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HomeMy WebLinkAboutAgenda Packet 03/23/2011• • I. Call To Order II. Roll Call IV. Adjournment City Council Special Meeting/Utility Advisory Committee City Hall Council Chambers Port Angeles, WA 98362 March 23, 2011 @ 5:00 PM N :\uaclfina11032311 AGENDA III. Information Only Items: A. Bonneville Power Administration Residential Exchange Program Settlement Agreement Workshop • • • GELES W A S H I N G T O N , U. S. A Utility Advisory Committee Memo March 23, 2011 Date: To: City Council and the Utility Advisory Committee From: Larry Dunbar, Deputy Director of Power Systems Subject: Bonneville Power Administration Residential Exchange Program Settlement Agreement Workshop Summary: A settlement agreement has been offered for City Council consideration regarding the Bonneville Power Administration's Residential Exchange Program. A workshop will be held this evening with presentations by the Western Public Agencies Group and the Bonneville Power Administration, Recommendation: For information only, no action requested. Background /Analysis: The Bonneville Power Administration (BPA) Residential Exchange Program (REP) was established by Congress under the Pacific Northwest Electric Power Planning and Conservation Act of 1980, which was intended to provide rate relief to residential and small - farm customers served by higher -cost electric utilities. Its roots go back to the 1970s . when electricity rates between public and private utilities began to diverge sharply. Public preference to the low -cost power from the federally based generation system was at the heart of the debate. The City is one of numerous electric utilities that is a stakeholder in the program, since it shares the cost of providing the benefits to higher -cost utilities that are eligible to participate in the program. The settlement agreement is a very complicated and significant issue for the City's Electric Utility and will affect future wholesale power costs for the next 17 years. A workshop will be held this evening and the presenters include Mr. Terry Mundorf with the Western Public Agencies Group and Mr. Chuck Foreman with the Bonneville Power Administration. The presentations will include background information on the program and a summary of the advantages and disadvantages of the proposed settlement agreement. A factsheet titled "A history of BPA's Residential Exchange Program" is attached for additional information. The deadline set by the BPA to accept or reject the settlement agreement is April 15, 2011. A special Utility Advisory Committee meeting has been scheduled on March 28, 2011 to consider a recommendation to City Council on the settlement agreement. The City Council will be asked to either accept or reject the settlement agreement at its April 5, 2011 regular meeting. N: \UAC \Final\BPA Residential Exchange Program Settlement Agreement Workshop.docx • B O N N E V I L L E P o W E A h'story of BPA's Residential Exchange Program n , a)' 3, 2007 :.. he_:U S .:N .... � rrtt :: °areatatCoust o Iwo lawsuits ti�rat have si A:. erns �u ..:. � ..........:.. -.::. _ :::::: . :.. pp led .;on �ti�:, :: , . ...:.... gn cant implications for the_ Bonneville Power Administra -: iorz. s Residentir l:Excha t l t the;` ou t: s decisi n and the hei htened .........:. interest.:tt.has:,created ovver:t ae R ' ' B A. has pre- ar�ed_this::histor .::and back r=ound o�the: �'... P g f 'the •utilities with 'preferience. r i hts. At the:same':ti Congress intended to'lirnit the financial exposure o public utilities to . certain costs occurring under the Northwest Power Act. i`cr=a tin: Section ii . r:e s :directed that t ie::. ; �enefrts of tI 7 pede is Ri er 'otiver s tmt;: FCRPS would share with those Jr rt1w:.:... . est utrlrtre�, � hose ar crage :;sy -stern cast . or {` average cost of r=es ?u s) as = Iii ...h. t°c lalrve appli 1'r tcrr rty: irrrr xchange_ r"at ::..:::: r r n'; e lie *hits_ PP4. -provides th ough_ the ppg a i must _be passed on to each utility residential: a nd small= arrrri cirslomners and;cannot:be ° used .r :any;: f f o 3.' other : urpose,. s i c p p. ih is pr ies. !r:`t stthzdiz� otlie, aspects f a speco utility „s b usiness. h as es t ahl i. shed "ir�i:;5e�cti :.:::.:... �; ., - c�n. 5 c} n Pacific Northwest :Electric. Power Planning,and Act Conser ation:'of x980 _ knoi n eeppiponi . ' . a ' � Iyas Acts The goal.of the pro been t o pr ovide rate: relie to :Northwest residentia and small-farm m cost omers: ser-ved:.by high-Cost :rnve,stor• owned :utilities, :as:well:as ".tco.residential and srriall : farm customers Serve b y „high -cos t F rom its start, the Residential Exchange Program (REP) has been a source of nearly continuous controversy. Its roots go back to the 