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GAOUnited States General Accounting Office

Report to the Chairman, Subcommitteeon Water and Power, Committee onResources, House of Representatives

March 2000 POWER MARKETINGADMINISTRATIONS

Their RatesettingPractices ComparedWith Those ofNonfederal Utilities

GAO/AIMD-00-114

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Page 1 GAO/AIMD-00-114 Power Marketing Administration

Contents

Letter

Appendixes Appendix I: Objectives, Scope, and Methodology 4Appendix II: Comments From Southeastern, Southwestern,

and Western Area Power Administrations 4

Appendix III: Comments From the Bonneville Power Administration 5

TablesTable 1: Percentages of the PMAs Debt Repaid Before Due as of

Fiscal Year-End 1998 (in Total and at Least 10 Years Before Due) 2Table 2: Percentages of the PMAs High Interest and Low Interest

Debt Repaid as of Fiscal Year 1998 3

Figures Figure 1: Percentages of Retail and Wholesale Power Sales for PMAs,POGs, and IOUs for 1998, in Megawa tthours (mWh) and Dollars

Figure 2: Illustrative Pinch-Point Year for a PMA Ratesetting System 1Figure 3: The Three PMAs Rate Development Process 1

Figure 4: Bonnevilles Rate Development Process 2Figure 5: Financing Costs as a Percentage of Operating Revenues

for the PMAs, IOUs, and POGs for Fiscal Year 1998 3

Figure 6: Average 1998 Operating Expenses by Generation Typefor Plants Operated by IOUs 3

Figure 7: Percentage of Power Generated by Hydroelectric Plantsfor PMAs, IOUs, and POGs for Fiscal Year 1998 3

Figure 8: Investment in Utility Plant per Megawatt ofGenerating Capacity, 1998 3

Figure 9: Average Revenue per Kilowatthour for Wholesale Salesfor 1998 for PMAs, POGs, and IOUs 3

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Abbreviations

CVP Central Valley ProjectCWIP cons truc tion-work-in -progressDOE Department of EnergyEIA Energy Informa tio n Ad min istr atio nEPAct Energy Policy Act o f 1992FERC Federal Energy Regulatory CommissionGA-AL-SC Georgia-Alabama-South CarolinaIOU investor-owned utility

mWh megawatthourO&M operating and maintenancePMA power m arketing administrationPOG pub lic ly owned gene ra ting u tilityPRS power repayment studyPUC public utility commissionRRS revenue requirement studySCLA-IP Salt Lake City Area Integrated Projects

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United Stat es General Accounting OfficeWashington, D.C. 20548


Accounting and InformationManagement Division

B-283123

March 30, 2000

The Honorable John T. DoolittleChairman, Subcommittee on Water and PowerCommittee on ResourcesHouse of Repres entat ives

Dear Mr. Chairman:

This report responds to your request that we review the ratesettingprac tices of the Department of Energys (DOE) power marketingadministrations (PMA) and compare them with those of other utilities. As afollow-on to our p revious work, which d iscussed the PMAs ability to deferrecovering through rates so me of the federal governments investment in

power facilities, you asked that we examine the PMAs ratesetting practicesand assess the ir impact o n the PMAs future competitiveness. Specifically,you asked us to determine

1. how the PMAs set their rates to recover costs,

2. how the PMAs ratesetting practices compare to those of investor-owned and publicly owned utilities, and

3. the impact of the PMAs ability to defer repayment of portions of theirdebt on their future competitiveness.

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We evaluated the assumptions and p rocesses the PMAs use in setting theirrates and recovering their costs by collecting key data and analyzingmethodologies at the four PMAs,1 DOE, and the Federa l Energy RegulatoryCommission (FERC) as well as three investor-owned utilities (IOU) an dfour publicly owned generating utilities (POG).2 We also compared thePMAs financial data to IOU and POG financial data obtained from theEnergy Informat ion Administrat ion (E IA).3 We cond ucted our review fromJune 1999 through March 2000 in accordance with generally accepted

government auditing standards. Additional information on our ob jectives,scope , and methodology is contained in append ix I.

Results in Brief The PMAs determine the adequacy of rates by performing annual reviewsof their projected costs and revenues,4 using processes and assump tionsthat are to identify and factor into rates costs that are legally recoverable,

while keeping rates as low as possible. Southwestern, Southeastern, andmost Western projects make this determination throu gh po wer repaymentstudies (PRS); Bonneville uses a revenue requirement study (RRS). These

studies analyze historical data and project estimated future costs andrevenues as a key part of ratesetting. The primary goal of the review is todetermine whethe r existing rates will generate sufficient revenue to

recover identified costs over the period under review. The PMAs are to take

action to remed y the situation when the projections indicate that this costrecovery goal is not being met. Any considerat ion of a rate change promp ts

a public process during which customers and the general public are able toprovide input before the change is finalized and approved by FERC.

1The four PMAs are Bonneville Power Administration (Bonneville), Southeastern PowerAdministration (Southeastern ), Southwestern Power Administration (Southwester n), andWestern Area Powe r Administration (Western). Because of differences in legislativeauthority and rate setting practices, in this repo rt we sometimes discuss Bonnevilleseparately and refer to the other PMAs as the three PMAs.

2See appendix I for a further discussion of ou r selection criteria for IOUs and P OGs.

3EIA is a statistical and analytical agency in the Depart ment o f Energy.

4The three PMAs rates are based o n cash flow pr ojections of the revenue required torecover costs. Bonnevilles revenue requirements are set at the higher of forecasted accruedexpenses ( including depreciation expense) or cash requirements. Revenue generated in anygiven year is used to r epay annual expenditures o f the year, such as o perating andmaintenance costs, interest costs, and the cost o f power purcha sed from other u tilities forresale. Any revenue remaining after payment of such annual expen ditures is allocated torepay appropriated debt.

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Although there are similarities between the PMAs ratesetting pract ices andthose o f IOUs and POGs, there a re some key differences. Regulatoryoversight and the processes and assumptions that guide cost recovery varyamong PMAs, IOUs, and POGs. In addition, rates are affected byresponsibilities to investors and/or taxing authorities and whether theentity operates in a cost-based or market-based environment. All theentities we reviewed had some kind of public process that took place wh enchanges in rates were und er con sideration. However, PMAs differed

significantly from IOUs and POGs in two areas. First, they have theflexibility to defer repayment of appropriated debt5 until the year due,which is typically longer than other utilities are able to defer repaymen t of

their debts.6 Second, unlike IOUs and POGs, PMAs do not have to generatea return for owners7 and genera lly do not pay taxes.

While PMAs have the flexibility to defer r epayment of appropriated debtuntil the year due, in practice they have repa id significant po rtions beforedue and generally retire high interest ra te debt first. Neverthe less, the

financing costs as a percentage of opera ting revenues of three o f thePMAsBonneville, Southeastern, and Westernare high relative to IOUsand POGs. Bonnevilles financing cos ts ar e relat ively high because o f itslarge interes t-bearing debt of about $13.8 billion, of which $4.2 billionrelates to nonoperational and canceled nuc lear facilities. Southeasterns

and Westerns financing costs are relatively high because of capitalexpenditures made in recent years, some a t relatively high interest ra tes,much of which has not yet been repaid. These high financing costs maybecome more s ignificant in an increasingly competitive elect ricity indust ryWhile the high financing costs will pose challenges for these three PMAs,

5We call this appropriated debt b ecause PMAs are r equired to set rates t o repayappropriations us ed for capital investments with interest. However, these reimbursableappropriations are not technically considered lending by Treasury. The PMAs in some casesreceive financing through means other than ap propriations. For example, Bonneville issuebonds to th e U.S. Treasury an d Western receives nonfederal (third p arty) financing atcertain projects.

6Due dates for appropriated d ebt vary. In general, appropriated debt r elated to (1) originalconstruction of assets us ed to generate power must be paid within 50 years, (2) assets usedto transmit pow er must b e paid within 35 to 45 years, and (3) replacements of assets th atgenerate or transmit power must be paid within 50 years or their useful service lives,whichever is less.

7IOUs are typically expected to generate a return for shareholders, and some POGs transfefunds from accumulated net revenues to other government units to fund othe r governmentactivities.

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all of the PMAs have importan t cost advantages that enhance theircompetitive positions as indust ry restructuring proceeds and ot her utilitiesattempt to cut costs and become more efficient. Key among the PMAsadvantages is that they market low-cost hydropower, much of it generatedfrom facilities built decades ago at low cos t. In addition, in contrast to IOUsand POGs, PMAs are generally not required to pay taxes or genera te areturn for owners. Because of these inherent cost advantages, the PMAsoverall are well positioned compe titively.

