oversight

Federal Electric Power: Bonneville's Residential Exchange Program

Published by the Government Accountability Office on 1990-02-06.

Below is a raw (and likely hideous) rendition of the original report. (PDF)

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General Accounting Of’tlce
Washingtxm, D.C. 20648

Resonrcee, Communfty, and
Economic Development Division

B-236682

February 6,199O

The Honorable George Miller
Chairman, Subcommittee on Water,
  Power, and Offshore Energy Resources
Committee on Interior and Insular Affairs
House of Representatives

Dear Mr. Chairman:

In accordance with your request, this report provides our evaluation of the Bonneville Power
Administration’s implementation of the Residential Exchange Program-a program designed
to reduce the disparity in power rates charged to residential consumers of Pacific Northwest
interties-including   the program’s benefits and costs and Bonneville’s efforts to monitor the
pass-through of program benefits to utility customers.

Unless you publicly announce its contents earlier, we plan no further distribution of this
report until 30 days from the date of this letter. At that time we will provide copies of the
report to the Secretary of Energy; the Administrator, Bonneville Power Administration; and
the Director, Office of Management and Budget. We will also make copies available to other
interested parties upon request.

This work was performed under the direction of Victor S. Rezendes, Director, Energy Issues,
(202) 2751441. Major contributors to this report are listed in appendix IV.

Sincerely yours,     ,




J. Dexter Peach
Assistant Comptroller General
Ekecutive Summary


7                  The Bonneville Power Administration, one of five Department of Energy
    /              (DOE) power-marketing    administrations, wholesales nearly half of the
                   electric power used in-the Pacific Northwest. Since 1981, Bonneville has
                   also participated in a power exchange with certain Northwest utilities,
                   as authorized by the Northwest Power Act. The purpose of this
                   exchange is to reduce the disparity in electric rates paid by residential
                   and small farm customers of the region’s utilities by having Bonneville
                   “exchange” its relatively low-cost power with Northwest utilities that
                   have higher-cost power.

                   As requested by the Chairman, Subcommittee on Water, Power, and Off-
                   shore Energy Resources, House Committee on Interior and Insular
                   Affairs, GAOassessed the significance of the residential exchange pro-
                   gram and Bonneville’s efforts to ensure that program benefits are being
                   received by the utilities’ residential and small farm customers,


                   During the 1970s residential and small farm customers of Northwest
Background         investor-owned utilities were paying up to three times more for electric-
                   ity than similar customers of the region’s public utilities. Some of the
                   region’s public utilities were able to charge lower power rates primarily
                   because they were being supplied with low-cost power from Bonneville.
                   The power Bonneville markets is from 30 federal dams and 3 thermal-
                   generating facilities.

                   In 1980, the Congress enacted the Northwest Power Act, in part, to
                   address this disparity. The act authorizes Northwest utilities to
                   exchange their higher-cost power for an equivalent amount of Bonne-
                   ville’s lower-cost power. The power exchange is limited to the amounts
                   utilities need to supply their residential and small farm customers’
                   requirements and is accomplished through a “paper transaction” rather
                   than an actual exchange of power. Under the act, cost savings resulting
                   from the exchange are to be passed along to residential and small farm
                   customers.


                   The disparity in electric power rates paid by residential and small farm
Results in Brief   customers in the Northwest has decreased over the past decade. The
                   $1.37 billion in exchange program benefits that Bonneville provided to
                   Northwest utilities through fiscal year 1988 has contributed to this
                   decrease. However, a more important factor in reducing the rate dispar-
                   ity was the fact that Bonneville’s costs-and, consequently, its power



                   Page 2                    GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                            rates-increased   significantly more than did those of the regional
                            utilities.

                            Bonneville has not been conducting the reviews needed to ensure that
                            utilities are passing program benefits through to their residential and
                            small farm customers, although the Northwest Power Act does not spe-
                            cifically direct Bonneville to do so. Given the dollar value of the benefits
                            that have been provided to regional utilities, GAO believes Bonneville
                            should perform such reviews.



Pri#cipal Findings

Sigrji ficance of Program   The residential exchange program has provided benefits to Northwest
Ekn+fits                    utilities that had higher power costs than Bonneville. Three investor-
                            owned and two public utilities received about $1.2 billion, or about 88
                            percent, of the $1.37 billion in program benefits paid through fiscal year
                            1988. The remaining benefits were shared by other Northwest utilities.
                            According to Bonneville data, exchange program benefits are expected
                            to total about $1.3 billion for fiscal years 1989-1995.

                            The program benefits have reduced the cost of the electricity provided
                            to residential and small farm customers of these utilities. For example,
                            on the basis of data GAO obtained from the five utilities that were major
                            program beneficiaries, their residential customers paid between 10 and
                            26 percent less for electricity in 1988 than they would have absent pro-
                            gram benefits, These data indicate that the program has contributed to
                            reducing the disparity in the region’s power rates.

                            GAO  also found other indications that the disparity between the electric-
                            ity rates charged to residential customers by investor-owned utilities
                            and the rates charged by public utilities has been reduced. For example,
                            the 1978 average monthly residential electricity bill was $14 in Wash-
   /                        ington, which is primarily served by public utilities, compared with $25
                            in Oregon, which is primarily served by investor-owned utilities. By
                            1988, the average monthly residential bills in these two states were $42
                            and $48, respectively.

                            In GAO'S view, the significant increase in Bonneville’s rates is a more
                            important reason than the residential exchange program for the reduced



                            Page 8                     GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                           Executive Summary




                           disparity in Northwest power rates. Between 1981 and 1987, Bonne-
                           ville’s rates have more than tripled, thus increasing the cost of Bonne-
                           ville’s power relative to the costs of utilities’ power.


Siknificance of Program    GAOfound that about 9 percent of Bonneville’s operating revenues were
                           needed to cover the $1.37 billion program cost through fiscal year 1988.
cqsts
                           These costs have been passed on to Bonneville’s power customers
                           through the rates Bonneville charges to its various customer classes.
                           More specifically, GAOestimated that about 46 percent of program costs
  I                        are reflected in rates Bonneville charges its industrial customers and 29
                           percent are reflected in rates charged to investor-owned utilities in the
  I                        Northwest and California. Most of the remaining costs are reflected in
                           rates charged by Bonneville to public utilities. GAOobtained these esti-
                           mates from data Bonneville used to establish its power rates.


Bonneville Has Not         Although the act provides that benefits are to be passed through to resi-
Determined Whether         dential and small farm customers, GAOfound that Bonneville has not
                           been routinely determining whether utilities receiving program benefits
Program Benefits Reached   have passed through these benefits. Bonneville officials told GAOthat
Customers                  Bonneville has relied on state utility regulatory commissions and public
                           utility boards to make this determination.

                           State utility regulatory commissions are reviewing whether program
                           benefits are being passed through by the investor-owned utilities they
                           regulate, but the depth of these reviews varies among states. According
                           to utility commission staff, benefits, overall, are being passed through to
                           residential customers, and, when problems are identified, utilities take
                           corrective action. Yet GAOalso found that there are no independent
                           reviews covering public utility districts, municipal utilities, and electric
                           cooperatives, since they are outside the regulatory purview of the state
                           utility commissions.

                           Bonneville did conduct a pilot review of the benefit pass-through actions
                           of two public utilities in 1987. According to Bonneville’s preliminary
                           review results, the utilities either had not passed through sufficient ben-
                           efit amounts or had passed benefits through to customers other than
                           residential customers. However, Bonneville did not follow up with these
           Y
                           utilities to discuss its findings.

                           GAObelieves that Bonneville needs to initiate reviews to determine
                           whether residential exchange program benefits are being received by


                           Page 4                    GAO/RCED-90-94 Ronneville’s Residential Exchange Program
*,       j
                  Exeautlve summary




                  utilities’ customers. Such reviews should include examining the timeli-
                  ness of benefit payments and, if warranted, testing customer bills to
                  ensure that actual benefit amounts are correct. Bonneville should also
                  coordinate its reviews with state public utility commissions.


                  GAOrecommends that the Administrator,       Bonneville, initiate reviews to
Recommendations   determine whether residential exchange program benefits are appropri-
                  ately passed on by utilities to residential and small farm customers. GAO
                  also recommends that the Administrator resolve the problems identified
                  in Bonneville’s 1987 reviews of two public utilities.
     ,
                  In commenting on GAO'Sdraft report, DOEstated that it agreed with the
Aghcy Comments    thrust of the report that benefit pass-throughs should be monitored. DOE
                  stated that Bonneville is developing and implementing benefit pass-
                  through reviews that will help ensure the timely and accurate pass-
                  through of benefits to eligible residential and small farm customers. WE
                  also stated that Bonneville will take action to ensure that the problems
                  identified in its 1987 reviews of two public utilities are resolved.




             Y




                  Page 5                    GAO/RCED@O-34 Bonneville’s   IteeidentialExchangeProgram
contents


EAecutive Summary                                                                                      2

C apter 1                                                                                              8
In9 reduction          Objectives, Scope, and Methodology                                              9

Cl+apter 2                                                                                            11
Exchange Program       Exchange Program- How It Works
                       Activities Affecting Exchange Program Implementation
                                                                                                      11
                                                                                                      13
Oqerview                    and Operation
                       Conclusions                                                                    17

Chapter 3                                                                                            18
Significance of the    Significance of the Exchange Program’s Benefits
                       Significance of the Exchange Program’s Costs
                                                                                                     18
                                                                                                     21
Exchange Program’s     The Exchange Program’s Future Benefits and Costs                              26
R&e Relief Benefits    Rate Disparity Has Narrowed                                                   29
arid Costs             Conclusions                                                                   31


Chapter 4                                                                                            33
Current Efforts Are    Bonneville’s Reviews of Benefit Pass-Throughs Have
                           Been Limited
                                                                                                     33
Inadequate to Ensure   Benefit Pass-Through Reviews by State Officials                               34
That Utilities’        Bonneville Plans to Review Benefit Pass-Throughs                              36
Ctistomers Have        Conclusions                                                                   37
                       Recommendations                                                               37
Rkeived Rate Relief    Agency Comments and GAO Evaluation                                            37
Bknefits
Appendixes             Appendix I: Utilities, State Regulatory Agencies, and                         40
                           Organizations Contacted by GAO
                       Appendix II: Utilities That Have Participated in the                          41
                           Exchange Program
                       Appendix III: Department of Energy Comments                                   43
                       Appendix IV: Major Contributors to This Report                                46

Tables    ”            Table 2.1: Rate Relief Benefits of Exchange Program to                         12
                           Participating Utilities’ Residential and Small Farm
                           Customers



                       Page 6                   GAO/RCED-90-34 Bonneville’s Residential Exchange Program
 ,
         Contants




         Table 2.2: Utilities in Deemer Status and Benefit Offset                         14
              Balances as of April 1989
         Table 3.1: Cost Savings Realized by Utilities Participating                      19
              in the Exchange Program
         Table 3.2: Exchange Program Rate Relief Benefits                                 21
              Received by Average Residential Customer, Calendar
              Year 1988
         Table 3.3: Projected Gross Costs for the Exchange                                23
              Program Versus Projected Gross Costs for All
              Bonneville Operations in 1982, 1983, 1986, and 1987
              Rate-Setting Processes
         Table 3.4: Allocation of the Exchange Program’s                                  24
             Projected Gross Costs for Bonneville’s Rate-Setting
             Processes
         Table 3.6: Projected Exchange Energy Cost Savings for                            26
             Utilities Participating in the Exchange Program,
             Fiscal Years 1989-96
         Table 3.6: Typical Monthly Residential Power Bills for                           30
              1,000 Kilowatt-Hours of Electricity in Three Pacific
             Northwest States
         Table 3.7: Typical Monthly Residential Power Bills for                           30
              1,000 Kilowatt-Hours of Electricity

Fi@we    Figure 2.1: Basic Relationship Between Parties in the                            12
     I        Residential Exchange Program




         Abbreviations

         ASC        Average System Cost
         DOE        Department of Energy
         GAO        General Accounting Office


         Page 7                      GAO/RCED-9944 Bonneville’s Residential Exchange Program



                               ‘,.
Chdpter 1

Ir;ltroduction


-
                 The Bonneville Power Administration (Bonneville), created by an act of
                 Congress in 1937, markets electric power to utilities and industries
                 located primarily in a 300,000~square-mile area that encompasses Ore-
                 gon, Washington, Idaho, western Montana, and small portions of
                 Nevada, Utah, and Wyoming. Bonneville markets electric power gener-
                 ated at 30 federal hydroelectric projects and several nonfederal hydro-
                 and thermal-generating facilities in the region. Its customers include
                 public utility districts, municipal utilities, rural electric cooperatives,
                 investor-owned utilities, and a number of industrial customers, primar-
                 ily aluminum companies. In addition, Bonneville markets and exchanges
                 electric power with Southwest utilities over the Pacific Northwest-
                 Pacific Southwest Inter-tie’ and, through other interconnections, with
                 utilities in British Columbia.