1970s when electricity rates between public and private utilities began to diverge sharply. Public preference was at the heart of the debate between public and private interests. Historically, private and public utility rates had been comparable. This changed after 1973 when, faced with likely energy shortages, BPA halted firm power sales to the region's investor -owned utilities. The rates of some IOUs then began to rise sharply. Oregon drafts DRPA legislation At that point, Oregon's Public Utility Commissioner awarded a 90 -day contract "to find a legal way to overturn ... the preference clause, thus qualifying Oregon's private utility customers for the same A D M M l N 1ST R_ A TI O N 3 -' ° ,�`.::. , . �.-_._ ,. x- ..� ..r Y + �.. � . ” &.� �.+n`' ;i:g• "' „•.3 .':. .�.M."..xiieti�m .'nRa.:al'ir m .r...,, °F'4.: °•c..,..,. .. am.,,. June 2007 electricity rates that public power customers enjoy." When it appeared preference could not be overturned legally, the state turned to an innovative solution. In 1977, the Oregon state legislature approved form- ing the entire state into a Domestic and Rural Power Authority (DRPA), which was to lay claim as a publicly owned utility to federal hydropower to benefit all of the state's citizens. DRPA was to be- come effective March 1, 1979, if no federal energy bill addressing the problem had been passed. The deadline later elapsed because, by that time, it appeared national legislation was imminent. Section 4 of the Bonneville Project Act of 1937 grants public bodies and cooperatives priority access to federal power. This is known as the preference clause. , In 1977, the Pacific Northwest Utilities Conference Committee (PNUCC), which includes both public and private utilities, presented draft legislation "for discussion purposes" to the region's congressional delegation to address multiple issues precipitated by growing concern about power shortages. Fearing their right to first call on federal power would be curbed, Snohomish PUD and Seattle City Light broke ranks and opposed the draft. Snohomish introduced rival legislation aimed at protecting public preference. Public preference challenged As various proposals emerged, the fight over prefer- ence heated up. Washington Governor Dixie Lee Ray dubbed it "a regional civil war." Idaho threatened to follow Oregon's lead to create a domestic and rural power authority. The executive director of the Washington Public Utility District Association declared DRPA "nothing but a facade to protect the profits of private power companies serving his [Oregon governor's] state." In February 1978, the governors of Oregon and Idaho declared BPA "must honor the commitments in acts of Congress that domestic and rural customers have first call on energy' from the Federal dams that are even more basic than those of what BPA calls prefer- ence customers." BPA Administrator Sterling Munro strongly defended preference. His view was that the way to get cheap federal power to the three "have -not " states was to increase the size of the resource pie, rather than do away with preference. Oregon Congressman Robert Duncan responded, "If the preference clause isn't changed, then we'll bust the sonofabitch in a lawsuit. The people of the Northwest, all of the people of the Northwest, are entitled to similar energy rates, and they should share the burden of those costs." By the late 1970s, a number of proposals were coalescing into what eventually would culminate in the Northwest Power Act. Any legislation would have to pass through the Senate Energy and Natural Resources Committee, headed by Senator Henry "Scoop" Jackson. Jackson, who was from Washington 2 state, was an advocate of public power and not overly' sympathetic to the public - private power rate disparity arguments. Eventually, however, he realized that, if the legislation was to have any chance, it had to deal with the issue. Otherwise, the principle of preference would be at risk. DSI "subsidy" paves way for exchange A breakthrough came when the direct - service indus- tries, facing expiration of their contracts, agreed to pay significantly higher rates for a limited period in return for new 20 -year contracts. At the time "assured supply" was more important to them than price. Under this arrangement, public power would continue to get first call on federal power, but a "subsidy" from the DSIs (the higher rates the industries were willing to pay) would offset and lower IOU rates. This "money deal," which only covered five years, paved the way for an "exchange clause" in the new legislation. The exchange provision allowed BPA to offer IOUs and certain public power entities that owned higher - cost generating facilities a quantity of power at BPA's standard rates equivalent to the total needs of those utilities' residential and small -farm customers. In exchange, BPA would accept from these utilities an equal quantity of power at their average system costs. No power needed to change hands; in reality, it was primarily a monetary paper transaction. 