Background The PMAs were established between 1937 and 1977 to sell and transmitelectricity generated primarily from federal hydropow er facilities. Thefacilities were constructed as par t of a larger effort to developmultipurpose wate r projects that have functions in addition to powergeneration, such as navigation, flood control, irrigation, water supply, and

recreation. Most of these facilities were construc ted, and con tinue to beowned and operated, by the Department of the Interiors Bureau ofReclamation and the U.S. Army Corps of Engineers. As required by law, the

PMAs give preference in the sale of power to public power cust omers suchas irrigation distr icts, municipally owned ut ilities, customer-ownedcooperatives, and, in some cas es, state governments and the federal

government.

The electricity industry encompasses both wholesale and retail markets.

Wholesale power sa les are sales by one entity to anoth er for resale toultimate consumers. Retail power sales are sales to res idential,commercial, industr ial, and othe r end-use consumers . Accord ing to EIA,about one ha lf of all electricity genera ted in the United States is traded inthe wholesale market before being sold to the ultimate consumer.

The PMAs sell power primar ily in the wholesale power market. In contras tIOUs and POGs sell mostly retail power. Figure 1 shows the percentages oretail and wholesale power sales for the PMAs, POGs, and IOUs for 1998.

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Figure 1: Percentages of Retail and Wholesale Power Sales for PMAs, POGs, and

IOUs for 1998, in Megawatthours (mWh) and Dollars

Source: Developed by GAO based on data from the PMAs annual reports and composite national daton IOUs and POGs from EIA.

81%

19%

84%

16%

37%

63%

25%

75%

25%

75%

13%

87%

0%

20%

40%

60%

80%

100%

PMAs

(mWh)

PMAs ($) POGs

(mWh)

POGs ($) IOUs

(mWh)

IOUs ($)

Wholesale Sales Retail Sales

Percentage

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The PMAs ope rate in an e lectricity industry that is changing from a h ighlyregulated environment , in which cost is the main factor in determiningrates , to one that increas ingly relies on compet itive market s to set prices.The implementa tion of the Energy Policy Act of 1992 (EPAct) andinitiatives to promote r etail competition in a growing number o f states arecrea ting greater competition in the industry. EPAct authorized FERC8 toorder public utilities to provide tran smission, or wheeling,9 services topromote competitive wholesale power sales. Before the passage of EPAct,

FERC could not require utilities to provide wheeling services to promotewholesale power sales.

Pursuant to its authority under the EPAct, in 1996 FERC issued Order 888,which required u tilities to offer wheeling services to other u tilities orelectricity providers at the same price and availability that th ey give

themselves. This promotes competition by allowing genera tors to makesales for resale (e .g., wholesale sales) to no ncont iguous u tilities. Order 888also allows recovery from customers of prudently incurred stranded costs1

by utilities transitioning into a competitive marketplace . Recovery ofwholesale stranded costs is regulated by FERC. Recovery of retail strandedcosts is regulated at the state level, and implementation varies by state.

In addition, legislature s and public utility commissions in most stat es are

considering, or have approved, initiatives that will promote competition inthe market for re tail power sa les. As of February 1, 2000, 24 state s hadenacted legislation or regulatory orders promoting reta il access tocompetitive markets; the rema ining states and the District of Columbiawere e ither actively pursu ing restructur ing or investigating restructu ringoptions.

8FERC is an independ ent agency within the Department of Energy with broad regulatoryauthority over the interstate trans mission a nd s ale of wholesale electricity, natural gas, andoil.

9Wheeling is the transmission of power over lines owned by another utility.

10As defined by FERC, a stranded cost is any legitimate, prudent, and verifiable costincurred by a public or transmitting utility that is no longer economically viable in acompetitive environment.

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PMA Rateset tingPractices

The PMAs ratesetting practices ( i.e., the processes and assumptions usedin ratesetting) are expected to identify and factor into ra tes all costs thatare legally recoverable from power cus tomers while keeping rates as lowas possible.11 The PMAs rece ive the ir authority to set cost-based rates fromthe Reclamation Project Act of 1939 and the Flood Control Act of 1944. In

addition, the p rimary sta tute governing Bonnevilles ra tesett ing process isthe Northwest Power Act. DOEs ratesett ing practices for the PMAs havebeen established by the Secretary of Energy in Order RA 6120.2.12 Each

PMA performs an an nual ana lysis to identify revenue requirements13 for, ingeneral, a 50-year period.14 In doing so, each PMA costs to be recovered and

levels those costs over the ratesetting period so as to keep rates low andstable. Rates are then set to recover costs.

11Previous GAO reports (Powe r Marketing Administra tions: Cost Recovery, Financing, andComparison to Nonfederal Utilities(GAO/AIMD-96-145, Septembe r 19, 1996); FederalElectricity Activities: The Federa l Governments Net Cost and Pote ntial for Futu re Losses,volumes 1 and 2(GAO/AIMD-97-110 and 110A, Septembe r 19, 1997); and Power MarketingAdministrations: Repayment of Power Costs Needs Closer Monitoring(GAO/AIMD-98-164,June 30, 1998)) have demonstrated that the PMAs are not recovering all costs of generatingtransmitting, and marketing power.

12DOE Order RA 6120.2 on Powe r Marketing Administrat ion Financial Reportingestablishes requirements for a broad range of financial issues, including setting rates,recovering costs, preparing repayment studies, establishing and m aintaining the acco untingsystems, and financial reporting.

13

Revenue requirements are the revenues that must be generated to rep ay costs and debtand irrigation payments due in the applicable time period. In addition, Bonneville includesin its revenue requirements an annual reserve amou nt to mitigate the risk of not achievingrepayment obligations.

14The period covered by the PRSs is longer than 50 years for some projects. For example, thePRSs cover 60 years for the Salt Lake City AreaIntegrat ed Projects an d 100 years for thePick-Sloan pro ject. It can also be shorter than 50 years if the appropriated debt related toassets u sed to generate and transmit powe r is paid off earlier. As discussed later, there canbe a difference between the repayment period and the ratesetting period.
http://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-96-145http://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-97-110http://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-97-110Ahttp://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-98-164http://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-97-110Ahttp://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-98-164http://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-97-110http://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-96-145

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Ident ifying RevenueRequirements

PMAs are required to estab lish power rates sufficient to pay annualexpenditures, such as operating and maintenance costs, interest costs, and

the cost of power purchased from other utilities for resale. Rates must alsobe sufficient to repay debt, including the approp riations that financedcompleted generation and transmission facilities.15 In addition, rates mustbe sufficient to repay certain nonpower costs the Congress has assigned topower users to repay. Bonnevilles and Westerns ra tes are set to co llectadditional revenue to rep ay the federal appropriations that financed certainirrigation facilities.16 In addition, Bonneville is required to provide power tospecified residential and small farm consumers of IOUs.

In addition to the above, Bonnevilles rates mus t cover the cost s of

bonds issued to the Treasury to finance capital programs, such as

transmission system development , conservation, and fish and wildlifeenhancement;

debt service on nonfederal bonds primarily for the construction of

Energy Northwest (formerly the Washington Public Power SupplySystem) nuclear plants;17 and

15In a limited number of cases, the ca pital costs of some completed projects are not includedin rates. For example, as discussed later, certain construction costs and capitalized interesat the Richard B. Russell Project are not included in Southeasterns rates. Other co sts thatare sometimes not recovered from rates include cer tain environmental mitigation costs thahave been legislatively exempted from recovery.

16Reclamation law provides for Bonneville and Western to use their pow er revenues to repaya por tion of the capital costs allocated to completed irrigation facilities that are deter minedby the Secretary of the Interior to be beyond the ability of the irrigators to repay. As ofSeptember 30, 1998, appr oximate ly $863 million in irrigation costs had b een allocate d for

repayment through power revenues at Bonneville and $3,139 million at Western. Of thoseamounts, $25 million (3 percent) had been repaid at Bonneville and $35 million (1 percent)repaid at Western.

17Bonneville used its contracting author ity to acquire all or part of the generating capabilityof nuclear power projects in Energy Northwest. Under these contracts, Bonneville agreed topay all or part o f the annu al projects budgets, including debt se rvice, whether or not theprojects are completed. Two of the nuclear plants are no noperational and therefore do notgenerat e revenues. As of September 30, 1998, Bonneville had $6.9 billion o utst anding innonfederal project debt.