                 In 1973, Bonneville ceased providing power to investor-owned utilities
                 in order to meet the growing power demands of public utilities. Public
                 utilities have priority over investor-owned utilities for Bonneville’s
                 power under the Bonneville Project Act of 1937. Over the next several
                 years, investor-owned utilities increased their rates to resiential and
                 small farm customers by as much as 300 percent because the power gen-
                 erated or purchased to replace the power previously acquired from
                 Bonneville was so much higher in cost.

                 As a result, congressional reviews of the late 1970s found that custom-
                 ers of some Pacific Northwest utilities were paying substantially higher
                 electric rates than others within the region. For example, in 1980 the
                 House Committee on Interior and Insular Affairs found that the retail
                 rates of the region’s investor-owned utilities were as much as 300 per-
                 cent higher than the rates charged by the region’s public utilities that
                 purchased power from Bonneville. A central factor in these rate differ-
                 ences was the access some utilities had to low-cost power from
                 Bonneville.

                 Although the substantial rate increases during the period primarily
                 affected customers of investor-owned utilities, customers of some public
                 utilities were also affected. In the case of public utilities, substantial rate
                 increases stemmed from high transmission system costs or from their
                 own generation facilities that produced electric power at a higher cost
                 than Bonneville charged Taken together, the higher electric rates at
                 investor-owned and publicly owned utilities were affecting about 2.6
            Y

                 million residential and small farm customers in the Pacific Northwest.

                 I A msjor electricity transmission interconnection between the Pacific Northwest and California.



                 Page 8                              GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                             Chapter 1
                             Introduction




                             The Congress intended to reduce this rate disparity when it passed the
                            ,Zjacific Northwest Electri Power Planning and Conservation A& in
                              1980. Section S(c) of the, K orthwest Power Act (16 USC. 839c(c)) pro-
                             vides for a residential pbwer exchange. The exchange, which is ’
                             explained in more detail in chapter 2, provides a means for Pacific
                             Northwest utilities with higher resource costs to have access to Bonne-
                             ville’s lower-cost power by exchanging it for their own higher-cost
                             power. Section S(c) requires the utilities to pass on the cost savings to
                             their residential and small farm customers. Bonneville’s cost of purchas-
                             ing the utilities’ higher-cost power is in turn to be passed on in the rates
                             Bonneville charges its customers for power.

                             While the act does not specifically call for a “program,” Bonneville
                             refers to the exchange activities as a program. We, likewise, refer to the
                             exchange as a program.


                            In March 1988 discussions with the office of the Chairman of the Sub-
Obj xtives, Scope,and       committee on Water, Power, and Offshore Energy Resources, House
Me1hodology                 Committee on Interior and Insular Affairs, we were asked to review the
                            exchange program. We focused our review on the following:

                        l   the significance of the exchange program to utilities participating in the
                            program, to the utilities’ residential and small farm customers, and to
                            Bonneville and its customers, and
                        l   Bonneville’s efforts to ensure that utilities participating in the program
                            pass on the exchange energy cost savings they receive to their residen-
                            tial and small farm customers.

                            To address the significance issue, we developed data to determine (1)
                            whether utilities participating in the exchange program have realized
                            cost savings, (2) to what extent the program’s rate relief benefits have
                            affected the electric bills of the residential and small farm customers of
                            participating utilities, and (3) which of Bonneville’s customer classes
                            have paid the cost of the exchange program, We also developed data to
                            determine whether Bonneville expects the exchange program to provide
                            future cost savings to participating utilities. In addition, we developed
                            data to determine whether the electric power rate disparity that existed
                            in the Pacific Northwest before the Northwest Power Act has been
                            reduced. The information we used to develop these data was obtained
           Y
                            from Bonneville, utilities participating in the exchange program, and
                            Department of Energy reports.



                            Page 9                     GAO/RCED-90-34 Bonneville’s Residential Exchange Program
    Chapter 1
    Introduction




    To address the rate relief benefit pass-through issue, we (1) determined
    the extent to which Bonneville has ensured that utilities participating in
    the exchange program have passed rate relief benefits through to their
    residential and small farm customers; (2) reviewed the efforts of other
    organizations, and the significance of their findings, to ensure that par-
    ticipating utilities pass rate relief benefits through to their residential
    and small farm customers; and (3) reviewed the draft procedures Bonne-
    ville developed for conducting rate relief benefit pass-through reviews.
    We did not attempt to conduct any benefit pass-through reviews, but we
    did review the procedures that four utilities participating in the
    exchange program established for passing rate relief benefits through to
    their residential and small farm customers.

    To develop general information about the exchange program, we
    reviewed the legislative history of the Northwest Power Act to deter-
    mine why the program was established, who was to benefit from the
    program, and who is to pay program costs. In addition, we interviewed
    officials and reviewed exchange program files at Bonneville headquar-
    ters in Portland, Oregon, and contacted individuals from 11 utilities, 3
    state regulatory agencies, and 14 organizations. These utilities, state
    regulatory agencies, and organizations were selected because they (1)
    received significant exchange energy cost savings from Bonneville, (2)
    were involved in reviews to determine whether rate relief benefits had
    been passed through to customers, (3) represented major Bonneville cus-
    tomers, or (4) represented utilities. Appendix I shows the utilities, state
    regulatory agencies, and organizations from which we obtained
    information.

    Our review was conducted between December 1988 and mid-July 1989
    in accordance with generally accepted government auditing standards.




*




    Page 10                   GAO/RCED-90-34 Bonneville’s Residential Exchange Program
    1.
Chapber 2




                              The exchange program provides rate relief to residential and small farm
                              customers of participating Pacific Northwest utilities. During the first 7
                              years of the program, the amount of rate relief provided was about
                              $1.37 billion. This amount was also a net cost for Bonneville. Bonneville
                              recovers its costs through the power rates it charges its customers.


                              Under the exchange program, which began in October 1981, whenever a
Ex ’ hange Program-           Pacific Northwest utility offers to sell electric power to Bonneville, the
Ho It Works                   Bonneville Administrator acquires and, in exchange, offers to sell an
                              equivalent amount of power to the utility for resale to its residential and
                              small farm’ customers. Utilities that participate in the program sell
                              power to Bonneville at a price higher than what they pay to buy it back.
   :                          The exchange is essentially a paper transaction in that no power is actu-
                              ally transferred between Bonneville and the participating utilities. How-
                              ever, the difference between the utilities’ higher-cost power and
                              Bonneville’s lower-cost power results in exchange energy cost savings to
                              the utilities.

                              The steps in the exchange program can be described as follows:

                        A utility sells Bonneville the amount of electric power the utility needs
                          l


                        to serve its residential and small farm customers. Bonneville purchases
                        this power at the utility’s average system cost (Asc)-a calculation
                        based on the utility’s expenses for power generation and transmission.
                      . In return, Bonneville sells the same amount of electric power back to the
                        utility at Bonneville’s “priority firm power rate”-the      basic rate paid by
                        public utilities for guaranteed electric power from Bonneville. Because
   ,                    these sales occur when the priority firm power rate is lower than the
                        utility’s ASC,the net effect is that the utility receives exchange energy
                        cost savings.
                      . The utility passes the cost savings on to their customers as rate relief
                        benefits, in the form of reduced electric power rates, credits on monthly
                        power bills, or checks distributed to their customers monthly or
                        annually.
                      l The net cost of the exchange program-the         difference between Bonne-
                        ville’s high purchase price and low sale price is recovered through the
                        power rates Bonneville charges its customer classes.


            w

                              ‘The Northwest Power Act defines residential and small farm as all usual residential, apartment,
                              seasonal dwelling, and farm electrical uses within certain limits.



                              Page 11                            GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                                         Chapter 2
                                         Exchange Program Overview




-._-.I   .--....._   -_

                                         Figure 2.1 depicts the relationship between Bonneville, the utilities that
                                         participate in the exchange program, and Bonneville’s customer classes
                                         that pay the program’s net cost.
     I

ii &re 2.1: Basic Relationship Between
PaI ’ ies in the Residential Exchange
Pn gram                                                                        Average System Cost
   5
                                               Bonneville                                                    ’ Exchange           Program
    ,
                                                                              Priority Firm Power Rate


                                           Exchange Program                                                                   Exchange Program
                                           Net Cost                                                                           Rate Relief Benefit




                                         During the program’s first 7 years (fiscal years 1982-88), Bonneville
                                         purchased $5.83 billion in residential and small farm power and sold an
                                         equivalent amount of power for $4.46 billion, as table 2.1 shows. Thus,
                                         the total rate relief benefits from the first 7 years of the exchange pro-
                                         gram-equal to the net costs of the program-were         $1.37 billion.

Table 2.1: Rate Relief Benefits of
Ex/change Program to Participating       Dollars in million9                         _--                               ____..___       .-
Utillities’ Residential and Small Farm   -~-                           Cost of power                                      Value of benefit to
Customers                                                              purchased by Revenue from power                 residential and small
                                         Fiscal year                      Bonneville    sold by Bonneville                   farm customers
                                         1982                                     $428.4                    $211.8                          $216.6
                                         1983                                       551.3                    400.1                            151.2
                                         1984
                                         ----_-.~ -. ~~_~....._~~
                                                               ~- .-~~
                                                                    .-..-    ..-... 836.8                    651.0..--.-.--          .-~-     185.8
                                                                                                                                            .--. -~
                                         1985                                    1,008.8
                                                                                .~-    ___--                 801.0                            207.8
                                         1986                                    1.046.4                     838.1                            208.3
                                         1987                                    1,010.l                     796.7                            213.4
                                         1988                                     949.7                      761.7                            188.0
                                         Total                               $5.831.5                    $4.460.4                       $1.371.1
                                         aNominal dollars not adjusted for inflation.
                                         Source: Bonnewlle’s Exchange Program Branch




                                         Page 12                            GAO/RCED-90-34 Bonneville’s Residential Exchange Program
     I
     /,                                                                                                         r
 .                       Chapter 2
                         Exchange Program Overview




                         During the first 7 years of the exchange program, Bonneville made sev-
                         era1 important decisions affecting the utilities that participate in the
                         program. Bonneville
Im lementation and    . developed a method that keeps utilities from paying Bonneville if their
Opif ration             MCS fall below Bonneville’s priority firm power rate;
                      . revised its method of determining utilities’ ASC to exclude unauthorized
                        costs and became more active in reviewing the utilities’ ASCcomputa-
                        tions; and
                      . suspended, terminated, or bought out the exchange program contracts
                        for 18 of the 40 utilities participating in the program because the utili-
                        ties considered it no longer advantageous to participate.