'Under the exchange, the utilities were required to pass on the benefits to their residential and small -farm customers in the form of lower rates. Section 7(c)(1) of the Act addressed the DSI provi- sion saying that DSI rates shall be established for the period prior to July 1, 1985, at a level sufficient to recover the costs of resources required to serve the DSIs' loads and "the net costs incurred by the Admin- istrator pursuant to Section 5(c) of this Act." Section 5(c)(1) stipulates the exchange of power with eligible utilities requesting such an exchange. 2 The "have -not states" refers to Oregon, Idaho and western Montana, which, unlike Washington, are served primarily by investor -owned utilities that do not have preference to BPA power. P;� • • Not all the DSIs were happy with the arrangement. In August 1978, Reynolds Metals objected, saying the draft bill language placed too much of the burden of exchange costs on the DS1s. At the time, the alumi- num industry had a great deal of leverage as it was providing enormous benefits to the region in terms of wages, freight services and state and local taxes. The industry had provided about 30 percent of BPA's revenues. NW Power Act changes regional landscape After several stops and starts, the Northwest Power. Act finally emerged and was signed into law in December 1980. The Act's exchange provision extended benefits of the federal system "at cost" to 2.5 million residential and small -farm consumers of IOUs and a handful of consumer -owned utilities that had relatively high ASCs. To win public power support while the Northwest Power Act was being developed, or at least to counter opposition, an amendment had been added in the form of a rate test to provide some cost protection to the preference customers' rates. This is the 7(b)(2) test, which compares costs developed pursuant to the Act with costs reflecting five specified assumptions listed in Section 7(b)(2). In very general terms, it was designed to ensure public customers would pay .BPA no more than if their rates had been developed based on the five assumptions. BPA is required to formulate a hypothetical case to assess what costs would have been by using the five assumptions in Section 7(b)(2). If the rate test shows preference customers would have to pay more for firm power under actual rates than under the hypo- thetical case, the Administrator must lower the rates of public utilities to eliminate the excess costs and shift the burden to BPA's other customers. The Act contains five assumptions under Section 7(b)(2) to be used in determining what the hypothetical world would look like. The language in Section 7(b)(2) is complex and has been subject to differing interpretations. Former BPA 3 he 7(b)(2) rate tes The Northwest Power Act provides, .. ... : through Section 7(b)(2). a= complex formula (rate test g . .shields . reference : :customs that, ... In enera; terms .::::.:::.:.::: p : :. : :.;... :. :... : :. :, :.... : : :.. ers from certain i mnpacts .o f the Northwest Power::. Act. Basically,: this rate test is desi c designed . to ensure that the cost of the Residential :ExchangePro- : gram and other factors;, when considered togetl.= er : :do not raise the rates of :pullic utilities ities beyon . what' - they would have been absent the Northwest P ower. Act.: It: is 7(b)(2) " triggers, "then .aril am aun of.cvsts :.ts ,...:: r ate :.....:.:.... .. _......: :.allocated to es other than :the a Priority Firm) p©\\ver rate which is :tl e rate t.:... that ; :. a ..... ; t applies to preference : customers requirements loads. nsequeritlys RPA de :elups a :..... xcha.ng . ge. .,:.. .. .o A�' Ex rate..far REP <loads.that :includes :costs°fron :an Section 7(b)(2) :ifigg076. ount If:there is:a �g t ri e , the PF: ::Exchan .. e: r ate is higher "than ;the: PF : Preference rate, and the difference between the PF : :Excl�iari e' rat : an d: t iiti }� :s =ASC ..emu ... _ : - .- .... :.