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measures to protect fish and wildlife populations and to mitigatedamage to Pacific Northwes t fish stocks affected by the constructionand ope ration of the Fed eral Columbia River Power System.18

DOE Order RA 6120.2 requires that the PMAs annually determine theadequacy of power rates by calculating how much revenue is needed eachyear to meet annual expenditures and debt r epayment requirements overthe ratesett ing period. The three PMAs make this determination through

power repayment s tudies (PRS). Bonneville uses a revenue requirementstudy (RRS), which is similar to a PRS. Bonneville considers several risksin developing its revenue requirements. Among the r isks considered are

weather-related uncertainties associated with the reliance on hydropowergeneration, market prices for power, general economic conditions, theperformance of its generation assets, and expenditures Bonneville must

make to protect, mitigate, and enhance fish and wildlife populations.Bonnevilles ta rget is to set rates that will result in a 97.5 percentprobability that payment s to the Treasury will be made on time and in full

for each year o f the rate per iod (or 88 percent over a 5-year period). OnceBonneville establishes its revenue requiremen ts, it allocates co sts toclasses of service and designs rates.

PMAs prepa re these studies on either a pro ject basis or a system basis,

consistent with how they sell power and set rates. For examp le,Southeastern sells power within four separate power systems; eachincludes one o r more Corps projects for which rates are se t. BonnevillesRRS includes a ll of its power projects . However, Bonneville is required by26 FERC 61,096 to separately develop transmission rates.

A PMAs PRS or RRS determines its ann ual revenue requirements by

analyzing historical financial informat ion and projected e stimates of futurerevenues, expenditures, and capital costs throughout the period covered bythe s tudy. Historical financial information is gathered from the accounting

records. In addition, historical, and pro jected generation, hydrological andother data are provided by project operator s (i.e., the Bureau and the

Corps).

18Bonnevilles es timated range of funding is $438 million to $721 million annu ally for fiscalyears 2002 through 2006.

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When p repar ing a PRS or RRS, the PMAs mak e severa l assumpt ions aboutthe future in establishing revenue requirements and se tting rates. Keyassumptions include the following:

Historical hydrological data and projected river operations will be usedto project future water conditions.

Appropriated debt related to the original construction of assets used togenerate power will generally be repaid within 50 years.19

Appropriated debt related to assets used to transmit power willgenerally be repa id within 35 to 45 years.

Appropriated debt related to replacements of assets used in generating

and transmitting power will be repaid within the lesser of 50 years ortheir est imated use ful service lives.

The PRS/RRS will include a cost evaluation period, which usually is

the first 5 years of the PRS/RRS.20 During the cos t evaluation period,future estimates of costs and revenues, which are based on forecastedbudget data , may be modified to re flect changing conditions, such as

additions to the power systems or inflation. Operating and maintenance(O&M) cos t estimates ar e escalated by an inflation factor over the 5-yearperiod, and the est imate for the fifth year is then car ried through to theend of the ra tesetting period without further escalation.21

Interest rates in effect for each project will be those specified in the

individual project authorizing legislation, or in DOE Order RA 6120.2 forall future year investments. Where possible, to mitigate interest costs, the highest interest rate debt

will be paid first. The PMAs will take a credit against interest costs to recognize the

savings to the government for payments the PMAs make to the Treasurythroughout the year for obligations that are not due until the end of theyear.

19There are exceptions, such as Bonn evilles Yakima-Chandler Pr oject with a legislatedrepayment period of 66 years.

20

However, the length of the cost evaluation period is discretionary and is n ot always5 years. For ex ample, in its fiscal year 2002 Initial Power Rate Pr oposal, Bonneville uses an8-year cost evaluation period (fiscal years 1999 through 2006). The cost evaluation periodextends from the last year historical information is available (fiscal year 1998) through theproposed 5 year rate test p eriod (fiscal years 2002-2006), which is the period rates areexpected to remain in effect.

21Southeasterns cost estimates are es calated by an inflation factor to the mid-point of theevaluation period. These estimates are then ca rried through to the end of the rate r eviewperiod with no further escalation.

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In addition to the above, Bonneville makes the following key assumptions

U.S. Treasury bonds will be systematically repaid based on the term ofthe debt.

Revenue requirements will be set at the higher of forecasted accruedexpenses (including depreciation expense) or cash requirements.

Rates will be developed so as to create an 88 percent probability thatcash flows will be sufficient to enable Bonneville to make Treasury

payments on t ime and in full over a 5-year period. Bonneville analyzesopera ting (e.g., hydro generation) and nonoperat ing risks (e.g., fish andwildlife expenses) and risk mitigation measures in asse ssing whether

the 88 percen t probability is met . Financial reserves will be maintained to mitigate risk. For example,

Bonneville includes as a component of its revenue requirement,

amounts to mitigate risks associated with several factors, includingfunding of fish and wildlife initiatives, water conditions, and economicconditions.

As mentioned previously, unde r DOE Order RA 6120.2, the PMAs arerequired to se t rates sufficient to recover costs. The PMAs generally usePRSs and RRSs as a basis for setting rates and keeping rates as low andstable as possible, even though revenue r equirements vary from year to

year. For ex ample, a ratesetting system may have 43 years of comparativelystable revenue requirements, but a large increment o f appropriated debtbecomes due in year 44 of the rates etting period. The PMAs attempt to levepayments over the entire ratesetting period.

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Unless otherwise p rescr ibed by project enacting legislation or DOEregulation, the PMAs are generally allowed to defer th e repayment ofappropriated debt until it is due, generally 50 years for originalconst ruction of projects and additions to projects, 35 to 45 years fortransmission assets, and the lesser of 50 years or the estimated service livesfor replacements. These provisions give the PMAs some flexibility, withinthe parameters of DOE Order RA 6120.2, in determining when to repayappropriated debt.22 In practice, after paying annual costs that ar e required

to be paid in any given year, the PMAs then generally use any remainingrevenues to repay highest interest rate debt.23 The PMAs have flexibility inselecting which increment of debt to repay among those bearing the same

interest rate.

Although all the PMAs use a llowable repayment periods as noted above,

there are some d ifferences in their interpretations of DOE Order 6120.2regarding the ratesetting period. For example, Southwestern considers theratesetting period to be 50 years. Southeastern considers the ratesetting

period to be 50 years from the date of the last increment of appropriateddebt tha t would require a rate adjustment; there fore, if no additionalsignificant appropriated debt is incurred, the ratesetting period decreaseseach year. Some Western projects consider the ratesett ing period to be theperiod up to the p inch-point year, discussed below, or when the last

increment of appropriated debt is repaid, whichever is later.

22According to DOE Order RA 6120.2, the order of precedence for repayment each year is

annual expend itures (O&M, purchased and exc hange power, and tr ansmission service),interest costs, unpaid or deferred annua l expenditures, if any, and any debt due in that yearRemaining revenues are available for repayment of a ppropriated debt. In add ition, PublicLaw No. 89-448 authorized the payment of irrigation costs from remaining revenues. Costsincurred in any year in which revenues fail to recover annual expenditures are deferred tothe following year and accrued o n the balance sheet as a liability. Deferred c osts are repaidwith interest.

23Debt that is due in a given yearincluding low interest debt an d irrigation deb t that carrieno interestis a higher priority for repayment than h igher interest rate debt.

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The PMAs rates are generally set based on the projected cumulativerevenue requirements t hrough a time frame ending with what is referred toas the pinch-point year.24 The pinch-point year is the year within theperiod covered by the PRS in which the annua l revenue requirements areprojected to be th e highest. Rates are set to ensure that the cumulativerevenue for the first year of the study through the end o f the pinch-pointyear is at least equal to the cumu lative revenue requirements for the sameperiod. The pinch-point year occurs when a significant required payment is

due for annual expenditures and /or a capital repaymen t obligation.25 Figure2 illustrat es that cumulative revenue an d cumulative revenue requirementsmust be equal by the pinch-point year.

24Rather than pinch-point, Bonneville uses the t erm critical year. The critical year is theyear whe re Bonn evilles levelization of debt s ervice is at the point whe re ea ch ob ligation isscheduled for repayment by no later than its due date .

25

These expenditures that must be made in the pinch-point year arise because (1) annu alexpenditures a re generally required to b e paid in the year incurred, although certainexpenditures can be deferred in years when revenues are insufficient to cover th em, (2) therepayment of some debt cannot be further deferred be cause they are at their due dates,(3) the amoun t of revenue the P MAs can generate each year is limited and therefore th ePMAs canno t wait until the years that the debt is due to repay it, and (4) some lower interesdebt cann ot be p aid earlier because cash available to repay debt will be used to repay higheinteres t rate debt first un der DOE Order RA 6120.2s repayment p reced ence. Only significanchanges in these factors, such as large additions or replacements that w ould affect revenuerequirements, would move the pinch-point year.

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Figure 2: Illustrative Pinch-Point Year for a PMA Ratesetting System

Source: Developed from information provided by the PMAs, particularly the Western Area Power

Administration.