                        These key decisions are explained in greater detail below.


“Dekmer Clause” and     An issue of concern in 1980-81, as decisions were being made by Bonne-
Be&fit Offset           ville to implement the program, was whether utilities should pay Bonne-
   /                    ville when their ASCS drop below Bonneville’s power rate. This issue
                        anticipated a reverse of the power cost situation that the program was
                        designed to address and that generally existed at that time. According to
                        Bonneville officials, neither the Northwest Power Act nor its legislative
                        history contains specific provisions on this point.

                        After several meetings between Bonneville and participating utilities,
                        the parties negotiated in 1981 to include a clause in exchange program
                        contracts specifying that if a utility’s MC dropped below Bonneville’s
                        priority firm power rate, the utility may deem its ASC to be equal to
                        Bonneville’s priority firm power rate. The effect of this “deemer clause”
                        is that a utility would not be required to pay Bonneville for the differ-
                        ence between its MC and Bonneville’s priority firm power rate.

                        According to Bonneville, the deemer provision represents a contractual
                        compromise by limiting the extent to which the exchange program
                        should disadvantage residential and small farm customers of utilities
                        whose ASCSare lower than Bonneville’s priority firm power rate. Specifi-
                        cally, the deemer clause keeps a utility from immediately paying Bonne-
                        ville. Instead, Bonneville maintains a benefit offset balance, which
                        accrues interest, to record how much the utility would have paid Bonne-
                        ville if it was not in deemer status. Bonneville offsets this debit balance
                        against positive benefits the utility receives once its MC again exceeds
                        Bonneville’s priority firm power rate. In order for a utility to come out
                        of deemer status, a condition it would logically elect only if its tic was


                        Page 13                      GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                                            Chapter 2
                                            Exchange Program Overview




                                            greater than Bonneville’s priority firm power rate, the utility would
                                            have to either pay Bonneville the benefit offset balance or wait until its
                                            now-positive benefits reduced the offset balance to zero. Thus, a utility
                                            in deemer status will not receive exchange program rate relief benefits
                                            until its benefit offset balance is liquidated.

                                            Since the beginning of the exchange program, four participating utilities
                                            have accrued a total benefit offset balance of approximately $115 mil-
                                            lion. Table 2.2 identifies those four utilities and their April 1989 benefit
                                            offset balances.
._ + -_.I___-.-
             .._
               - __-
Table 2.2: Utilities in Deemer Status and
Bebefit Offset Balances as of April 1989    Dollars in millions                                                               ___
                                            Utility                                                                    Benefit offset-___--
                                                                                                                                       balance’
                                            Idaho Power ComDanv                                                                               $53.2
                                            Washington Water and Power Company
                                                                             ___--                                                             44.0
                                            Puget Sound Power and Light Company                                           ---              --- 14.6
                                            Montana Power Company                                                                             3.2
                                            Total                                                                                          $115.0
                                            “These amounts are estimates and do not reflect all final ASC adjustments, interest on deemer bal-
                                            ances, or final invoices.
                                            Source: Bonneville’s Exchange Program Branch.




Revised Average System                      Since the beginning of the exchange program, there have been continual
Cost Me‘thod                                discussions between Bonneville, its customers, state regulatory agencies,
                                            and utilities participating in the program concerning what costs should
                                            be included in the method for determining a utility’s MC. The ASC
                                            method is used to determine the level of exchange energy cost savings
                                            Bonneville should pay to utilities participating in the program.

                                            In accordance with section 5(c)(7) of the Northwest Power Act, the
                                            Bonneville Administrator developed, in consultation with others, a
                                            method for determining a utility’s MC. The method, developed in 1981,
                                            relied on state regulatory agencies to determine what costs would be
                                            included in the ASCfilings of utilities participating in the exchange pro-
                                            gram. Under this approach-called       a jurisdictional costing approach-
                                            retail rate orders of regulatory agencies were used as the primary
                                            source of data for computing the MC. According to the Bonneville
                                            Administrator’s Record of Decision for the 1981 MC method, the juris-
                                            dictional costing approach was used to determine a utility’s MC because
                                            costs allowed or established for rate-making purposes should be used in



                                            Page 14                             GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                           Chapter 2
                           Exchange Program Overview




                           calculating MCS and intrusion by Bonneville into jurisdictional          rate
                           issues should be avoided.

                           According to Bonneville’s July 1986 legal brief, one investor-owned util-
                           ity seriously abused the 1981 MC method by attempting to recover $79
                           million in nuclear plant termination costs through the exchange pro-
                           gram. Bonneville disallowed the inclusion of the $79 million cost from
                           the utility’s ASC filing. Although section 5(c)(7) of the Northwest Power
                           Act expressly prohibits the inclusion of plant termination costs in ASC
                           calculations, the regulatory agency for the state in which the investor-
                           owned utility is located did not exclude that amount.

                           Subsequent to the situation described above, Bonneville specifically
                           identified the costs that could not be included in ASC calculations and
                           issued a revised ASC method in June 1984. The 1984 method retained the
                           basic jurisdictional costing approach included in the 1981 method. How-
                           ever, Bonneville now determines independently, through a complex
                           review process, the validity of data submitted in ASC filings to ensure
                           the appropriateness of the A% calculations. This independent determi-
                           nation may require Bonneville to monitor the retail rate-setting
                           processes of utilities participating in the exchange program.
                                         ..
                           In spite of the changes made earlier, the MC methodology issue contin-
                           ues to concern Bonneville. For example, in a June 1987 letter to Bonne-
                           ville’s customers, the Bonneville Administrator said that he is concerned
                           that utilities participating in the exchange program, or contemplating
                           participation, may take potential exchange energy cost savings into
                           account when evaluating the costs associated with the acquisition of
                           future electric power-generating facilities. He said that including these
                           costs in a participating utility’s MC could quickly drive up Bonneville’s
                           costs and inappropriately increase Bonneville’s rates to all customers.

  I~~




Contract Suspension,       According to Bonneville officials, 99 utilities signed exchange program
Termination, and Buy-Out   contracts with the assumption they would begin active participation
                           once their ASCSwere greater than Bonneville’s priority firm power rate,
                           Only 40 of the utilities (see app. II) participated in the exchange pro-
                           gram during the first 7 years of the program. However, 18 of the 40
                           participating utilities have had their contracts suspended, terminated,
                           or bought out by Bonneville.
            Y


                           Five utilities have suspended their contracts with Bonneville on the
                           basis of mutually agreeable suspension periods-generally     for the


                           Page 15                     GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                                                                                   I
Chapter 2
Exchange Program Overview




length of time the utilities estimate it will take for their ASCS to rise
above Bonneville’s priority firm power rate. For example, the Washing-
ton Water Power Company, an investor-owned utility, negotiated an
agreement with Bonneville to suspend its exchange program contract
from June 30, 1987, until September 30, 1990. According to the agree-
ment, Washington Water Power and Bonneville agreed to suspend the
contract because the utility had incurred and would continue to incur
substantial costs in connection with the preparation and review of its
ASCsubmissions and because its ASC was consistently below Bonneville’s
priority firm power rate, thereby resulting in no likely future rate relief
benefits.

Two utilities have terminated their exchange program contracts with
Bonneville. According to Bonneville, the residential and small farm cus-
tomers of the two utilities were likely to receive limited rate relief bene-
fits According to Bonneville officials, utilities that have terminated
their contracts have foregone their contract rights to participate further
in the exchange program until after June 30,2001, when the current
contracts expire.

Eleven utilities asked Bonneville to buy out their contracts. A buy-out is
the same as a termination except that Bonneville pays the utility a nego-
tiated amount based on the discounted net present value of the pro-
gram’s exchange energy cost savings that the utility expects to receive
during the remaining life of the contract. The total cost of the buy-outs
has been about $68.3 million.

Bonneville purchased the exchange program contracts from 9 of the 11
utilities in a negotiated settlement totaling $11 .O million. According to a
Bonneville exchange program fact sheet, these nine utilities had their
contracts bought out to eliminate the administrative burden associated
with participation in the program. The contracts of the other two utili-
ties-Snohomish County Public Utility District and Clark County Public
Utility District, both in Washington State-were bought out at a cost of
$43.3 million and $14 million, respectively. According to the buy-out
agreements, the two public utility districts wanted Bonneville to pur-
chase their exchange program contracts because of disagreements in the
interpretation and implementation of the ASC method.

According to Bonneville, the contract buy-out amounts were negotiated
between Bonneville and the utilities. The amounts were based on the
discounted net present value of the exchange energy cost savings that
utilities expect to receive during the remaining life of the contracts. The


Page 16                     GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                   Chapter2
                   ExdulngeProgramoverview




                   negotiated buy-out amounts took into consideration such variables as
                   projected costs, estimated amounts of residential and small farm electric
                   power to be exchanged, past AK filings, prior allowances for certain
                   costs, and uncertainties about future exchange energy cost savings.

                   According to Bonneville officials, the details behind the negotiated buy-
                   outs are proprietary information, which the utilities do not want
                   released. We reviewed the negotiated settlement process for the Sno-
                   homish County buy-out-the      largest of the 11 settlements-and    found
                   no reason to take exception with the negotiation process followed by
                   Bonneville.


                   During the first 7 years of the exchange program, Bonneville purchased
Coticlusions       $6.83 billion in residential and small farm power and sold an equivalent
                   amount of power for $4.46 billion. The difference between these two
                   amounts-$1.37 billion-is both the total amount of rate relief benefits
                   and the net cost of the exchange program.

                   Bonneville and utilities participating in the program have made several
                   significant decisions that have affected program costs.

                   Bonneville and the utilities agreed to contracts providing that future
                   benefits would be offset when the utilities’ present costs exceeded
                   Bonneville’s priority firm power rate. As a result, as of May 1989, four
                   utilities had accrued offset balances of $115 million, which were to be
                   applied to offset future benefits,
                   Bonneville decided to revise the method used for preparing ASCfilings to
                   better ensure that the utilities do not include prohibited costs and thus
                   realize inappropriate rate relief benefits. This decision resulted, in part,
                   because one investor-owned utility had attempted to include a prohib-
                   ited $79 million in plant termination costs in its AX filing under the ini-
                   tial method.
               l   The number of utilities participating in the exchange program has been
                   reduced from 40 to 22 because 18 utilities considered it no longer in
                   their benefit to participate. The contracts of 11 of the 18 were bought
                   out at a cost of $68.3 million.




                   Page17                    GAO/RCED-90-34
                                                         Bonneville’sResidentialJbchangeProgram
Chapter 3

S{gnificame of the Exchange Program’s Rate
Relief Benefits and Costs

                      During the first 7 years of the exchange program, residential and small
                      farm customers of the 40 utilities that participated in the program were
                      entitled to receive about $1.37 billion in rate relief benefits. Exchange
                      program benefits have varied from utility to utility, with more than 86
                      percent, or about $1.18 billion, of the benefits passed through to the res-
                      idential and small farm customers of investor-owned utilities. The two
                      largest investor-owned utilities have received $941 million, or nearly 69
                      percent, of the exchange program’s total rate relief benefits. Bonneville
                      projections indicate that over the next 7 years the exchange program
                      may result in cost savings of about $1.3 billion to participating utilities.

                      During its rate-setting process, Bonneville allocates the projected gross
                      costs of the exchange program to its firm power rate classes. The largest
                      portion of the projected gross costs of the exchange program-about
                      $2.36 billion. or 45 percent- has been allocated to Bonneville’s direct
                      service industry rate class. Customers who purchase firm power-
                      including utilities Bonneville serves directly, publicly owned and cooper-
                      ative utilities that have priority for Bonneville power, and investor-
                      owned and public utilities in the Pacific Northwest and California-pay
                      the net costs of the program. However, Bonneville has not analyzed how
                      much of the exchange program’s net costs its firm power customers
                      have paid.