- _,: ...... p y y residential:.and siria armoa 'etel-lxiineS .the':RE P `benefits °for a 3. utilitj!: Section 7(b)(2) includes five assumptions the Administrator uses to develop a set of costs set of costs reflecting the is compared °..:... _ : with a . . : :.. - .. N orthwest fowle A ct This comparison is use i l setting prefere nce: °rates. :.See box on the assumptions. Administrator Peter Johnson said of this section, " ... l know how Alice felt when she stepped through the mirror. We seem to have entered an unreal world. The assumptions direct BPA to hypothesize power supply arrangements between itself and its customers — arrangements that are quite different from reality. The Act bounces us back and forth between what might have been had the Act not been passed and what is." I. BPA is not engaging in an exchange of-power: with IOUs and - consumer- owned utilities to provide rate relief to. those utilities' residential and small- arm customers. BPA'_ : public 2: p bloc utility customers would serve certain � f the direct-service .... :firm o ct ser�rice .indusfri�s with power. The industries that would be served by the public utilities:. are (a) those industries served bpi BPA,;:: and ( ...- ...:..:. .. b) those that are situated within or adjacent to the service territories of the public customers. ::: ..:...::.::..:.. 3. The preference customers' load the DSI loads mentioned in the second ;assumption, would be served first with Federal Base System rower.. t ..... . pre .erence c :...... ustomers, require more power t e to serve their; loads:, than federal .:reso ces urces can;: -. supply, the :additional power .to m cat these needs w.ould:be :acquired :from certain ° s ources .:; This additional :powerr'would be provided in a' least -' cost -firs t manner: 5..., ere. are no dollar savju s:to`ti e re.feret�ce:._:::.. • CUSto1mer-S- . .... iced financin costs as a res u o : re � to BPA.bac-king:oif resource acquisitions, and no reserve benefits , ''due to :the Administrator's actions • under :theAct: accrue _to'them.. Sectia i 7(b)(2) includes five assumptions � . ��� i : - ... . � the Administrator is to observe in rlFe .settl37 preference setting fere P rates. d wision war, eat etas.: These : assum trans en w l n �r . the: Northwest °Power `:. ::coiitrasts:whh. the or d u de ..... - ... aver: " : � Act.,= In:othe . r, words the.Acin�i ; ,.. :must assume. that this .hypothetical :worl : In 1983, BPA sought to clarify Section 7(b)(2) and, after an initial round of comments, published a "Notice of Proposed Legal Interpretation of Section 7(b)(2)." After adopting the legal interpretation, BPA developed a Section 7(b)(2) Implementation Method- ology. BPA published the Implementation Methodol- ogy, which reflected its legal interpretation of 7(b)(2), in the Federal Register in March 1984. Subsequently, BPA developed computer models,' in consultation with customers, for the rate test. The 7(b)(2) rate test has triggered several times. in BPA's 1996 . and 2002 power rate cases, the upward pressure on the PF Exchange rate was significantly more than in previous years. In the WP -96 and WP -02 rate cases, due to high 7(b)(2) triggers, the PF Exchange rate was 8.3 mills per kilowatt -hour and 13.7 mills per kilowatt -hour higher, respectively, than the PF Preference rates. ASC Methodology established BPA established its initial Average System Cost Methodology in 1981, issuing a Record of Decision on Aug. 26 of that year and filing the methodology with the Federal Energy Regulatory Commission 4 the following day. FERC granted interim approval effective Oct. 1, 1981, and final approval of the ASC Methodology on Oct. 6, 1983 (retroactive to 1981). At its inception, the REP was implemented through Residential Purchase and Sale Agreements (RPSA) first executed in 1981. These contracts established exchange benefits only through July 1, 2001. Between 1981 and BPA's Subscription Strategy proposal, all of the RPSAs held by the 'utilities that had received REP benefits had been settled, except for one, which was in "deemer" status. BPA's 1981 RPSAs did not require a customer to own generation or transmission facilities to qualify for an RPSA. Utilities were able to include wholesale purchase power expenses and wheeling contracts with third parties as costs to establish an ASC. Distribution costs were excluded from the ASC calculation. 3 BPA used a computer -based model known as the Supply Pricing Model (SPM). The model simulated the rate - setting process. 4 BPAs 1981 RPSAs included a provision described as a deemer account. Deemer referred to a status wherein a utility sets its ASC equal to BPA's PF Exchange rate and does not receive positive monetary benefits but accrues a negative balance that must be worked off before resuming receipt of additional monetary benefits. u,'o:.R.m`Y . ". � .:. �; • • �f. �a.i . � �.h�.. K �"e�- ..'ti,�a.. +�' . R 'h:: ' . - vFerage .System . Cos :An: ASC` represents the average cost::o f e s for resourc= �;' utility.: An. ASCcannot... .. . >.ven: an:. by n clude . additional resource:.. costs :to serve:new:.:: ..