ending December 31, 1987. The Company

requested permission to place the proposed rates into effect on an interim b~is,

subject to investigation and refund, for service on and after July 1, 1988.

On June 15, 1988, the Commission entered an order suspending the proposed in­

crease for the full 150 days authorized by Virginia Code §56-238. In ordering the

suspension, the Commission noted that Virginia Power's base· rates were reduced by

approximately $44.3 million on April 7, 1988, in Case No. PUE870014. The Commission

held that the Company's current application, filed only 6 weeks after the major rate

reduCtion ordered in Case No. PUE870014, represented a "substantial change" in

circumstances justifyibg a 150 day suspension of the proposed rates. By order dated

June 24, 1988, the Commission modified the terms of the suspension to commence on May

20, 1988. Otherwise, the full iso day suspension period was affirmed and the proposed

rates were suspended through October 17, 1988.

On June 30, 1988, the Commission entered an order scheduling a hearing on the

application to commence on September 8, 1988. The Company was further directed to

revise its original filing to reflect a rate year beginning on October 18, 1988.

The application came on for hearing on September 8, 9 and 12, 1988. Counsel

appearing were Evans B. Brasfield and Edgar M. Roach, Jr., for Virginia Power; AC.

Epps, Hullihen W. Moore, and Carol C. Raper for the Virginia Committee for Fair

Utility Rates ("the Committee"); William S. Bilenky, for the Division of Consumer

Counsel, Office of the Attorney General; Senator Clive L Du Val2d, and Donald G.

Owens for the Senator's Northern Virginia constituents; Edward L Flippen for #

Chesapeake Corporatio~ Stone Container Corporation and Westvaco Corporation; and

Anthony Gambardella, Deborah V. Ellenberg, and Wayne N. Smith for the Commission's

statt1

POSmON OF THE PARTIES

All parties agree that two basic inquiries must be made in this case. First,

whether Virginia Power's earnings in 1987 were sufficient to allow the Company to

fully recover the capacity charges deferred in its books between January 1 and

September 13, 1987. This inquiry can only be answered by examining the Company's

"actual" operating results for 1987. Moreover, since the emphasis of this inquiry

1Notices of Protest were filed by the Board of Supervisors of Fairfax County, Peoples Drug Stores, Incorporated ("Peo~les") and Old Dominion Electric Cooperative ("ODEC'). Fairfax County withdrew its Notice of Protest on September 6, 1988, and elected to participate as an intervener. Peoples and ODEC did not appear at the hearing. Therefore, Virginia Power's Motion to Dismiss these parties was granted when the hearing commenced September 8. Finally, counsel for Virginia Power and Chesapea.Ke, Stone Container and Westvaco requested that a separate proceeding be commenced to consider Virginia Power's Schedule 8. By Ruling dated September 13, 1988, the parties' proposal was accepted and the Examiner re.commended that the Commission enter an order initiating a separate proceeding to consider Schedule 8. By order dated October 27, 1988, the Comnnssion severed the consideration of Schedule 8 from this proceeding.

2

relates to historic operating results· for 1987, the traditional ratemaking analysis

with its restatement of test year operations and adjustments for known and measurable

changes occurring after the test period is inappropriate. The parties have aptly

described this inquiry as a historical "earnings test."

The second inquiry is a prospective, or forward looking analysis to determine

whether current rates, after fully adjusting 1987 test year data, will produce a

reasonable return in the future. This second inquiry is simply the traditional rate­

making analysis performed for every utility seeking a rate increase.

Virginia Power argued it is entitled to a base rate increase of at least

$96,696,000. Although the revenue deficiency increased to approximately $107.7

million when the Company revised its filing for a new rate year, the Company's final

analysis showed a revenue deficiency of $96,941,000. This deficiency reflected all

changes and corrections made during the course of the proceeding, as well as the

Company's acceptance of several of the adjustments proposed by other parties.

Of the $96,941,000 deficiency, $16,972,000 is related to the recovery of one­

half of the Company's 1987 deferred capacity charges. The Company argued that it is

entitled to a full recovery of these deferred charges because it did not recover

these costs during 1987. Its analysis revealed that it earned less than its

authorized return on equity during 1987 even if the capacity charges are not

considered If the deferred capacity charges were fully expensed during 1987, the

Company said that its earnings were depresse~ far below a reasonable rate of return.

The baiance of the proposed increase, mD:Ounting to approXimately $79,969,000,

was due to the growth of the Company's rate base, substantial increases in operating

costs, termination of the ODEC settlement payments and an increase in the equity

rati~ in the Company's capital structure. According to Virginia Power, a $96,941,000

increase in base rates is the minimum amount necessary to produce its authorized

3

return on equity of 13.25%. However, the Company continued to request the lesser

increase of $96,696,000, set forth in its original application. ·

The Commission's Staff investigated the Company's application and concluded that

no increase in base rates should be granted The Staff found that Virginia Power

fully recovered its deferred capacity charges during 1987. Any additional allowance

for these charges in future rates would result in a double recovery of the charges

from ratepayers.

The Staff further argued that current rates are just and reasonable. After

fu.lly adjusting the Company's 1987 operating results, the Staff concluded that

current rates produce a return on equity ~f 12.64%.2 Since this return falls squarely

within the 12.5% to 13.5% range established in the Company's last rate case, the

Staff argued that no additional increase should be granted.

The Attorney General and Senator DuVal concurred with the results of the Staff's

investigation. Both said that Virginia Power fu.lly recovered its deferred capacity

charges in 1987. They also claimed that current rates, after fully adjusting 1987

operating results, produce a return on equity within the range established by the

Commission in the Company's last rate case. Accordingly, no increase in rates should

be granted.

The Committee did not recommend that Virginia Power's rate request be denied in

its entirety. Rather, the Committee found that Virginia Power needed an increase of

$27,241,000 in order to give the Company an opportunity to eam the 13.25% return on

2rrhe Company's return on equity in the Staff's closing brief was calculated to be 12.68%. This equity return was bas~d on acceptance of the Company's updated capacity costs, disallowance of North ·Anna tube repair and spar arm replacement costs, removal of unamortized front ...end costs of certain nuclear fuel assemblies, and updating the Westinghouse recovery balance and accumulated deferred fuel balance.

4

equity authorized in the Company's last rate case. The Committee made no allowance,

however, for the Company's 1987 deferred capacity charges.· The Committee's earnings

test revealed that Virginia Power fully recovered its deferred capacity costs in 1987.

DISCUSSION

Although most of the evidence in this case related to the Company's deferred

capacity charges and the reasonableness of current rates, there is an additional

issue raised by the Company in its closing brief concerning the permissible scope of

an expedited rate case. Virginia Power argued that certain ratemaking adjustments

proposed by the Staff and other parties, most notably the adjustments for customer

growth, prior period taxes, and cash working capital, were beyond the scope of an

expedited rate case. The Cow,pany therefore urged the Commission to dismiss these

issues on procedural grounds alone and not consider the merits of the proposals in

this limited issue proceeding. Since Virginia Power is attempting to limit the

examination of these issues on procedural grounds, the scope of this proceeding must

be clearly defined before addressing the merits of each issue raised in this case.

I. SCOPE OF AN EXPEDITED RATE CASE

This one issue has undoubtedly generated more discussion and debate over the

last eight years than any other issue raised in utility rate cases. Indeed, Virginia

Power devoted over s~ven pages of its closing brief explaining why it would be

inappropriate for the Commission to consider the merits of several issues the Company

believes are beyond the scope of an expedited rate case. (Company briefpp. 4-10).

The only other party to address this issue in any detail was the Attorney

General. Mr. Bilenky argued that any restraints imposed on parties other than the

utility would violate that party's right of due process. The Staff and the Committee

5

did not attempt to define the permissible scope of an expedited case. The Staff

merely suggested that its proposed annualization adjustment for customer growth could

be considered in an expedited rate case.

As the Commission is aware, the permissible scope of an expedited rate case has

been discussed at length in numerous past decisions and will not be repeated in any

detail here. See Westvaco Corp. v. Columbia Gas of Vuginia, 233 Va. 135 (1987);

Application of Appalachian Power Company, Case No. PUE860015, Report of Glenn P.

Richardson, Hearing Examiner, pp.4-10 (February 4, 1987); Westvaco Corp. v. Columbia

Gas ofVuginio, Inc. 230 Va. 451,454-55 (1986);Application of Virginia Natural ,

Gas, Case No. PUE850036, Interim Order (April 8, 1986); Roanoke Gas Co. v. Corporation

Commission, 225 Va.186, 188 (1983); Application ofVuginiaElectric and Power

Company, Case No. PUE800056, Report of Stewart E. Farrar, Hearing Examiner, pp.7-8

(July 28, 1980); Application of Vuginia Electric and Power Company, 1980 SCC Ann.

Rep. 459,460-61. All these cases recognize that issues in expedited rate cases are

more limited than those presented in general rate cases. Limits have been imposed so

expedited rate cases can remain a workable concept and viable alternative to general

rate cases. As a result of this distinction, such issues as a company's return on

equity, certain accounting adjustments and rate design are held constant in an

expedited rate case.

The flaw with Virginia Power's argument, however, is that issues are limited

only if a utility has not experienced a substantial change in circumstances since its

last general rate case. If a substantial change has occurred, Rule II provides that

" ... the Commission may take appropriate action, such as directing that the applica­

tion be dismissed or treated as a general rate [increase] application." Here, the

Commissio~ bas previously found that a substantial change in circumstances occurred

since Virginia Power's last rate case, where a major reduction in rates was ordered.

6

Indeed, the reduction was ordered only 6 weeks prior to Virginia Power's current

application. The current increase was therefore deemed to represent a substantial

change in circumstances. The "appropriate action" taken was to suspend the proposed

increase for the fulllSO day period authorized by Virginia Code §56-238.

After reviewing the evidence submitted by Virginia Power's witnesses and after

considering the sheer magnitude of the proposed increase filed so soon after a major

rate reduction, I share the Commission's view that a substantial change in circum­

stances has occurred since the Company's last rate case that requires, indeed

demands, that a more comprehensive review of the application be made than the limited

review contemplated by the expedited rules. It must be remembered that only seven

months ago Virginia Power was ordered by the Commission to reduce its base rates by

$44.3 million and to refund aJ!no~~ $80 million in exce~ deferred taxes created by the

Tax Reform Act of 1986. This reduction was ordered in recognition of a substantial

and unprecedented decline in the Company's cost-of-service.

In its current application, however, the Company claims that its cost-of-service

has increased to such an extent that a rate increase of almost $97 million is

necessary to allow the Company an opportunity to earn a reasonable rate of return.

While almost $17 million of the increase is related to the recovery of deferred

capacity charges, a cost that the Commission directed to be considered in this case,

the $80 million balance of the increase was requested, almost literally, before the

ink was dry on the Commission's order of April 8, 1988. A $97 million rate increase

proposed so soon after a major rate reduction is confusing to the public, causes rate

instability and merits a thorough and comprehensive examination by th~ Commission.

The limited scope of an expedited rate case precludes such an in-depth examination.

Under Rule II, a finding of a substantial change in circumstances allows the

Commission to take appropriate action. Such action may include a dismissal of the

7

Company's current application, treating the application as a general rate increase

application, or any other action the Commission finds appropriate. Obviously, a

dismissal of the current application at this late stage would prejudice the Company.

Nevertheless, I believe an outright dismissal of the current application could easily

and legitimately be ordered under the Commission's rules. A substantial change in

circumstances has occurred, and a dismissal of the application is a form of "appro­

priate action" contemplated by the Commission's rules. On the other end of the

spectrum of permissible "appropriate action", is the removal of the traditional limits

imposed in expedited rate cases. See, for example, the Commission's decisions in

Application of Columbia Gas of Vuginia, Case No. PUE850053, Interim Order dated

AprilS, 1986, andApplication of Appalachian Power Company,. Case No. PUE860015,

Interim Order dated April3Q.L 19~6. In these cases the Commission allowed the

utilities' return on equity to be litigated by all parties based upon a finding of a

substantial change in the cost of capital.

Based on the substantial change in Virginia Power's cost-of-service ''alleged" in

its application, I find it is appropriate to treat this application as a general rate

case and remove the limits traditionally imposed upon parties in an expedited rate

case. Although I suspect I will be criticized by Virginia Power for taking this

action sua sponte, I would hasten to point out that the Company itself has proposed

several adjustments that do not technically comply with the expedited rules.

Rule II (2), for example, provides that a utility requesting an expedited

increase in rates must comply " ..• with the instructions accompanying schedules 12,

13, and 14 ... ". The instructions to schedule 14 provide that "[p]roforma adjustments

will be limited in expedited cases to the amount of increase or decrease that will be

in effect durin& the proforma period. with the exception of fuel expenses." (emphasis

added) A brief review of the Company's testimony and supporting schedules reveals

8

many proposed adjustments that are not limited to the increase or decre~e in effect

during the proforma period.3 Many adjustments reflect a full rate year level of

expense in direct contradiction to the instructions contained in the rules. Moreover,

in its rebuttal testimony the Company proposed to use an updated capital structure in

calculating its cost of capital rather than an end of test period capital structure

traditionally used in expedited cases. These ratemaking adjustments and proposals are

no different than those traditionally proposed and considered only in the context of a

general rate case. For obvious reasons, if the rules are to be applied, all parties

must comply with the limits imposed by the expedited rules.

In making these observationS, I hope all parties recognize that I am not

attempting to criticize Virginia Power for its actions. My observations are made for

one simple reason: all parti~~ shQuld be subjected to the same rules in a rate case.

A utility or any other party should not be allowed to argue inconsistent and mutually

contradictory positions in an expedited rate case. If Virginia Power seeks to impose

limits on other parties, it must also be subjected to the limits imposed by the

expedited rules and be required to me an application consistent with the rules.

Its current application, however, is clearly-inconsistent with the expedited rules.

Accordingly, for the reasons set forth above, I find that Virginia Power's

current application should be treated as a general rate increase application. I

further find that no limits should be imposed on any parties in this case given the

substantial change in circumstances occurring since the Company's last rate case.

3Examples of adjustments that are not limited to the effective level during the proforma penod include: (1) the termination of the ODEC settlement payments, (2) Salary and Wages/Fringe Benefits, (3) projected capacity costs, (4) a cash working capital allowance based on "rate year" level of fuel costs and (5) a new adjustment to restore certain Westinghouse settlement credits back to rate base.

9

ll. DEFERRED CAPACITY CHARGES ·TilE 1987 "EARNNNGS TEST"

In Virginia Power's last rate case it sought to recover approximately $32.9

million of estimated capacity charges deferred on its books between January 1 and

September 13, 1987. The Commission refused to allow recovery of these c~arges in Case

No. PUE870014 because the charges fell outside the test year. As a result, the record

in the prior case did not contain sufficient financial data to determine whether 1987

revenues were adequate to allow a complete recovery of the charges. The Commission

therefore ordered that the issue be reconsidered in the Company's 1987 Annual

Informational Filing. This would prevent a potential double recovery of the charges

from ratepayers, while offering the Company relief against a significant cost-of-

service shortfall.

All parties agree that ~e r~covery of the deferred capacity charges depends on

whether Virginia Power's earnings were sufficient in 1987 to allow it to fully recover

the charges. To make this inquiry, one must determine the Company's 1987 return on

equity after fully expensing the Company's deferred capacity charges. If the

resulting return on equity is equal to or greater than the Company's authorized return

on equity, the deferred capacity costs were fully recovered in 1987 and no further

allowance in future rates is necessary. Conversely, if the Company's return on equity

during 1987 was below its authorized return, the Company did not fully recoyer the

deferred charges and an allowance in future rates would be appropriate. Although the

earnings test is simple enough to describe, the specific parameters of the test and

its actual application to the Company's 1987 operating results generated substantial

controversy.

Virginia Power's analysis, sponsored by Company witness Bolton, showed the

Company earned a return on equity of 11.95% in 1987 after the deferred capacity

charges were fully expensed. (Exh. No. MSB-2, pp. 7-8) Since this return was below

10

the Company's proposed benchmark return on equity of 14.24%, Mr. Bolton testified that

the Company was entitled to a full recovery of the deferred eharges in future rates.

He proposed that the charges be recovered over a two year period This would increase

the Company's revenue requirements by approximately $16.97 million.

All other parties argued that the deferred capacity charges were fully recovered

during 1987. Any additional allowance in future rates would allow a double recovery

of the charges from ratepayers. Staff witness Peterson found that the Company earned

a 13.29% return on equity in 1987 after fully expensing the deferred capacity charges.

(Exh. No. KKP-9, Col. 5, line 25). Committee witness Dooley calculated a return on

equity of i3.94% in 1987, well in excess of the range of 12.5% to 13.5% found reason­

able by the Commission in the Company's last rate case. (Exh. No. BCD-15, Sch. 1).

Atto~ey General witness S!QnJaq also concluded that the Company fully recovered its

1987 deferred capacity charges. (Exh. No. AFS-14, pp. 4, 9-10) His conclusion,

however, was based upon 1987 operating results with all of the traditional proforma

and rate year adjustments that are normally used to set rates for the future. For

obvious reasons, a fully adjusted test year is of little value when determining

whether Virginia. Power fully recovered its 1987 deferred charges. Our inquiry must

focus on actual operating results for 1987, not hypothetical future results generated

from fully adjusted 1987 test year data.

The parties found almost as many issues to discuss in applying the earnings test

as they did when investigating the reasonableness of current rates. The disputed

issues caused a wide divergence in the calculated returns on equity for 1987 ranging

from a 11.95% returq, supported by Company witness Bolton, to a 13.94% return on

equity calculated by Committee witness Dooley. A brief discussion of each disputed

issue follows.