                      During the past decade, the disparity has narrowed between the power
                      rates paid by Pacific Northwest residential and small farm customers of
                      investor-owned utilities participating in the exchange program and the
                      rates paid by customers of public utilities with access to Bonneville
                      power. Since 1981, for example, Bonneville has increased its power rates
                      by more than 300 percent. The narrowing rate disparity can be attrib-
                      uted, in part, to the exchange program. However, numerous other fac-
                      tors have also affected retail rates in the Pacific Northwest since 1980.


                      We assessed the significance of the exchange program’s benefits in
Significance of the   terms of (1) the total exchange energy cost savings for participating util-
Exchange Program’s    ities and (2) the savings realized by residential and small farm custom-
Benefits              ers of five participating utilities, The benefits varied greatly from utility
                      to utility, but for those utilities and their customers receiving the great-
                      est benefits, the amounts were substantial.




                      Page 18                    GAO/RCED-90-34 Bonneville’s Residential Exchange Program
            I.

                                           Chapter 3
                                           Significance of the &change Program’s Rate
                                           Relief Beneflte and Costs




Sign’ficance of Benefits to                Through the end of fiscal year 1988, Bonneville paid utilities participat-
Pa icipating Utilities                     ing in the exchange program more than $6.83 billion for their residential
                                           and small farm electric power and sold the utilities an equivalent
                                           amount of power for about $4.46 billion. The difference between the two
    j                                      amounts-about       $1.37 billion-was   the cost savings to the participating
                                           utilities. In essence, during this 7-year period, for every $1 Bonneville
                                           paid participating utilities for their exchange energy, the utilities saved
                                           almost 24 cents in costs because they bought the energy back from
                                           Bonneville for only 76 cents.
        I
                                           The total cost savings realized by participating utilities in any 1 year
                                           ranged from about $151 million to almost $217 million, as shown in
                                           table 3.1. The table also shows that since fiscal year 1984, the annual
        ,                                  cost savings, as a percentage of the cost of energy exchanged, has
        /                                  ranged from 20 to 22 percent.

Table $1: Coat Saving6 Realized by
Utilitic/s Participating in the Exchange   Dollars in millions
Progrbm                                                                                  Exchange energy              Exchange energy
                                                                    Cost of exchan e cost savings realized              cost savin 8 as
                                                                 energy purchased I!       by participating         percentage 08 cost
                                           Fiscal year              Bonneville at AS E               utilities     of exchange energy
                                            1982                                 $428.4                  $216.6                     51
                                            1983                                   551.3                  151.2                     27
                                            1984                                   836.8                   185.8                    22
                                           ii385                                 LOO8.8                   207.8                     21
                                           1986                                  1‘046.4                  208.3                     20
                                           i987                                  1,010.1                  213.4                     21
                                           1988                                    949.7                  188.0                     20
                                           Total                               $5,831.5                $1,371 .l                    24
                                           Source: Bonneville’s Exchange Program Branch.


                                           Annual fluctuations in the amount of cost savings have resulted from
                                           several factors, according to Bonneville officials. These factors include
                                           (1) changes in the level of Bonneville’s priority firm power rate, (2)
                                           changes in the level of utilities’ ASCS,(3) modification of the ASCmethod
                                           in 1984, (4) changes in the amount of electric power exchanged between
                                           Bonneville and the participating utilities, (5) termination and suspension
                                           of several exchange program contracts, and (6) the gradual phase-in of
                                           the exchange program. With regard to the last factor, the Northwest
                                           Power Act required a gradual phase-in of the amount of power
                                           exchanged under the program, initially limiting utilities to exchanging




                                           Page 19                            GAO/RCED-90-34 Bonneville’s Residential Exchange Program



                                                                         ,’
                            Chapter 3
                            Significance of the Exchange Program’s Rate
                            Relief Benefits and Costa




                            50 percent of qualified residential and small farm power, and increasing
                            the amount of power exchanged to 100 percent beginning July 1985.

                            The energy cost savings varied considerably from utility to utility.
                            Investor-owned utilities, which generally have higher ASCS than publicly
                            owned utilities, received most of the cost savings. In all, investor-owned
                            utilities received about $1.18 billion, or about 86 percent, of the total
                            cost savings. In particular, the two largest investor-owned utilities of
                            the region -Portland General Electric Company and Pacific Power and
                            Light Company-received       the largest share of the cost savings. Nearly
                            69 percent of the total cost savings, or about $941 million, went to these
                            two utilities, which serve about 954,000 residential and small farm
                            customers.


Si&ficance of Benefits to   To illustrate the significance of the rate relief benefits provided for resi-
                            dential and small farm customers, we compared the benefits received in
Residential and Small       calendar year 1988 by an average residential customer and an average
Farm Customers              small farm customer1 of five participating utilities. Together, these five
                            utilities-three   investor-owned utilities, one cooperative utility, and one
                            public utility district-accounted   for about $1.18 billion, or more than
                            86 percent, of the program’s total cost savings. The highest residential
                            benefit among the five utilities went to Utah Power and Light Com-
                            pany’s customers living in Idaho (see table 3.2). Without rate relief, the
                            average Idaho residential customer would have paid an annual electric
                            bill of about $1,137. However, after subtracting a rate relief credit of
                            almost $286 for the year, the average Idaho residential customer had an
                            annual power bill of approximately $851. In essence, the rate relief ben-
                            efit received by an average Idaho residential customer of Utah Power
                            and Light was the equivalent of receiving 3 months of power usage at no
                            cost.




                            ‘An average residential and small farm customer for each of the five utilities is defined by the aver-
             J
                            age annual amount of power purchased by a residential customer and small farm customer from each
                            utility. The average annual residential power purchased was different for each utility and ranged
                            from a low of 12,049 kilowatt-hours for Pacific Power and Light Company to a high of 16,334 kilo-
                            watt-hours for Snohomish County Public Utility District.



                            Page 20                             GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                                             Chapter8
                                             Sm           of the Exchange Program’r Rata
                                             Reltef Beneflta and Coats




Table .2: Exchange Program Rate Relief
Benef tr Received by Average                                                            Aveta e
Rerid ntiai Curtomet, Calendar Year                                                  resident Pal Rate relief benefit    Electric bill paid
1988                                                                                curtomet’s          pet aveta e            by aveta e
                                                                            electric bill before          terldent Pal          resident Pal
                                             Utility                         rate relief benefit            customer             customer
                                             Investor-owned utilities
     I                                          Portland General Electric
                                                                                        $699.81               $104.46              $595.35
                                             -- Company
                                                Pacific Power and Light
                                                  Company                                710.00                 74.00               636.00
                                                Utah Power and Light
                                                  Company                              1,136.92                285.61               851.31
                                             Coooerative
                                                Central Electric
                                                  Cooperative, Inc.                      986.28                141.84               844.44
                                             Public utility district
                                                Snohomish Countv                         825.03                115.97               709.06


                                             In addition to affecting residential electric bills, the exchange program
                                             had a significant effect on power bills paid by small farm customers,
                                             according to officials for three of these five utilities. Specifically, during
                                             the May-September 1988 irrigation season:

                                         . The power bills for small farm irrigators served by Utah Power and
                                           Light Company in Idaho were reduced on average from $10,751 to
                                           $6,043. This $4,708 rate relief was an average reduction of almost 44
                                           percent.
                                         l The average power bills for small farm irrigators served by Pacific
                                           Power and Light Company in Oregon were reduced from $1,336 to
                                           $1,010. This was an average reduction of $326, or more than 24 percent.
                                         . The average power bills for small farm irrigators served by Central
                                           Electric Cooperative, Inc., in Oregon were reduced from $988 to $664.
                                           This was an average reduction of $334, or almost 34 percent,


                                             Bonneville recovers the cost of the exchange program through the rates
Significance of the                          it charges its customer classes. Assessing the significance of this cost for
Eichange Program’s                           Bonneville’s customer classes is more difficult than assessing the signifi-
C@sts                                        cance of the program’s exchange energy cost savings on participating
                                             utilities and their customers. This difficulty stems from the fact that
                                             Bonneville allocates the gross costs of its exchange program to its rate
                  u                          classes prior to setting rates, but does not record the actual net costs
                                             paid by each of its customer classes. Nonetheless, these allocations of
                                             gross costs can provide several indications of the significance of the


                                             Page 21                          GAO/RCED-90-34 Bonneville’e Residential Exchange Program
-__-
                           Chapter 3
                           Significance of the Exchange Program’s Rate
                           Relief Benefits and Costs




                           exchange program’s costs. We assessed this significance in two ways: (1)
                           in terms of the relationship between the exchange program’s gross costs
                           and Bonneville’s total operating gross costs and (2) in terms of the allo-
                           cation of the exchange program’s gross costs among Bonneville’s rate
                           classes.


Significance of Costs to   As part of its rate-setting process, Bonneville projects the gross costs for
Bobneville’s Total         all aspects of its operations, including the exchange program. For our
                           purposes in assessing the significance of the program, the cost to be
Opbrations                 recovered is best expressed as a net cost-that is, as the dollar differ-
                           ence between the power Bonneville buys from participating utilities and
                           the power it sells back to them. During the first 7 years of the exchange
                           program, the program’s total net cost of $1.37 billion was approximately
                           9.2 percent of Bonneville’s total operating revenue of $14.98 billion.

                           For rate-setting purposes, however, Bonneville does not directly use this
                           net amount. The gross cost of the exchange program used for rate-set-
                           ting takes into account the cost of the exchange energy Bonneville
                           expects to purchase. Bonneville’s revenue estimate for the rate test
                           period includes the amount Bonneville expects to sell in return.

                           Table 3.3 compares Bonneville’s total projected gross operating costs
                           with the projected gross costs of the exchange program for the four
                           rate-setting processes covering fiscal years 1983-8ge2For those four
                           rate-setting processes, the projected annual gross costs of the exchange
                           program ranged from almost $671 million to about $2.3 billion. This
                           amount ranged from 30 to 39 percent of Bonneville’s total projected
                           gross costs for all aspects of its operations. For the four rate-setting
                           processes, the projected gross cost of the program averaged 37 percent
                           of Bonneville’s total projected gross costs.




              J

                           %onneville did not project the gross cost of the exchange program in its rate-setting process for fiscal
                           year 1982 because the program was too new for a projection to be developed. The four rate-setting
                           processes for fiscal years 1983-89 took place in 1982, 1983, 1985, and 1987.



                           Page 22                             GAO/RCED90-34 Bonneville’s Residential Exchange Program
                                             Chapter8
                                             Significance of the Exchange Progrm’r        Rate
                                             Relief Beneflta and Ckmta




Table   3.3: Projected Gross Costs for the
Exch    ngo Program Versus Projected         Dollars in millions
Qror     Costs for All Bonneville                                                                                        Projected exchange
Oper    tlons In 1992,1983,1986, and 1987                                                                               program gross costs
Rate-    ettlng Processes                                                                                                   as percentage of
                                             Year ot rate-            Projected exchange               Projected gross       projected gross
                                             setting process         program gross costs               operating costs        operating costs
                                                                                                                                          -
    i                                        1982                                   $670.9                     $2,225.2                     30
                                             1983                                     1,108.5                     2,927.l                          38
                                             1985                                     1,107.4                     2,929.4                          38
                                             1987                                    23304.5                     5,874x9                           39
                                             Total                                  $5,191.3                  $13,956.6                            37
                                             Source: Bonneville’s Exchange Program Branch.


