ready has received its carrot the exclusive franchise. Its quid pro 9240 is to buy resources efficiently

Suppose an independent gener- ator, 15 years into a 20-year con- tract, sought an extra payment for the final five years. The utility buyer would point to the contract, not pay more carrots. The fran- chise obligation is no less binding. Utilities always say their “fran- chise obligation” is sturdier than the independents’ “contract obli- gation.” Now the shoe is on the other foot. If a legal monopoly can redefine its franchise obliga- tion with each inconvenient task, themisnolimitoncarrots.

Arguments for “incentives” fo cus on the utility’s interests rather than its obligations. The law of regulation is the opposite. The regulatory question is not ‘How do we make utilities whole?” but “How do we set prices at competi- tive levels?” In a competitive mar- ket, the loser is never “made whole”; it just tries harder. w

Endnotes:

1. Incentive advocates call for a “re- turn on purchased power.” That is a logical impossibility. Return is associ- ated with an investment. Purchased power is an expense. Mixing these concepts clouds the debate. Even if one accepted the debt equivalency ar- gument, one never would talk about a “return on debt.”

2. Direct Testimony of Barry N.l? Hudddleston at 19-20, Investigation on the Commission’s Own Motion Into Barriers to Contracts Between Electric Utilities and Nonutility Cogen- erators and Certain Related Policy Is- sues, Docket No. 05-EI-112 (Tr. 2526, June 29,1993).

Integrating Purchased Power into the Resource Portfolio - an Exercise in Mitigating Risks With the breakdown ofthe traditional regulatory model, utilities are looking to the integrated resource plan to addms such disparate issues as mitigating risk, profitingj&n competition, and achting public and regulatory acceptance qf the utility’s role.

Rent Foster

L Bntakdown of the Old Order

T raditionally electric utility regulation postulated that

utilities that made prudent invest- ments in plant that was used and useful would return the capital in- vested to their shareholders and bondholders and earn a fair re- turn on that capital. Without go- ing into a long history of the so- called “regulatory compact/ it is probably fair to say that electric utilities no longer view the risks of building new generating facili- ties as being represented by that traditional view.

It is also probably fair to say that most utilities, including my own, assumed when they began

constructing plants completed during the late 1970s and early ’80s that regulators would allow them to pass along to customers the prudently incurred risks of ac- quiring new supply resources. As we all know, events proved this assumption wrong: Sta*permit- ted power plants were afflicted

with ex post cost disallowances af-

ter the plants were constructed. Just as these denials of cost re-

covery mached their peak during the 198Os, new laws designed to inject competition into the electric industry also took effect. The Pub- lic Utility Regulatory Policies Act

Kent Foster is vice president of Entergy Services., where he is

responsible for state regulatory and government aflairs for Entergy Corp.

operations in Arkansas, Louisiana, Mississippi, Missouri and the City of

New Orleans. Prior to joining the Entergy staffi he was a partner in the law firm of Mitchell, Williams, Selig

and ‘kker, where he worked on public utihty regulatory matters. In

1974-76 he was chief counsel to the Arkansas Public Service Commission. Mr. Foster earned a B.A. degreefrom

the University of Arkansas in 1970 and a I.D. from the University of Arkansas School of Law in 1973. Walter W. Nixon ZZZ, Director of Regulato y Research, assisted in

preparation of this article.

August&Wnber 1993 4S

and certain state-enacted meas- ures served to revitalize the cogen- eration industry upon which much of the electric utility infra- structurehadbeenfoundedinthe 1920s and ’30s.

Although these laws clearly worked to stimulate creation of the non-utility generation (NUG) industry as we know it today they did not always work to the advantage of electricity users. In- stead, users’ costs sometimes in- creased over what they would have been if their utilities had not been required to pay NUGs more than their true avoided cost of power.

A tthesametimethatmany utilities were seeking to re-

main financially viable (in spite of the disallowances) and the NUG industry was gaining a foothold, customers began to respond to higher electricity prices by con- serving energy Demand growth in the ’80s slowed dramatically from what it had been in the ’60s and ‘7Os, exacerbating the finan- cial condition of utilities, espe- cially those struggling to com- plete costly new plants.