11

1. Westinpouse Settlement Credits

This issue first arose in Virginia Power's 1985 fuel factor proceeding, Case No.

PUE850001. During the course of that proceeding, the Commission discovered that

ratepayers were not receiving the full benefit of ~e settlement which Virginia Power

received from Westinghouse Corporation as a result of its breach of contract to

supply Virginia Power with uranium for its nuclear generating units. As the

Commission recognized:

The settle~ent provided funds in excess of the level currently required to supply the utility with the necessary volumes of leased and purchased nuclear fuel. Although the ratepayers are paJ41~ all capital costs associated with nucfear fuel, the utility's accounting methodology gives only partial benefit to the ratepayers for the cost-free ~itill acquired throup the Westinghouse settlement. E1 ~ In re: Investigatton to detennine appropriate tariffs pursuant tg_Cocle §56-249.6 for V"uginia Electric and Power Co., 1985 SCC Ann. Rep. 450.

In order to give ratepayers the full benefit of the Westingho~e settlement, the

Commission made two ratemaking adjustments effective December 18, 1985. First, in

Case No. PUE840071, the Commission deducted the total balance of the Westinghouse

settlement credits from the Company's rate base. Second, the Commission directed

that Virginia Power cease recognizing in its fuel factor the credit associated with

interest on cover uranium for leased nuclear fuel. The Company was also directed to

refund approximately $12.3 million of overcollected ·interest through its fuel factor

commencing on May 1, 1986.

Both the Company and the Staff proposed adjustments in their prospective

analyses to remove the effects of the refund in future rates. Staff witness Peterson

proposed a comparable adjustment for purposes of his earnings test for 1987. This

had the effect of increasing operating revenues by $3,396,000, for purposes of the

earnings test and increased ~e Company's 1987 return on equity to 13.29%.

(Exh. No. KKP-9, Statement I revised, Tr. pp. 154-55).

12

Company witne~ Bolton claimed the Staffs adjustment was improper. While he

supported the adjustment for setting future rates, Mr. Bolton claimed the adjustment

should not be accepted when evaluating Virginia Power's actual earnings for 1987.

According to Mr. Bolton:

The refund made in 1987 represents costs that were actually recorded in that year. The propriety of that refund has not been questioned. ... These costs, like all other costs incurred during 1987 ... ought to be included in the test for purposes of determining what the Company actually earned on tts common equity investment. (Tr. pp. 539-40)

I find the Staffs proposed adjustment to remove the effects of the Westinghouse

settlement credit should be accepted for several reasons. First, the Westinghouse

refund is related to Virginia Power's overcollection of interest between 1980 and

1985. The refund is therefore directly related to prior periods and could be

excluded from 1987 operating resUlts on this basis alone. Nevertheless, there is a

more fundamental reason why this adjustment must be made.

Mr. Bolton was clearly mistaken when he characterized this refund as a "cost" to

the Company. The refund is simply a return to the ratepayers of dollars that were

overcollected by Virginia Power in prior periods. It is not a true .. cost" as that

term is commonly understood.

In addition, failure to reverse the effects of the Westinghouse settlement

credits will understate the Company's 1987 earnings by reflecting a "phantom" short- •

fall in operating revenues. To illustrate this phantom shortfall, it must be

remembered the refund was made through the Company's fuel factor. As a result of

this refund mechanism, the Company's 1987 fuel revenues were lower than normal

because the refund was reflected as a credit to the Company's fuel factor. To give

ratepayers the full benefit of the refund, 1987 operating revenues must be restated

to remove all effects of the refund.

13

The Staff's adjustment to 1987 operating revenues to reverse the effect of the

Westinghouse settlement credit is accepted.

2. Prior Period Exvenses

Prior to the 1987 test year, Virginia Power incurred certain costs studying the

feasibility of constructing a new fossil fuel generating unit and studying sources

of alternate energy. These costs were accumulated in a suspense account over a

period of several years rather than expensed currently on the Company's books. In

1987 the Company decided to terminate both studies. The costs were therefore fully

expensed in late 1987.

Staff witness Peterson proposed that these costs be removed from the earnings

test because the costs were attributable to several years preceding 1987. His

adjustments to remove the COsts of the two studies reduced the Company's 1987

expenses by approximately $6.2 million. (Exh No. KKP-8, Sch. A, adjs. 1 and 2).

However, since Mr. Peterson found the costs were prudently incurred, he did not

recommend that the study costs be denied in their entirety. Rather, he recommended

that Virginia Power be allowed to recover the full balance of the costs over a three

year period commencing on the effective date of the new rate year. (October 18,

1988) In other words, Mr. Peterson proposed that the costs be fully recovered in

future rates but not considered for purposes of the 1987 earnings test.

Although the Company agreed with Mr. Peterson's proposal to recover the costs in

future rates, the Company maintained that it would be improper to remove the costs

from the earnings test. According to Company witness Bolton:

An accurate measure of what the Company actually earned in 1987 must take into account all proper expenses actually recorded in that year. No question has been raised as to the propriety of recording those expenses in 1987, and it was proper because the events that led to the expensing of the projects occurred in that year. Since they were properly expensed in 1987, they must be included in the

14

calculation of the earned rate of return on common equity •.••• To remove them from the earnings calculation on which the recovery of deferred capacity costs will depend is inconsistent and Unfair to the Company. (Exh. No. MSB-28, p. 14). .

Contrary to the Company's claim, it is not inconsistent or unfair to the Company

to adopt the Staff's proposed treatment of these two items. In fact, a very persua-

sive argument can be made that Virginia Power's proposed treatment is inconsistent

and unfair to ratepayers. As the Staff noted in its closing brief, " ... the Company

would be effectively allowed double recovery of those costs if they are included in

the 1987 cost of service and also included in the cost of service calculation used to

set future rates.11 (Staff brief, p. 7, Tr. p. 173-75).

There are also two additional concerns I have with the Company's proposal.

First, the costs were incurrect_pri~~ to the test period and should not be considered

when reviewing actual operating results for 1987. When reviewing the Company's 1987

earnings, only revenues, expenses and investment related to that year should be

considered in determining whether the Company fully recovered its deferred capacity

charges. Recognition of any prior period items in the earnings test will only

distort actual operating results and render it virtually impossible to determine

whether the Company fully recovered its deferred capacity costs. Moreover, the

Staff is being extremely charitable in recommending that the costs be recovered in

future rates. Prior period items are usually totally excluded from a utility's cost­

of-service.

Another concern I have with the Company's argument relates to the timing of

entries on the Comp~y's books. The Company has considerable latitude when

determining when to expense prior period items booked over several years and carried

in suspense accounts. The Commission must therefore scrutinize the Company's expenses

very closely to ensure that costs included in the earnings test are true 1987 costs,

15

not costs generated solely by a company's decision to expense prior period items.

Here, the future fossil site study costs and alternate energy costs were

generated primarily by the Company's decision to expense these prior period items in

late 1987. Including these prior period costs in the earnings test would distort

1987 results by reducing the Company's reported return on equity. Accordingly, the

Staff's proposal to remove these costs from the earnings test, but allow a full

recovery of the costs in future rates is fair and reasonable.

3 . .TDC Capital Egense

The Company and the Staff included JDC capital expense in their calculation of

Virginia Power's earnings during 1987. (Exh. Nos. CKT -4, pp. 4-5; KKP-8, p. 5).

Committee witness Dooley, however, recommended that Company's JDC capital expense be

excluded from the earnings test because it represents an imputed expense which

Virginia Power did not actually incur. (Exh. No. BCD-15, P.· 11). Mr. Dooley's exclu-

sion of JDC capital expense and his use of average rate base to measure earnings,

produced a return on equity of 13.94% for 1987 even after the Company's deferred

capacity charges were fully expensed.

Company witness Trible maintained that JDC capital expense is a ratemaking

adjustment that is mandated by Section 46(f)(2) of the Internal Revenue Code. JDC

capital expense DlllS1 be recognized if Virginia Power wants to retain the considerable

tax benefits associated with investment tax credits. H the Committee's adjustment

was accepted, Mr. Tnble testified that:

... it would attribute to common equity the earnings mandated by Congress for JDC, with the result that, for ratemaking purposes, the return on common equity [for 1987] would be correspondingly overstated. ... H earnings attributable to JDC are included in the return on common equity, it could be the controlling factor in determining whether Cle(erred capacity charges will be recovered. The denial of recovery on the basis of such inclusion would be a denial of a return

16

on JDC, which is prohibited by the Internal Revenue Code. (Exh. No. CKT -4, p. 5)

The Committee responded to Mr. Tnble's criticism by arguing that the IRS

mandate only applies to setting rates for the future, and the Committee has no objec­

tion to including JDC capital expense in the context of prospective ratemaking.

However, there is nothing in the tax code that requires inclusion of the JDC capital

expense in the earnin~ test calculation. (Committee briefp.16)

It is true, as the Committee points out in its closing brief, that no provision

in the Internal Revenue Code or IRS rulings specifically addresses this issue.

Nevertheless, the legislative history of section 46(t) gives the Commission

considerable guidance in this matter. The House Report to the Revenue Act of 1971,

the legislation that added section 46(t) to the Internal Revenue Code, states:

In restoring the -investment credit for public utility property of regulated companies, the committee has given careful consideration to the impact of this credit on ratemaking decisions. Although there are many different ways of treating the credit for ratemaking purposes, your committee, in general, believes that it is appropriate 12 diyide the benefits of the credit between the customers of the regulated industries and the investors in the regulated industries. (emphasis added) H.R. Rep. No. 92d Cong., 1st Sess. 24, U.S. Code Cong. & Admin. News 1971, 1839 (1971)

In past utility rate cases before the Commission, the benefit of the investment

tax credit has been shared The ratepayer receives a benefit from the credit by a

reduction in the utility's federal income taxes by a ratable portion of the credit.

The investor receives a benefit by earning a return on the unamortized balance of the

credit. Use of this methodology ensures that both the ratepayers and investors

receive a benefit from the investment tax credit, as mandated by Congress.

The Committee's proposal, however, would upset the balance of ratepayer and

investor benefits. In effect, the ratepayers would receive all the benefits of the

investment tax credit under the Committee's proposal. The investor would receive

17

absolutely nothing. The Committee's proposal, for example, would not only allow

ratepayers to receive the benefit of reduced federal income -taxes in 1987 as a result

of the credit, but its proposal would also impute to ratepayers the return that

Congress bestowed to investors. Such a result is directly contrary to the clear

legislative intent of section 46(f) of the Internal Revenue Code.

There is also a distinct possibility that accepting the Committee's proposal on

this matter could be deemed an impermissible reduction in Virginia Power's cost-of­

service under section 46(f)(2). This of course would cause a forfeiture of the

credit. Prudence dictates a cautious approach in this case, for the consequences of

an error in the construction of the Internal Revenue Code could result in the total

loss of an extremely valuable tax benefit for both the utility's ratepayers and

investors.

For these reasons, the Committee's proposal to remove the Company's JDC capital

expense from the earnings test is denied.

4. Ayeraa y. Year-End Investment

Both the Commission's Staff and Committee supported the use of average, rather

than year-end investment to measure Virginia Power's 1987 earnings. Although both

readily admitted that the Commission traditionally uses year-end investment when

setting future rates, they argued that a distinction must be drawn when examining

historic earnings.

Witnesses for the Staff and Committee testified that use of year-end investment

is mm appropriate when setting future rates. This is because year-end investment

operates as an attrition allowance designed to offset the effects of "regulatory

lag". By contrast, attrition is not a relevant consideration when revieMD:g historic

earnings. Average investment is the only accurate standard to measure past operating

results.

18

Staff witness Tanner explained why such a distinction must be drawn when

reviewing historic earnings.

Because of growth in the rate base, setting future rates on the basis of average historical investment contnbutes to erosion in the earned return over time. The year-end level of investment is used to capture growth during the test year and helps compensate for the attrition inherent in the his­torical average approach. It is, in fact, an adjustment in and of itself much like other ratemaking adjustments.

To monitor earnings in [prior] periods, returns on average investment must be reviewed. Use of year-end investment to set rates is not inconsistent with the use of average investment to calculate the actual earned return. In fact, the only precise way to judge the adequacy of earnings for a past period is by considering the level of investment which generated the earnings. That level of investment is the average amount during the year, not the amount at year-end. ••• The Virginia Commission's use of a year-end rate base to set mtes is properly viewed as an attrition adjustment. This ratemaking policy must be distinguished from use of average investDient to calculate the earned return for the pull!_Ose of evaluating the Company's 1987 earnings. (Exh. No. DLT-12, pp. 6-7)

The Staff and Committee supported the use of average investment for a number of

additional reasons as well: (1) the Accounting Principles Board uses average invest­

ment as the proper standard for determining earnings; (2) average investment is used

by Dominion Resources Inc. ("DRI") and the entire financial community to report

earnings to investors; and (3) average investment focuses on what Virginia Power

actually earned - on the real dollars available to shareholders - not on a hypo-

thetical number that reflects ratemaking adjustments. Simply stated, the use of

year-end investment to monitor earnings is contrary to accepted accounting standards

and it understates the Company's 1987 earnings because year-end investment wrongly

assumes that " ••• the entire investment in plant and equipment were made on the first

day of the test year." (Exh. No. BCD-15, p. 5)

19

Virginia Power urged the Commission to use its year-end investment to measure

1987 earnings. The Company argued the use of average investment to measure earnings

is directly contrary to past Commission precedent decided in a recent Virginia Power

rate case, Case No. PUE840071. Application of Vuginia Electric and Power Co. 1986

SCC Ann. Rep. 258. In that case, the Committee claimed that Virginia Power was not

entitled to a future rate increase because the Company earned a return on equity in

excess of its authorized return. Committee witness Refvik arrived at this conclusion

by using the Company's average investment to measure test year results. Both the

Commission's Hearing Examiner and the Commission itself rejected the use of average

investment as the appropriate standard to measure the necessity of future rate

relief./d. Report of Russell W. Cunningham, Senior Hearing Examiner, p. 4 (March 4,

1986); Final Order dated M~,I16?- 1986, 1986 SCC Ann. Rep. 258, 261.

Virginia Power and all other parties acknowledged that this case mandates the

use of year-end investment when setting future rates. However, Virginia Power argued

that the case stands for another, equally important proposition as well. It claimed

year-end investment is also the standard for testing the results of previously

approved rates. As a result, it argued that its 1987 earnings must be measured based

upon year-end investment.

In support of this argument, the Company referred to the following language

found on page 4 of the Hearing Examiner's Report in Case No. PUE840071.

The use of an averaging methodology to test the results of projections based on an end of period methodology is like­wise unrealistic. Any such test ts instantly flawed because you are using a different test with different assumptiens to measure the results of rates established under separate and distinct criteria.

The Company said the Commission expressly agreed with the Hearing Examiner on

this point in its Final Order.

20

We agree with the Hearing Examiner's rejection of the Virginia Committee's proposal to use an average rate base · and earnings standard for the purpose of testing the results

- of previously approved rates. 1986 SCC Ann. Rep. 258, 261.

This language, according to the Company, requires the use of year-end, rather than

average investment to test the results of its 1987 rates and measure its 1987

earnings.

In reviewing the arguments on this issue, I believe the Company is reading some­

thing into Case No. PUE840071 that was never intended by either the Hearing Examiner

or the Commiwon. It must be remembered that the Committee raised only one issue

with respect to average investment: should the need for future rate relief be based

upon average or year-end investment? The Commission held that year-end investment is

the standard for determining the necessity for future rate relief. Quite obviously,

the revenues generated by ptevioilsly approved rates are factored into this determina­

tion in a fully adjusted rate of return statement In this sense, "previously

approved rates" are tested for reasonableness based on year-end investment when

setting future rates. However, it bears repeating that the Commission's reference to

testing previously approved rates was made solely in the context of setting future

rates.

It also requires a quantum leap in reasoning to support the same forward looking

year-end approach when reviewing the Company's earnings to determine whether the

deferred capacity costs were fully recovered during 1987. Certainly, Case No.

PUE840071 cannot be cited as mandatory precedent for that proposition. There, the

prim8ry issue presented was whether the Company was entitled to any future rate

relief. The recovery of deferred capacity charges was not at issue in that case, nor

was such an issue even remotely considered by the Commission. The Company's

reference to the Commission's language as support for the use of year-end investment

to review historic earnings is simply misplaced.

21

In my opinion, average investment must be used to review Virginia Power's

historic earnings. Use of year-end investment to monitor historic earnings has a

number of flaws, many of which were identified by the Staff and Committee. The major

flaw with year-end investment is that it wrongly assumes the Company's year-end level

of plant and equipment was in existence and providing service from January 1 through

the end of 1987. As we all know, this is not a reasonable assumption for Virginia

Power or any other utility during a period of significant growth. As Company witness

Ferguson testified, Virginia Power is in the midst of enormous customer growth with a

corresponding growth in test year rate base of approximately $433 million since its

last rate case. (Exh. No. JHF-1, p. 5, See generally Tr. p. 529-34; Exh. No. MSB-30).

As a result of this continuing growth, the use of year-end investment will signifi-

cantly distort the Company's actual earnings for 1987 and will substantially lower

the reported return on equity. In other words, it would be just as unfair to rate-

payers to use year-end investment as it would be to the Company to use the level of

rate base existing on January 1, 1987 when measuring earnings. Both methods would

zero in on investment for one particular day during 1987 and distort historic

earnings. Average investment is the only reliable standard to measure Virginia

Power's 1987 earnings.

I would also note in passing that the Commission's proposed experimental plan

for the regulation of telephone companies uses average, rather than year-end invest­

ment to monitor the earnings of companies electing to participate in the Commission's

new plan for rate regulation. Case No. PUC880035, Ex~: In the matter of

promulgating an experimental plan for the optional regulation of telephone companies.