                                             It is important to remember that the gross costs reflected in table 3.3 are
                                             projections for rate-setting purposes, not actual amounts. A comparison
                                             of the exchange program’s total gross costs that were allocated (table
                                             3.3) with the actual gross costs of energy purchased by Bonneville (table
                                             3.1) will show considerable differences. For example, table 3.3 shows
                                             that in the 1983 and 1986 rate-setting processes, Bonneville’s projected
                                             gross costs for the exchange program totaled about $2.2 billion. How-
                                             ever, the actual gross cost of exchange energy purchased by Bonneville
                                             for fiscal years 1984-87, the 4 fiscal years covered by the 1983 and 1986
                                             rate-setting processes, amounted to $3.9 billion-a difference of approx-
                                             imately $1.7 billion. Bonneville officials pointed out that before the 1987
                                             rate-setting period, projections were based on l-year test periods rather
                                             than on the full-period rates that were expected to be in effect. (In its
                                             1987 rate-setting process for fiscal years 1988-89, Bonneville used a 2-
                                             year test period.)


Estjimated Distribution of                   During its rate-setting processes, Bonneville has generally allocated the
Costs Among Bonneville’s                     exchange program’s projected gross costs to its firm power rate custom-
                                             ers.” Bonneville has classified its firm power rate customers as follows:
Customers



                                             “In its rate-setting process for fiscal years 1986-87, Bonneville also allocated the exchange program’s
                                             gross costs to its non-firm power rate classes-the only time Bonneville did so during the first 7 years
                     Y                       of the program. According to the Bonneville Administrator’s Record of Decision for the 1987 Final
                                             Rate Proposal, inclusion of the exchange costs made the 1986 non-firm power rates uneconomical and
                                             forced Bonneville to an emergency rate reduction. The inclusion of exchange program costs in Bonne-
                                             ville’s non-firm power rates for fiscal years 1986-87 is an issue waiting final resolution by the Federal
                                             Energy Regulatory Commission.



                                             Page 23                              GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                                            Chapter 3
                                            SignWicance of the Exchange Program’s Rate
                                            Relief Renef’ita and Costa




                                        l   Direct service industry rate class: This rate class consists of industries-
                                            primarily aluminum companies -that purchase power directly from
                                            Bonneville.
                                        l   Preference rate class: This rate class consists of publicly owned utilities,
                                            cooperatives, federal agencies, and municipalities, which have priority
                                            for Bonneville power under federal law, and utilities participating in the
                                            exchange program.
                                        l   Surplus firm power rate class: This rate class consists of investor-owned
                                            utilities in the Pacific Northwest and utilities in California that have
                                            signed contracts with Bonneville for firm power surplus to Bonneville’s
                                            preference customer requirements.
                                        l   “Other” rate class: This rate class consists of a variety of utilities that
                                            purchase small amounts of firm power.

                                            Table 3.4 shows how Bonneville allocated the projected gross costs for
                                            the exchange program among its customer classes. The largest portion-
                                            about $2.36 billion, or 45 percent- was allocated to the direct service
                                            industry rate class. The surplus firm power rate class and preference
                                            rate class had the next largest shares, with 29 and 24 percent,
                                            respectively.

Table 3.4: Allocation of the Exchange
Program’s Projected Gross Costs for         Dollars in millions                                                                         .--
Bonneville’s Rate-Setting Processes         --                               Cost allocated to each rate class
                                            Year of rate-               Direct                                                       Total
                                            setting                   service Surplus firm                                      allocated
                                            process--.-- ~-.~--..--. industry
                                            ______._                  _____-.____      power    Preference           Other     gross cost
                                            1982                       $511.9           $99.6         $54.0           $5.5          $671.0
                                            1983                         522.6           286.7          269.4         29.7         1,108.4
                                            1985                         459.6           416.5          214.0          17.3        1,107.4
                                            1987                         861.8           690.7          706.9         45.1         2,304.5
                                            Total                     $2,355.9       $1,493.5       $1,244.3         $97.6       $5,191.3
                                            Source: Bonneville’s   Exchange Program Branch.


                                            According to Bonneville, after allocating costs among the rate classes,
                                            Bonneville adjusts the allocated costs to set rates. One adjustment
                                            accounts for the difference between the costs allocated to the surplus
                                            firm power rate class and the revenues Bonneville expects to receive
                                            from the sale of that power. Market conditions have historically com-
                                            pelled Bonneville to sell surplus firm power either in the open (economy
                                            energy) market or under contract for less than fully allocated costs. The
                                            adjustment allocates costs in the amount of the deficiency from the sur-
                                            plus firm power rate class to all other firm power rate classes. Because



                                            Page 24                              GAO/RCED-90-34 Bonneville’s Residential Exchange Program
I
!   l




            Chspter a
            Sigdflcance of the Exchange Program’s Rate
            Relief Benefits and Co&a




            of this reallocation, the amount of the exchange program’s costs that
            remains in surplus firm power rates is less than the original amount
            allocated.

            Once rates are set, Bonneville is able to negotiate sales for surplus firm
            power under the rate schedules. The negotiated contract rates reflect
            market conditions perceived by each party to the negotiated sale.
            Bonneville attempts to recover fully allocated costs from each sale of
            surplus firm power, but it uses its opportunity cost-the revenue that
            Bonneville would receive from selling surplus firm power in the short-
            term economy energy market-as its lower limit for negotiating a sur-
            plus firm power sale price.

            The actual amount of program costs paid by each Bonneville customer
            class has not been determined, since the actual revenues received from a
            customer class may differ substantially from those forecast for rate-
            making. For example, in fiscal year 1988, Bonneville’s revenues from its
            direct service industrial customers were over $200 million more than
            forecast in the 1987 rate-setting process. Also, revenues from surplus
            firm power customers were about $150 million less than forecast in that
            rate-setting process.

            To illustrate the difficulty in determining which customer classes pay
            actual program costs, we developed information about a 20-year power
            sale and exchange agreement between Bonneville and Southern Califor-
            nia Edison, a surplus firm power customer. Beginning July 1, 1989,
            Southern California Edison agreed to purchase surplus firm power from
            Bonneville. Southern California Edison will initially pay 2.85 cents per
            kilowatt-hour for electric power purchased and as much as 3.69 cents
            per kilowatt-hour, based on annual increases in oil and gas prices. Under
            Bonneville’s gross cost allocation, approximately 26 percent of Southern
            California Edison’s power costs under the agreement would go toward
            the exchange program’s gross costs.

            According to Bonneville, however, revenues have differed substantially
            from those projected in Bonneville’s 1987 rate-setting process, when the
            gross cost allocation was made. In addition, because Bonneville and
            Southern California Edison agreed to rates for this sale that are below
            Bonneville’s fully allocated cost rate, less than 26 percent of Southern
            California Edison’s power costs will be attributable to the exchange
        Y
            program.




            Page 25                       GAO/RCED4O-24 Bonneville’s Residential Exchange Program
                                               Chapter 3
                                               Slgniftcance of the Exchange Program’s Rate
                                               Relief Benefits and Costa




                                               Utilities participating in the exchange program may continue to receive
                                               significant cost savings. However, three of the utilities participating in
                                               the exchange program are currently involved in either wholesale electric
Bebsfits and Costs                             power marketing or merger activities, which could affect the net costs of
  I                                            the exchange program.


The Exchange Program’s                         According to data compiled by Bonneville’s Exchange Program Branch
Futture Energy cost                            in preparation for the 1989 rate-setting process,* the cost savings to be
cc,.l:,A,
Day 11tgj3
                                               realized by utilities participating in the exchange program for fiscal
                                               years 1989-95 may range from $142 million to about $228 million annu-
                                               ally (see table 3.5). The projected total cost savings of about $1.3 billion
                                               is almost 18 percent of the projected $7.3 billion Bonneville expects to
                                               pay utilities for their exchange energy.

Table 3.5: Projected Exchange Energy
Cost ,Savings for Utilities Participating in   Dollars in millions
the E’xchange Program, Fiscal Years                                           Projected cost of                                 Projected exchange
1989.95                                                                    exchange energy to       Projected exchange          energy cost savings
                                                                              be purchased by       energy cost savings            a8 percentage of
                                                                                  Bonneville at         for participating          projected cost of
                                               Fiscal year                       utilities’ ASCs                   utilities      exchange energy
                                               198ga                                     $870.2                      $142.0                               16
                                               1990                                        887.3                      143.1                               16
                                               1991_----~--
                                               .--                   --_                   925.1                       175.8                              19
                                               1992                                      1,080.3                       186.2                              17
                                               1993                                      1,126.6                       202.2                              18
                                               1994                                      1.181.5                       214.2                              18
                                               1995                                      1,243.6                       228.3                              18
                                               Total                                   $7,314.8                   $1,291.8                            18
                                               aExcludes $22.1 million for buyouts of the Clark and Snohomish County public utility districts that were
                                               expensed in 1989 but obligated in 1988.
                                               Note: Amounts adjusted by Bonneville for inflation.
                                               Source: Bonneville’s Exchange Program Branch




                                               4Because Bonneville extended the rates established for fiscal years 1988-89 to fiscal years 1990-91, it
                                               did not undertake a full rate adjustment process in 1989. Until Bonneville conducts another rate-
                                               setting process, the most current allocations of exchange program gross costs are those used for set-
                                               ting rates in 1987.



                                               Page 26                               GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                            Chapter8
                            Slgnlflcanceof the ExchangeProgram’sRnte
                            Relief Benefits and Costa




Act vities That Could       Wholesale electric power marketing and merger activities involving
Aff t ct Exchange Program   three utilities participating in the exchange program could affect the net
co+                         costs of the program. The activities in which the three utilities are
                            involved and the potential impacts of the activities on the exchange pro-
                            gram’s net costs are described below. The residential and small farm
                            customers of the three utilities were entitled to more than $1 billion, or
                            almost 79 percent, of the exchange program’s total energy cost savings
                            paid by Bonneville during the first 7 years of the program.

Port and General Electric   The Portland General Electric Company, a subsidiary of the Portland
                            General Corporation, received almost $66 million in exchange energy
    !                       cost savings in fiscal year 1988. In addition, Portland General Electric
                            has received the most exchange energy cost savings-approximately
                            $602 million-of    any utility participating in the program.

                            Portland General Electric Company sells electric power to customers in
                            northwestern Oregon and to utilities in California. Revenue from the
                            California sales offsets the cost to Portland General Electric, reduces its
                            GSC,and reduces the cost savings the utility receives from the exchange
                            program. According to Bonneville officials, a net revenue of $60 million
                            from electric power sales to California utilities would reduce Portland
                            General Electric’s annual exchange energy cost savings by approxi-
                            mately $12 million.

                            In February 1988, the Portland General Corporation established the
                            Portland General Exchange to operate in the wholesale power market.
                            According to Portland General Electric officials, Portland General
                            Exchange would be able to purchase power from any source; however, if
                            it purchased any power from Portland General Electric, it would be
                            under a Power Services Agreement filed with the Federal Energy Regu-
                            latory Commission. Portland General Exchange may sell to any utility
                            on a long-term basis and is not confined to any geographical area.

                            Bonneville estimates that if Portland General Exchange’s power sales
                            should undercut Portland General Electric’s sales to California utilities,
                            Portland General Electric’s AX would increase. According to Bonneville
                            officials, this potential increase in Portland General Electric’s ASCcould
                            increase the exchange program’s net costs by about $161 million
                            through June 200 1.