- ..... large ule .loads regionalload :or :the costs .of a, re .pI Or`t{7: c.ommer cial operation. the : calculation number =of details; but: enerally, :;paver costs and :Certain transmission c' sts are'Currentl:y ineluded the ASC altho u h . is> ri bu g �icn costs ::. are excluded. :Custoni .. . - . ers : with.market:_purGhases :: or those who own.their own generation :are most likefy `haie:ASCs:that.are- higher :than BPA's g . ..... F :Eschan e:;rate� Since man y - af the::Nort ltd: est s ativestor- ..:....... oWnpd ut i lti;es caal o re p o....11y th. .. i �Yhav�;had Iii; _ d larits laistoracai - s: l an RPA P ::Exchange BPA's 1981 RPSAs included a number of contractual terms and conditions describing BPA's right to purchase power in lieu' of the utility's resources priced at its ASC. These reflected the electric power industry of the period and assumed that a utility would be developing its own resources or entering long -term purchase power contracts to serve its loads. BPA revises ASC Methodology From the start, things did not go smoothly. The DSIs, who were bearing the cost of the exchange through 1985, complained that the IOUs were including inappropriate costs and overhead in their average system costs. in 1983, Northwest Aluminum News wrote, "The main problem --- and a monumental one — is that some participating utilities are using the exchange to recover costs other than `resource' costs ... Some of the questionable costs include items such as taxes, overhead, and expenses related to uncompleted or discontinued power plant projects." The IOUs denied the costs were improper. At the same time, public utilities that weren't participating in the exchange complained that attempts to include inappropriate costs in the ASC calculation were driv- ing up the costs of power they were buying from BPA. a ....i°E?.,.Lf'eve :?1 ±_§.' �`LLL .. - ,.4y.;'5. �.�9'.' �< S� rm�- i §�,.. r�� ° �r. W`✓*"^�' a ' � ��i "nS "� v .. Soi..,Y" Qr'. ..: k: 7=ke. `. ,. ".�,� 5 Beginning in 1983, the DSIs and public agency customers sought a change in the ASC Methodology. They had a number of concerns, including perceived abuses to the system related to the attempted inclu- sion of terminated plant costs. BPA had previously removed terminated plant costs from an ASC filing made by an exchanging utility. BPA Administrator Peter Johnson agreed that the exchange was "not working as Congress intended." A. B.PA issue alert described the existing methodology as "unworkable, expensive, time consuming, and difficult to administer." Consequently, BPA staff recommended tighter procedures for computing the ASC. Section 5(c) of the Northwest Power A.ct provides that the Administrator shall develop an ASC Method- ology in consultation with the Northwest Power and Conservation Council, the Administrator's customers and appropriate state regulatory bodies. BPA initiated a consultation process open to the public to begin revising its ASC Methodology to address multiple issues. These issues included the source data for the method- ology, determination of whether transmission costs should be treated as resource costs, subsidization of construction work in progress, treatment of equity return, treatment of income taxes, determination of generating resources that could be included in com- puting ASC, treatment of affiliated fuel costs, includ- able conservation costs and functionalization between subsidized and nonsubsidized accounts. A Federal Register notice on the consultation process was issued in October 1983. 5 In the context of the REP. "in lieu" comes up when the market price of power (or the price of other resources) is less than the exchanging utility's average system cost. In that case, the Northwest Power Act allows BPA to purchase power "in lieu" of exchanging at the utility's ASC. BPA would buy power at the market or resource rate and sell to the exchanging utility at the PF Exchange rate, thus reducing the level of benefits to the difference between the market price and PF Exchange rate. The utility would then have to find something else to do with the high -cost resources that have been "in lieued." Or, instead of being stuck with unwanted power, it could deem its ASC to be equal to the cost of the resource BPA would have acquired and sold to the utility. Either way, BPA saves on a unit basis the difference between the utility's ASC and the lower in-lieu resource cost. • • • After taking regional comment, BPA published a proposal on a revised ASC Methodology in February 1984 and, after a public comment period, issued a record of decision on its revised ASC Methodology in June 1984. In that year, nine IOUs and 16 public utilities were participating in the exchange. IOUs challenge ASC revisions Although the IOUs challenged the ASC Methodology change in the FERC proceeding, FERC approved the revised methodology. A number of IOUs challenged the change in the Ninth Circuit Court of Appeals, but the Court upheld BPA's