Obviously, this order lends support to the view that the best m~thod to monitor the

historic earnings of a utility is through the use of average investment.

22

I therefore find the Staff's proposal to use a 13 month average for rate base

and common equity is reasonable and should be accepted for purposes of measuring

Virginia Power's 1987 earnings. Use of year-end investment will significantly

distort 1987 operating results and understate the Company's actual earnings.

S. Benchmark Rate of Return on Egpity

Once Virginia Power's actual1987 return on equity is calculated, the remaining

component of the earnings test is the selection of an appropriate benchmark return on

equity against which the Company's. actual performance is measured. If the Company's

earnings, after fully expensing the 1987 deferred capacity charges, equal or exceed

the benchmark, the Company has fully recovered its 1987 deferred capacity charges

through base rates. If the Company's earnings are lower than the benchmark, this

would indicate that the Company-aid not fully recover the deferred charges and an

allowance in future rates would be appropriate. Thus, the selection of an appro-

priate benchmark return on equity is crucial to determining whether Virginia Power

fully recovered its deferred capacity charges. Not surprisingly, there was a wide

divergence of opinion on what should be the appropriate benchmark to measure

the Company's 1987 earnings.

The Company proposed using a weighted return on equity as a benchmark for

measuring 1987 results. Since the Company had two authorized returns on equity

during 1987, it stated that a weighted return was the only appropriate benchmark to

use when measuring earnings. The Company's authorized return on equity was 14.5%

from January 1 through September 13, 1987, and 13.25% from September 14 through

December 31, 1987. Using monthly income available for common equity, Company witness

Bolton calculated a weighted average return of 14.24% for 1987. (Exh. No. MSB-2, p. 8;

Sch. 6). Since the calculated returns on equity of all parties fell below the

Company's 14.24% benchmark for 1987, Mr. Bolton said a full recovery of the 1987

23

deferred capacity charges should be allowed. Interestingly enough, under the

Company's proposed benchmark, it would be entitled to a full recovery of the charges

even if all issues in the earnings test were resolved against the utility.

The Company's benchmark was unanimously opposed by other parties as excessive

and unreasonable. In their view, the only appropriate benchmark is the 12.5% to 13.5%

return on equity range approved in the Company's last rate case. H the Company's ·

1987 return fell within the range, after fully expensing the deferred capacity

charges, no additional allowance for the charges should be made in future rates.

Several reasons were cited why the Company's benchmark should be rejected.

Committee witness Dooley testified that:

The purpose of deferral was to protect the Company's opportunity to recover these costs, not to enhance the Company's pos~tion !>Y locking in an outdated authot1zed return. ApproWI of deferral by the Staff for accounttng purposes sliould not be a basis for binding the Commission to a return known to be unreasonable by all parties. Use of VEPCO's weighted return would permit VEPCO to conven the Staff's authorization of accounting procedures into Commission authorization of an unreasonable and otherwise impermissible level of return. (Exh. No. BCD-15, p. 15)

Staff witness Tanner further testified that ~e Company's proposed benchmark

would run directly contrary to the purpose of the earnings test.

The p~se of the earnings test is to determine whether or not VirgiDia Power earned an ade~ate return in 1987. It did. An inequity would clearly result if the Company's earnings are tested against an outdated benchmark that existed solely because of the delays encountered in the · processin~ of the Company's last rate case. When the Commission ordered all electric utilities to file an expanded AIF in early 1987, it did so citing an awareness of vast improvements in the national economy. Shortly there­after, the Commission specifically cited the authorized ROE as an issue to be litigated. Virginia Power should not prevail on the deferred capacity charge issue simply because Its case was one of the last to be completed. The Company has already benefited once from re21ilatory lag by having its 1987 rates based on an outdated ROE for 8 1/2 months of the year. That benefit should not be carried over into the future. (Exh. No. DLT-12, p. 8)

24

The Attorney General argued that the Company's proposed benchmark is not only

excessive, but it "would guarantee the recovery on equity of 141/2% for the first

eight and one half months of 1987." (Attorney General brief p. 7). Under generally

accepted regulatory principles, a utility is not guaranteed a fixed return, it is

only granted a reasonable opportunity to earn a fair return. In the Attorney

General's view, the Commi§ion should not guarantee the recovery of deferred capacity

charges or any other costs.

The Company countered that using the return on equity found reasonable in its

last rate ca5e to measure earnings for 1987 would. constitute unlawful, retroactive

ratemaking. A weighted return must be used. Otherwise, the Commission's rate of

return determination in Case No. PUE870014 would have an unlawful "retrospective

effect~~ since a 12.5% to 13.5% range would be used to evaluate earnings for the first .. ,_, --

8 1/2 months of 1987. A 14.5% on equity return must be used to evaluate earnings

during this 8 1/2 month period

In urging the Commission to adopt a 14.24% benchmark for measuring 1987

earnings, the Company has given little or no rationale why a weighted return is

appropriate. It merely claims that its authorized return on equity was not reduced

until September 14, 1987, and its previously authorized return on equity of 14.5%

must be factored int~ any benchmark return that is adopted for purposes of the

earnings test. As the Committee recognized in its closing brief, however, the

Company's proposed benchmark can be adopted only under one of two conditions: 1) a

finding that a 14.24% return on equity better reflects the cost of capital in 1987

than the 12.5% to 13.5% range established in the Company's last rate case, or 2) a

finding that the 14.5% return on equity established in Case No. PUE840071 nmn be

included in the benchmark calculation to avoid the prohibition against unlawful

retroactive ratemaking.

25

Not surprisingly, the Company did not attempt to show that its proposed bench­

mark represented a better indicator of the cost of equity during 1987. No one even

remotely familiar with utility regulation or cost of capital markets can make such a

bold and unsubstantiated claim. The cost of money declined significantly since the

early 1980's when the country was experiencing double digit interest and inflation

rates. The Commission recognized this improvement in the local and national

economies when it ordered Virginia Power to file an expanded AIF in early 1987 so the

Commission could conduct a general investigation of the Company's financial

condition. Moreover, even before the investigation was complete, the Commission

found the Company's 14.5% return on equity to be so excessive that rates were

converted to interim rates on September 14, 1987. The Commission took this action to

eliminate any additional overrecovery from ratepayers. Certainly,. under these .. ,_ .. -

circumstances, no one can claim that a 1424% return on equity is a "reasonable"

return on equity for 1987.

This brings us to the second inquiry. Must the Commission use an outdated and

excessive return on equity when measuring the Company's 1987 operating results and

considering the recovery of deferred capacity charges? The Company answers "yes .. ;

otherwise, the Commission would be engaging in retroactive ratemaking. Other parties

in this case say "no." Retroactive ratemaking does not prevent the use of a 12.5% to

13.5% benchmark.

I do not believe that Virginia case law supports the Company's retroactive rate­

making argument. In Virginia, retroactive ratemaking is narrowly construed to occur

only when retroactive increases or decreases are ordered that depart from previously

approved Commission rates. For example, if the Commission found a utility was not

earning a reasonable return under current rates, the Commission has no power to

impose a retroactive rate increase exceeding the currently effective rates to make up

26

for any past deficiency in earnings. VEPCO v. State Corporation Commission 226 Va.

541,549 (1984). Similarly, the Commission has no authority !' ••• to go back in time

to order refunds of revenues collected under [excessive] rates that were legally in

effect at the time the revenues were collected" Commonwealth Gas Pipeline v.

Anheuser-Busch 233 Va. 396, 402 (1987). Once rates are legally established by the

Commission, the rates are conclusively presumed to be reasonable until changed by the

Commission in the manner prescribed by law. Alkali Works v. N.& W. R.. Co., 147 Va.

426,447 (1927); Commonwealth v. Old Dominion Power Co., 184 Va. 6, 17 (1945). An

elementary rule of ratemaking in Virginia is that any revision in rates can only

operate prospectively.

The use of the Company's current authorized return on equity, however, does not

constitute unlawful retroactive ratemaking. This is tme simply because the --- .-

Commission will not retroactively increase or decrease the Company's rates that were

in effect during 1987 regardless of the ultimate disposition of the deferred capacity

issue. Rates in effect between January 1 and September 13, 1987, which were

excessive by any reasonable measure, will not be changed retroactively to require

Virginia Power to make refunds for any overcollections. Similarly, rates in effect

from September 14, 1987, until the beginning of the rate year in this case will not

be changed retroactively to tme-up any over or underrecovery of earnings by the

Company. Simply stated, the use of the Company's most recent authorized return on

equity cannot be deemed to be retroactive ratemaking because there will be no retro­

active change in previously approved rates regardless of the Commission's decision on

the deferred capacity charges. Prior rates will not be altered.

For this reason, I find that Virginia Power's most recent authorized return on

equity should be used as a benchmark to measure 1987 earnings. The Company's

proposed benchmark of 14.24% is so excessive as to merit little, if any, considera-

27

tion. Use of such an excessive benchmark would only further aggravate the over­

recovery of revenues collected from ratepayers during the fir.st 8 1/2 months of 1987.

6. Ranae y. Point

There was considerable discussion by the parties over whether the equity range

approved in the last rate case or a _specific point within the range should be used as

a benchmark for the earnings test. The Staff, Committee and Attorney General argued

that if Virginia Power's 1987 earnings fell within the 12.5% to 13.5% range, the

Company had fully recovered its deferred capacity charges. The Company, on the other

band, supported a specific point as a benchmark - preferably 14.24%, but in no

event less than the 13.25% return on equity used to establish rates in its last case.

This issue is now moot. Based on my findings above, Virginia Pow8r earned a

return on equity in 1987 of 1~.29%, as calculated in Exhibit No. KKP-9, Statement I

Revised, Column 5, line 25. Thus, regardless of the benchmark applied (range v.

point), Virginia Power fully recovered its deferred capacity charges in 1987 and no

additional allowance for the charges should be made in future rates.

7. Conclusion as to Deferred Capac;ity Qames

In the recent generic proceeding addressing the recovery of capacity charges,

Commissioner Shannon expressed the Commission's view on this subject.

We think the company should recover, there's no question it should recover every prudently incurred cost, but the rate­Fluers shouldn't pay one cent more. (emphasis added) Case o.PlnE880052{T~p.74)

This is a statement I wholeheartedly endorse because it balances the interests

of both the ratepayers and investors. When a Company can purchase capacity at lower

costs than constmcting its own generating units, the Company should be encouraged to

buy the lower cost capacity. Also, because ratepayers are the ultimate beneficiaries

of any decision that reduces a utility's cost-of-service, the Commission has allowed

28

Virginia Power a full recovery of prudently incurred capacity charges and a return on

the unamortized balance of such charges. Application of V'uginia Electric and Power

Co., 1981 SCCAnn. Rep. 238,241-42. Interests are balanced because the ratepayer

receives the benefit of lower power costs while the investor is allowed a full

recovery of all costs incurred to purchase capacity. However, as Judge Shannon

recently stated, "[t]he ratepayers should not pay one penny more" than the amount

necessary to reimburse the Company for its capacity costs. The next question that

immediately arises is how do you ensure that ratepayers do not pay "one penny more?"

Obviously, using a fully adjusted test year and year-end investment is not the

appropriate standard to determine whether Virginia Power fully recovered its capacity

charges. This traditional ratemaking analysis for setting future rates is simply not

a reliable measure of past e~gs. It is also misleading to evaluate recovery of

capacity charges based upon operating results contained in the Company's annual

report. Annual reports are stated using Generally Accepted Accounting Principles

(GAAP). As any accountant knows, there are some tremendous differences between

GAAP and regulatory accounting. I am therefore unable to accept the invitation of

some of the parties in this case to rely solely on GAAP accounting contained in the

Company's unadjusted financial statements or annual10-K Report when deciding the

deferred capacity issue.

The only reliable method available to test historic 1987 earnings is actual 11per

book" operating results adjusted for: 1) restatements from GAAP to regulatory

accounting, 2) removal of out-of-period expense and revenue items, 3) inclusion of

JDC capital expense .~d associated tax savings, and 4) use of average investment to

measure earnings. This is the only method that will accurately reflect what Virginia

Power's actual earnings were during 1987. The basic problem with the Company's

approach is that it distorts 1987 earnings by failing to remove major out-of-period

29

items and uses an inflated year-end investment to measure actual results.

H Virginia Power's 1987 earnings are calculated based upon properly adjusted

per book data, the Company achieved a 13.29% jurisdictional return on equity in 1987

after fully expensing its deferred capacity charges. This demonstrates that Virginia

Power's earnings were more than sufficient during 1987 to fully recover the deferred

capacity expenses and still earn a very healthy return on its investment. Any addi­

tional allowance for the charges in future rates would allow Virginia Power a double

recovery of these charges from ratepayers.

ill. VIRGINIA POWER'S REVENUE REQUIREMENT

Having found that Virginia Power fully recovered its 1987 deferred capacity . charges, the Company's fu~!! re~enue requirement should not reflect any additional

allowance for these charges. This reduces the Company's proposed increase by approx­

imately $17 million. The next inquiry is whether the Company's current rates must be

increased at all.

As with the earnings test, discussed in Section II above, several issues were

raised by the parties that merit discussion when reviewing the need for future rate

relief. Although the revenue impact of the issues differed considerably, all are

controversial and require resolution in this Report and by the Commission.

1. Customer Growth Adjustment/Weather Nonnalization

The Staff, Committee and Attorney General increased the Company's test year

revenues by approximately $38.6 million to annualize sales based upon the year-end

level of customers. (Exh. Nos. KKP-8, pp. 7-8, Sch. C, Adj. 2; BCD-15 pp. 17-21,

Sch. 2; BCD-16, Sch. 2 Revised; Exh. No. AFS-14 pp. 7, 24-26, Sch. 2 p. 2).

Virginia Power, on the other hand, calculated its adjustment based on actual test

30

year sales using end of period tariff rates - the same method approved in the

Company's last rate case.

Staff witness Peterson supported the growth adjustment because it would provide

a better match between revenues, expenses and end of period rate base.

This ~justment properly reflects the additional revenues that will be collected by the Comp81\Y in the proforma period from the customer base existing at the end of the test period Once adjusted, operating revenues will better match operating expenses and end of period rate base. Operating expenses have for the most part been either annualized to end of period levels or preformed beyond lear­end. End of test period rate base includes the amount o plant required to serve the year-end level of customers. {Exh. No. KKP-8, p. 7).

Attorney General witness Skirpan agreed with the Staff's proposal stating that

"[w]ithout this adjustment, the adjusted test year will produce arbitrary and mis­

matched results that will yiela excessive rates that are not fair and reasonable."

~ No. AFS-14, pp. 25-26). Committee witness Dooley claimed that "[i]f the expenses

associated with increased numbers of customers are included in rates, the revenues to

be generated by these customers must also be included. Otherwise, VEPCO will have

built in an overrecovery in its rates." (Exh. No. BCD-15, p. 20)

Virginia Power cited several reasons why the proposed growth adjustment should

be rejected. First, the Company argued that a sales annualization adjustment for

year-end customers is beyond the scope of an expedited rate case. A similar adjust­

ment was considered and rejected by the Commission in its last general rate case.

However, since I have previously found that Company's application should be treated

as a general rate case, Virginia Power's procedural argument must be rejected.

The Company further argued that acceptance of the adjustment would undermine the

attrition allowance associated with the use of year-end rate base. The Commission

uses year-end rate base when setting rates because it tends to offset the attrition

that results for the lag inherent in the use of a historic test year. Company

31

witness Bolton testified the Commission's acceptance of a growth adjustment would

" ... be equivalent to adoption of an average rate base for the purpose of fixing rates

for the future." (Exh. No. MSB-28, p. 17). Adjusting revenues to a year-end level,

" .. .no longer provides any offset to attrition." Id.

Mr. Bolton testified that another reason the adjustment should be rejected is

because it is inconsistent with the method for allocating costs among jurisdictions.

The Company's allocation factors are based upon actual kwh sales and kw demand. A

growth adjustment, on the other hand, is based upon year-end customer sales. This

would cause a distortion in the amount of revenues, expenses and rate base items

allocated to Virginia.

The Company also claimed that several other items would need to be adjusted if

the customer growth adjus~~nt ~ accepted. Specifically, Mr. Bolton said the

Company's test year operating expenses would need to be increased by approximately $4

million to reflect increased postage expense for year-end customers, non-fuel clause

energy related expenses and customer related operation and maintenance expenses.

Finally, Virginia Power argued that if the growth adjustment is accepted, test . year revenues would also need to be weather normalized. This proposal, sponsored by

Company witness Laposata, became a hotly contested issue in the case.

Dr. Laposata explained that the purpose of a weather normalization adjustment is

similar to that of a customer growth adjustment: " ... to rectify differences between

the historical test period and the future period over which new rates will apply."

(Exh. No. SML-26, p. 2). Therefore, an accurate restatement of operating revenues

should reflect both a_year-end customer growth adjustment and an adjustment to remove

the effects of abnormal weather. H future revenues are to be accurately predicted,

consistency would require that both adjustments be adopted.

32

Dr. Laposata's analysis revealed that weather during the test year was the most

extreme in Virginia over the last 17 years, as measured by total billing cycle

weighted cooling and heating degree days. Dr. Laposata therefore normalized test

year sales for all customer classes, except the industrial and lighting classes,

which he said were not weather sensitive.

Dr. Laposata used a three step method to weather norma1ize test year sales.

First, he used regression analysis to remove the effects of abnormal weather from

historic monthly sales data from 1977 to 1987. Second, this normalized sales data

was deseasonalized using a model adopted from the Census Bureau's X11 procedure.