                            Bonneville does not want any unwarranted reductions of Portland Gen-
                            eral Electric’s revenues, and corresponding increases in the utility’s AK,
                            to result from Portland General Exchange’s efforts to capture electric


                            Page 27                     GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                                  Chapter 3
                                  Significance of the Exchange Program’s Rate
                                  Relief Benefits and Costa




                                  power sales to California utilities. Bonneville officials said they may
                                  participate in Federal Energy Regulatory Commission and state regula-
                                  tory proceedings to ensure that there is no unwarranted reduction in
                                  Portland General Electric’s off-system revenues that would result in an
                                  MC increase and exchange energy cost savings paid by Bonneville.
                                  I3onneville does not consider a change to the ksc method necessary at
                                  this time.

I Jt:   Power and Light Merger    On January 9, 1989, Pacific Power and Light Company, a subsidiary of
Wil     Pacific Power and Light   PacifiCorp, and Utah Power and Light Company conditionally merged
                                  through a stock exchange worth approximately $1.9 billion. Utah Power
                                  and Light generates and sells power to about 510,000 retail customers in
                                  Utah, southeastern Idaho, and southwestern Wyoming. Pacific Power
                                  and Light generates and sells power to about 680,000 retail customers in
                                  California, Idaho, Montana, Oregon, Washington, and Wyoming.

                                  In fiscal year 1988, Utah Power and Light had an ASC of approximately
                                  4.1 cents per kilowatt-hour and received almost $22.8 million in cost
                                  savings from Bonneville. Pacific Power and Light had an ASC of approxi-
                                  mately 3.1 cents per kilowatt-hour and received more than $48.9 million
                                  in cost savings.

                                  In 1987, Bonneville estimated that the merger of Utah Power and Light
                                  with Pacific Power and Light could reduce the exchange program’s net
                                  costs by as much as $5 million annually for fiscal years 1989-95 and $50
                                  million annually for fiscal years 1996-2001. Earlier net cost reductions
                                  would be due to operating the combined generating system more effi-
                                  ciently and selling power to other utilities. Net cost reductions after fis-
                                  cal year 1995 would occur largely because Pacific Power and Light can
                                  use Utah Power and Light’s surplus power to meet demand instead of
                                  building additional generating facilities.

                                  Bonneville is concerned about the equitable distribution of net merger
                                  benefits-benefits    minus costs-between Pacific Power and Light and
                                  Utah Power and Light. For example, Bonneville estimates that $1 of net
                                  benefits allocated to Pacific Power and Light would reduce the utility’s
                                  MC and the exchange program’s net costs more than it would if the same
                                  benefit was allocated to Utah Power and Light, This is because a signifi-
                                  cant portion of Utah Power and Light’s service territory is outside
                                  Bonneville’s service area. According to Bonneville officials, even with
                                  net benefits, Pacific Power and Light’s MC could increase because (1)
                                  generation and transmission costs may be allocated from a Utah Power
                                  and Light service territory that does not qualify for rate relief benefits


                                  Page 28                        GAO/RCED-90-34 Bonneville’s Residential Exchange Program
/      j.


                        chapter a
                        Signiflcanee of the Exchange Program’s Rata
                        Relief Benefib and Costs -




                        into a Pacific Power and Light service territory that does qualify for
                        benefits, (2) interdivisional power transfers between the two utilities
                        may include prohibited costs, and (3) merger benefits may not be appro-
                        priately allocated between the two utilities’ service territories.

                        In a March 31, 1989, letter to Bonneville, Pacific Power and Light stated
                        that a committee has been established to review the complexities sur-
                        rounding the allocation of costs between Utah Power and Light and
                        Pacific Power and Light for financial and regulatory reporting. Accord-
                        ing to the letter, the committee has developed a detailed proposal for
                        allocating costs and is meeting with representatives from the state util-
                        ity commissions to refine the proposal so that it is acceptable to all
                        parties,

                        Through the rate intervention process provided for in the MC method,
                        Bonneville is monitoring the merger to identify increases in Pacific
                        Power and Light’s ASCand corresponding increases in the exchange pro-
                        gram’s net costs. According to Bonneville officials, as part of its moni-
                        toring effort, Bonneville may intervene in electric power rate-setting
                        activities to obtain better information concerning the costs used by
                        Pacific Power and Light and Utah Power and Light in setting retail rates
                        and to ensure the equitable allocation of net benefits between the two
                        utilities.


                        As chapter 1 explained, the exchange program was designed to narrow
    R&e Disparity Has   the disparity between retail power rates for residential and small farm
    N&owed              power charged by utilities. To determine whether the disparity that
                        existed before enactment of the Northwest Power Act has been reduced,
                        we reviewed power rates in three states and for nine electric utilities in
                        the region.

                        The statewide data indicate that power rates have declined. This decline
                        can be seen by comparing statewide averages for Washington, where
                        residents are served primarily by publicly owned utilities, with averages
                        for Oregon and Idaho, where residents are served primarily by investor-
                        owned utilities. Table 3.6 shows the average bill for all utilities serving
                        residential customers in the three states. In 1978, the average monthly
                        bill in Washington was $14.00, or 66 percent of the bill in Oregon and 70
                        percent of the bill in Idaho. In 1988, the average monthly bill in Wash-
                        ington was still lower than those in the other two states, but it was now
                        almost 88 percent of the average bill in Oregon and 94 percent of the
                        average bill in Idaho.


                        Page 29                        GAO/RCED-90.34 Bonneville’s Residential Exchange Program
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                                           Chapter 3
                                           Significance of the Exchange Program’s Rate
                                           Relief Beneflts and Costs




TabI” 3.6: Typical Monthly Residential
Pow r Bills for 1,000 Kllowatt-Hours of                                                           Monthly residential power bill
Elec ricity in Three Pacific Northwest     State                                      1978                      1983                             1966
Stat i 8                                  Oregon                                     $24.91                        $34.71                       $47.80
                                                                    ..-~--.-
                                          Washington                                  14.00 .____---..-             31.07                        41.95
                                          Idaho                                       19.92                         35.63     --                 44.61
                                          Source: Department of Energy’s Typical Electric Bills reports

                                          We also compared rate information from the Department of Energy’s
                                          Typical Electric Bills reports for 1978 (4 years before the program took
                                          effect), 1983 (the second year of the program), and 1988. These bills are
                                          based on rates charged by utilities for residential electric use of 1,000
                                          kilowatt-hours per month.” Table 3.7 shows residential power bill data
                                          for five investor-owned utilities that have participated in the exchange
                                          program and four publicly owned utilities that do not participate in the
                                          program. The power bill difference between these two groups of utilities
                                          was smaller in 1988 than in 1978. For example, in 1978, the average
                                          monthly bill of $10.84 for the Seattle Department of Light was 40 to 70
                                          percent of the average monthly bills of the five investor-owned utilities.
                                          In 1988, by comparison, the Seattle Department of Light bill was 63 to
                                          78 percent of the bills of the five investor-owned utilities.

Table 3.7: Typical Monthly Residential
Power Sills for 1,000 Kilowatt-Hours of                                                                     Monthly residential power bill
Electricity                               Utilitv                                                          1978           1983          1988
                                          Investor-owned
                                             Washington Water and Power Company                           $15.38              $30.67          $43.37
                                             Puget Sound Power and Light Company                           19.28               34.09           46.91
                                             Portland General Electric Companv                             27.00               35.78 ----~____-48.93
                                            Pacific Power and Light Company                                27.24               37.14           53.55
                                            Idaho Power Company                                            21.57               38.65           43.95
                                          Publicly owned
                                            Burley Municipal Distribution System (Burley,__--
                                                                                           ID) ~--         15.26               38.50             45.50
                                            Eugene Water and Electric Board (Eugene, OR) --.               18.27
                                                                                                               ~.-             32.81             34.23
                                            Seattle Department of Light (Seattle, WA)                      10.84               23.99
                                                                                                                            __-.-___-            33.68
                                                                                                                                                --
                                            Tacoma Department of Public Utilities (Tacoma,
                                               WA)                                                         12.80               20.45            29.80
                                          Source: Department of Energy’s Typical Electric Bills reports


                                          According to Bonneville officials, the reductions in the residential rate
                                          disparity during the past decade cannot be attributed solely to the

                                          “One kilowatt-hour   of electrical energy equals 1,000 watts of power supplied for 1 hour.



                                          Page 30                              GAO/RCED90-34 Bonneville’s Residential Exchange Program
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           Signlflcance oPthe Exchange Program’6 Rate
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I--        exchange program because numerous factors have affected rates in the
           Pacific Northwest. For example, the Washington Public Power Supply
           System’@ construction and settlement costs, costs associated with power
           conservation and fish and wildlife restoration activities, the condition of
           the regional economy, and the existence of considerable surplus power
           in the region have affected the disparity of retail rates. Also, between
           1981 and 1987, Bonneville increased its power rates by more than 300
           percent-primarily    to meet debt service obligations on about $6 billion
           in debts Bonneville had incurred to purchase power from nuclear power
           plants.

I
           The exchange program has resulted in significant dollar benefits to the
+lusions   utilities participating in the program. Specifically, participating utilities
           have received $1.37 billion through the exchange program to benefit
           their residential and small farm customers. In addition, Bonneville esti-
           mates that during the next 7 years of the exchange program, participat-
           ing utilities will receive an additional $1.3 billion in program benefits.

           The net costs of the exchange program are paid by Bonneville’s custom-
           ers. As the rate-setting process shows, Bonneville’s industrial customers
           bear the largest portion of the program’s costs. However, Bonneville has
           not identified the actual costs paid by its customers, and the cost alloca-
           tion factors used for setting rates differ from the actual revenues
           received.

           Three utilities participating in the exchange program are involved in
           wholesale electric power brokering and merger activities, which could
           significantly affect the exchange program’s net costs. Bonneville is mon-
           itoring these activities to ensure that the utilities’ ASC claims are
           appropriate.

           The data we reviewed also indicate that the disparity in residential and
           small farm rates that existed between investor-owned utilities and pub-
           lic utilities before enactment of the Northwest Power Act has been
           reduced. However, this reduction cannot be attributed solely to the
           exchange program because numerous factors have affected retail rates
           in the Pacific Northwest since 1980. The significant increases in Bonne-
           ville’s costs and rates appear to be a more important reason than the


           “As of August 1, 1989, the Washington Public Power Supply System was a coalition of 14 public
           utilities that joined together to create power-generating facilities.



           Page 31                           GAO/RCED-90-34 Bonneville’s Residential Exchange Program
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residential exchange program for the reduced disparity in Northwest
power rates.




Page 32                         GAO/RCED-SO-34 Bonneville’s Residential Exchange Program
Cyrrent Efforts Are Inadequateto Enswe That
U$lities’ CustomersHave ReceivedRate
R4jliefEknefits
                         Section S(c) of the Northwest Power Act requires utilities participating
                         in the exchange program to pass rate relief benefits through to their
                         residential and small farm customers. Included in the exchange program
                         contracts signed by participating utilities are provisions giving Bonne-
                         ville a contractual right to ensure that the utilities pass the benefits of
                         the exchange to their customers. However, Bonneville has limited its
                         benefit pass-through verification to two utilities and has otherwise
                         relied on state regulatory agencies, utilities, or organizations to ensure
                         that rate relief benefits are passed through by participating utilities.

   I
                         According to Bonneville officials, they performed two limited pass-
Bo neville’s Reviews     through reviews on a trial basis, both in 1987. Bonneville performed
of enefit Pass-          these reviews to (1) determine the methods used by public utilities for
Thrioughs Have Been      passing the exchange program’s rate relief benefits through to their resi-
                         dential and small farm customers, (2) verify that the benefits had been
Limited                  properly distributed, (3) identify Bonneville’s future role in conducting
                         reviews of benefit pass-throughs, and (4) provide Bonneville with infor-
                         mation and experience regarding the relative costs and benefits of con-
                         ducting such reviews.