In this example, cumulative revenue meets cumulative revenuerequirements in year 44 of the ratesetting period, the pinch-point year.Under DOE Order RA 6120.2, the PMAs are to take action if the cur rent ratewill not genera te su fficient cumulative revenue to equal cumulativerevenue r equirements by the pinch-point year. Such ac tion may includecutting costs and/or adjusting rates. As illustrated by figure 2, cumulativerevenues exceed cumulative revenue requirements prior to the pinch-pointyear. During this ratese tting period, early repayments of approp riated debtdue in the pinch-point year facilitate meeting total cumulative revenuerequirements by lowering the amount due in the p inch-point year. This

allows a single rate to genera te sufficient revenue t o recover cu mulativecosts by the pinch-point year. Beyond the pinch-point year, the cumulativerevenues exceed the cumulative revenue requirements and rates would be

recalculated.

PMAs Use Open PublicProcess in Developing Rates

When they are considering a rate adjustment, the three PMAs are required

to publish notices in the Federal Registerto notify customers, the general

$0

$500,000,000

$1,000,000,000

$1,500,000,000

$2,000,000,000

$2,500,000,000

$3,000,000,000

$3,500,000,000

$4,000,000,000

00 05 10 15 20 25 30 35 40 45 50

Ratesetting years

Irrigation paymentsdue

Appropriated debtpayments due

Cumulative interestpayments

Cumulativeexpenditures

Cumulative

revenue

requirementsPinch-point

Cumulative revenue

Revenue

requirements

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public, and other interested par ties. The three PMAs then have 90 daysfrom the date of the Federal Registernotice to conduct pub lic informationand public comment forums, which are transcribed formal events in whichthe three PMAs explain the procedures us ed to establish and support therate ad justments and provide citizens the opportunity to voice theiropinions and suggestions. All comments a re considered dur ing the ratedevelopment process. If this public participation process leads tosignificant changes in the proposed rate adjustment, a modified proposal

may be published in the Federal Registerand the public again offered anopportunity to comment on the modifications.

The three PMAs prepare a final rate propo sal for each ratesetting systemand forward the information to the Secretary of Energy or his designee,requesting the Secretary to confirm, approve, and place the rate into effect

on an interim bas is. Once this approval takes p lace and the interim rate isplaced into effect, the Secretary submits the rate p roposal to FERC for finaapproval. After reviewing the rate p roposal, FERC is authorized to take one

of three actions, but does not have authority to change the r ate. FERC may(1) confirm, approve, and place the ra te into effect on a final basis, (2) sendit back to t he PMA for further s tudy, or (3) disapprove it, in which case therate that existed prior to the inter im rate goes back into effect. Uponrende ring its dec ision, FERC publishes a not ice in the Federal Register.

The rate d evelopment pro cess for th e three PMAs is depicted in figure 3.

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Figure 3: The Three PMAs Rate Development Process

At the beginning of each fiscal

year, each PMA updates PRSs

to verify that rates are adequate

to meet repayment criteria

PMAs publish the proposed rates

in the Federal Register

PMAs hold formal public

information and commentforums to explain proposed rate

change

PMAs review comments and

make adjustments, as deemed

appropriate

PMAs submit rates to the

Secretary of Energy or his

designee for approval on an

interim basis

Secretary of Energy or his

designee reviews and approves

the rates on an interim basis(new rates become effective)

FERC allows intervention

before approving the rates on a

final basis or remands the

rates to the PMAs

Each PMA reports the status of

repayment for all of its projects to

the Secretary of Energy

or his designee

(existing rates remain in effect)

PMAs prepare a Revised Power

Repayment Study to support

rate approval requests

Are rates

sufficient to

recover all

costs?

YES

PMAs notify customers and

public of new rate proposal

NO

Development Process

Identifying Revenue

Requirements

Public Rate

Rate Implementation

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Like the three PMAs, Bonneville prepares its revenue r equirementanalysis26 under DOE Order RA 6120.2 guidance and files a notice of theinitial rate proposal in the Federal Register. Bonnevilles rate set ting processis specified in the Northwest Power Act which, among other things,requires Bonneville to hold rate case p roceedings in dete rmining the finalrate proposal.

Bonneville holds field hear ings throughout the region to obtain public input

and questions from all interested pa rticipants (e.g., consumers ). Thehearings are recorded and transcribed and become a part of the officialrecord. In add ition to field hearings, Bonneville ho lds formal hearings,

which are semijudicial rate case proceedings. Both types of hearings arepresided over by a hear ing officer. However, only parties to the ra te case27may take part in the formal hear ings. Such parties file direct cases

(test imony) including responding to Bonnevilles initial rate proposal.Bonneville and the parties file rebuttal testimony to the par ties direct casesand have the opportunity to ask c larifying questions about on e anothers

testimony and submit written data requests in order to prepare theirresponses. In addition, both Bonneville and parties to the rate case have anoppor tunity to cross-examine one another s witnesses on all relevantissues.

At the c lose of the formal hearings, the pa rties prepare initial briefssummarizing their issues to date .28 Bonnevilles Administ rator reviews theofficial record and prepares a draft Record of Decision. Parties to the ra tecase may respond to the d raft Record of Decision by filing Briefs onExcep tions, by a specified date (usually within a month) .29 Theadministrator reviews the entire record and issues a final Record ofDecision. Unlike the th ree PMAs, Bonneville is not r equired to submit its

26When con sidering a rate adjustmen t, Bonnevilles planned exp ense s and capitalinvestments for the rat e period are made su bject to public review and comment before arate p roposal is initiated.

27

Parties to the rate case are th ose individuals or groups designated by the hearing officer aparties. Interested individuals or groups must submit a petition to intervene forconsideration to become parties.

28The purp ose o f an initial brief is to identify separately each legal, factual, and policy issueto be resolved by the Administrator.

29The purpose of the briefs on exceptions is to (1) raise any alleged legal, policy, orevidentiary errors in th e draft Record of Decision and (2) provide additional support fortentative decisions co ntained in the draft Record of Decision.

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rate pro posal to the Secretary of Energy. The proposed ra tes are submitteddirec tly to FERC for approval. FERCs approval process for Bonneville isthe same as for the other th ree PMAs. The rate development process forBonneville is depicted in figure 4.

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Figure 4: Bonnevilles Rate Development Process

Bonneville holds a

prehearing conference

Bonneville holdsfield hearings 1/

Parties file testimony includingresponding to Bonneville's initial

proposal

Bonneville and parties file rebuttal

testimony to parties' direct testimony

Notice of initial proposal published in the Federal Register

(official start of the rate case)

Bonneville and partiescross-examine one

another's witnesses

Parties file initial briefs summarizingthe issues to date

Bonneville's Administrator reviewsthe official record and prepares

draft Record of Decision 3/

Parties review draft Record of

Decision

Parties prepare "Briefs onExceptions"

Bonneville's Administrator reviews

the entire record and issues a finalRecord of Decision

Bonneville files rates with FERC for

approval

Discovery: Partieshave the

opportunity to askclarifying questionsabout Bonneville'sand one another's

testimony andsubmit written data

requests in order toprepare their

respondingtestimony.

1/ The rate case is open to the public; comments become part of the official record.

2/ Some of the field hearings are held concurrently with the formal hearings. Only "parties" to the rate

case may take part in the formal hearings. The hearing officer determines "parties" to the rate case.

3/ Official record includes testimony, exhibits, hearing transcriptions, letters

and other documents filed during the rate case.

Public Comment

and Interaction

Rate Approval Phase

Formal

Hearings2/

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Ratesetting Practicesof the PMAs, IOUs, andPOGs Differ

Like PMAs, IOUs30 and POGs gather data and prepare studies to determinethe revenue requirements necessary to reco ver their costs, obtain inputfrom interested parties at public forums, and present rate proposals to theappropriate oversight body. However, the processes an d assumptions usedby IOUs and POGs differ from those of the PMAs in severa l respec ts. Key

differences relate to

1. cost recovery and the process for setting rates, including oversight

procedures,

2. whether rates are cost-based or market-based, and

3. the responsibilities to owners or taxing authorities.

Cost Recovery Practicesand Ratesetting Processes

In general, PMAs recover their costs through wholesale rates while IOUsand POGs recover costs th rough a combination of retail and wholesalerates. In both regulated and re structured stat es, the mark et generally setsIOUs and POGs wholesale generation ra tes. In a regulated environment,IOUs generally recover their fixed cost s through their re tail rates. As aresult, excess power sold in wholesale markets generates a profit to the

exten t that prices set by the wholesa le market exceed IOUs marginalcosts. As states rest ructu re, IOUs will likely begin to recover more fixedcosts through their wholesale rates because compe titive pre ssures on retai

rates w ill likely reduce the amount o f fixed costs th at IOUs can recoverthrough retail sales. In general, POGs are owned and operated by themunicipalities they serve and repor t to an elected or appointed local

oversight body, such as a city council or u tility governing board. Inaddition, in 12 states POGs are also sub ject to regulation by a stateregulatory aut hority. As a r esult, POGs ratesetting practices vary.