Finally, normalized sales for December 1987 were multiplied by twelve to produce

annualized test period kwh sales at _end-of-period customer and usage levels.

Dr. Laposata's propos~g we.ather adjustment would have a tremendous impact on

the Company's revenue requirements. Based on his analysis, he claimed that weather

norma1izing test year sales would increase the Company's revenue requirement by $79.7

million. When the customer growth adjustment is offset against his weather normali­

zation adjustment, the net increase in the Company's revenue requirements would be

$41.1 million. (Exh. No. SML-26, p. 5). It should be recognized, however, that the

Company is proposing a weather normalizing adjustment 2Dl! if a customer growth

adjustment is accepted. (Company brief p. 19). If the traditional method for

annualizing test year revenues is adopted, no weather adjustment is necessary.

I am once again unable to ignore test year customer growth when establishing

Virginia Power's revenue requirements. In Case No. PUE870014, I recommended that a

similar growth adjustment be accepted by the Commission when determining the

Company's revenue requirement. The Commission, however, rejected that recommendation

because the growth adjustment included an element to adju_st test period data for

weather. The Commission held that the weather element " ... did not receive the

33

thorough analysis at the hearing which we believe necessary." Case No. PUE870014,

Final Order and Opinion, datedApril7, 1988, p. 21. Accordingly, the traditional

method to annualize revenues based upon actual sales and end of period tariff rates

was approved in the Company's last rate case.

In this case, the Staff, Attorney General and Committee have removed. the effects

of weather in their proposed sales annualization adjustment. In fact, the adjustment

was calculated by the Company and submitted in response to a Staff data request. As

a result, the accuracy of the adjustment itself cannot be disputed by the Comp~y.

The only issue is whether the adjustment should be accepted without any further

revisions to normalize for weather experienced during the test year.

I find the sales annualization adjustment based upon the Company's year-end

customers should be acceptel_lwi$.out any offset for test year weather. All parties

admit that Virginia Power is experiencing tremendous customer growth in its service

area. Failure to recognize this growth by annualizing revenues based upon year-end

customers will therefore cause a significant distortion in future rates simply

because operating revenues will be understated. Had the December 1987 customer base

been on line for the entire test year, as it will be during the proforma and rate

year, operating revenues would have been substantially greater than that reported

during the test year. This additional revenue should be recognized when setting

future rates.

This proposal is also not unfair to Virginia Power. Most of the Company's test

year expenses have been adjusted to year-end levels or levels expected to be incurred

during the proforma or rate year. Salaries, wages, employee benefits, insurance

expenses, depreciation expenses and taxes have been adjusted at least to year-end

levels. In addition, Virginia Power's capacity charges, one of the Company's largest

expense items, were adjusted to an anticipated rate year level of such charges. The

34

proposed growth adjustment will do nothing more than provide a better match of

revenues and expenses expected to be collected or incurred in the future. It will

not, as the Company claims, be comparable to using average rate base to set rates.

The use of year-end rate base will remain intact and the attrition allowance will be

recognized. However, failure to make the adjustment will produce a mismatch of the

Company's cost-of-service items and will result in excessive rates not truly

reflective of reasonable future revenue requirements. I therefore find the sales

annualization adjustment for customer growth should be accepted when determining the

Company's revenue requirements.

Moreover, the proposed adjustment is very conservative since only growth during

the test year is captured. Growth will continue in the future and these additional

revenues will not be conside~~d ~~en setting rates in this case. This additional

growth after the test year will provide the Company with yet another attrition

allowance in addition to the use of year-end rate base.

The Company's other arguments opposing the adjustment also suffer some serious

shortcomings. While the proposed weather adjustment appears reasonable in theory,

its actual application to Virginia Power's operations produces some rather bizarre

results. Dr. Laposata's analysis, for example, would reduce test year sales by

approximately 1.6%. This, in turn, would increase the Company's revenue requirements

by almost $41.1 million if the weather norma1ization adjustment was netted against

the Staff's growth adjustment, or a $79.7 million increase if viewed in isolation.

The most glaring problem with this analysis· is that it wrongly assumes that future

sales will decrease to a level below that experienced during the test year.

According to Dr. Laposata, this will generate lower revenues in the future and result

in a shortfall in rates if "normal" w~ather returns during the rate year.

35

However, such a myopic analysis highlights the danger of viewing weather as a

stand alone item. Weather cannot be viewed in isolation, as Dr. Laposata suggests.

In order to produce accurate results, two inquiries must be made. First, was test

year weather abnormal? In this respect, I am willing to agree with Virginia Power

that it appears that 1987's weather was abnormal b~d upon Dr. Laposata's analysis.

But, it does not necessarily follow that an adjustment should be made on this basis

alone.

The second inquiry is just as basic, but even more important in reviewing the

necessity of a weather normalization adjustment: will the test year's abnormal

weather cause future sales to be less than test year sales, thereby requiring an

adjustment to prevent a potential shortfall in future revenues? This is where the

fallacy in Dr. Laposata's propgsed_ weather adjustment becomes apparent. In order to

accept the Company's proposed weather adjustment, there must be a finding that

abnormal test year weather will cause future sales to be lower than that occurring

during the test year. Only then will an adjustment to normalize sales for abnormal

weather be necessary.

Virginia Power's evidence reveals, however, that annual sales will increase by

almost 5.3% over the level experienced during the test year. (Tr. pp. 204, 214)

This sales projection is in direct contradiction to the Company's analysis which

projects a reduction in Virginia Power's future sales because of the test year's

abnormal weather. This projected reduction in future sales, the very premise upon

which the Company's weather normalization adjustment is based, will simply not occur

for Virginia Power. Normalizing Virginia Power's test year revenues for weather will

cause a serious understatement of operating revenues and needlessly increase the

Company's revenue requirements. It would indeed be ironic that a weather adjustment

36

would introduce the very distortion in test year operating results that such an

adjustment seeks to avoid.

In addition, even if I agreed that a weather adjustment should be made in this

case, which I do not, there are some serious problems with the Company's proposed

weather adjustment. Many criticisms of the adjustment are set forth in the closing

briefs of the Staff, Committee and the Attorney General, and I will not repeat those

criticisms here.4 Nevertheless, there is one fundamental problem with the analysis

that must be highlighted in this Report.

When calculating his proposed weather adjustment, Dr. Laposata made no attempt

to determine the impact abnormal weather would have on the Company's expenses or

other cost-of-service items. His analysis focused solely on revenues to the absolute

exclusion of all other cost-of-service itt!ms. In order to produce accurate and

reliable results, the Company's entire cost-of-service must be weather normalized.

Focusing solely on revenues causes a distortion in the weather adjustment and

prejudices ratepayers by substantially decreasing test year revenues with no

corresponding reduction in expenses.

Finally, I am unable to accept the Company's other arguments in opposition to

the proposed growth adjustment. The Company will be allowed an attrition adjustment

by the use of year-end rate base to calculate its revenue requirements. Also, the

Company will still receive an attrition allowance because customer growth occurring

during the proforma and rate year is not captured ~y the adjustment In addition,

4rhe parties criticized the Company's weather adjustment for a number of reasons: _the Commission does not weather normalize for electric utilities; the weather adjustment is unrelated to the ~owth adjustment; the weather adjustment is speculative and not adequately explained in the record; and the adjustment will improperly shift risks from the utility to ratepayer.

37

the growth adjustment does not affect attrition any differently than any other

adjustment lowering the Company's revenue requirement. For obvious reasons, such a

broad brushed approach to deny legitimate ratemaldng adjustments cannot be accepted.

There is also little merit to the Company's argument that jurisdictional alloca­

tion factors must be revised. if the growth adjustment is accepted. This argument is

apparently based upon Mr. Bolton's claim that revenues, expenses and rate base were

allocated in the Company's cost-of-service study based upon actual rather than year­

end kwh sales and kw demand. However, any distortion in allocation, if it occurs at

all, would only occur if growth was greater in Virginia than other jurisdictions.

There is simply no evidence in the record demonstrating that growth in Virginia was

any greater than growth in other jurisdictions causing a distortion in the allocation

~actors. ~ fact, Staff witness-Eeterson seemed to imply that just the opposite was

occurring for Virginia Power. He testified that his analysis of the Company's cost­

of-service studies for 1986 and 1987 indicated that allocation to Virginia decreased.

(Tr. p. 212) This would appear to indicate that growth in the Company's service area

is causing Virginia allocations to decrease. It is also in direct contradiction to

Mr. Bolton's claim that allocation to Virginia Power would increase if year-end sales

and demand were incorporated into the Company's cost-of-service study.

Mr. Bolton further claimed that Company's operating expenses should be increased

by approximately $4 million if the growth adjustment is accepted. Although I am

willing to increase the Company's expenses by approximately $60,000, to restate

postage expense based upon the number of year-end customers, as calculated by Staff

witness Peterson, the remaining $3.994 million of expense is not substantiated in the

record. Mr. Bolton made absolutely no effort to explain how these adjustments were

calculated or what specific items were in~luded in the $4 million of expenses.

38

Accordingly, the balance of the proposed expense adjustment, amounting to $3.994

million is rejected.

For the foregoing reasons, I find the proposed adjustment to annualize revenues

based upon year-end customers should be accepted without any offset for weather

normalization. This will increase the Company's test year revenues by $38.6 million.

I further find the Company's test year expenses should be increased by $60,000 to

restate postage expense based upon the level of year-end customers.

2. The Tennination of OPEC Capacity Payments

The ODECfVirginia Power settlement was made so ODEC could purchase up to .

300 MW of capacity from the Allegheny Power System. The settlement required that the

300 MW previously purchased from Virginia Power by ODEC be reallocated to Virginia

Power's customers. The ·reallocation of load will result in future savings to

Virginia Power's customers, although the settlement caused an increase in the

Company's base rates during 1988. ODEC therefore agreed to make monthly payments to

Virginia Power to offset any additional revenue requirement associated with the

reallocation of the 300 MW of load. These payments will terminate in December of

1988.

Virginia Power included the remaining 2 1/2 months of ODEC payments as a credit

to its revenue re·quirement for the rate year. Attorney General witness Skirpan

recommended that a "two-phased" approach be adopted for the termination of the ODEC

payments. This approach would essentially reduce the Company's revenue requirement

for service between October 18 and December 31, 1988, because the entire amount of

the ODEC payments would be reflected in the revenue requirement for 2 1/2 months.

Beginning January 1, 1989, the Company's rates would increase because no ODEC pay­

ments would be reflected in rates after that date.

39

I find Mr. Skirpan's two-phased approach should be rejected for two reasons.

First, a two-phased approach will setve no useful purpose in 1his case. The

Company's annualized approach, which provides a credit to the Company's cost-of­

service equal to 2 1/2 months of the ODEC payments, properly reflects the impact on

the Company's revenue requirements for the termination of payments. Thus, ratepayers

would receive no appreciable benefit under Mr. Skirpan's two-phased approach.

Second, and more importantly, Mr. Skirpan's proposal would appear to run afoul

of the provisions of Virginia Code §56-235.4, which prevents multiple rate increases

in a twelve month period. For example, if the Company's base rates are increased on ,

October 18, 1988, Code §56-235.4 would preclude a second increase on January 1, 1989,

as proposed under Mr. Skirpan's two-phased approach. Yet this is exactly what would

occur under his proposal.

Moreover, even assuming the second phase of the increase could in some way be

placed into effect on January 1, 1989 without violating the statute, the proposal

would also prevent any further rate relief in 1989 through an increase in base rates

or an increase in the Company's fuel factor. While no one relishes the thought of a

rate increase, a two-phased revenue requirement to reflect the termination of ODEC

payments would prejudice the Company and lead to some results that I don't believe

Mr. Skirpan even considered when making his recommendation. In making this observa­

tion, I note that the Attorney General did not support a two-phased approach in its

closing brief. I can only assume the Company's rebuttal testimony opposing Mr.

Skirpan's proposal was deemed to be meritorious by the Attorney General.

Mr. Skirpan's two-phased approach for the termination of ODEC settlement

payments is therefore rejected.

40

3. Rate Year Cavacity Charzs

Since the Commission's decision in Case No. PUE840071, Virginia Power has

included in base rates a "going level" of capacity charges expected to be incurred

during the rate year. Application of V'uginia Electric and Power Co. 1986 SCC Ann.

Rep. 258 at 261. Company witness Bolton originally increased test year expenses by

$53.8 for additional projected rate year capacity charges. (Exb. No. MSB-3, Sch. 5,

Supp., Adj. 12). This amount was later reduced to approximately $42.3 million

because of transmission constraints in the Northeast corridor which prevented the

transmission of all contracted capacity to the Company and the disappointing response

to the Company's Request for Proposals (RFP) to supply capacitY for the summers of

1989 and 1990. These two events caused the Company to reduce its projected capacity

charges by $11.5 million on~ugust 17, 1988. The projected capacity charges were

once again revised in the Company's rebuttal testimony to approximately $51.0

million. (Exh. No. MSB-28, p. 21). The latest revision was made to reflect

projected purchases of 450 MW of capacity from South Carolina Public Service

Authority and South Carolina Electric & Gas. {Tr. p. 455)

Although no party is objecting, in principle, to the proposal to build into base

rates projected rate year capacity charges, the Commission's Staff refused to accept

the Company's latest revision increasing projected capacity charges by approximately

$8.714 million. Staff witness Peterson recommended that only $42.3 million be

allowed for projected capacity charges. According to Mr. Peterson, this level of

capacity charges is the only amount supported by firm contracts or letters of intent.

(Tr. p. 184). Any additional allowance for capacity purchases unsupported b3

contracts or letters of intent would be speculative in the Staffs view.

Attorney General witness Skirpan did not include the Company's latest revision

to capacity charges in his analysis. The Attorney General's closing brief also made

41

no reference to the latest revision of the Company's rate year capacity charges.

Under these circumstances, I can only assume the Attorney General does not oppose the

Company's latest revision to projected capacity charges.

The Company argued that the full amount of projected capacity charges should be

allowed in base rates. In order to satisfy the Staff's concern over the speculative

nature of its latest revision, Company witness Ellis testified that Virginia Power

had letters of intent supporting all capacity purchases descnbed in his rebuttal

testimony. (Tr. pp. 456-60). Since the additional purchases are now "known and

measurable", the Company claimed that all projected rate year capacity charges should

be allowed.

In its closing brief, however, the Staff continued to support a disallowance of

the $8.714 million of additional capacity charges because the Company had not yet

arranged for transmission of the capacity. (Staff brief pp. 21-22). The Staff once

again argued that any allowance for the additional capacity purchases would be

speculative. The Staff further complained that the Company should not be allowed to

continually update its adjustments on the eve of a hearing when it knew, or should

have known, the need for the adjustments much earlier. (ld. p. 22).

The problem with the Staff's proposal is that it would build an automatic short­

fall in Company's base rates by not allowing a full recovery of the Company's rate

year capacity charges. The Company reduced its projected capacity charges in August

because it could not obtain transmission of its contracted capacity over the PJM

grid. The Company's problems were further aggravated when its RFP generated very few

offers to supply capacity for the summers of 1989 and 1990. The revision in capacity

charges was not caused by any changes in the Company's forecasts. It still needs

every MW of capacity included in its original projection so the "lights will stay on"

42

during the next two summers. The revision was caused by circumstances beyond the

Company's controL

So what did the Company do to ensure reliable future service? First, it

attempted to purchase power from utilities located in the south where transmission

constraints are not a problem. The Company began negotiations with South Carolina

utilities to supply capacity to meet its expected needs during the summers of 1989

and 1990. The Company also obtained letters of intent from the two utilities to

supply this capacity. Nevertheless, even this additional capacity will not be

sufficient to allow the Company to meet its expected future demand. As Company

witness Ellis testified, " ..• we are still projecting a shortfall of 291 MW by the

summer of 1989" even with the additional purchases from the South Carolina utilities.

(Exh. No. L WE-22, p. 7). TQ _ _!lle~t. this additional shortage, the Company recently

filed an application with the Commission requesting authority to construct four new

generating units at its Surry power station. Application of Vuginia Electric and

Power Co., Case No. PUE880083.

I believe it would be counterproductive to disallow any portion of the projected

capacity charges in this case. ·The capacity revisions were not caused by any

changes in the Company's forecasting, but by unforeseen events beyond the CompanY's

controL It cannot be seriously debated that the Company does not need the

additional450 MW of capacity. The Company has also made reasonable efforts to

obtain this additional capacity by negotiating purchases from two South Carolina

utilities. The additional purchases are reasonably "known and measurable" because all

purchases are now s~pported by contracts or lette~ of intent. For these reasons, I

find the Company's most recent projected capacity charges should be allowed as a

legitimate ratemaking expense. The Staff's proposal to reduce the projected

capacity charges to $42.3 million is therefore rejected.

43

4. Miscellaneous Non-Recuaine Exuenses Committee witness Dooley disallowed four test year expense items on the ground

they were non-recurring in nature and should not be reflected in future rates. The

four items identified by Mr. Dooley as non-recurring were: (1) the North Anna .steam

generator tube repair costs, (2) spar arm replacement costs, (3) future fossil site

project study costs and ( 4) fuel cell and wind resource project study costs. (Exh.

Nos. BCD-15, pp. 21-24, Sch. 2; BCD-16, Sch. 2 revised; Tr. 385-86). His adjustments

to eliminate these test year expenses would reduce the Company's revenue requirement

by $8,287,000. (Exh. No. BCD-16, Sch. 2 revised; Tr. p. 386).