                         Bonneville conducted the pass-through reviews at one public utility dis-
                         trict and one electric cooperative utility. Both reviews disclosed prob-
                         lems. Specifically:

                       . At the public utility district, which had received almost $1.2 million in
                         rate relief benefits through fiscal year 1988, Bonneville’s preliminary
                         review indicated that the utility may not have passed through about
                         $73,000 in benefits to customers, may not have passed through benefits
                         to all qualified customers, and may have passed through benefits to
                         unqualified customers. In addition, Bonneville’s preliminary review indi-
                         cated that the utility used a rate approach that made tracing benefits
                         difficult. On the basis of these preliminary data, the review team’s draft
                         recommendations were that the utility establish a balancing account (an
                         account in which the receipt and disbursement of rate relief benefits are
                         recorded), maintain sufficient documentation to trace benefits passed
                         through to customers, and allocate retroactive and future benefits to all
                         qualified customers.
                       . At the electric cooperative utility, which had received about $7 million
           Y
                         in rate relief benefits through fiscal year 1988, Bonneville’s preliminary
                         review indicated two minor errors. First, the conversion to a new com-
                         puter program resulted in the utility’s not passing through almost
                         $4,300 in benefits. Second, the utility erroneously passed through more


                         Page 33                   GAO/RCED90-34 Bonneville’s Residential Exchange Program
                                                                                                         -        -.


                       Chapter 4
                       Current Efforts Are Inadequate to Ensure
                       That Utflities’ Customers Have Received Rate
                       Relief Benefits




                       than $2,900 in benefits to nonresidential customers. Bonneville’s prelim-
                       inary review indicated that the utility had a process for receiving and
                       distributing benefits that essentially resulted in benefits being applied to
                       customer’s bills. On the basis of these preliminary data, the review team
                       recommended that the utility correct the two minor errors identified and
                       forward the journal entries to Bonneville.

                       In response to our questions about these reviews, Bonneville, in a
                       November 23, 1988, letter to us, stated that officials in Bonneville’s
                       Office of Financial Management reviewed the preliminary results of the
                       two reviews and elected not to issue reports on the preliminary findings
                       and recommendations. Bonneville did not issue the reports because
                       Bonneville management did not want to become involved in the two util-
                       ities’ rate-setting processes with regard to how the program’s benefits
                       would affect the utilities’ rates. In addition, Bonneville officials told us
                       that one of the utilities had been informed verbally of Bonneville’s
                       review results. Utility officials said, however, that they had not been
                       provided the results.

                       According to Bonneville officials, they also decided not to conduct addi-
                       tional reviews of benefit pass-throughs to minimize their costs and to
                       avoid raising issues that could negatively affect their relations with the
                       utilities. Instead, they said that Bonneville has relied on (1) the contrac-
                       tual requirement that participating utilities pass rate relief benefits
                       through to their residential and small farm customers and (2) the utili-
                       ties’ customers, public interest groups, and-in the case of investor-
                       owned utilities-state    regulatory commissions to ensure that benefits
                       are passed through to residential and small farm customers.


                       We asked officials of state utility regulatory commissions in Oregon,
Bdmefit Pass-Through   Washington, and Idaho if they verify that investor-owned utilities pass
Reviews by State       through their rate relief benefits. Investor-owned utilities receive about
Officials              86 percent of the program’s benefits. They said that they do review the
                       benefit pass-throughs during the utilities’ rate-setting process. Officials
                       of all three state public utility commissions acknowledged, however,
                       that their reviews are limited in that they do not test customers’ bills to
                       verify that the utility’s rate structure actually provides customers with
                       the correct amount of benefits.

                       The rate-setting process begins when an investor-owned utility submits
                       a proposed rate change to its regulatory commission. The commission
                       establishes the utility’s revenue requirement-the  amount the utility


                       Page 34                         GAO/RCED-90-34 Bonneville’s Residential Exchange Program
U




        Chapter 4
        Current Efforts Are Inadequate to Rnsure
        That Utilities’ Customers Have Received Rate
        Relief Reneflta




        can collect from its customers to cover reasonable expenses and a return
        on the utility’s investment. On the basis of the revenue requirement, the
        utility then establishes rates for each of its customer classes, such as its
        residential, industrial, commercial, and agricultural classes.

        The utility also develops a special tariff for customers qualifying for the
        residential exchange program. These rate schedules and special tariffs
        are then reviewed by the state utility regulatory commission to ensure
        that an appropriate credit is being applied to residential and small farm
        customers. The utility then adjusts its residential and small farm cus-
        tomer bills according to the approved special tariff, which contains the
        credit for the rate relief benefit.

        We found that the methods used to review benefit pass-throughs vary
        somewhat from state to state as follows:

    . The Oregon Public Utility Commission reviews proposed rates and bal-
      ancing accounts of two investor-owned utilities-Pacific       Power and
      Light Company and Portland General Electric Company. According to
      the state employee responsible for reviewing the balancing accounts, the
      Pacific Power and Light account, which is reviewed annually, is
      straightforward and does not include an interest calculation, while the
      Portland General Electric account is reviewed quarterly because it is
      more complex, includes an interest calculation, and has many adjust-
      ments. The Commission detected only one minor problem during its
      reviews of the two balancing accounts. Specifically, Portland General
      Electric was inconsistent in its interest calculation on overpayment or
      underpayment of rate relief benefits. In 1987, the Commission sent a
      letter cautioning Portland General Electric to be consistent in calculating
      the interest due on the temporary use of funds when Bonneville makes a
      benefit overpayment or underpayment to the utility.
    l The Washington Utility and Transportation Commission reviews the
      benefit pass-throughs of investor-owned utilities as part of the rate-fil-
      ing process by reviewing the utilities’ rate tariffs and balancing
      accounts. It does not request utilities to submit their balancing accounts
      annually or quarterly for review. An example of the Commission’s moni-
      toring of the investor-owned utilities involved a rate tariff submitted by
      Puget Sound Power and Light Company in 1987 to pass through about
      $7.5 million in rate relief benefits to its residential and small farm cus-
      tomers. In 1988, Puget Sound Power and Light informed the Commission
      that about $3 11,000 remained in its balancing account after the 1987
      rate tariff had ended in 1988. Puget Sound Power and Light asked the



        Page 35                        GAO/RCED-99-34 Bonneville’s Residential Exchange Program
                           Chapter 4
                           Current Efforts Are Inadequate to Ensure
                           That Utlllties’ Customers Have Received Rate
                           Relief Benefits




                           Commission whether the company could retain the $311,000 in its bal-
                            ancing account. The Commission did not agree and on July 1, 1988,
                           instructed the utility to submit another rate tariff to pass the $311,000
                           through to the utility’s residential and small farm customers.
                       l   The Idaho Public Utility Commission reviews the benefit pass-throughs
                           of investor-owned utilities as part of the rate-filing process. For exam-
                           ple, the Commission questioned whether the credit on Utah Power and
                           Light Company’s customer bills covered the rate relief benefits received
                           from Bonneville. Utah Power and Light provided the Commission with
                           background data on the development of the credit and a 1989 estimate
                           of the utility’s balancing account showing a gradual pass-through of the
                           existing benefits in the account. The Commission agreed that the util-
                           ity’s 1989 estimate was sufficient to pass through the benefits received
                           from Bonneville. However, the Director, Utilities Division, stated that
                           the Division had identified a deficiency in its monitoring of the pro-
                           gram’s rate relief benefits as a result of their discussions with GAOstaff
                           during this review. The Director further stated that, in the future, com-
                           mission auditors will be required to audit utilities’ balancing accounts
                           whenever a general review or rate case audit is done on a utility partici-
                           pating in the exchange program.

                           The officials said they do not notify Bonneville of the results of their
                           pass-through reviews even if a utility is not passing through benefits,
                           because they believe it is their responsibility to ensure that the situation
                           is corrected.

                           While the benefit pass-throughs of investor-owned utilities are reviewed
                           by their state public utility commissions, no organizations review the
                           pass-through efforts of municipalities, cooperatives, or public utility dis-
                           tricts. This fact was confirmed in our discussions with officials of public
                           utilities, as well as with officials from organizations representing utili-
                           ties and consumer groups. These utilities accounted for about $195 mil-
                           lion, or 14 percent, of the rate relief benefits received from the exchange
                           program.


                           As a result of our discussions with Bonneville staff, Bonneville officials
Bonneville Plans to        agreed that reviews of benefit pass-throughs should be performed. They
Review Benefit Pass-       drafted steps (dated May 3, 1989) for reviewing the utilities’ procedures
Throughs v                 and controls over the receipt and disbursement of rate relief benefits.
                           The draft procedures stated that pass-through reviews would be per-
                           formed at all participating utilities once every 2 to 5 years.



                           Page 36                        GAO/RCED-90-34 Bonneville’s Residential Exchange Program
                      Chapter 4
                      Current Eff-orta Are Inadequate to JSnsure
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                      Belief Benefits




                      However, our review of these draft procedures showed that additional
                      steps are needed to ensure that the reviews are complete. The draft pro-
                      cedures did not include (1) steps for determining that the benefits are
                      actually being passed through to residential and small farm customers,
                      (2) a process for ensuring timely pass-through of benefits, and (3) coor-
                      dination with the state utility regulatory commissions to ensure an
                      exchange of the results of pass-through reviews between Bonneville and
                      the commissions.


                      Bonneville cannot now assure the Congress that utilities participating in
Conclusions           the exchange program are passing the appropriate amounts of rate
                      relief benefits through to their residential and small farm customers as
                      intended by the Northwest Power Act. While state utility commissions
                      have reviewed whether some investor-owned utilities have passed
                      through benefits, Bonneville has not determined whether the extent of
                      these reviews is sufficient. Also, public utilities are not being reviewed.
                      Bonneville needs to correct these conditions by implementing a review
  ,                   program.


                      We recommend that the Administrator, Bonneville, initiate benefit pass-
Recommendations       through reviews of utilities that were and are now participants of the
                      exchange program,’ Bonneville should include in its review procedures
                      for (1) testing customer billings to ensure that the appropriate amounts
                      of benefits are passed through to customers, (2) ensuring the timely
                      pass-through of these benefits, and (3) coordinating Bonneville’s
                      reviews with those performed by state utility regulatory commissions.
                      Bonneville could consider placing some reliance on state commissions’
                      reviews. Before doing so, however, Bonneville should determine the ade-
                      quacy of the commissions’ reviews&In addition, we recommend that
                      Bonneville inform the two public utilities-for    which it conducted pilot
                      benefit pass-through reviews- of the review results and follow up to
                      ensure that issues raised in the reviews are resolved.


                      The Department of Energy (DOE), in commenting on a draft of our report
Agency Comments and   (see app. III), stated that it agreed with the thrust of the report that the
GAO Evaluation        pass-through of benefits to utilities’ residential and small farm custom-
                      ers should be monitored. DOEfurther stated that Bonneville started
          b           implementing benefit pass-through reviews in September 1989 that will
                      help ensure the timely and accurate pass-through of benefits to eligible
                      customers.


                      Page 37                        GAO/RCED-!JO-34 Bonneville’s Residential Exchange Program
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    Chapter 4
    Current Efforts Are Inadequate to Ensure
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    Relief Benefits




    DOE provided the following specific information about Bonneville’s
    plans:

. Bonneville has added a benefit pass-through component to its load
  review procedures;
. Utilities that are current program participants, as well as utilities whose
  contracts were purchased or mutually terminated, will be considered for
  review;
l Bonneville will work with utility commissions and elected governing
  bodies to address any apparent deficiencies; and
. Bonneville will take action to ensure that problems identified in its 1987
  reviews of two public utilities are resolved.

    We believe that the reviews Bonneville has initiated are appropriate
    steps that appear to be consistent with our recommendations. If fully
    implemented, these reviews should provide information Bonneville
    needs to assess whether benefit pass-throughs are taking place in a
    timely and appropriate manner.