30For purposes of this discussion, we define an IOU as a for-profit utility that generates,transmits, and distributes powe r.

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As noted earlier, the PMAs PRSs/RRSs include information on historicalcosts from project inception and projected costs and revenues over theratesetting period, genera lly 50 years. When setting rates, the PMAs factorprojected inflation into their analyses dur ing the first 5 years of the PRS,which is called the cost evaluation period. In contras t, in setting their retairates IOUs use a much shorter perioda 1-year historical periodandgenerally project costs only from 0 to 2 years forward . Among the POGs,the number of historical years used in setting rates generally ranges from

1 to 3 years while the number o f years u sed to project revenuerequirements typically ranges from 3 to 5 years.31 All of the POGs wecontacted considered the impact o f inflation and/or trends on their

projections of future revenue requirements.

IOUs systematically recover their capital costs through ra tes by using

annual depreciation or amortization,32 either on a s traight-line basis overthe life of the asset or on an accelerated basis.33 IOUs also pay financingcosts, including interest on loans and bond interest, on a systematic annua

basis. They typically repay debt financing obta ined by issuing bonds ortaking out loans in accordance with the terms of the bo nd and loanagreements.

POGs use depreciation and amort ization expense to recognize capital costs

for financial reporting purposes, but generally reco ver capital costs basedon the deb t service requirements included in their annual budgets. They

31For the POGs we contacted, the num ber of historical years used in setting rates rangedfrom 1 to 10 years, while the number o f years used to project revenue requirements rangedfrom 3 to 25 years. However, POGs generally use revenue requirement projections beyond5 years to make de cisions abo ut future ex pansion or to identify when they believe futurerate adjustments or new bo nd issuances may be needed, rather than for immediateratesetting purposes.

32Depreciation is the allocation of the expense associated with prop erty, plant andequipment t o each period benefited by the asset. Amortization is the allocation of expen seassociated with intangible and other assets, such as aban doned plant, to each period

benefited. Straight-line depreciation and amortization are calculated by dividing the cost ofthe as set less es timated sa lvage value, if any, by its estimated u seful life or allowable periodof time.

33Some IOUs are preparing for the move towa rd market-based rates by acceleratingdepreciation while their retail rates still remain protected. For example, some states thathave restructure d have frozen retail rates until a future set date. IOUs can us e thisopportun ity to accelerate depreciation to recover as much of their investment as possible;then, when they make the tr ansition to full market-based rate s, they can stretch outrecovery of their remaining capital costs to make their rates mor e competitive.

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repay financing costs and principal in the same manner as IOUs. Thefinancing period for capital assets and the period for recovering the cost ofcapital projects used by the POGs we contacted ranged up to 35 years. Incontrast t o IOUs and POGs, the PMAs have flexibility to repay theirappropriated debt any time up to the year due, which is generally the 50thyear for generation assets.

IOUs Ratesetting Process To set ra tes in a regulated environment,34 IOUs identify the costs that mustbe recovered through rates, such as those related to O&M, transmission,purchased power, debt related to capital assets, interest on financed debtand/or bonds, and taxes. In identifying these costs, IOUs adjust for known

events, such as salary increases and property tax increases. In addition,IOUs determine the total cost of assets that must be recovered throughrates and ar e allowed to set rates to generate a r egulated rate of return for

investors on the value of these assets.

To determine expec ted revenues, IOUs take the total sales for all classes of

customers for the prior year; in some cases, they recalculate theserevenues to adjust them to a normalized weather year. They then makeadjustments for known future events, such as a ma jor new factory that

would require a s ignificant amount of power in the coming year. In generalIOUs use 1 year of historical data and project from 0 to 2 years into the

future. They compile the data into a rate case, with proposed rates by classof customer (e.g., industrial, commercial, or residential) and submit thecase to the ir state regulatory commission. Like the PMAs rate proposals,the IOUs rate proposa ls undergo a public process whereby interestedparties can testify and introduce exh ibits to support their positions. IOUsnegotiate with their state commissions over the proposed r ates, and thestate commissions actually set the rates.

POGs Ratese tting Process POGs also prepa re cost studies and evaluate their revenue requirements toidentify the need for ra te chan ges, give public notice of proposed ratechanges, obtain input from interested parties at public forums, and presentrate proposals to the appropr iate oversight body for approval. However, we

found significant d ifferences among the POGs regarding the costevaluation period used to identify revenue requirements and se t rates, asillustrated by the following:

34In a restructured environment, the market sets the price for generation and only thedistribut ion port ion of an IOUs rates re mains regulated .

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One POG sets its rates based on projected demand for power andexpec ted costs for the following year only. Although it prepareslong-term cost projec tions internally, these project ions are usedprimarily to make decisions about future expansion and to identifyopportunities to purchase power, and not for setting rates.

A second POG analyzes costs over 5 to 10 years to set rates. Estimates ofuture power needs are generally projected 10 years, while cost ofservice ana lyses used to project future revenue requirements and set

rates a re generally projected over 5 years. A third POG projects its revenue requirements over 25-years and uses

the 3-to-5 year projections to se t rates. These p rojections are based on

actua l historical costs over the last 5 years and pro jected changes in thebudget. The revenue requirement projections for years 6 through 25 areused pr imarily to identify the need for future ra te adjustments or the

issuance of new bonds. The projected costs for this period are based onvarious trend and regression analyses using historical data, the forecastdata for years 1 through 5, and pro jected capital projects.

The fourth POG does not follow a specific or formal process to set ratesThe staff of its electric division makes recommendations to the citycounc il to ensure tha t rates for the following year generate sufficientrevenue to cover ac tual budgeted expenses plus a required payment inlieu of taxes to the c itys genera l fund. Costs a re generally not pro jected

beyond the 1-year period.

POGs propose the ir own reta il rates , which are generally reviewed andapproved by the POGs boards of commissioners or o ther loca l elected o rappointed oversight body, such as a city council. In 12 states, the POGs arealso subject to regulation by a state regulatory authority. Because POGsgenerally are not required to repor t to a sp ecific regulatory body, we did no

identify a consistent o versight and rate approval methodology applicable tothem. For two of the POGs we contacted, the rates are se t by the utility andapproved by the city councils. For the other two POGs we contacted, the

boards of directors approve all rate changes without the need for citycouncil approval.

Cost-Based Versus Market-Based Ratesetting

As the electricity industry continues to move toward market-based rates,utilities are expected to find ways to become more efficient. In a regulated

environment, IOUs reta il rates are based on t he cost s their statecommissions allow in their rate bases, but in a competitive environmentthe IOUs will have an incentive to reduce costs to enhance the

competitiveness o f their rates. The PMAs are also taking steps to reduce

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costs and prepare themselves for a competitive market situation, but theycontinue to se t rates based on costs, as required by current law. Meanwh ilemany of the larger POGs are increasingly abandoning their trad itional fullyallocated cost me thods for designing rates and are focusing more onmarket conditions.

As noted, in a restructured environment the market generally sets the pricefor the generated commodity (power),35, 36 FERC regulates transmission,

and the state commissions set the rates for distribution (retail sales) forIOUs and some POGs. Local governing bodies genera lly set the ra tes forretail sales for most POGs. In most s tates this is the final approval process

however, in some states final approval is given by the state regulatoryagency. Restructuring legislation varies from state to state and thereforedifferences exist among IOUs ratesetting prac tices. However, several

elements are similar among states that have restructured, and in general

IOUs will continue to file rate cases for distribution services with their

state commissions and where applicable, an IOU that provides defaultservice37 (from a cost-of-service per spect ive on ly) will also file a ratecase with its state commission, and

some states have frozen rates until a set future date, which should allowutilities an opportunity to recover potential stranded costs while rates

are still protected.

Responsibilities to Investorsand Taxing Authorities

IOUs are expected to generate a return for owners and pay income andother taxes . These costs a re included in the IOUs rate cases . POGs, as

publicly owned utilities, typically do no t pay income taxes because they areunits of state or local governments. However, many POGs do makepayments in lieu of taxes to local governments. In addition, in some cases

POGs generate a return for owners in that the excess revenues they

35The market may not always set the price for power in a restructur ed state. For example,

Oregons restructu ring legislation allows res idential and small commercial custome rs whodo not w ant to pur chase power at market the option to continue to receive cost-of-service-based power.