In the late Ws, the Federal En- ergy Regulatory Commission acted to inject new competitive forces into the industry by mov- ing to foster open access transmis- sion and market-based pricing of wholesale power. These trends culminated in the passage by Con- gress last October of the Energy Policy Act, which formal&d open access, reformed the Public Utility Holding Company Act of 1935 to authorize the creation of

exempt wholesale generating (EWG) companies free from mgu- lation under PUHCA, and institu- tionalized the legitimacy of inte- grated resource planning for both electric and gas utilities.

Caught in these crosswinds, electric utilities now seek to rede- fine their place in American soci- ety in a manner consistent with these challenges. Competition, open access, integrated resource planning, demand-side manage- ment and energy efficiency, non- utility power, customer bypass

andmtailwheelingamthechal- lenges of the day

In the context of ‘buy vs. build,” I believe that competition between the buy and build op- tions should serve the goal of cost mmimization for utility custom- ers and society at large. I also be lieve the playing field is leveled when there is no artificial prefer- ence for either utility-generated or pumhased power.

II. Purchased Power aqd Risk

The best tool for choosing when (and what) to buy or build is the integrated resource planning proc- ess. Within that context, pur-

chased power is clearly one of the . major resource options to be con- sidered.

It is my sense that neither utili- ties nor their regulators wish to IV- live the contentious times of the recent past, with ex pcsf prudence reviews, used-and-useful disal- lowances, and tortuous and lengthy litigation aimed at fixing blame for decisions that didn’t turn out as originally expe&d.

W ill injecting long-term purchased power into

the resource mix improve our chances of avoiding a repeat of those litigious times? Recent pro- nouncements of the nation’s ma- jor credit rating agencies - Stand- ard and Poor’s, Duff & Phelps, and Moody’s - acknowledge that there am both benefits and risksassociatedwithpumhased power contracts. Our industry is rightly concerned when rating agencies treat purchased power agreements as off-balance sheet debt and downgrade the securi- ties of companies who, in the rat- ing agencies’ view, have ventured too deeply into the buy side.

Anumber of utilities have sought increases in equity ratios and/or increased returns on eq- uity to account for the rating agen- cies’ imputation of debt equiva- lents when making the financial ratio calculations that am used to rate the utilities’ bonds, preferred stock, and commercial paper. It is still too early to tell how state IeglllatoIWill respond to these requests. One would hope that those regulators who are encour- aging increased reliance on pur-

4% The Eltxtrkity Journal

&asedpowerwillbewillingto

compensate shareholders for any additional risks the market im- putes to their securities.

The rating agencies use differ- ent methods for calculating these ratios. Clearly the process is not an exact science. Agreat deal of judgment must be applied in as- sessing whether a utility that in- creases its reliance on purchased

power has taken on significant new risks that directly threaten bondholders, or taken prudent steps to mitigate that risk

Utilities am always looking for ways to avoid or at least reduce risks. It is no different when they purchase power on a long-term basis, for which the rating agen- cies have identified market risks,’ operating risks,2 regulatory ri~ks,~ and financialrisksP

According to the rating agen- cies, the factors bearing upon those different kinds of risks are:

0 The quality of the contract document negotiated by the util- ity (e.g., how well does it protect the utility against undesirable con- tingencies?); l Take-&-pay contracts (as op-

posed to risky take-or-pay con- tracts); l Dispatchability of power; 0 Comprehensive integrated re-

source planning processes (par- ticularly if the IRP is approved by regulators);

0 Regulatory-out clauses in pur- chased power contracts; l Cost recovery adjustment

mechanisms that permit dollar- for-dollar recovery of purchased power expense;

l Astate regulatory environ- ment that supports and encour- ages purchased power (presum- ably much enhanced if the regulator allows an incentive);

0 Prospective approval of pur- chased power contracts (i.e., pm- app~-%

l Competitive bidding proc- esses for resource acquisition (con- noting a strong perception of pru- dence); and l “Market-based” pricing for

power, which may lessen the need for regulatory scrutiny.