decision (PacifCorp v. Fed Energy Regulatory Comm 'n, 759 F.2d 816 a9th Cir° 1986) in 1986. While the Court's opinion upheld the revised ASC Methodology, it held that it did not "sanction any permanent implementation of these exclusions." Id. at 823. Since then, the IOUs have argued that the Court upheld the 1984 ASC Method- ology as a "temporary" change to address terminated plant cost issues and did not intend a permanent change. The ASC Methodology provides for future changes. Under the ASC Methodology, the Administrator may initiate a consultation process to determine whether to change the existing ASC Methodology at his discre- tion or upon request from three - quarters of utilities with Residential Exchange contracts, three - quarters of BPA's preference customers or three-quarters of BPA's DSIs (which was relevant at the time). Arguments continued into the 1990s as IOUs disputed BPA's calculation of the ASCs and other determina- tions related to the REP. Throughout the decade the . disputes were essentially continuous. Key elements of the disputes included benefits under the RPSAs — not enough in the IOUs' opinions and too much accord - ing to the publics and DSIs — as well as BPA's ASC Methodology, utilities' ASCs, deemer balances, "in lieu" transactions and BPA's PF Exchange rate. Region conducts Comprehensive Review The advent of deregulation of the electric power industry in the 1990s changed the industry dramati- 6 cally. Utilities no longer solely constructed generation or made long -term purchases. Increasingly, they purchased power on the wholesale market from independent producers, wholesale marketing entities and others, and some purchases were short -term. BPA began to face tough competitive challenges, and some questioned the agency's ability to fit into the newly deregulated world. In the mid- 1990s, the Department of Energy, BPA and the governors of the four Northwest states al] called for a Comprehensive Review of BPA's future role in the Northwest. One of the things that came out of the Comprehensive Review recommendations was a pro- posed Subscription process that would set parameters for allocating federal system benefits. This was pre- cipitated by the fact that power sales contracts custom- ers had signed with BPA were due to expire in 2001. The Comprehensive Review, which published a final report in December 1996, took the opposite stance of an earlier BPA Administrator, Sterling Munro, who had said the way to spread the benefits of the federal system was to increase the size of the pie. instead, the Comprehensive Review said BPA. should get out of the business of acquiring new resources to meet customers' load growth, except in those cases where the customer would bear the additional costs. The Comprehensive Review Steering Committee encouraged. BPA and other parties in the region to explore a settlement of the REP with the region's IOUs based in part on a sale of power to them rather than the historic practice of monetary payments. Congress helps stabilize exchange By the mid- 1990s, deregulation of the electric utility industry, spiraling fish costs brought by Endangered Species Act filings and reduced hydro supply had pushed BPA rates up. The most important factor, however, was the decrease in market price of power due largely to the entry of independent power produc- ers selling gas -fired generation. As market prices 6 The formal name of the review was the Comprehensive Review of Northwest Energy Systems. ?kxri='°: w« y• P7_; v°,°•; n"':x:'- •_.. ``Y"^a3x 'x,3:fa "�; s:�;:.; .... dropped, some BPA customers removed load from BPA. For the first time, BPA's PF Exchange rate was higher than many of the utilities it was exchanging power with. As public power customers sought to exit contracts, concerns arose over whether BPA would have adequate customers to cover its costs. In August 1995, BPA reported The calculation 7(b)(2) required by the law has forced I3PA to make the most significant reduction in Residential Exchange benefits in 11 years. The proposed reduc- tion could cause up to 45 percent of the region's residential and small -farm customers to see an increase in rates." BPA cited increased competition, especially from natural gas, and said "... for the first time in its history, BPA has lost wholesale customers to private utilities." At the time, BPA had been paying approximately $200 million a year to utilities participating in the REP. BPA's Initial Proposal in its 1996 power rate case indicated a large reduction of benefits under the REP starting in fiscal year 1997. BPA was assuming REP benefits of about $65 million a year. Concern about reduced benefits prompted Congress to take action. The Energy and Water Development Appropriations Act of 1996 