36Depending on state restructur ing legislation, some utilities are s etting up mark etingdivisions to se ll power. For ex ample, one utility we spo ke with sells power by phone on ashort-term contract basis.

37Default service is the re quirement for a provider to provide service for customers who donot choose an electricity supplier. State public utility commissions regulate default service

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generate are transferred from the POGs accounts and used to fund othergovernment activities. The PMAs do no t have to generate a retu rn forowners and generally do not pay taxes. The impact of these differences isdiscussed further in the next section.

Overall the PMAs AreWell PositionedCompetitively

The PMAs are allowed to defer repayment of approp riated debt until due,3

but in pract ice have been repaying significant portions before they are dueand generally focusing on re tiring high interest rate deb t first. Neverthelessthe financing costs of three of the PMAsBonneville, Southeas tern, and

Westernare high r elative to other utilities. While the high financing cost swill pose challenges for these th ree PMAs, the PMAs overa ll haveimportant cost advantages that enhance their competitive positions.

PMAs Debt RepaymentPractices

Under DOE Order RA 6120.2, the PMAs are not required to systematically

(i.e., on a normal amortizing basis) recover from power customers thefederal appropriations that finance the capital assets of projects at whichthe PMAs market power. Unlike traditional financing situations, such as

home mortgages and bank loans, annual repayments of the PMAsappropriated deb t do not have to be made to the Treasury. Instead, thePMAs are required to recover the appropriated debt from power customers

within a specified repayment period. The required recovery period isgenerally 50 years for a ssets used to generate p ower, 35 to 45 years forassets used to transmit power, and the lesser of 50 years or their estimateduseful service lives for replacements.

While the PMAs have the ability to defer the repayment of the appropr iateddebt, in practice they have been repaying significant portions before theyear in which they are due. Table 1 shows our analysis of the portions ofthe PMAs debt that have been repaid before the year in which the debts a redue. It shows the total percentages of debt rep aid before the year in whichthe PMAs debts a re due and the percen tages repa id at least 10 years beforethe year the d ebts are d ue for certain ratesetting systems.

38We are re ferring here t o the PMAs ability to put o ff into th e future t he rep ayment o f certainlow interest appr opriated debt, wh ile repaying high interest debt. We are not r eferring to thePMAs ability to defer payment of an nual operating and other e xpenses in years whenrevenues are insufficient to pay those costs.

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Table 1: Percentages of the PMAs Debt Repaid Before Due as of Fiscal Year-End 1998 (in Total and at Least 10 Years Before

Due)a

aThis analysis covered all Bonneville power projects (100% of 1998 power sales); SoutheasternsCumberland and Georgia-Alabama-South Carolina (GA-AL-SC) systems (89% of 1998 power sales)Southwesterns Integrated System (91% of 1998 generating capacity); and Westerns Central ValleyProject (CVP) and the Colorado River Storage Project of the Salt Lake City Area Integrated Projects(SCLA-IP) (47% of 1998 power sales).

bBonnevilles outstanding balance of appropriated debt was restructured as of October 1, 1996. Therestructuring resulted in a reduction in the principal amount outstanding from about $6.9 billion toabout $4.3 billion and an increase in the associated interest rate of about 3.6 percentage points. We donot consider the $2.6 billion principal reduction resulting from the restructuring to be a repayment.

cThis analysis is of the repayment of appropriated debt related to assets already placed in service. Itdoes not cover appropriated debt for assets not yet placed in service (e.g., construction-work-in-progress) because those assets do not have repayment due dates.

dThe data needed to calculate these percentages for the Pick-Sloan project were not available.

eSouthwesterns data is for fiscal year 1997. The actual percentage of appropriated debt forSouthwesterns Integrated System that was repaid at least 10 years before the year due is higher. Butbecause of the way the repayment data are categorized in the PRS, in many cases we were unable todetermine the exact year of the repayment.

fAlthough the repayment data for Westerns CVP indicates the exact year of repayment of appropriateddebt repaid in full as of September 30, 1998, it does not indicate the repayment year for appropriateddebt that has been partially repaid. Therefore, repayment percentages are based on the status ofrepayment as of September 30, 1998.

gBonneville has less flexibility in repaying bonds than in repaying appropriated debt. Although some othe debt is callable, the bonds are generally repaid based on the term of the debt (i.e., repaid on thematurity date).

hThe actual percentages for Southeasterns two systems are likely higher. But, because the repaymendata did not specify the exact year of repayment, in many cases we were unable to determine whethethe payment was made before due or at least 10 years before due.

Source: Developed by GAO based on information contained in the three PMAs power repaymentstudies and Bonnevilles Revenue Requirement Study.

The relatively low percen t of debt repa id by Bonneville re lates to itsinvestments in nuclear facilities. As of September 30, 1998, Bonneville had

about $13.8 billion in debt. Of the $13.8 billion, approx imate ly $4.2 billionrelates to nonopera tional and canceled nuclear projects, and an additional$2.5 billion re lates to one operating nuclear plant of Energy Northwest.

Bonneville Southeasternc,h Southwesternc Westernc,d

AppropriatedDebtb,c

TreasuryBondsg Cumberland GA-AL-SC Integratede CVPf SLCA-

Total percentage repaidbefore year due

17 28 64 27 43 63.2 60

Percentage repaid atleast 10 years beforeyear due

9 24 36 25 19 62.7 59

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In addition, as we repor ted p reviously,39 Bonneville has faced significantcompetitive pressure in recent years. In particular, low natura l gas pricesand improved technology for gas-fired generation facilities combined to pudownward pressure on elect ricity rates in Bonnevilles region. Also, excessgenerating capacity in the region resulted in additional downward pressureon pr ices in wholesale market s. Thus, Bonneville has had little pricingflexibility in recent years, which has limited its ability to set rates highenough to repay debt at a faster rate.

The relatively low percen tage of appropriated debt repaid forSoutheas terns Georgia-Alabama-South Carolina System is related

primarily to the relatively recent construction of the Richard B. RussellProject.40 The Russell Project has four operational conventional generatingunits that provide 300,000 kilowatts of capacity and four nonopera tional

pumping units41 intended to provide another 300,000 kilowatt s of capacity.The last of the four convent ional units came on-line in 1986, and the costsassociated with the units are included in the customers rates .

The four pumping units were completed in 1992. However, because oflitigation over the ir environmental impacts, the four pumping units havenever been allowed to opera te commercially. As a resu lt, Southeas tern hasnot included the cos ts of the four pumping units in the customers rates and

has not begun repaying the appropriations.

Because the costs of the conventional units have been in the r ate base arelatively short time, Southeaste rn has repaid little of the federalappropriations. As of Septemb er 30, 1998, Southeastern had repaid$31 million (nearly all of which was related to additions to the project) ofthe $366 million in cos ts associated with the operat ional conventional unitsand none of the $603 million in costs assoc iated with the nonopera tionalpumping units.

39Feder al Electricity Activities: Appen dixes to The Fede ral Governmen ts Net Cost andPotential for Future Losses(GAO/AIMD-97-110A, September 19, 1997).

40The Richard B. Russell Project was originally named the Trotters Shoals Dam.

41The pumping units are designed to allow water, after it has passed through generatingunits, to be pumped back into the reservoir during periods of low demand for electricity.The water can then b e used to p roduce po wer during periods of high demand for electricit
http://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-97-110Ahttp://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-97-110A

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The fact that the th ree PMAs have been repaying large portions of the debtbefore it is due does not mean that they have repaid as much or more thanthey would have if required to repay their debt systematically on a normalamor tizing basis. For high-interest debt, the three PMAs have gene rallyrepaid more than they would have on a normal amortizing basis. Forlow-interest debt, the three PMAs have genera lly repaid less than theywould have on a normal amortizing basis. This is because, in accordancewith provisions in DOE Order RA 6120.2, the three PMAs have generally

been repaying the highest interest debt first and de ferring repayment oflower interest rate debt.42, 43 By doing so, the three PMAs effectively reducetheir future interest costs.

In contras t, although Bonneville has repaid some of its higher interest ra teappropriated debt before it is due, Bonnevilles percentage of higher

interest ra te appropriated debt repaid is relatively low.44 This is primarilyrelated to its large interest payments on nuclear facilities and theapproaching maturity of lower interest rate appropriated debt and Treasury

bonds. Table 2 shows the percentages of high interest and low interest ratedebt the PMAs have repaid.

42However, appropriated debt du e in a given fiscal year must be paid.

43The PMAs ability to defer repayment of appropriated debt for a longer period than IOUsand POGs and to repay highest interest rate appro priated debt first offsets their generalinability to refinance app ropriated deb t, which could be a disadvantage in times of declininginteres t rates . As discus sed pr eviously, however, Bonnevilles appr opriate d debt was in factrestructured as of October 1, 1996.