III. Utility Diversification into Other Phases of the Industry

As even a novice investor knows, diversification of risk is critical to a successful strategy At Entergy, as a complement to our retail distribution operations in the three states we serve, we have also formed our own EWG, known as Entergy Power, Inc., which is marketing outside our system capacity that is excess to our customers’ currentneeds.

Under the direction of our un- regulated affiliate, Entergy Enter- prises, we have also invested in cogeneration projects in Virginia,

generation and transmission sys- temsinArgentinaasapartofthat counws privatization efforts, and DSM ventures. The first of theseD!SMventuresiswithaSili- con Valley fiber optics company that has developed an exceptional load management technology The second is with a Memphis- based commemial lightingprod- ucts and energy services com- pany In each of these ventures and others we may pursue we am sticking to what we know. Our di- versification is, and will continue to be, related to our core utility business.

TV. IRP on the Thtergy System

Currently our forecasts indicate that Enteigy will not need new generating capacity until the year 2001 or later and that we will not need to construct any power plants at new sites for 20 years. We now purchase very little ca- pacity outside our system to meet the needs of our customers. Ow- ing to our pending merger with Gulf States Utilities, which has even more abundant reserves than Pntergy our capacity needs may well be pushed out a couple of years further. Thus, we are not currently in the market as a buyer and do not expect to be for sev- eral more years.

Will the distribution side of En- tergy be a buyer in the wholesale power market? It will if that is the least-cost option at the time we need new resources. The mag- nitude and timing of our involve- ment as a purchaser fmmnon-

J

August/September 1993 47

utility generators will depend, however, on how our on-going IRPpmcessturnsout

In the meantime, we have filed a Dyear Least Cost Integrated Resource Plan (LCIRP), with a threeyear Action Plan for each of our retail companies in all four of our jurisdictions (Arkansas, Lou- isiana, Mississippi, and the City of New Orleans). Over the next three years we anticipate gaining experience in the D!3M market for the benefit of our retail customers through a number of pilot pm- grams that we hope our regula- tors will approve for irnplementa- tionlaterthisyear Oneofour objectives in pursuing DSM is to defer sti.lI further our need for new capacity - either built or bought.

0 ur LCIRPposits that when we do need capacity, our

least-cost option wiI.l be to m- power our existing gas/oil and coal facilities. That proposition will be tested at the appropriate time, however, because we have committed to put that capacity n+ quirement up for bids from any- one who believes they can beat our projection of the cost to refur- bish our own facilities.

It is my hope that all the partici- pants in our collaborative IRP process throughout the Bntergy system will agree that we should consider pumhased power from NUGsasaresourcejustaswedo DSM and constructing or repow- ering our own t&il.ities.

Bntergy has not proposed to earn an incentive for pu&asing power wisely for the simple ma-

son that we aren’t seeking any ca- pacity at all right now. We do not reject the idea out of hand, how- ever On the contrary, I believe one can easily analogize the idea of permitting shareholders to earn an incentive for (or share in the savings of) acquiring low-cost pumhased power to the now-com- mon practice of allowing utilities to earn an incentive or “kicker” for doing a good job in acquiring DSMresources.

I should add, however, that in our recent request to our retail

regulators to allow us to go on with the implementation of pilot DSM projects, we have indicated that we will not ask to earn incen- tives during the pilot phase, so long as we are not precluded from asking for them once the pi- lots have proven their mettle.

If Bntergy assembles a top flight, balanced portfolio of re- sources over the course of our ZS year leastcost planning horizon, perhapsincludingplx&ased power as we approach a capacity constraint, we believe that our regulators and the bond rating agencies should and will take fa- vorable notice and treat us fairly if

wedotherightthingsanddo themwell. Furt&rmo re,ifweare able to reach consensus withma- jor stakeholders on our least-cost plan and obtain regulatory ap proval to implement it, we believe that ought to be viewed as miti- gating regulatory and financial risks.