specified setting 1997 exchange benefits at the 1996 level of $1.45 million for the one -year period. BPA was to distribute the benefits to each participating utility at the percentage share each received in fiscal year 1995.' In the 1996 Conference Report of the Energy and Water Development Appropriations Act. Congress recognized BPA's authority " ... to implement in lieu transactions, among other actions, which could effect- ively terminate the residential exchange after 2001." The report went on to say, '`Consistent with the regional review, Bonneville and its customers should work together to gradually phase out the residential exchange program by October 1, 2001." BPA, however, could not eliminate implementing the REP without direct action by Congress to change the law. In September 1997, BPA and the Northwest Power and Conservation Council jointly launched a review of BPA's costs. The purpose was to set the stage for a 7 successful Subscription process by providing further cost - cutting recommendations to build customer confidence that BPA was doing all it could to contain costs. Among the recommendations, the Cost Review said the REP made no sense in the current market- place and should be eliminated, although this could not be accomplished without legislative change. In early summer 1996, Puget Sound Energy, Pacific Power and Portland General Electric expressed interest in a possible settlement of REP disputes. BPA entered negotiations with the three IOUs regarding a settlement of such disputes but deferred negotiations after failing to reach agreement on the total dollar settlement. Eventually, BPA settled with Puget in January 1997 and with Pacific in A.pril of that year. BPA settled with PGE, then owned by Enron, a year later in April 1998. These agreements specified that they did not set precedents for how the Residential Exchange would be handled after 2001. Payments to the IOUs for the 1998 -2001 period averaged $59 million annually. As it turned out, 1996 was the last year that exchange benefits were determined through the traditional REP process (i.e., Appendix 1 filings, calculation ofASCs and PF Exchange rates). Congress set the level of exchange benefits for 1997. Following that, benefits were determined through the settlement agreements. Such settlements had been recommended by the Comprehensive Review and Congress. These settle- ments had the advantage of being far less labor intensive. Running the regular REP required about 50 B.PA staff as well as significant numbers of staff from utilities. 7 in February 1995, BPA listed four key pressures driving up its rates: 1) protracted drought; 2) increased salmon costs; 3) generation debt service due to the way refinancing for Wash- ington Public Power Supply System bonds had been structured; and 4) additional generation costs due to short -term purchases and new generation projects including Tenaska, a gas -fired combustion turbine. 8 Puget had a Periodic Rate Adjustment Mechanism (PRAM) to true up rates two years after the end of each rate period. In 1991, BPA and Puget formulated a "true -up" mechanism to permit an accurate determination of Puget's ASC benefits in conjunction with the Washington Utility and Transportation Commission's PRAM. PRAM true -up benefits were to be paid two years after the end of the exchange period. k affi N ac4e• a is 2000 REP Settlements crafted In the late 1990s, the market began to change as natural gas prices began to rise. BPA's Competitive- ness Project, launched in 1993, was paying off in terms of improved financial performance and cus- tomer confidence. BPA's net revenues for 1997 were the best since 1991. In 1998, BPA launched a Sub- scription process generally consistent with recom- mendations from the Comprehensive Review. it was designed to culminate in new 10 -year power sales contracts for the post -2001 period. 8 As part of the Subscription Strategy, BPA proposed to either continue the traditional R.EP through agree- ments known as Residential Purchase and Sale Agree- ments (RASA) or enter into negotiated settlements of REP disputes for the FY 2002 -2011 period. Such settlements were intended to provide benefits for the IOUs in return for their waiver of claims. in the settlements, the benefits reflected possible outcomes of ASC determinations and the effect of Section 7(b)(2) on BPA's PF Exchange rate. ey issues can swing F BPA does a. 7.( b)(2 ) lest it must de !elop a hypothetical: case :to determine. °•wha the costs to :. preference customers :would °ha e been under the ...h s.. T:here::are :in five 7(b)(2 } • a ssui�ptiQia any:arcane issuies :embedded: :in: this :calculation that have a: significant impact .on the potential level o f REP payIneInts One .assurrrnption (see five: assurriptioris 'box)::is :th a t; p i r ou er tha if i- eference customers require more..p �: n federal resource s•:can, supplyBPA, would acquire the :additional : you .er to meet these needs resource: stack::in a least: st rco -.. .. _.. ...... -first sequence. Thhis brings u the uestion 'of what can he inc • p 9 .. ..:.: ::. -.. 