44However, Bonne ville has rep aid a significant p ortion o f its U.S. Treasu ry bond s before due

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Table 2: Percentages of the PMAs High Interest and Low Interest Debt Repaid as of Fiscal Year 1998a

a

This analysis covered all Bonneville power projects (100% of 1998 power sales); SoutheasternsCumberland and Georgia-Alabama-South Carolina (GA-AL-SC) systems (89% of 1998 power sales)Southwesterns Integrated System (91% of 1998 generating capacity); and Westerns Central ValleyProject (CVP) and the Colorado River Storage Project of the Salt Lake City Area Integrated Projects(SCLA-IP) (47% of 1998 power sales).

bThis analysis is of the repayment of appropriated debt related to assets already placed in service. Itdoes not cover appropriated debt for assets not yet placed in service because repayment of thoseappropriations has not begun.

cFor each ratesetting system, we calculated a simple average interest rate and considered everythingabove the average to be high and everything below the average to be low.

dSouthwesterns data are for fiscal year 1997.

eThe data needed to calculate the percentages for the Pick-Sloan Project were not available.

Source: Developed by GAO based on information contained in the three PMAs Power RepaymentStudies and Bonnevilles Revenue Requirement Study.

The financing costs of three of the PMAsBonneville, Southeastern , andWesternare relatively high compared to those of IOUs and POGs. Theirrelatively high financing costs mean tha t Bonneville, Southeastern, andWestern have less flexibility to respond to competitive pressures in anincreasingly competitive market environment. Moreover, while interestcosts are fixed, IOUs have some flexibility in dec iding whethe r to paydividends to shareholders. Financial flexibility is an importantconsidera tion in an increasingly competitive electricity indust ry. Directcomparisons of financing costs are somewhat difficult because thefinancing structures of the entities differ. IOUs financing consists o f bothequity and debt , while the PMAs and POGs financing consists mostly of

debt.45

Bonneville Southeasternb Southwesternb,d Westernb,e

AppropriatedDebtb

TreasuryBonds Cumberland GA-AL-SC Integrated CVP SLCA-I

Percentage of highinterestc debt repaid

13 81 100 100 99 93 5

Percentage of lowinterestc debt repaid

66 33 62 21 25 53 6

45The three PMAs financing generally consists of appropriations that must be repaid to thefederal governme nt, with interest. In addition to federa l appropr iations, Bonnevillesfinancing includes U.S. Treasury bonds and nonfederal debt (i.e., debt held by the public,primarily related to nuclear projects). POGs financing generally consists of debt capital,which is obtained primarily by issuing electric revenue bonds.

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To determine the entities relative financing costs, we compared the PMAsand POGs percentage of interest cos ts to operating revenues to the IOUspercentages of interest and dividend (both common and preferred) costs toopera ting revenues . The results of our analyses are shown in figure 5.

Figure 5: Financing Costs as a Percentage of Operating Revenues for the PMAs,

IOUs, and POGs for Fiscal Year 1998


Like the percen tage of appropriated debt repaid, the relatively highfinancing costs at Bonneville are related to its nuclear investments and theinterest it must pay on its out standing interest-bearing debt. Two of thenuclear plants Bonneville invested in were te rminated and therefore do notgenerate revenues to offset the interest costs of the associated debt. As ofSeptember 30, 1998, Bonneville had ou tstanding debt of about $13.8 billion

36.4%

40.6%

16.6%

24.0%

15.2%

7.1%

15.8%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

Bonn

eville

Southe

astern

Southw

estern

Western

POGs

IOUs

w/Pref

Div

IOUs

w/All D

iv

Percent

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Of that amount, unpaid federal appropriations totaled about $4.4 billion,bonds owed to the U.S. Treasury totaled ab out $2.5 billion, and debt relatedto nonfederal pro jects totaled about $6.9 billion.

The high financing costs at Southeastern are related to interest costs on thefederal appropriations that financed the construction of the RussellProject. Little of the appropr iations related to th is project have beenrepaidonly $31 million as of September 30, 1998and the balance

continues to incur an interest cost each year. Although Southeastern paysinterest annually ($20.8 million in fiscal year 1998) on the outstandingfederal appropriations related to the operational conventional units, it does

not pay interest annually on the federal appropriations related to thenonope rational pumping units. Instead, Southeas tern has been capitalizinginterest annually by adding it to a construction-work-in-progress (CWIP)

account; for fiscal year 1998, the capitalized intere st amounted to$34.7 million. Thus, the am ount to be recovered if the pumping unitsbecome operational continues to grow.

As we repor ted previously,46 if the nonoperational Russell units are a llowedto operate commercially and the costs go into rates, rates wo uld have to beraised to recover the construc tion and accumulated interest costs reflectedin the CWIP balance an d to pay interest ann ually on this amo unt. Such an

increase in interest expense would increase Southeasterns financing costssignificantly. For ex ample, if Southeastern were to have paid thecap italized intere st of $34.7 million in fisca l year 1998, its financing cost swould have been about 60 percent of operating revenues. Southeasternofficials expect that the Russe ll units becoming fully operational wouldnecessitate a substant ial rate increase for the Georgia-Alabama-SouthCarolina System. As we repor ted p reviously, the longer the eventualopera tion of the pumping units is delayed, the greater the costs that willhave to be recovered through rates and the greater the potential impact onrates . This situation would pose a cha llenge to Southeas tern in a

competitive electricity market because at some point the price of thepower generated at the Russell Project may not be competitive.

The relatively high financing costs at Western are related to relativelyrecent construc tion projects that carry higher interest rates. For example,

about 60 percent of the debt ou tstanding as of September 30, 1998, for the

46Feder al Electricity Activities: Appen dixes to The Fede ral Governmen ts Net Cost andPotential for Future Losses(GAO/AIMD-97-110A, September 19, 1997).

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Salt Lake City Area Integrated Projects car ry interest ra tes ranging from7 percent to 11 percent.

Cost Advantages EnhancePMAs CompetitivePositions

In addition to examining the PMAs ratesetting practices and how theyaffect their repayment of debt and financing costs, other factors a re critica

to any assessment of the PMAs competitive po sitions. The PMAs havesome important cost advantages that enhance their competitive position,including primarily marketing low-cost hydroelectric power, marketing

power from facilities that in many cases were built decades ago atrelatively low cost , and not having to generate a return for owners o r paytaxes.

One of the PMAs most significant competitive advantages is tha t theymarke t primarily low-cost hydroelectric pow er. Largely because there is nofuel cost associated with hydroelectr ic power, its costs are substantiallylower than for other sources of genera tion. Figure 6 shows 1998 averagedata on ope rating expenses, including fuel costs, for fossil fuel, gas, andhydroelectric and nuc lear generation plants operated by IOUs.

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Figure 6: Average 1998 Operating Expenses by Generation Type for Plants Operated

by IOUs

Source: Developed by GAO based on data from EIA.

Marketing primarily low-cost hydroelectric power gives the PMAs asignificant overall competitive advantage compared to IOUs and POGs,

which generate far less of their power from hydroe lectric plants. Figure 7shows the percentages of power generated by hydroelectric plants for thePMAs, IOUs, and POGs for fiscal year 1998.

20.6

30.5

5.8

21.6

0

5

10

15

20

25

30

35

Fossil Gas Hydro Nuclear

Mills per kWh

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Figure 7: Percentage of Power Generated by Hydroelectric Plants for PMAs, IOUs,

and POGs for Fiscal Year 1998


Another competitive advantage for the PMAs is that they market powerfrom facilities that were , in many cases , built decades ago at relatively low

const ruction costs. To show the r elatively low capital cost of the PMAshydroelectric p lants, we compared t he PMAs investment in ut ility plant permegawatt of generating capac ity. Figure 8 shows that the PMAs haveinvested less in utility plant per megawatt of genera ting capacity than IOUsand POGs.

82.0%

100% 100%

91.7%

27.5%

3.1%

0

20

40

60

80

100

Bonn

eville

Southe

astern

Sou

thwe

stern

Western

POGs

IOUs

Percent

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Figure 8: Investment in Utility Plant per Megawatt of Generating Capacity, 1998


In addition, as discussed previously, the PMAs do n ot have to genera te areturn for owners or pay taxes. In cont rast, according to EIA, in 1998 IOUspaid dividends to investors to taling about 8.3 percen t of opera tingrevenues. Also according to EIA, in 1998 IOUs paid taxes totaling about13 percent of operating revenues. POGs, as publicly owned utilities,typically do not pay income taxes because they are units of state or localgovernments. However, many POGs make payments in lieu of taxes to loca

governments. According to EIA, in 1998 POGs made tax and tax equivalentpayments to taling about 2.6 percent of operating revenues. In addition,according to industry sources , some POGs transfer additional funds fromtheir accumulated net revenues accounts to fund other governmentactivities, thereby essentially generat ing a ret urn for owners. Not having to

include a return to owners and tax payments in their rates is a comp etitiveadvantage for the PMAs.