    The Department expressed concern that our recommendation appeared
    to require that Bonneville perform detailed reviews of utilities’ retail
    rates and cost of service studies because, according to the Department,
    that is the only way to ensure that appropriate benefits are passed
    through to qualified customers. The Department further stated that
    efforts recently undertaken by Bonneville are effective and appropriate,
    whereas extensive retail rate reviews would not be cost-effective and
    would be inconsistent with, and unnecessarily duplicative of, existing
    regulatory oversight.

    We do not envision the need for Bonneville to perform detailed utility
    rate reviews of utilities participating in the program. Our recommenda-
    tion is directed at establishing a process by which Bonneville can deter-
    mine whether benefit pass-throughs meet the requirements of the
    Northwest Power Act. Our recommendation is not intended to specify
    precisely how Bonneville should make its reviews. To the extent bene-
    fits provided to participating utilities are separately accounted for by
    those utilities, we do not envision a major review effort by Bonneville to
    determine that a timely pass-through occurs. On the other hand, if bene-
    fits are treated by participating utilities as one source of revenue among
    other sources, Bonneville’s review efforts may need to be more exten-
    sive to make its determination. In either case, the results of Bonneville’s
    review efforts should provide a sufficient basis for Bonneville to deter-
    mine whether appropriate pass-throughs are occurring.


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Current Efforts A& Inadequate to Ensure
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Page 39                          GAO/WED-99-34 Bonneville’s Residential Fkchauge Program
Apgwndix I

Ikikities, State Regulatory Agencies, and
OkganizationsContacted by GAO

                Utilities                                                    Location
                Central Electric Cooperative, Inc.
                _---                                                         Redmond, OR
                Clark Countv Public Utilitv District -                       Vancouver, WA
                Consumers Power, Inc.                                        Philomath, OR
                Idaho Power
                -._--   ---    Company                                       Boise, ID
                Lewis
                .-..---
                        CountvL-
                                 Public UtilitvI District                    Chehalis. WA
                Pacific Power and Liaht Companv                              Portland, OR
                Portland General Electric Company                            Portland, OR
                Puget Sound Power and Light Company                          Bellevue, WA
                Snohomish Countv Public Utilitv District                     Everett. WA
                Utah Power and Liqht Company                                 Salt Lake City, UT
                Washington Water and Power Company                           Spokane, WA
                State Reaulatorv Aaencies
                Idaho Public Utilities Commission                            Boise, ID
                Oregon Public Utility Commission                             Salem, OR
                Washington Utilities and Transportation     Commission       Olympia, WA
                Oraanizations
                Direct Service Industries, Inc.                              Portland, OR
                Evergreen Legal Services                                     Seattle, WA
                Idaho Citizens
                             ~--. Network                                    Boise, ID
                Idaho Leaal Aid                                              Couer d’Alene, ID
                League
                --____ of Publicly Owned Electric Utilities of Oregon        Salem, OR
                Oregon
                 -..._-    Farm Bureau Federation                            Salem, OR
                Oreaon Public Utilitv District Association                   Salem. OR
                Oreoon Rural Electric Cooperative Association                Salem, OR
                Pacific
                  _..-._- Northwest
                _..        ._.---      Generating Company                    Portland, OR
                Pacific Northwest
                                __-.._ Power Planning Council                Portland, OR
                Pacific Northwest Utilities Conference Committee             Portland. OR
                Public Power Council                                         Portland, OR
                Washington Industrial Customers for Fair Utility Rates       Portland, OR
                Washington State Assistant Attorney General, Office of       Seattle, WA
                    Public Involvement




                Page 40                          GAO/RCED-90-34 Bonneville’s Residential Exchange Program
Acti e Participants   Benton Rural Electric Association
                      Blachly-Lane County Coop
                      Central Electric Coop Inc.
                      Clearwater Power Company
                      Consumers Power Inc.
                      Coos-Curry Electric Coop Inc.
                      Douglas Electric Coop Inc.
                      Fall River Rural Electric Coop Inc.
                      Harney Electric Coop Inc.
                      City of Idaho Falls
                      Lewis County Public Utility District
    /                 Lincoln Electric Coop
                      Lost River Electric Coop Inc.
                      Lower Valley Power and Light Company
                      Montana Power Company
                      Oregon Trail Electric Consumer’s Coop
                        (assignment from CP National)
                      Pacific Power and Light Company
                      Portland General Electric Company
                      Puget Sound Power and Light Company
                      Raft River Rural Electric Association
                      Umatilla Electric Coop Association
                      Utah Power and Light Company


Sus+nsions            Ferry County Public Utility District No. 1
    /
                      Idaho Power Company
                      Peninsula Light Company Inc.
                      Springfield Utility Board
                      Washington Water Power Company


Terminations          Montana Light and Power Company
                      City of Soda Springs


Buy-Outs              Clark County Public Utility District No. 1
                      Snohomish County Public Utility District No. 1
                      Clallam County Public Utility District No. 1
                      Flathead Electric Coop Inc.
               Y      Glacier Electric Coop Inc.
                      Grays Harbor County Public Utility District No. 1
                      Klickitat County Public Utility District No. 1


                      Page 41                  GAO/RCED-SO-84
                                                          Bonneville’sResidentialExchangeFrom
    Appendix II
    Utilities That Have Participated in the
    Exchange Program




-
    Orcas Power and Light Company
    Prairie Power Coop Inc.
    Salmon River Electric Coop
    Vigilante Electric Coop Inc.




    Page 42                          GAO/RCED-90-34 Bonneville’s Residential Exchange Program
      ,
      j’

Apper$ix   III


&partment of Ehergy Comments

                                                Department of Energy
                                                    Weehington, DC 20565

                                                     October   23, 1989




                     Mr. Keith 0. Fultz
                     Director,  Energy Issues
                     Resources, Community, and
                        Economic Development Dlvlslon
                     U.S. General Accounting Office
                     Washlngton, DC 20548
                     Dear Mr. Fultz:

                     The Department of Energy (DOE) appreciates      the opportunlty to review and
                     comment on the General Accounting Office (GAO) draft report entitled      Federal
                                              vllle's ResJ&ntlal   Fx&ange Program (GAO/RCED-90-34).
                     Minor editorial  changes are enclosed.      DOE hopes that the comments in thls
                     letter  and the enclosure wlll asslst GAO in their preparation     of the flnal
                     report.

                     The significant  dollar amounts associated with thfs program required 8PA to
                     develop and maintain extensive   Internal   controls and management systems to
                     ensure that the exchange beneflt    payments made by 8PA to public and
                     investor-owned  utllltles (IOU) are proper and correct.

                     We are concerned about GAO's recommendation regarding EPA's role In revlewing
                     the benefits     passed through to residential          and small farm customers by
                     exchanging utllltles.          Whlle we agree with the thrust of the report that
                     benefit    pass-through     should be monItored, DOE does not concur with GAO's
                     speclflc    recommendations to the extent that we understand them to require that
                     BPA perform extensive         retall     rate reviews.    The only way to ensure that the
                     appropriate     amounts of benefits          are passed through to quallfled        customers Is
                     to analyze the utlllties'            cost of service studies and retail         rates.    We
                     believe that the changes that BPA has recently               Implemented to revlew benefit
                     pass-through     are effective        and appropriate.     DOE believes    that GAO's
                     reconneendatlons would not be cost-effective              and would be inconsistent        with,
                     and unnecessarily       duplicative       of, existlng  regulatory    oversight     of benefit
                     pass-through.
                     As noted In GAO's draft report,          86 percent of total exchange program benefits
                     have been paid to IOUs. IOUs are regulated             by State public utility
                     commissions (PUCs) which have overslght           responsibility  for retall   rates.    The
                     PUCs have ordered corrective        actions,    when necessary, to ensure exchanging
                     IOUs in their respective      jurlsdlctlons      are passing through appropriate      benefit
                     amounts to eligible   utlllty      customers.
                 Y




                        Page 43                           GAO/RCED-90-34 Ronnetie’s       Residential Exchange Program
       Appendix III
       Department of Energy Commentn




                                                                                              2


The public utllitles     partlclpatlng   in the Resldentlal     Exchange Program have
received 14 percent of total exchange beneflts.           While not generally     regulated
by State PUCs, these public utllltles       are nonprofit    organizations    regulated     by
elected officials     who represent the interests    of, and are accountable       to, the
utlllties'   ratepayers.     Residential  and small farm customers represent         the
largest constituency     of these elected officials.

GAO concludes that, given the signlflcant            dollar amounts paid through the
program (approximately       $1.4 bllllon),    further      action must be taken by BPA to
avoid potential      problems in passlng beneflts         through to eliglble       ratepayers,
even though GAO's audit ldentlfled          no particular       utillty  discrepancies     or
lmproprletles      in processing exchange benefits.           GAO's flndings     dld include a
specific    reference to the two pilot beneflt          pass-through     reviews lnltiated      by
BPA staff in 1987, and recommended that EPA take followup action to resolve
outstanding     Items.

BPA management concluded from these pllot reviews that apparent over and under
payments were attrlbutable      to either startup problems, involved a question of
timing of beneflts,     or were not materially   slgnlflcant      in regard to total
benefits   paid.    Based on these conclusions,   and the fact that there was no
statutory   requirement for BPA audlts of beneflt        pass-through,    BPA decided not
to undertake a formal, ongolng program to audit the pass-through             of exchange
benefits,   and that no followup was necessary at that time on the two pllot
exercises.
BPA does share, and has responded to, GAO's concerns by developing              and
implementlng a benefit     pass-through  component to its existing       load review
procedures.   BPA worked closely with GAO staff during their audlt to assure
that these reviews would be consistent       with GAO's objectives.       We believe this
enhancement, coupled wlth the existing       level of regulatory     oversight,     provides
reasonable assurance that approprlate      benefits   are belng received.        This
approach 1s cost-effective      and documents the utlllty    pass-through      systems and
procedures.   BPA will share this Information,      and work wlth utility
commlsslons and elected governing bodies to address any apparent
deflclencles.
In addltlon,      to assure the apparent problems wlth the results of the pilot
revlews have been resolved,       BPA will review the two subject utilities'     beneflt
pass-through      systems.   Thls will be undertaken as part of BPA's load revlew
program which 1s conducted on a j-year cycle.        The methodology for selecting
utllities     for revlew will include consideration   of those utllltles     whose
contracts     have been purchased (bought out) by BPA or mutually terminated.        BPA
has lnltlated      these reviews in September 1989.




       Page 44                            GAO/RCED-90-34 Bonneville’s Residential Exchange Program
-   -I-




    t
                                                                                                3


          In summary, DOE shares GAO's concern that appropriate          and effective   controls
          must exist to ensure the timely and appropriate        pass-through    of beneftts    to
          ellglble   resldentlal   and small farm customers.     To that end, BPA wlll continue
          to exercise    Its contractual  rights in a cost-effective      manner consistent    with
          the intent of Congress and BPA's statutory      obligations.
                                                             Sincerely,




                                                    Fov; 6 nna      R. Fltzpatrlck
                                                            Assistant   Secretary
                                                            Management and Admlnlstratlon


          Enclosure




                 Page 45                         GAOAUXDWB4         Bonnevllle’r Residenti@ lSx+ange Program
Aipendix IV                                                                                            .i-
l!@ajorContributors to This Report


                          John W. Sprague, Associate Director
                          Paul 0. Grace, Assistant Director
                          Charles M. Adams, Assistant Director




                          Laurence L. Feltz, Regional Assignment Manager
Seattle Regional Office   Robert B. Arthur, Evaluator-in-Charge
                          Janet L. George, Evaluator




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