Staff witness Peterson included all the costs associated with the North Anna

steam generator tube repair and the Company's spar arm replacement program as test

year expenses. With respect to the future fossil site project study costs and the

alternate energy study costs, Mr. Peterson proposed that the costs be fully recovered

over a three year amortization period. (Exh. No. KKP-8, p. 4). At the hearing,

however, Mr. Peterson testified that the Company should still be required to justify

the reasonableness of these non-recurring items. (Tr. pp. 176-177) The Company

accepted Mr. Peterson's recommendation with respect to these items, provided the

unamortized balance of the costs are included in rate base. (Exh. No. MSB-28, p.

26).

In reviewing the challenged costs, I am unable to agree with Mr. Dooley's

analysis with respect to the costs incurred for the future fossil site project costs

and alternate energy costs. These costs are nothing more than normal research and

development costs that are incurred on a fairly routine basis by all regulated

utilities, and most unregulated companies. While these specific research studies may

not, as Mr. Dooley alleges, recur in the future, it cannot be seriously contended

that specific research studies must remain constant year after year in order to

44

qualify for expense allowance in a rate case. Innovative research must be encouraged

by the Commission because ratepayers and utility stockholders are the ultimate

beneficiaries of any technological breakthroughs that improve efficiency and reduce

costs. The Commission itself has recognized the value of research and development

programs in its decision in Virginia Power's 1984 rate case.

Over the years this Commission has encouraged utility research and development programs, for our experience has been that both the utility and ratepayer derive compen­sating benefits from research and development. Such pro­grams are essential to contain costs, promote more efficient generation and assure a safe and dependable electric power supply. Application of Yugin!a Electric and Power Co., 19~6 sec Ann. Rep. 258, 260.

Mr. Dooley's proposal, however, would be fundamentally unfair to the Company's

stockholders and would discourage innovative research and development projects. His

proposal would require that ~ch specific research project be reviewed on a case-by-

case basis and that all costs be disallowed for those projects found to be unfeasible

and discontinued by a utility. Such a standard for the allowance of research and

development costs would effectively give ratepayers the benefit of successful

research projects that are implemented to reduce costs while requiring stockholders

to pick-up all costs associated with abandoned research projects. Not only is this

proposal extremely unfair to the Company's stockholders, but it would also give the

Company very little incentive to explore new and innovative ways of doing business.

A utility would be very hesitant to embark upon an ambitious research and development

program if there was no hope of ever recovering the cost associated with abandoned

projects. Ratepayers may also be harmed in the long run if utilities are not

encouraged to conduct research and development designed to reduce costs and improve

efficiency.

For these reasons, I find the future fossil site project study and alternate

energy study costs are normal research and development costs that should be included

45

in the Company's cost-of-service. In addition, since these co~ts were incurred over

a period of several years, the Staffs proposal to amortize these costs over three

years is reasonable.

The second area of dispute concerns the Company's program to replace spar arms

on its utility poles. In early 1987, the Company discovered that wooden spar arms on

its transmission poles were rotting and causing power outages. The Company therefore

began a system-wide program to replace the wooden spar arms with steel spar arms.

The cost of the program incUrred during the test year amounted to approximately $2.0

million. (Exh. No. BCD-15, p. 22).

Mr. Dooley admitted the costs were prudently incurred and that the replacement

program benefited customers by reducing power outages. Nevertheless, he claimed the

entire amount of replacement costs should be disallowed because the costs are non­

recurring.

Once again, I am unable to accept Mr. Dooley's rationale for this item. There

appears to be nothing unusual or non-recurring about the replacement of spar arms on

transmission lines. Spar arm replacement is nothing more than a normal and ongoing

maintenance expense that is incurred by the Company on a fairly routine basis. The

costs were prudently incurred, by Mr. Dooley's own admission, and the customers will

receive a substantial benefit from the Company's replacement program by a reduction

in power outages. Mr. Dooley once again appears to suggest that maintenance projects

must be exactly the same year in and year out to justify an allowance for mainte-

nance costs. I reject this as a standard for cost allowance. As· with research and

development projectS, maintenance programs may change from year to year depending on

a company's current maintenance priorities. As one maintenance project is completed,

another is started in its place. Th~re is absolutely nothing unusual or non-

recurring about this practice.

46

As long as the Company's test year maintenance expenses appear reasonable, with­

out any great fluctuation from year to year, the allowance of such items should not

cause regulators a great deal of concern. The Commission should be hesitant to step

in and disallow normal maintenance expenses unless it is clear that a major,

unexpected maintenance program was undertaken during the test year that distorts test

year results and would cause an overstatement of future rates. Obviously, if such a

distortion in maintenance expenses occurs, each maintenance program should be

scrutinized closely so maintenance expenses can be restated to a level that is

expected to be incurred in the future. Here, the spar arm replacement costs were not

abnormal, the costs were fully anticipated by the Company, the costs were prudently

incurred and the expenditures were made for the direct benefit of ratepayers. I am

therefore unable to recomm~gd a __ disallowance of this. item as a test year expense.

Simply stated, I find these maintenance costs to be a normal and recurring cost of

doing busin~s that should be passed on to ratepayers through the Company's cost-of­

service.

The final item Mr. Dooley challenged was the repair costs of the North Anna tube

rupture. For this particular item, I am inclined to agree with Mr. Dooley's

analysis. The North Anna tube rupture was a sudden and unexpected occurrence that

was very costly to Virginia ratepayers. In response to Senator DuVal's data reqtJest,

the Company stated that it incurred approximately $5.5 million in repair costs and

over $21 million for replacement power during 1987 for the tube rupture. (Exh. No.

JHF-38, p. 2). Additional costs will be incurred in 1988. Obvi~usly, the tube

rupture was costly to Virginia ratepayers. The repair costs identified by Mr. Dooley

are also not a normal, run-of-the-mill maintenance expense as the Company attempts to

suggest in its closing brief.

47

In past cases, the Commission has normalized test year expenses caused by extra­

ordinary non-recurring events. In Appalachian Power Company's (" Apco") 1978 rate

case, for example, the Commission amortized the costs associated with a fire at

Apco's Amos generating plant, holding that " .. jt would be inappropriate to set rates

based upon the entire amount of this extraordinary expense." AppUcation of

Appalachian Power Co., 1979 SCC Ann. Rep. 201, 205-06. Similarly, in Apco's 1986

rate case, the Commission amortized over three years the costs associated with a

flood that exceeded the 100-year flood plain. Application of Appalachian Power Co.,

Case No. PUE860015, Report of Glenn P. Richardson, Hearing Examiner, pp. 11-12

(February 4, 1987); /d. 1987 SCC Ann. Rep. 244. The practice of the Commission is

not to totally disallow such prudently incurred costs for ratemaking, but to reduce

the impact on ratepayers by ~!!JoiJizing the costs over a number of years.

Given the Commission's prior decisions on items comparable to the North Anna

tube rupture, I find the repair costs should be amor:tized over three years. Since

the tube rupture was an unforseeable event and not caused by any imprudence of

Virginia Power's management, it would be improper to totally disallow this expense as

suggested by Mr. Dooley.

5. Allocation of Research and Develooment Exuenses

Attorney General witness Skirpan recommended that Virginia Power's research and

development costs related to generation be allocated among Virginia Power, Dominion

Energy and Dominion Capital in proportion to the amount of generating capacity each

owned. In support of this proposal, Mr. Skirpan testified that Dominion Energy and -

Dominion Capital have interests in 13 cogeneration and independent power projects

with a total generating capacity of more than 2500 MW. He further claimed these

unregulated subsidiaries of Dominion Resources Inc. ("DRf') are receiving benefits

from Virginia Power's generation related research expenditures. It is only fair,

48

according to Mr. Skirpan, that the unregulated companies share a portion of the

generation related research costs. Mr. Skirpan's proposal would increase Virginia

Power's operating income by $619,000, and reduce its revenue requirements by approxi­

mately $965,000. (Exh. No. AFS-14, pp. 6, 17-19).

The Company opposed Mr. Skirpan's proposal. It said that if it were providing

research benefits to Dominion Energy and Dominion Capital, it would charge those

companies an appropriate amount for the services, just as it currently charges DRI

for services rendered to that company. However, the Company points out that it was

specifically prohibited from furnishing any services to Dominion Capital and Dominion

Energy by the Commission's Opinion and Final Order in Case No. PUE860037. That being

the case, Virginia Power claimed that its affiliated companies receive no more

benefit from the research proie~. than any other unaffiliated cogenerator or small

power producer.

In resolving this issue, I notice that the Company did not claim that Dominion

Energy and Dominion Capital receive no benefits from Virginia Power's past and cur-

rent generation related research and development projects. I also find unconvincing

Virginia Power's argument that the affiliated companies receive no more of a benefit

from Virginia Power's research and development than other UMffiliated cogenerators

or independent power producers. After a1l, there has ~een an exodus of Virginia Power

employees with generation related experience to Dominion Energy and Dominion Capital.

This fact alone demonstrates that the affiliates have received greater benefits from

Virginia Power's research and devel'?pment than other unaffiliated companies.

Moreover, DRI's upper management has expressly acknowledged "they", i.e., DRI and its

subsidiaries, are using their 1'proven expertise in building and operating power

stations to develop non-regulated capacity and earn higher returns than. •• permitted

in the regulated utility business." (Exh. No. AFS-14, App. II, p. 3). If Dominion

49

Energy and Dominion Capital have received no more benefits from the research than

unaffiliated power producers, how can DRI's management make this claim?

I am also not naive enough to believe that a sharing of generation related

expertise and information does not occur between Virginia Power and its affiliates.

While it may be true that there are no charges for this information in order to

comply with the Commission's order in the diversification case, it is apparent that a

sharing of generation related research is occurring. If not, how can DRI's manage­

ment claim they are using "their" proven expertise to build unregulated power

stations? Quite simply, this proven expertise came from Virginia Power and was

funded, in part, by ratepayers. It is only proper and fair that a small portion of

Virginia Power's generation related research costs be allocated to its unregulated

sister companies.

The Attorney General's proposal is a fair one, I believe, and it will have a

relatively small impact on yirginia Power's revenue requirements. Although the

Commission's diversification decision did prevent Virginia Power from rendering

services to its affiliated companies other than DRI, there is nothing I am aware of

that prevents the Commission from allocating a portion of the research costs to

Dominion Energy and Dominion Capital. Accordingly, I find the Attorney General's

proposed adjustment should be accepted. Based on Mr. Skirpan's analysis, this will

reduce the Company's revenue requirements by approximately $965,000.

6. Prior Period Taxes

Virginia Power included in its cost-of-service income taxes actually paid during

the test year, but representing tax liabilities from periods prior to the test year.

Attorney General witness Skirpan removed the prior period taxes from the test year.

This reduced the Company's operating income by $4,774,000, and reduced its revenue ·

requirements by $7,445,000. (Exb. No. AFS-14, pp. 6, 20-22).

50

This specific issue was considered in the Company's last rate case, Case No.

PUE8~0014. There, the Commission allowed the inclusion of prior period taxes holding

the " .•• allowance of this expense will provide the Company with the proper incentive

to pursue an aggressive tax strategy in an attempt to minimize its income tax

expenses, with a consequent benefit to ratepayers." SCC v. V'uginia Electric and

Power Co. Final Order and Opinion, p. 16 (April 7, 1988).

Mr. Skirpan failed to demonstrate why the Commission's decision on this item

should be reversed. He merely disagrees with the CommiMion's decision.

Accordingly, the proposed adjustment to remove prior period taxes is rejected.

7. Cbismau Creek Cleanup Costs

In Case No. PUE870014, the CommiMion disallowed approximately $9.6 million of

Chisman Creek clean-up costs thai were booked in the test year but not yet incurred.

The Commission held " ..• that it will be time enough to consider the permissibility of

these expenses for ratemaking purposes when, and at the level, actually experienced."

/d. p. 17. The Commission further permitted the Company to implement deferred

accounting so the clean-up costs could be reviewed in future cases.

The Company originally included sixteen months of clean-up costs in its test

year operating r~ults. The Staff, however, proposed that the "estimated" clean-up

costs be amortized over three years. This would allow approximately $3.2 million of

clean-up costs to be built in future rates. The Company accepted the Staff's recom­

mendation.

Comrttittee witness Dooley, on the other hand, recommended that only the amount

of clean-up costs actually incurred during the test year be allowed. Mr. Dooley's

proposal would reduce the Company's revenue requirements by $972,000. (Exh. No. BCD-

16, Sch. 2, Col. 2, line 24).

51

I find Mr. Dooley's proposal to include only the test year level of clean-up

costs should be accepted. The Staffs proposal is based upon the total estimated

clean-up costs, $9.6 million, amortized over three years. As in Virginia Power's

last rate case, we still don't know whether the Company will incur the entire $9.6

million for the Chisman Creek clean-up. In addition, in the Company's last rate

case, the Commission held that it would only consider the permissibility of the

expenses based on the level"actually experienced." The Staff's proposal is based

upon the total"estimated" clean-up costs, rather than the amount "actually

experienced" during the test year. For this reason, I find Mr. Dooley's proposal

should be accepted.

8. Cash Worldne Capital

Virginia Power filed aTead:.lag study on August 15th in response to the

Commission's Final Order and Opinion in Case No. PUE870014. However, given the time

constraints and abbreviated filing schedule in this case, Virginia Power did not

propose that its cash working capital allowance be established using the lead-lag . study. All other parties, with the exception of th~ Attorney General, accepted the

Company's calculation of cash working capital using the traditional formula approach.

Attorney General witness Skirpan reviewed the study "for about a week" and pro­

posed a cash working capital allowance of approximately $12.37 million. (Exh. No.

AFS-14, Sch. 11; Tr. p. 369). Mr. Skirpan testified that his proposed allowance was

almost $148 million less than the $158-$160 million cash working capital allowance

produced by the Company's lead-lag study. (Tr. p. 371).

Mr. Skirpan made four adjustments to the Company's study that substantially

reduced the Company's cash working capital allowance. First, he excluded deprecia­

tion and amortization costs because these were "non-cash" itenis that do not require

any additional investment to meet day-to-day operating needs. The removal of these

52

so-called "non-cash" items reduced the cash working capital allowance produced by the

Company's lead-lag study by over $110 million. (Tr. p. 371). -Second, Mr. Skirpan

amended the Company's study to include a 91.25 day lag for the payment interest on

long-term debt and a 45.63 day lag for dividends on preferred stock. (Exh. No. AFS-

14, Sch. 11) These adjustments further reduce~ the Company's allowance by an addi­

tional $31 million. (Tr. p. 369). Finally, Mr. Skirpan revised the fede.ral income

taxes in the Company's study to reflect 59.45lag days. This number of lag days

reflects a 90% payment of income taxes in the calendar year, consistent with the

Company's aggressive tax strategy. This amendment to lag days reduced the Company's

cash working capital allowance in its study by an additional $6.6 million. (Tr. p.

370). If Mr. Skirpan's revisions to the Company's lead lag study are accepted, the

Company's revenue requirem;nt)vould be reduced by $16,234,900. (Exh. No. AFS-14, pp.

7, 28-36).

In Case No. PUE870014, Mr. Skirpan proposed a lead-lag study that is virtually

identical to his present proposal. In reviewing his earlier proposal, I found his

study "significantly understates the Company's cash working capital requirements~~

because it "excludes depreciation and· other so called non...cash items." sec v.

"Vuginia Electric and Power Co., Case No. PUE870014, Report of Glenn P. Richardson,

Hearjng Examiner, p. 45 (February 26, 1988). The Commission agre~d with my recommen­

dation on this issue, holding that Mr. Skirpan's study " ... had many weaknesses

identified by the Hearing Examiner .... " SCC v. "Vuginia Electric and Power Co.,

Final Order and Opinion, p. 23 (April7, 1988).

While case authorities are split on the inclusion of depreciation and amorti­

zation costs in a lead-lag study, I continue to believe that the better reasoned

decisions support the inclusion of these items in a lead-lag study. Robert L Hahne

and Gregory E. Aliff, two recognized experts in the field of public utility

53

accounting, explained why such "non-cash" items should be included~

(O]n occasion, the issue has been raised that depreciation IS a noncash char~e and therefore cannot produce a need for cash working cap1tal. While it is true that recording depreciation does not requb:e the expenditure of cash at the time the expense is recorded and charged to the customer, cash was expended at the time the property was acquired, and the recordea depreciation is used to reduce the investment in that property even though approximately one-and-one-half month's depreciation ( eqwvalent to the revenue lag) has not yet been received.... Hahne and Aliff, Accountine fQr Public Utilities, §5.08[2], 1987 (originally published in 1983)

The customary method to compensate investors for this timing difference between the

bookkeeping entry for depreciation and its recovery through rates is to include

depreciation and other "non-cash" items in the study with a zero lag.

As in Virginia Power's last rate case, I once again find that Mr. Skirpan's -

lead-lag study substantially understates the Company's cash working capital require-

ment and should be rejected. I continue to believe that depreciation and amoniza­

tion costs must be included in a lead-lag study to produce an accurate cash working

capital allowance. Since Mr. Skirpan's proposal does not include these items, his

recommendation is rejected.

In addition, it does not appear that the formula approach will overstate the

Company's cash working capital allowance in this case. If Mr. Skirpan's lead-lag

study is amended to include depreciation and amortization costs, the study would

produce a cash working capital allowance of approximately $123 million.

Interestingly enough, this allowance is very clo~e to the Staffs cash working

capital allowance of $129.8 million using the traditional formula approach.s

SThese figures were calculated by taking Mr. Skirpan's proposed allowance for cash working ca~ital of $12.4 million and reversing his proposals to exclude the so­called non-cash Items. The exclusion of these items reduced the allowance by $110.53 million. ($12.4 + $110.53 = $122.93 million). The Staffs cash working capital allowance under the formula approach is shown in Exh. No. KKP-8, Statement IIA.