81 7

69 3

53 950 4

1,068

1,144

0

200

400

600

800

1,000

1,200

Bon

neville

South

east

ern

Southw

este

rn

Wes

tern

POGs

IOUs

Dollars in thousands

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Although the PMAs en joy significant cost advantages, they face somedisadvantages relative to IOUs and POGs. For example, due to the irreliance on hydropower, the PMAs face weather-related uncertainties to agreater ex tent than IOUs and POGs. Because the amo unt of rainfalldetermines how much power many of the projects marketed by the PMAscan generate, in low water years they may have to p urchase power athigher rates to fulfill contrac ts. In addition, because o f the multipurposenature of federal water project s, operating restrictions may limit the

amount of power the PMAs can market. IOUs and POGs that usehydropower also face weather-related uncertainties and operatingrestr ictions, but given the PMAs reliance on hydropower, these factors may

have a proportionately larger adverse impact on them. Also, the previouslymentioned congressionally-assigned irrigation costs that Bonneville andWestern must recover through power rates are obligations that IOUs and

POGs do not have.

On balance, the PMAs cost advantages outweigh their d isadvantages. As a

result of these cost advantages, the PMAs power p roduction costsasreflected in calculations of average revenues per kWhare lower thanthose of the IOUs and POGs. Becaus e PMAs genera lly recover coststhrough rates with no profit, average revenues per kWh should reflect the irfull power production costs . For IOUs and POGs, average revenues per

kWh should represent costs plus the return generated for owners.

47

Asshown in figure 9, the PMAs average revenues per kWh were considerablybelow those of IOUs and POGs in 1998.

47

EIA cautions that average revenues per kWh per unit of energy sold should not be u sed asa substitute for the price of power. The price that any one entity charges another forwholesale energy comprises numerous tran saction-specific factors such as the fee chargedfor reserving a portion of capacity, the fee for the energy actually delivered, and the fee forthe use of the facilities. The fees are influenced by factors such as time of delivery, quantityof ener gy, and reliability of supp ly. However, despite its limitations, we b elieve that avera gerevenues per k Wh is a good indicator of relative power production c osts since, over time,utilities must recover all costs to remain in business. In addition, analysts and bond ratingagencies commonly use the measure in assessing the competitiveness of pow er rates, andEIA uses it to ap proximate costs.

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Figure 9: Average Revenue per Kilowatthour for Wholesale Sales for 1998 for PMAs

POGs, and IOUs


Therefore, despite the PMAs higher financing costs, the PMAs remain

well-positioned because o f their inherent advantages.

Agency Comments andOur Evaluation

We received separate written comments from the Depar tment o f Energys

Power Marketing Liaison Office, representing the thr ee PMAs, and from theBonneville Power Administration. The three PMAs comment lette r isreproduced in append ix II. Bonnevilles comment letter, and the enclosure

accompanying it, is reprod uced in appendix III. The th ree PMAs commentsare d iscussed below. Bonnevilles comments a re discussed be low and inappendix III. The three PMAs and Bonneville a lso provided technical

comments, which we incorporated as appropriate.

The Three PMAs In commenting on a draft of this repor t, the three PMAs stated that therepor t is a generally fair representation of PMA ratesetting practices . They

2.637

1.931

1.4631.713

3.463.147

0.00

1.00

2.00

3.00

4.00

Bonn

evill

e

Southe

astern

Southw

estern

Western

POGs

IOUs

Cents per kWh

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did, however, request that the report segment discussing PMA costadvantages also include a more deta iled discussion of certain costdisadvantages faced by the PMAs to offer an additional perspec tive on th eircompetitive positions. Specifically, the three PMAs su ggested that therepor t include discussion o f the PMAs (1) inability to r efinance,(2) reliance on hydropower, which is subject to weather-relateduncer tainty, (3) operating restrictions affecting the amount o f poweravailable for the PMAs to market, (4) requirement to repay certa in costs

related to irrigation facilities, and (5) inability to diversify into other linesof business.

We have added so me discussion of the first three issues into the repor t.Regarding the PMAs inability to refinance, however, it is important to notethat th is disadvantage is offset by the flexible repayment terms assoc iated

with this debt . As we note in ou r report, the PMAs have th e ability to deferrepayment of appropr iated debt for a longer period than IOUs and POGsand are able to repay highest interest rate debt first while deferring

repayment of low interest debt.

Regarding the requiremen t to repay certa in irrigation cost s, our repor tclearly states tha t Bonneville and Western are required to se t rates at levelssufficient to repay certain nonpower costs, such as irrigation, that the

Congress has assigned to power users to repay. However, based on thecomment of the three PMAs, we have noted in our report that this is anobligation tha t IOUs and POGs do not have.

Regarding the last item, the PMAs are limited in the ir choice of services tooffer to those that fall within their congressional mandate. We have nobasis for agreeing that diversification cou ld accelerate return of the

taxpayers investment. Inherent in this assertion is the presumption thatthe PMAs would be able to generate excess revenues b y diversifying. Wehave not evaluated whether this is a reasonable assumption.

Bonneville PowerAdministration

The Department o f Energys Bonneville Power Administrat ion stated tha t ihad significant concerns w ith our message. Specifically, Bonneville statedthat we (1) misconstrue the role of repayment studies in its revenuerequirements and ra tes, (2) inadequately address its risk mitigation

activities, (3) mischaracterize its debt obligations and debt managementprac tices, (4) do not consider the public benefits that it must p rovide, and(5) fail to ment ion the many rate direct ives found in Section 7 of the

Northwest Power Act.

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In our view, the comments provided by Bonneville were largely of anelaborative and technical nature. We have incorporated some of theinformation provided to give additional context to the report. However, thechanges incorporated as a result of Bonnevilles comments did not alter o uroverall assessment of its ratesetting and debt repayment practices and wedisagree th at our report misconstrues these practices. Given the detailednature of Bonnevilles comments , our de tailed evaluation of thosecomments is included in appendix III.

As agreed with your office, unless you publicly announce its con tentsearlier, we plan no further distribution of this report until 30 days from its

date. At that time, we will send copies to Representa tive Calvin Dooley,Ranking Minority Member, House Subcommittee on Water and Power,Committee on Resources; Representa tive Joe Barton, Chairman, andRepresentative Rick Boucher, Ranking Minority Member, HouseSubcommittee on Energy and Power, Committee on Commerce; SenatorGordon Smith, Chairman, and Senator Byron Dorgan, Ranking MinorityMember, Senate Subcommittee on Water and Power, Committee on Energyand Natura l Resources. We are a lso sending copies of this report to theHonorable Bill Richardson, Secre tary of Energy; the Honorable Jacob J.Lew, Director, Office of Management and Budget; Judith A. Johansen,

Administrator and Chief Executive Officer, Bonneville PowerAdministration; Charles A. Borchardt , Administrator, Southeaste rn Power

Administration; Michael A. Deihl, Administrator, Southwestern PowerAdministration; Michael S. Hacskaylo, Administrator, Western Area PowerAdministration; and other interested par ties. Copies will also be made

available to others upon request.

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If you or your sta ff have any questions concerning this repor t, pleasecontact me at (202) 512-9508 or Robert Martin, Assistant Director, at(202) 512-4063. Major contributors to th is report were Mary Merrill,Donald R. Neff, and Patricia B. Petersen.

Sincerely yours,

Linda M. Calbom

Directo r, Resources, Community, andEconomic Development Accountingand Financial Management Issues

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Appendix I

Objectives, Scope, and Methodology

We were asked to dete rmine (1) how the PMAs set the ir rates to recovercosts, (2) how the PMAs ratesetting practices compare to those ofinvestor-owned u tilities (IOU) and publicly owned generating (POG)utilities, and (3) the impact of the PMAs ability to defer repayment ofportions of their debt on the ir future compet itiveness. In determining howthe PMAs set their rates to recover costs, we were also asked t o examinethe assumpt ions the PMAs use in setting their rates and the processes thePMAs use to set r ates to recover costs.

Determining How thePMAs Set Their Ratesto Recover Costs

Before setting rates, the PMAs perform power r epayment studies (PRS) orin the case of Bonneville Power Administrat ion, revenue requirementstudies (RRS) to identify costs to be recovered and revenue requirements.As a result, to achieve this ob jective we focused on the PMAs PRSs andRRSs. We di

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