Havinglivedthloughthestrug- gle over cost recovery following the major baseload construction era, I share with some of the rat- ing agencies the belief that plac- ing alI one’s eggs in the self-build basket would be every bit as risky as moving toward total reliance onpumhasedpower

So, what’s in it for a utility to purchase power? Is there a bias on the part of vertically integrated utilities to build their own plants, sothattheycanearnareturnon those assets through traditional rate of &urn regulation? Or is an era of incentive regulation dawn- inginwhichmarket-andvalue based pricing will become the or- der of the day? Can a utility make a profitable business out of purchasing power wisely? I don’t know the answer to these ques- tions and doubt that anyone does. ButIagreewiththosewhothink that the “price-cap” approach would work and deserves serious consideration.

V Reconciling IRJ? and Competition

One of the most interesting questions that is beginn@ to oc- cupy the attention of thoughtful students of our industry is

48 The EIe&cityJoumal

whether there are fundamental conflictsbetweenintegratedre- sourceplanningandacompeti- tive environment. Must regula- tion have a heavy hand in the IRP process in order for it to work properly? Can the ideas of com- petition, flexible market pricing, and incentives be reconciled with IRP principles without turning a utility’s resource acquisition proc- ess into a morass of micro-man- agement?

I believe there is both mom for and a need for competition

and IRl? Entergy did not embrace IRP because we were forced to by our regulators; indeed, some might say we are stepping out ahead of our regulators and other stakeholders in seeking to operate within a system-wide IRP frame- work long before we need new ca- pacity We think we are doing the right thing in acting now. We thinkIRPwillhelpusbecome more competitive, not less.

We also proposed and worked in the last Congress to advance the concept of Regional IRP -al- beit without success -because we see value for everyone in try- ing to align our interests inmore efficient planning with those whom we serve in our region

At the same time, we have statedinourLCIRPfilingsthat we plan to design a competitive resourcep rocumment process (i.e., some form of bidding) for use when we reach the point at which our System is becoming ca- pacityconstrained.5

We are also studying the possi- ble advantages of broader incen-

tive regulation approaches, which have already been adopted for some other utilities by our regula- tors in Mississippi.

OurIRPprocessnowunder way will, I believe, stand us in good stead with our regulators, as

they examine with us the benefits and risks associated with the buy option IRP provides a cornpIp hensive, fair. and openly accessi- ble framework for evaluating all resource options. It can also ac- commodate market-oriented mechanisms for acquiring those

resouxes, once they havebeen identified and scmened for cost ef- fectiveness.

Finally if the major stakehold- ers in our region, including regu- lators and staffs, consumer advo cates, and industrial and commercial customers, can forge aconsensusonthebestmixofre sources for meeting both short- and longterm needs, I am confi- dent that Rntergy and other utili- ties that follow such a path will find they have mitigated their risks and made major strides to- ward serving customers’ energy needs at least cost. n

Endnotes:

1. Market risks include the risk that demand will fall short of forecasts and that purchased power will become un- economic relative to other sources, leading to a loss of customers, sales, and earnings.

2. Operating risks include the possibti- ity that contracted NUG capacity may never come on line because of environ- mental constraints; uncertainty over whether NUG plants will operate well over their lifetimes; and the poten- tially deleterious effect of NUGs on a utility’s efficiency and reliability, ow- ing to lack of control of the NUG plant’s operations, dispatch and shut- downs for maintenance. Other operating risks are the danger of over- reliance on any one fuel to fire NUGs - e.g., natural gas - and the fact that, unlike the utility, a NUG has no obligation to serve and will remain in business only as long as it is profitable.

3. Regulatory risks include the chance of prospective or retrospective disal- lowances of purchased power expense recovery and the mechanics used by the state in allowing such recovery- e.g., whether an automatic adjustment mechanism for purchased power is in place.

4. Financial risks include the potential for “liquidating rate base” and the de- cline in earnings associated therewith; a shrinking rate base results in a reduc- tion in depreciation cost recovery, thus causing a decay in the cash flow sup- port for future construction. Probably the most important financial risk, in the eyes of the rating agencies, is the fact that long-term contracts contain fixed capacity cost components. Re- gardless of how the NUG has capital- ized its investment (presumably, even with 100% equity), the agencies tend to view these fixed capacity cost obli- gations as off-balance sheet debt equivalents of the purchasing utility.

5. We also intend to use competitive procurement in acquiring DSM re- sources.

August&&mber 2993 49