54

Moreover, the formula approach produces a cash working capital allowance far below

the cash working capital allowance produced by the Company's lead-lag study. It

therefore appears that the traditional formula approach produces reasonably accurate

results in this case.

9. Unamortized Balances

Virginia Power accepted the Staff's recommendation to recover its future fossil

site project study costs and alternate energy study costs over a three year period.

The Company proposed, however, that the unamortized balance of these costs, and any

other costs that are written off over several years, be included in rate base. This

would allow the Company to earn a full return on the costs until they are recovered

through _base rates.

The Staff opposed tbiS~eq~est, pointing out that the Commission has tradi­

tionally rejected rate base treatment of the unamortized balance of costs that are

amortized over several years. To illustrate this point, the Staff referred to several

past Virginia Power cases where the Commission allowed a recovery of certain costs,

such as nuclear plant abandonment costs and the costs of Surry steam generators that

were prematurely retired, but denied rate base treatment of the unamortized balances.

See Application ofVuginia Electric and Power Co., 1981 SCC Ann. Rep. 238, 240-41;

Application of Virginia Electric and Power Co., 1983 SCC Ann. Rep. 487. Mr. Peterson

further testified that the Commission has traditionally allowed the amortization of

such costs as storm damages, tank painting and rate case expenses, but denied any

associated rate base treatment. (Tr. p. 161-62)

The Company responded by claiming the Commission has allowed the unamortized

balance of deferred capacity costs to be included in rate base. It further claimed

the Staff made a similar proposal in the pending generic proceeding relating to the

recovery of capacity costs, Case No. PUE880052. In that case, the Staff report

55

recommended that the unamortized balance of capacity charges be included in rate base

if deferred accounting was implemented for the recovery of eapacity charges.

I find the Company's proposal to include unamortized balances in rate base

should be denied. As a general rule, the Commission never allows the unamortized

balance of costs to be included in rate base and earn a return. There are numerous

examples of this rule, but the few cited in Staff witness Peterson's testimony, the

Staffs closing brief and the two Virginia Power cases cited above will suffice.

The Company's reliance on the Commission's past decisions allowing the

unamortized balance of deferred capacity charges to be included in rate base is

misplaced. The Commission approved this treatment for capacity charges solely to

create an appropriate incentive for the Company to purchase capacity when it can do

so at lower costs than constru,¢D.g a new generating unit. Application of V'uginia

Electric and Power Co. 1981 SCC Ann. Rep. 238, 241-42. Failure to include the

unamortized balance of deferred capacity charges in rate base would give the Company

little or no incentive to purchase capacity. Denying rate base treatment for these

charges would require the Company to incur literally tens of millions of dollars in

capacity costs while receiving absolutely no allowance for the carrying costs

associated with the delay in recovering the charges. It must be remembered, however,

that this decision represents one very narrow exception to the general rule denying

rate base treatment for unamortized balances. The costs at issue here do not fall

within the exception. Furthermore, it is uncertain whether this practice of

including the unamortized balance of deferred capacity charges in rate base will be

continued in the future. This issue is currently pending Commission decision in the

generic proceeding relating to the recovery of capacity charges, Case No. PUE880052.

The S~s proposed treatment is appropriate for other reasons as well. First,

the Staffs approach will allow the Company to fully recover the costs associated

56

with the future fossil site and alternate energy studies. In addition, the Company

will also receive a return on the costs as they are written off each year through an

allowance on cash working capital. While it is true that the re~ will not be as

great as that afforded by rate base treatment, the fact remains that all costs will

be fully recovered and a portion of the carrying charges will be recovered through

the cash working capital allowance.

Finally, if the concept of rate base as a measurement of the Company's 11USed and

useful" property means anything, costs that have no hope of ever being capitalized as

a part of plant have no business being included in the Company's cost-of-service as a

rate base item. While the Company points out that amortization of costs creates a

"regulatory asset" in its books, there is no possible way this so-called "asset .. can

be deemed "used and useful"_pro~erty under generally accepted regulatory principles.

The costs were not incurred for the construction or improvement of Virginia Power's

property or plant and, for this reason, are not capitalized as a part of rate base.

Indeed, the Uniform System of Accounts requires that such abandoned study costs be

expensed rather than capitalized.

The Company's proposal to include the unamortized balances in rate base is

therefore denied.

10. Nuclear Fuel Assemblies

During his direct testimony, Staff witness Peterson proposed an adjustment to

remove certain nuclear fuel assemblies from rate base that are no longer 11USed and

useful". (Tr. pp. 166-67). The total amount related to the assemblies is $5.49

million, of which $2::24 million is related to fuel discharged prior to full amortiza-

tion due to shorter than expected burn life and $3.25 million is related to damaged

assemblies that cannot be reconstituted. (Tr. 541). Removal of the nuclear fuel

assemblies would reduce the Company's revenue requirements by approximately $900,000.

57

The Company also requested a full recovery of the costs associated with the

nuclear fuel assemblies in its fuel factor proceeding, Case No. PUE880082. Company

witness Bolton agreed that it would be proper to remove the assemblies from rate base

if the Company is allowed to recover these costs through the fuel factor. However,

he said if the Commission determined that inclusion of the costs in base rates is

preferable to recovery through the fuel factor, the rate base reduction proposed by

Mr. Peterson should be rejected

On October 17, 1988, the Commission entered an Order Setting 1988/89 Fuel Factor

for Virginia Power. In that order, the Commission allowed the Company to recover

$1,495,467, representing the unamortized front-end costs of fuel assemblies pre-

maturely discharged from January, 1985 to December 31, 1987. The Commission did not

allow a full recovery of the entire $5.49 million of unamortized nuclear fuel costs, -- --holding that " ... Virginia Power must bear most of the responsibility for not properly

accounting for these assemblies when it determined they were no longer useful to

generate electricity." /d. p. 4.

I find the entire amount of the unamortized balance of nuclear fuel assemblies

must be removed from rate base. This property is no longer "used and useful" and ·

therefore should not be included as a rate base item. Moreover, allowing the entire

balance of the unamortized costs to remain in rate base would allow the Company to

earn a return on the costs the Commission has specifically disallowed to be recovered

from ratepayers. Obviously, it would make no sense to allow a return on costs that

the Commission has refused to be passed on to ratepayers.

The Staffs adjustment to remove the unamortized balance of the nuclear fuel

assemblies from rate base is therefore accepted.

58

11. Rate of Return: Ranee y. Point

All parties agree that in Virginia Power's last general mte case, the Commission

found the Company's cost of equity W8:S within a range of 12.5% to 13.5%. The

Commission authorized a return on equity of 13.25~ for purposes of determining the

Company's revenue requirements given an improvement in the Company's generating unit

performance.

In accordance with the Commission's rate case rules, Virginia Power used a

13.25% cost of equity to calculate its revenue requirements. If its earnings

generated a return on equity below 13.25%, Virginia Power argued it was· entitled to a

rate increase to bring its earnings level up to a level sufficient to generate a

13.25% return on equity.

The Staff and the Attotp.ey __ General disagreed with the Company's contention that

it was automatically entitled to expedited rate relie.f if the return on equity fell

below 13.25%. Rather, they argued that if fully adjusted test year earnings generated

a return on equity within the range approved in the Company's last rate case (12.5%

to 13.5%), the Company was entitled to no rate relief. Moreover, since the Staff's.

and Attorney General's analysis revealed that Virginia Power was earning within the

authorized range, but less than 13.25% return on equity used to set rates in its last

rate case, they concluded that the Company was not entitled to any additional

increase in rates.

I have several problems with the Staff and Attorney General's suggestion that it

is the range itself, rather than a specific point within the range, that determines

the necessity for rate relief. First, and foremost, the Commission's Rules Governing

Rate Increase Applications do not support this argument. Nowhere is there any

indication in the rules that it is the range that governs the necessity for rate

59

relief. To the contrary, there is considerable support in the rules that it is a

specific equity point that is controlling.

Rule ll(l), for example, provides that an applicant in an expedited case

" ... shall use the equity return~ approved by the Commission and used to determine

the revenue requirements in the utility's most recent general rate case" to compute

its cost of capital. The emphasis on a specific rate is mirrored in the instructions

to schedule 12, which provide that the rate used to determine the Company's

additional revenue requirements " .. .in Column 6 [of the schedule] shall be the .r,am

used by the Commisgion to determine revenue requirements in the applicant's most

recent rate case." Simply stated, the standard for rate relief endorsed· by the

Commission's rules appears to be a specific return on equity rate, rather than the

range approved in a Companys ~~st recent rate case. I can find absolutely no rule

or reference supporting the use of the range of equity established in a prior case as

the standard for rate relief in a subsequent expedited case.

In addition, acceptance of this argument would be especially disastrous for

electric utilities because it would devastate the incentive program established by

the Commission to encourage efficient generating unit performance. In past cases,

the Commission has established a 100 basis point range when determining a reasonable

cost of equity for utilities. Superior plant performance is rewarded by approving a

return on equity in the upper end of the range, while inferior performance is

recognized by approving a return on equity at the bottom or low end of the range. I

don't believe anyone can claim that this incentive program has not worked well. It

has benefited ratepay~rs by substantially reducing generating costs and rates.

Using a range for equity as the standard for rate relief in an expedited case

would have a substantial and adverse impact on the performance incentive program

established for electric utilities. A utility with excellent generating unit perfor-

60

mance would be hesitant to file for an expedited rate increase if there was the

possibility of it being deprived of the return increment associated with improved

plant perform.ance. The attractiveness of the more simple expedited rate case would

be substantially dimjnishe~ especially for utilities with a good history of

generating unit performance.

I therefore find that the appropriate standard for determining the need for rate

relief in an expedited rate case should be a specific point within the range approved

in a company's prior case. This does not mean, however, that the specific equity

rate authorized in a prior general case will always be controlling. In past

expedited cases, the authorized equity rate within a previously approved range has

been moved upward as a reward for improved generating unit performance. Application

of Appalachian Power Co., 1983 SCC Ann. Rep. 360, 362 In such a case, the new -IJI8a- --

equity rate would be used .as the standard for rate relief. It is also possible that

a utility's generating unit performance has declined to such an extent that tne

previously authorized equity rate should be lowered. Once again, it would be the

equity rate ultimately selected that will determine the need for rate relief.

Regardless of the point selected, however, it is that point, and not a range that

should be used to determine the need for rate relief.

12. Generatina Unit Performance

Since this case was filed as an expedited rate increase, no witnesses presented

testimony on Virginia Power's current cost of equity. However, Senator DuVal

suggested during cross-examination and in his closing brief that the increment of·

return for superior generating unit performance should be removed given the Company's

decline in nuclear unit performance during 1987. The Senator pointed out that

Virginia Power had two major nuclear outages during 1987 which caused the Company's

nuclear capacity factors to drop significantly. The degraded performance also cost

61

ratepayers over $53 million in replacement power and an additional $10.8 million in

repairs. (Senator brief, p. 3).

I am concerned, as is Senator DuVal, with the Company's degraded nuclear

generating unit performance during 1987. The Company's weighted nuclear capacity

factor dropped from 73% during 1986 to 63% during the test year. (Exh. No. JHF-19).

However, based upon year to date figures through July of 1988, the Company's capacity

factor rebounded to 77%. This is above the 72.7% capacity factor upon which the

Commission awarded the equity premium in the last case.

If the incentive program is to provide appropriate signals to the Company,

degraded performance should be recognized by lowering the return within the

previously approved range. It must be recognized, however, that generating unit

performance will vary from y~ar t9 year. The incentive program should therefore

concentrate on sustained performance rather than zeroing in on one year's data alone.

Just as it takes sustained superior performance to reach the top of the range, it

should take sustained inferior performance before the equity rate is reduced.

In my opinion, degraded performance over a period of time longer than that

demonstrated in this case should be recognized by lowering Virginia Power's equity

return within the range. However, I do not believe that the Company's authorized

return on equity should be lowered at this time. I would merely suggest that the

Company's generating unit performance, especially its nuclear units, be monitored

very closely by the Commission's Staff through the end of 1988. If the degraded

performance is sustained through 1988, I would strongly recommend that the equity

premium be eliminated in the Company's next rate case. '

62

13. Revised Capital Stmctnre

Company witness Bolton's original capital structure, as of December 31, 1987,

showed a 10.26% overall cost of capital. (Exh. No. MSB-2, Sch. 7). Staff witness

~anner examined the Company's proposed capital structure and revised the cost of

Company's preferred stock to comply with the method used in the Company's last rate

case. This revision reduced the Company's overall cost of capital to 10.231%, using

the 13.25% return on equity approved in the Company's last rate case. (Ex. No. DLT-

12, Sch. 1). Otherwise, Ms. Tanner agreed to accept the Company's proposed capital

structure for purposes of this case. She did, however, question the Company's re­

classification of short-term pollution control notes from short-term to long-term

debt and the Company's removal of certain commercial paper relating to VP Fuel

Corporation, a subsidiary of Vir~a Power which finances nuclear fuel for Suny .,_ --

Units 1 and 2. Ms. Tanner did not revise the Company's treatment of the short-term

. pollution control notes because the revision would. not impact the cost of capital.

She did, however, state that in future filings the notes should be treated as short­

term debt as approved in Case N:o. PUE870014. With respect to the V.P. fuel issue,

she emphasized that the Staff was only accepting the Company's proposal for this

case. This will allow the Staff to investigate this item in the future.

In rebuttal testimony, the Company proposed that an updated capital structure be

used to calculate its revenue requirements. Company witness Bolton sponsored a

revised capital structure as of June 30, 1988, which increased the Company's cost of

capital to 10.34%. (MSB-28, Sch. 8). He testified that he used Staff witness

Tanner's methodology to calculate the updated cost of capital and claimed its use

would be consistent with the Commission's decisions in Case Nos. PUE870014 and

PUE840071. In both cases, the Commission used an updated capital structure to

determine Virginia Power's revenue requirements.

63

The Staff and Committee opposed using an updated capital structure claiming it

was beyond the scope of an expedited rate case. Updating for changes in a utility's

capital structure after the end of the test period is permissible only in general

rate cases, where a utility is required to file schedule 36 documenting changes in

the capital structure occurring after the test period. Both of the past cases cited

by Virginia Power in support of its proposal to use an updated capital structure were

general rate cases. This is why the capital structure was updated.

The Staff and Committee also complained that the updated capital structure was

not filed until September 1, 1988, and supporting information was not received by the

Staff until September 7, the day before the beginning of the hearing. Ms. Tanner

testified that she did not have sufficient time to analyze the information and check

its accuracy. .,_. .-

Having found that this application should be treated as a general rate case, any '-

limits imposed by the expedited rules would not preclude the acceptance of an updated

capital structure in this case. I believe evecyone would agree that an updated

capital structure represents a better proxy for the cost of capital in the rate year

than an end of test year capital structure. As with any other issue, however, the

Company must ultimately bear the burden of proving not only that an updated cost of

capital should be used, but must also prove that its proposed updated capital struc­

ture is accurate and is adequately supported in the record.

Here, the Company's proposed capital structure is not supported by one scintilla

of evidence other than one schedule in Mr. Bolton's rebuttal testimony. The

Commission's rate case rules r~quire that a utility file supporting data with its

proposed cost of capital for ratemaking purposes contained in schedule 3. Schedule

4, for example, requires a company to submit detailed information on its bonds,

mortgages, other long-term debt, preferred stock and cost-free capital. Among other

64

things, the instructions require a company to provide a description of each issue,

the amount of each issue outstanding, the percentage of total capitalization, and

the annualized cost based upon the embedded cost rate. In addition, schedule 5

requires a company to provide additional data and explain the methodology used to

calculate the cost and balance for short-term debt, revolving credit agreements and

similar arrangements. This supporting data is necessary so the Commission's Staff

and other parties will have a reasonable opportunity to review the proposed capital

structure and cost of capital prior to any hearing to consider a rate increase

· application.

A brief perusal of the Company's proposed updated capital structure reveals that

no supporting schedules were made a part of the record so an adequate review of the

cost of capital could be und~oak~n by any party in this case. Only one schedule was

submitted in the record and it is impossible to reconcile the differences between the

year-end and updated capital structure based on this schedule alone. Whil~ it may be

true that supporting information was filed with the Staff one day prior to the

hearing, none of this information found its way into the record. 6

Under these circumstances, I am unable to recommend that the Company's revenue

requirements be determined based upon such an unsupported and unsubstantiated capital

structure. If the Company desires to update its capital structure in future rate

cases it should, at a minimum, prepare supporting schedules and make sure this infor­

mation finds its way into record so the Commission can properly evaluate its proposal

and ensure the accuracy of the updated cost of capital. The supporting schedules

6 A review of the case jacket also reveals that 86 pages of documents "described" as supporting wor!q>apers for the revised capital structure were filed at 4:49 p.m. on September 6, 1988, wtth the Commission's Document Control Center. This late filing, however, contains workpapers relating to corrections and proposed adjustments for accounting data. No schedules or information were filed supporting the revised capital structure itself.

65

should also be filed well in a~ce of the hearing so all parties can adeq':lately

review the revised proposal. Since the Company's updated capital structure is

unsupported by any reliable evidence, I feel compelled to reject it in this

proceeding. I therefore find that Staff witness Tanner's proposed capital structure

and cost of capital as of December 31, 1987, should be used to calculate the

Company's revenue requirements. Accordingly, I am adopting the following capital

structure for use in this case:

Long-Term Debt

Preferred Stock

Common Equity

VIRGINIA ELECTRIC AND POWER COMPANY Capital Structure and Cost of Capital

December 31, 1987

Amount (QQQ'sl l!c!lbl ~

$3,728,984 47.712% 8.417%

·s 1m,124 8.996 7.485

$2,944,116 37.670 13.25

Investment Tax Credits s 419,919 5.313 10.257

Cost Free Capital $ 19.501 0.249 O.()QQ

$7,815,644 100.000%

14. ViJ%inia Power's Overall Reyenne Regpirement

Weighted Cost

4.016%

0.673

4.991

0.551

-10.231%

Based upon the resolution of the issues discussed above, the Company's rates in

effect prior to October 18, 1988, produce a return on rate base below 10.231%. The

Company is therefore entitled to some rate relief in this case. Based upon my

findings, current rates must be increased by $24,804,000, to give the Company an

opportun!ty to earn a 10.231% overall return and a 13.25% return on equity. This

overall revenue requirement is calculated below:

66

VIRGINIA POWER'S REVENUE REQUIREMENT

(OOOs)

A. Net Operating Income (Exh. No. KKP-8, Statement II) s ~,780 1. To adjust postage expense for year-end customers 60

2. To accept Company's going level capacity adjustment 8,714

3. To amortize over 3 years North Anna tube rupture repair costs (2,487)

4. To allocate generation related research and development costs to affiliates (937)

s. To restate Chisman Creek dean-up costs to actual test year costs _(23ll

6. Total increase to opetlling ~d maintenance e:xpeuses ~

7. Impact on Taxes (other) (10)

8. Impact on Federal Income Taxes W22l

Net decrease to Net Operating Income (2910)

Adjusted Net Operating Income Per Hearing Examiner . s 584,870

B. Rate Base (Exh. No. KKP-8, Statement II) $5,877,081

1. To remove unamortized balance of nuclear fuel assemblies (5,490)

2. To revise deferred fuel (net of tax) 1,998

3. To revise Westinghouse settlement credit (1,964)

4. To revise cash working capital allowance for changes in operating and maintenance expeuses 491

Adjusted Rate Base Per Hearing Evminer $5,872,116

67

c. Reyepge Reggfi"'!QQept

Revised Rate Base

Rate of Return

Required Net OperatiDg Income

Adjusted Net Operating Income

Deficiency

Tax Conversion Factor

Revenue Requirement

IV. REVENUE ALLOCATION AND RATE DESIGN

1. Revenue Allocation

$5,872,116

10.131%

s fi.XJ,776

584.870

15,906

0.641286

s 24,804

In the Company's last rate_case, the rate decrease was allocated among the

various customer classes using a two step method. First, a portion of the decrease

was allocated to bring each customer class within a plus or minus 10% bandwidth of the

jurisdictional return. The only class exempted from the first step was the church

schedule. Its rate of return was so low that bringing it up to 90% of the overall

return would have resulted in a rate increase for churches, while all other customer

classes would have received a rate decrease. Since a reduction was ordered, it was

only fair and reasonable that all customer classes benefited from the decrease.

The second step of the allocation method was to spread the remaining portion of

the decrease among the various customer classes on an equal percentage basis,

including the church schedule. This ensured that the rates for all customer classes

were decreased

In accordance with the method approved in the last case, Virginia Power proposed

that any increase be allocated to bring each customer class within plus or minus 10%

bandwidth of the jurisdictional rate of return. The remaining portion of the increase

68

would be applied on an equal percentage basis to customer classes earning less than

the jurisdictional return. The following table shows the allocation of the Company's

proposed $96.7 million increase:

SUMMARY OF CLASS REVENUE ALLOCATION

Desqlptlon

Residential Service

Small General Service

Church Service

Large Gen. Service

Outdoor I ighring Service

From Rate Schedules

Other Revenue

Total Vqinia Juris.

CompaDJ Proposed Rmnue Inqease

$59,009,437

$14,637,260

s 294,103

$22,364,121

$ 31J,055

$96,617$16

s 78,024

$96,696,000

Perantage Increase

6.09%

4.32%

4.29%

4.74%

5.39%

5.36%

Company witness Hilton noted in his rebuttal testimony that if the increase

granted by the Conunlssion is substantially less than that proposed by the Company,

some classes may receive a rate decrease under the allocation method while others will

receive an increase. (Exh. No. EPH-27 p. 4; Tr. 514). Nevertheless, Mr. Hilton

continued to support the allocation methodology under these circumstances. (/d.)

The Staff generally supported the allocation method used in the Company's last

case, but urged -the Commission to allocate the increase in such a way that no

customer class received a rate decrease. In the Staffs view, a rate decrease t~ any

customer class during a period of increasing costs would send an inappropriate

pricing signal to customers. (Staff brief, pp. 31-32).

I agree with the Staff. The allocation method approved in the last case should

be used, to the extent possible, when allocating any increase granted in this case.

69

However, the increase should be allocated in such a way that no customer class

receives a decrease in rates as a result of this case.

This recommendation is also not inconsistent with the allocation method used in

the Company's last rate case. In Case No. PUE870014, for example, the church class

was not moved up to a 10% bandwidth of the Company's jurisdictional return because it

would have resulted in a rate increase for churches while other customers received a

substantial reduction in rates. In other words, the allocation method was altered

slightly to ensure that all customers received the benefit of a rate reduction. The

same principle applies with equal force here. All customers should receive the

appropriate pricing signals by not having their rates decreased during a period of

increasing costs.

I therefore recommend that the prior methodology be used to the extent possible .,_. .-

to move each class return to within a plus or minus 10% bandwidth of the jurisdic-

tional return. In no case, however, shall the rate increase granted herein be

allocated so that any customer class receives a decrease in rates.

2. Rate Desip

A Industrial Schedules

The only significant rate design issues raised in this case concern the

Company's industrial schedules. In order to collect the amount of additional

revenues allocated to the industrial class, the Company increased the Power Supply

Demand Charge and the Energy Charges in Schedule 6. Similar increases were proposed

in Schedule 6 TS, Thermal Storage, and Schedule 8, Supplementary, Maintenance,

Standby, Interruptible Standby Service for Customers with Power Plants. The proposed

revisions would have the greatest impact on customers receiving service under

Schedule 6, since over 5600 customers subscribed to this service at the end of the

test year.

70

Both the Staff and Committee criticized the Company's proposed rate design for

industrial customers. Staff witness Raju pointed out that the decrease ordered in

the Company's last rate case was accomplished for industrial customers by lowering

m11x the Power Supply Demand Charge. Accordingly, he recommended that any increase

be allocated to industrial customers by increasing mDx the Power Supply Demand

Charge. In his opinion, the Company's proposal to increase the Energy Charges for

industrial customers was inconsistent with the methodology approved in the Company's

last rate case. Mr. Raju agreed, however, that the Company's proposal to increase

the Energy Charges would move the charges closer toward the Company's unitized energy

costs.

Committee witness Drazen proposed a number of modifications to Schedule 6.

First, he recommended that the _Qtst9mer Charge be increased from $69 to $73 per

month. Company witness Hilton acknowledged that his cost-of-service analysis

sup~orted a $73 charge. He did not propose such an increase because he thought he·

was prevented from doing so in an expedited rate case.

Next, Mr. Drazen recommended that ha1h the the Power Supply Demand Charge and

the Distribution Demand Charge be increased, rather than only the Power Supply Demand

Charge, as proposed by the Company. He said the Company's proposal would result in

the Power Supply Demand Charge being priced above cost while the Distribution Demand

Charge would be priced slightly below cost. (Exh. No. MD-17, p. 4). .

Company witness Hilton responded that if actual billing units were used it shows

that the current Distribution Demand Charge is above cost. This is why no increase

was allocated to this ch~ge. The Company's proposal for Power Supply Demand Charge

would place this charge slightly above cost. ($10.303/kW actual cost v. $10.35

proposed).

71

When allocating revenues and designing rates, the Commission has often stated

that its primary objective is to move rates toward the true cost of providing

service. However, as the Staff recognized in its closing brief, the movement toward

cost is generally limited to general rate cases where accurate and reliable cost­

of-service studies are available. In expedited cases, where an abbreviated schedule

is established to review the application, time constraints prevent the parties from

litigating revenue allocation and rate design issues in the comprehensive manner

afforded by a general rate case. Simplicity is encouraged so the application can be

processed quickly and the new rates placed into effect as soon as possible.

This case, however, is distinguishable from a normal expedited rate case, and I

do not feel compelled to mechanically allocate any increase solely to the specific

charge decreased in the Comp~rs l~t rate case. First, I have previously found

that this application should be treated as a general rate case. Rule ll(3) therefore

does not require that I follow the rate design for Schedule 6 approved in the last

case and allocate any increase ~ to the Power Supply Demand Charge. Second,

virtually all parties agree that certain elements of this schedule, most notably the

Customer Charge and tail block Energy Charge, are currently priced below cost. Since

there is a general consensus among the parties in this respect, there is no legitimate

reason why we should not apply a common sense solution to the probl~ms and correct

the elements that are improperly priced.

I therefore recommend that Mr. Drazen's proposal to increase the customer charge

to $73, as agreed to by the Company, should be appr~ved. This will price the charge

at its true cost. The remaining revenue allocated to the schedule should be

allocated on an equal percentage basis to the Power Supply Demand Charge,

the Distribution Demand Charge and the Energy Charges. This allocation methodology

should have the effect of moving most of these charges toward cost. Based on the

72

Company's analysis, for example, ~proposal will move the. Power Supply Demand

Charge and tail block Energy Charge toward cost. While the Company's analysis

indicates that its current Distribution Demand Charge is above cost, the increment

allocated to this element under the equal percentage method will be so small that no

significant movement away from cost should occur. In addition, all of the charges in

Schedule 6 can be reviewed in the Company's next generai rate case.

B. End of Period Sales Volume

The acceptance of the sales annualization adjustment based upon the end of test

period customer level must be recognized when the Company designs its rates in this

case. Use of actual test year sales to design rates to produce the additional amount

of revenues found reasonable herein will not properly reflect acceptance of the sales

annualization adjustment. For tbis reason, actual sales must be· adjusted to end of

period levels in order to build the $38.6 million revenue adjustment into future

rates.

3. Compliance Filina

The Committee recommended that Virginia Power be required to file a compliance

filing tt[i]n order to resolve any potential disagreements among the parties regarding

the implementation of rates to conform with the Commission's Final Order in this

matter... Any questions regarding the implementation of the order can be resolved in

technical conferences or, if necessary, by further Commission action." (Committee

brief, pp. 57-58). The Company did not object to this proposal, but pointed out that

" ••• this procedure would need to proceed rapidly since there is limited time between

when the Final Order is issued and the effective date of the final rates." (Exh. No.

EPH-27, p. 3).

73

I do not recommend that the Commission endorse the concept of a compliance

filing because it will only further delay and complicate the ratemaking process.

Delays will occur simply because if all differences cannot be resolved informally in

a technical conference, another hearing will be required to resolve any outstanding

revenue allocation or rate design differences. Such a bifurcated approach to the

ratemaking process was rejected in Virginia Power's 1969 rate case and it should

again be rejected here. Commonwealth v. VEPCO, 211 Va. 758,772-73 (1971).

All parties are given one opportunity to address revenue allocation and rate

design issues during a hearing on a rate increase application. Providing yet a

second opportunity to contest the Company's actual implementation of the revenue

allocation and rate design approved by the Commission would be inefficient,

unnecessary and will only delay tJJ.e ra_temaking process for no good reason. This case

has been on the Commission's docket for almost 6 months. There is no reason for any

further delays in this case by creating a potential for a second round of hearings on

the revenue allocation and rate design implemented by the Company in response to the

Commission's Final Order.

FINDINGS AND RECOMMENDATIONS

After considering the evidence in this ~e, I find that:

(1) The use of a test year ending December 31, 1987, is proper in this

proceeding;

(2) The 1325% re~ on equity authorized by the Commission to establish rates

in Case No. PUE870014,._ remains a just and reasonable return on equity and should be

used to establish the Company's revenue requirements in this case;

(3) The Company's weighted cost of capital as of December 31, 1987, was 10.231%;

74

( 4) !he Company's propose~ rates, designed to produce $96,696,000 in additional

gross annual revenues, are unjust and unreasonable because the-rates will produce a

return on investment exceeding 10.231 %;

(5) The Company's current rates should be increased to produce $24,804,000 in

additional gross annual revenues. This increase will afford the Company the

opportunity to earn a jurisdictioital return of 10.231%, and a return on equity of

13.25%;

( 6) The Company has fully recovered the capacity charges deferred on its books

between January 1 and September 13, 1987, through base rates in effect during 1987.

Any additional allowance for this item in future rates would be improper because it

would allow a double recovery of the charges from ratepayers;

(7) The rate increase should Q.e·allocated among the Company's rate schedules in

accordance with the revenue allocation method described in this Report;

(8) The Company's proposed rate design for all schedules, with the exception of

Schedule 6, is just and reasonable and should be accepted. Schedule 6 should be

designed using the method described in this Report;

(9) When designing rates to produce the amount of additional revenues found

reasonable, the Company should adjust sales volumes or additional revenues to reflect

the end of test period customer base. Use of actual sale volumes to design rates

will not properly reflect the sales annualization adjustment for customer growth;

(10) The Company's proposed rates placed into effect on October 18, 1988,

produce annual revenues greater than that found reasonable in this Report. The

Company should therefore refund, with interest, all amounts collected under the

interim rates that exceed the amount found just and reasonable herein.

15.

I therefore RECOMMEND that the Commission enter an Order that:

(1) Directs a prompt refund, with interest, of the excess revenues collected

under the interim rates in effect since October 18, 1988;.

(2) Permits rates calculated in accordance with the findings made in this

Report to be placed into effect on a permanent basis; and

(3) Dismisses this case from the Commission's docket of active proceedings.

COMMENTS

The parties are advised that any comments (Rule 5:15(e)) to this Report must be

filed with the Oerk of the Commission in writing, in an original and fifteen ( 15)

copies, within fifteen (15) days from the date hereof. The mailing address to which

any such filing must be sent is D9£UII!ent Control Center, P. 0. Box 2118, Richmond,

Virginia 23216. Any party filing such comments shall attach a certificate to the

foot of such document that copies have been mailed or delivered to all other counsel

of record and to any party not represented by counsel.

Respe~ysubmitted,

Document Control Center is hereby requested to mail or deliver a copy of the

above Report on November 10, 1988 to: John E. Cunningham, Esquire, Virginia Electric

and Power Company, One James River Plaza, Richmond, VA 23219; Evans B. Brasfield,

Esquire, Hunton & Williams, 707 E. Main Street, Richmond, VA 23219; Edgar M. Roach,

Jr., Esquire, Hunton & Williams, 707 East Main Street, Richmond, VA 23219; Hullihen

76

W. Moore, _Esquire, Christian, Barton, Epps, Brent & Chappell, 1200 Mutual_Building,

Richmond, VA 23219; Donald G. Owens, Esquire, Mays & Valentine, 1111 East Main

Street, Richmond, VA 23208-9970; Edward L Flippen, Esquire, Mays & Valentine, 111

East Main Street, Richmond, VA 23208-9970; WilliamS. Bllenky, Esquire, Office of

the Attorney General, Division of Consumer Counsel, 101 North 8th Street, Richmond,

VA 23209; Micheal L Hem, Esquire, Litten, Sipe & Miller, P. 0. Box 3G, 1001 East

Broad Street, Richmond, VA 23207; James C. Dimitri, Esquire, Christian, Barton,

Epps, Brent & Chappell, 1200 Mutual Building, Richmond, VA 23219; Dennis R. Bates,

Esquire, 4100 Chain Bridge Road, Fairfax, VA 22030; Kenneth G. Hurwitz, Esquire,

Ritts, Brickfield & Kaufman, Watergate 600 Bldg., Suite 915, Washington, DC 20037;

Frann G. Francis, Esquire, 1413 K Street, NW, Suite 600, Washington, DC 20005; and '

Anthony J. Gambardella, Jr., Esquire, Deborah V. Ellenberg, Esquire, and Wayne N.

Smith, Esquire, Commission Counsel.

77

I.

Attachment A

RULIS GOVBRRING VfiJ.Ift RAft IRCRBASB APPLICUIORS

An application for a rate increase filed by a public utility, as defined in Section 56-232, Code of Virginia, (except Electric Cooperatives, as defined in the Electric Cooperatives Act, Code of Virginia, Section 56-209, and Telephone Cooperatives, as defined in the Telephone Cooperatives Act, Code of · Virginia, Section 56-487), having annual revenues exceeding $1,000,000, which proposes to increase annual operating revenues shall include:

(1) The name and post office address of the applicant and the name and post office address of its counsel.

(2) A full clear statement of the facts which the applicant is prepared to prove by competent evidence, the proof of which will warrant the objectives sought.

(3) A statement of details of the objective · sought and the legal basis therefor.

(4) All applicant sought.

direct testimony by which the expects to support the objective

(5) Exhibits consisting of Schedules 1 through 36 shall be submitted with the utility's direct testimony. Such schedules shall be identified with the appropriate schedule number and shall be prepared in accordance with the instructions contained in the Appendix attached hereto and the following general instructions:

Supplement C

•":

··.::·

...

. ·~

A. Attach a table of contents of the Company's application, including exhibits.

B. The applicant will be expected to verify the accuracy of all data and calculations contained in and pertaining to every exhibit submitted, as well as support any adjustments, allocations or rate design relied upon by the utility.

c. Each exhibit shall be labeled with the name of the applicant and the initials of the sponsoring witness in the upper right hand corner as shown belowa

Exhibit No. (Leave Blank) Witnesss (Initials) Statement or Schedule Humber

The first page of all exhibits shall contain a caption, limited to 40 characters, which describes the subject matter of the exhibit.

D. If the accounting and statistical data submitted differ from the books of the applicant, then the applicant shall include in its filing a reconciliation schedule for each account or subaccount which differs, together with an explanation describing the nature of the difference.

E. The required accounting and statistical data shall include all 'WOrk papers and other information necessary to ensure that the items, statements and schedules are not misleading.

(6) Exhibits consisting of additional schedules may be submitted with the utility's direct testimony. Such schedules shall be identified as Schedule 37 et seq. and shall conform at a minimum to the general instructions contained in Rule I(S).

(7) Applications shall be filed in original with twenty (20) copies. An application shall not be deemed filed under Section 56-238, Code of Virginia, unless it is in full compliance with these rules.

-2-

(8) The selection of a test period is up to the applicant. However, the use of overlapping test periods will not be allowed.

(9) Each utility not requesting a base rate increase shall file Schedules 1 through 15 using the twelve months immediately following the test period used in the Company's most recent rate application. This information shall be filed with the Commission within 90 days after the end of the test period.

II. An applicant which has not experienced a substantial change in circumstances may file for an expedited increase in rates as an alternative to a general rate application. If, upon timely consideration of the expedited application and supporting evidence it appears that a substantial change in circumstances has taken place since the applicant's last rate case, then the CoJmDission may take appropr late action, such as directing that the application be dismissed or treated as a general rate application. Prior to public hearing, and subject to applicable provisions of law, an application for an expedited rate increase may be granted thirty days following the filing of such an application. An applicant seeking an expedited increase in rates shall comply with the following rules in addition to the rules contained in Section I, above: (1) In computing its cost of capital, as prescribed in Schedule 3 of the Appendix attached hereto, the applicant shall use the equity return ~ approved by the Commission and used to determine the revenue requirements in the utility's mos~ recent general rate case.

(2) An applicant, in developing its rate of return statement, shall make adjustments to its test period jurisdictional results only in accordance with the instructions accompanying Schedules 12, 13, and 14 in the Appendix attached hereto.

(3) Allocation methodologies and rate design objectives are determined by the Commission in general rate cases. Therefore, a utility seeking an expedited increase in rates shall allocate any proposed increases among its customer classes and shall design its proposed rates consistent with the Commission's order in the applicant's most recent general rate case.

-3-

III. Rates authorized to take effect 30 days following the filing of any application for an expedited rate increase shall be subject to refund in a manner prescribed by tbe Commission. If rates are subject to refund, the Commission may also direct that such refund bear interest at a rate set by the Commission.

IV. Fuel Factor-cogeneration Piling Requirements

1. General Rate Case - When an electric utility files for a rate increase in the context of a general rate case, fuel factor projections and cogeneration rates shall not be filed as part of the original application. The Commission shall by order, establish a filing date for fuel factor and cogeneration testimony.

2. Expedited Filing When an electric utility files for an expedited rate increase, it shall file fuel factor projections and cogeneration rates at least six full weeks prior to the anticipated effective date of interim rates. Such filing shall include the projections required by the Commission's Puel Monitoring System as well as the necessa~ testimony and exhibits in support of those projections and the proposed cogeneration rates.

3. In the event that an electric utility files an application to increase the fuel factor only, fuel factor projections and proposed cogeneration rates shall be filed six weeks prior to the proposed effective date. The filing shall include projections required by the Commission's Puel Monitoring System as well as the testimony and exhibits supporting the fuel factor projections and cogeneration rates.

4. Regardless of a utility's filing schedule, fuel factor projections must be filed at least six weeks prior to the expiration of the last projection or as required by the Commission.

v. Nothing in these regulations shall be interpreted to apply to applications for temporary reductions of rates pursuant to Section 56-242 of the Code of Virginia or temporary increases in rates pursuant to Section 56-245 of the Code of Virginia.

-4-

. ·. ~ .~ ...

•

VI. The applicant shall serve a copy of the information required in Rule I, paragraphs (1) through (3), upon the Commonwealth's Attorney and Chairman of the Board of Supervisors of each county (or equivalent officials in the counties having alternate forms of government) in this State affected by the proposed increase and upon the Mayor or Manager and the Attorney of every city and town (or equivalent officials in towns and cities having alternate forms of government) in this State affected by the proposed increase. The applicant shall also serve each such official with a statement that a copy of the complete application may be obtained at no cost by making a request therefor orally or in writing to a specified company official or location. In addition, the applicant shall serve a copy of its COJIIPlete application upon the Division of Consumer Counsel of the Office of the Attorney General of Virginia. All such service specified by this rule shall be made either by (a) personal delivery or (b) first class mail, to the customary place of business or to the residence of the person served.

-s-

&ACW:t CSAt<._.(,. .. _. .. _, ........... ·""·" .... · ...... _ ........ , ... f

. .

Schedule 12 Test Period Rate of Return Statement - Adiusted

Instructions: The applicant's rate of return schedule shall

conform to the format of the attached schedule.

- Item line 16 is the •capital expense• of Job Development

Credits, this item shall be computed bf multiplying the overall

rate of return times the percentage of JDC capital .reflected in

the total ratemaking capital times the rate base.

- In an application for an expedited increase in rates, column 2

shall consist of the ratemaking adjustments apprcwed by the

Commission in the applicant's last general rate case. Columna

4 and 5, however, shall be left blank, and the return on equity

shown in column 6 shall be the ~ used by the Commission to

determine revenue requirements in the applicant's most recent

rate case.

- In a general rate application, deviations from previously

approved adjustments shall be identified separately in Schedule

14(a). Previously approved adjustments shall be shown in

COlumn 2 while deviations and proposed new adjustments are

reflected in Column 4.

-20-

l.

2.

).

•• s. '· 7.

•• '· 10.

11.

u. u.

u. u. u. 17.

11. 19. zo. 21.

22. 2l.

.,. 2t •

2S.

26.

TES!' PERIOD RATB 01' RETURN

STATDCEH"'' - ADJUSTED

10~1 aavenuea

Operadng • Maintenance ~nH

Depreciation and a.ortiaatlon Inca- 'rue• !'u .. Otber ftaft I~ 'raaea Galn/Loaa on Prcterty Diapoaltlon

1'otal BllpenHa

Operating I~

Plua ~ &wbere applicable) Leaa a.ar ltable oanatlona Leaa tntereat BllpeAH on CUat~r

Depoe ita

Mjuauct Operatlag lncoM

Plua Otber lncoM (lbcpenae) , .... ,. AI911Able)

Leaa tntereat 8lpenM Leaa Preferred Dividend Leaa .JDC CApital Zl&penH

lncoM Available for eo-. lfquity

AlLowance for Morklng c.pltal Plua Net Otlllty •lant Leaa ~her llate .... Deduc:Uona 1'otal llate ....

1'otal c:aptul foe lateMillftl ec-. 8quity Clpltal

..te of .. turn .. rned on late BaH

VIrginia Juriadictional

Buaineaa Col. (l)

..te of .. curn larned on~ a.iulty

Mte of .. turn ,..t Autbcw la .. on~-..tty __ ,

Adjuauenta Previoualy

Approved Per SChedule U

Col. (2)

Amunta After

Adluataenta Col. (3)

-21-

New Propoaed Adjuauenta

Per SChedule lt(a) Col. ,.,

Alaounta After All

Ad1uat:JDenta Col. (S)

Additional Revenue

R.equire•nt Por a_, Return on

C:O..On P.gu 1 ty Col. (6)

Alllounta After

Additional Revenue

Requirement Col. (7)

...

Schedule 13 Statement of Net Original Cost of Utility Plant and Allowance for

Working Capital for the Test Period and Adiuated

Instructions: This statement shall include a 4etailec1 breakdown

of the total company and jurisdictional rate base. It shall also

indicate all property held for future use by account nwaber and

the date of planned use shall be shown.

- In an application for an expedited increase in rates, the

schedule shall be prepared using the same components and

ratemaking adjustments approved by the COmmission in the

applicant's last general rate case.

- In a general rate application, any deviations from the

ratemaking adjustments approved by the Commission in the

applicant's last rate case shall be shown in a separate column.

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0 0 0 ••••• ··- _________________ ,.

Schedule 14 Explanation of Adjustments to Book Amounts

Instructions: All ratemaking adjustments (test period and

proforma) are to be fully explained in a supporting schedule to

the applicant's rate of return schedule. Such adjustments shall

be numbered sequentially, beginning with operating revenues.

Supporting data for each adjustment, including the details of its

calculation, shall be provided in Schedule 17.

Adjustments previously adjudicated by the Commission are to be

shown in Column (2) on Schedule 12. All proposed new adjustments

are to be reflected in Column (4) on Schedule 12. Allowed

categories of adjustments are listed below:

I. Expedited

a. Adjustments to reflect the ratemaking treatment approved by

the Commission to determine revenue requirements in the

utility's last rate case, such as:

1. Adjustment to annualize changes occurring during the test

period.

2. Adjustments to reflect depreciation and property taxes

based on end-of-period plant balances.

3. Adjustments to reflect known and certain wage agreements

and payroll taxes occur ing in the test period and pro­

forma period (the 12-month period following the test

period).

b. Proforma adjustments will be limited in expedited cases to

the amount of increase or decrease that will be in effect

during the proforma period.

-23-

. . .

II. General

a. All adjustments allowed per schedule 14(1)

b. Additional adjustments not presented to the Coanission

before, for known or anticipated changes occurring during the

test year or proforma period. These adjustments are to be

reflected in Column (4) on Schedule 12.

c. Proforma adjustments shall be limited to the amount of

increase or decrease that will be in effect during the rate

year. Proforma adjustments are also ltmited to changes

occurring during the 12 months past the test year.

III. Expedited and General

Financial costs, line items 14, 15 and 16, and cOZIIDOn equity

capital, line item 23, in Schedule 12 shall be adjusted to

reflect the cost and weights embedded in the overall rate of

return requested by the applicant. These adjustments shall be

reflected in Col. (6) on Schedule 12.

Schedule 15 Statement of Compliance

Instructions: Include a statement signed by the principal

officer (consultant) for rate applications and the chief

executive officer or manager of the utility that the application

conforms to the rules governing rate increase applications and

that the schedules filed with this application comply with the

instruction·& contained in schedules 1-36 of the rules gcwerning

utility rate applications.

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. N T£R COMMONWEALTH OF vrRGrli 9l DOCUMENT CONTROl ~ :.~,.

STATE CORPORATION COMMIS~ION

Supplement D

-~ .. U-.);J

1991 ~JAY I 0 AM 9= 1,4 AT RICHMOND, MAY 10, 1991

APPLICATION OF

VIRGINIA-AMERICAN WATER COMPANY CASE NO. PUE910028

For an expedited increase in rates

PRELIMINARY ORDER

On April 22, 1991, Virginia-American Water Company

("Virginia-American" or the "Company'') filed an application,

supporting testimony and exhibits requesting expedited rate

relief. The proposed rates are designed to produce an increase

in the Company's annual operating revenues of approximately

$1,251,004. By Districts, the requested increases are as follows:

$397,340 or 5.21% increase for Hopewell; $265,042 or 2.39% increase for Alexandria; and $588,622 or 14.27% increase for Prince William.

Prior to filing its application, on April 12, 1991, the

Company filed its Motion for Waiver. In its Motion, Virginia­

American requested a waiver of Rule II(2) of the Commission's

Rules Governing Utility Rate Increase Applications and Annual

Informational Filings ("Rules"). Rule II(2) generally prohibits

an applicant seeking an expedited rate increase from proposing

new adjustments. Schedules, therefore, must be prepared using

the same components and ratemaking adjustments approved in an

applicant's last rate case.

Specifically, the Company requested the Commission to

consider a rate base adjustment for extraordinary maintenance

repairs associated with the reconstruction of its filter building

in the Southern Division. Virginia-American proposes to include

1/8 of those expanses in the currant rate year and include the

unaaortized balance in rate base. No such adjustment vas

considered in the Company's last case. The Coapany also requests

permission to eliminate the expenses associated with the

administration of American Water Works Company's pension plan

from its coats of service in the context of this expedited case.

In its Motion, the Coapany recognizes that maintenance

repairs associated with reconstruction of the filter building

were not considered as a component of rat~ base in its last case.

The Company argues, however, that those repairs were substantial

and will significantly prolonq the life of the existing facility.

The Company argues that the expenses are tantamount to capital

improvements and should be given treatment similar to the

treatment afforded the Company's multi-million dollar

reconstruction program in the last case.

The Company also argues that it should be allowed to

eliminate pension plan administrative costs although they were

included in the Company's cost of service in its previous case.

The Company states that, in 1990, these administrative costs were

internalized by American Water Works Company with no charqe to

each operating subsidiary.

HOW, BAVXHG CONSIDERED the Company's Motion, the Commission

finds that it should be granted and the Company should be

permitted to raise the issues it identified in its Motion in the

context of this expedited rate case. Although extraordinary

maintenance repairs were not previously qiven rate base

treatment, we agree with the Company that these repairs are an

2

integral part of Virginia-American's reconstruction proqraa which

was addressed in its last case, case Ho. PUB900017. It is also

appropriate to consider removing the pension plan administrative

costs from the Company's cost of service. Granting the company's

Motion for Waiver, however, should not be considered a final

deteraination on the merits of these adjuataenta. Accordingly,

IT IS ORDERED:

(1) That Virqinia-American•s application for expedited rate

relief is b~reby docketed and assigned Case No. PUB910028; and

(2) That the Motion for Waiver filed by the Company is

qranted.

AN ATTESTED COPY hereof shall be sent by the Clerk of the

Commission to Richard D. Gary, Esquire and Graham c. Daniels,

Esquire, Hunton & Williams, Riverfront Plaza, East Tower,

951 East Byrd Street, Richmond, Virginia 23219-4074; Edward

Petrini, Office of the Attorney General, Division of Consumer

Counsel, 101 North 8th Street, Richmond, Virginia 23219: and to

the Commission's Divisions of Energy Regulation, Public Utility

Accounting and Economics and Finance.

ATrueCowJI 'A..IJ/)_,~· -r ~ · .. Testa: (IV~._,. ~~- Clerk of tha

-·Ji~~·Ctariaretiaa Cemmtuian .,. ----. ..... -

3

~ Supplement E COMMONWEALTII OF VIRG~ 91 L

IW'\.I _Sl'AJE.CORPORA1lON COMMISSION ;J .1. U :J l.f. ~ DOCUMENT CONT nuL Q:.N I t.K

01 MAY t ~ PM 4: 07 \9ilPPLieATIOR OF

AT RICHMOND, MAY 13 ~~ 1991

SOUTHWESTERN VIRGINIA GAS COMPANY CASE HO. POE910024

For an expedited increase in ratea

ORDER GRANTING MQTIQN

on May 1, 1991, Southwestern Virginia Gas Company

("Southwestern" or "the company") filed a Motion for Waiver with

and delivered an application for expedited rate relief to the

State Corporation Commission ("Commission"). In its Motion,

Southwestern noted that its rate application requested an

increase in revenues of $270,596, and included several rate

design and tariff items the Company acknowledqed could be

construed as falling outside the scope of traditional

expedited rate applications. Specifically, the Company requested

the Commission to grant it a waiver of Rule II(3) of the Rules

Governing Utility Rate Increase Applications and Annual

Informational Filings ("Rules•). Rule II(3) provides in

pertinent part that 11 ••• a utility seeking an expedited

increase in rates shall allocate any proposed increases amonq its

customer classes and shall design its proposed rates consistent

with the co .. ission•s order in the applicant's most recent

general rata case.•

The company's Motion asserts that the Final Order in

Southwestern's last rate case directed Southwestern to conduct a

cost-of-service study as part of its succeeding rata case and

encouraged it to consider restructuring its rate schedules based

on its customers• load and usage characteristics. Additionally,

Southwestern stated that it has filed its coat-of-service

study and that the study supports a proposed customer

charge for residential customers, an increase in transportation

rates by 10¢ per Mcf, and a new rate for metered propane qas

service. In addition, the company proposes to replace Rules 9

and 11 of its tariffs to require its customers to use natural gas

for their primary heat, primary coolinq, water heat or other

connected load rated in excess of 100,000 Btu/hour input before

the Company must extend a qas main or install a gas service line

without charge to these customers.

NOW, UPON CONSIDERATION of the Company's Motion, the

Commission is of the opinion and finds that the Company's request

for waiver should be granted and that the company should be

permitted to raise the issues it has identified in its Motion as

part of its expedited rate application. In our opinion, the rate

desiqn issues relatinq to the increase in the transportation rate

and the residential customer charge appear to be within the scope

of the issues recoqnized in our September 29, 1989 Final Order in

the Company's last case. The Metered Propane Gas Service may be

considered a new service, but this revision, together with new

Rules 9 and 11, do not, in our judgment, pose such a substantial

change in circumstances that would warrant dismissal of the

application or conversion of the application to a general case.

However, our decision to permit these issues to be raised as part

of Southwestern's expedited application should not be considered

a final determination of these issues.

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Accordingly, IT IS ORDERED that Southwestern's request for

waiver is granted for the purpose of considerinCJ the issues the

Company baa identified in its May 1 Motion: and the Company

may addres• its proposed residential customer charge, increased

transportation rata, new metered propane ga• service, and new

Rule• 9 and 11 within the context of ita expedited rate

application. IT IS FURTHER ORDERED that this .. tter is hereby

continued.

AH ATTESTED COPY hereof shall be sent by the Clerk of the

Commission to: Richard D. Gary, Esquire, Bunton ' Williams,

Riverfront Plaza, East Tower, 951 East Byrd Street, Richmond,

Virqinia 23219-4074; Edward L. Petrini, Senior Assistant Attorney

General, Division of Consumer counsel, Office of the Attorney

General, 101 North 8th Street, 6th Floor, Richmond, Virqinia

23219; and the Commonwealth's Office of General Counsel and

Divisions of Energy Requlation, Public Utility Accounting, and

Economics and Finance.

..·~· .. .

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