13.PA's resource stack.in this hypothetical orl d. An example 1s: the :Mid - Columbia resources no t dedicated .:.to public: a proxim ... p of hyda•apower, wliicl� are-relatively chea . The', publics .that own the MMid-Columbia dams sol `a Significant amount of the o.vver::to the .i ....: . 'Otis by contract. , the . :is in e d to :tne �terpreted:t� tnean. : these: =:..: Mid - Columbia resources_ sol, :to .thelO Is can be included in BP :s.resource stack :.in the ihYpothetidal scenario :BPAs.:resource , costs. would: be: - com.para= : .:..: tive1y low. That: would m ean a s .rrcharge r . likely to'be.added:to the:.P:F :.Exchange rate to ensure::•: the publics aren't paying more than they would have:in circurnutainces reflecting the five assuimptions. This:.would.reduce REP benefits: a ents su stantia ll 1 , however, the that in`the hypothetical case those Mid-Columbia resources dedicated to 1 U load are unavailable to iPA then BPA vould lave to o to the next est-resour in th � P ce s e.:..... 3 .... .. .. resource ,stack : which is much more expensive than the.11ilid- Columbia hydro This makes 7(h)(2) less REP l ike to trigger, and therefore .r�ieaz�s`:hi higher : :..: y gg _... g. benefits for the IOUs. The issue .of w hether; the .:Mid-Columbia .resources could be included in the BPA reource stack came up in 1996 but turned out to be moot since at the time there were enough Federal :;Base System resources o... s to meet public needs without these additional : resources. At the 'time,' °BPA assume th at :onl y y the resources exported could be:: include include in the resource stack. BPA has calculated that this issue alone would create a difference between the - IOUs receiving $30 million annually versus $260 million: annually. There are other sim ilarl . F arcane issues that :.. .: .. can ;..:..:. swing the benefit levels substantially. he issue next arose in :2002. where it :once again: became moot During the VP 2007 power rate case . :.the u w :n li i c ,. . ss e. as• of t aed becauso` partia g.. P men ::1� wv hn. next t : o e er , :the e� settle rie.B:PA. develops • rates' thk is likely to be;ai _issue as::it reniairisari. open question. .'.. . • • The concept of substituting a power sale for the "paper" exchange was discussed extensively during EPA's public involvement process for Subscription and was supported by many public utilities and other interests, as well as IOUs. BPA's proposed settlement of REP issues had a value of $140 million a year to be provided in the form of both a power sale and money. BPA estimated that, under its traditional calculation of REP benefits, the IOUs would receive $48 million annually for the FY 2002 -2006 period. The IOUs were advancing a position under which payments could be $323 million or more annually. The IOUs' agreements, which were for 10 years, provided power at a specified rate — to be determined in a Section 7(i) rate hearing -- and stipulated monetary benefits were to be paid based on a comparison of the REP settlement power rate and at a rate related to market prices. BPA offered the IOUs 1,800 aMW for the FY 2002- 2006 period with 1,000 aMW in the form of power O and the rest as cash payments. BPA also offered to 450,000 - 400,000 350,000 300.000 - 250 - fl3 200,000 - 150,000 - 100,000 • 50,000 -•• —:— r r r r r � r r t � .> > > > , Fiscal Year 9 Through the settlement, BPA. hoped to resolve long- standing REP disputes, eliminate the administrative burden of implementing the REP (i.e., processing average system costs, filings, etc.) and align the interests of the IOUs with BPA and its other custom- ers by providing them benefits comparable to what would have been provided within the range of possible REP outcomes. BPA also hoped to provide longer -term certainty through the settlements. provide 2,200 aMW during the 2007 -2011 period. The intent at the time was that the 2.200 aMW would be entirely physical power deliveries, although whether the benefits would be power, monetary or a mixture was not decided. BPA felt that such power deliveries would be possible due to the expiration of existing long-term surplus sales and public power's interest in diversification due to market conditions. This theory did not anticipate the West Coast energy crisis along with its impact on the value of power, public power's willingness to buy from BPA and the impacts on IOU and BPA rates. IOU and Public Agency Residential Exchange Benefits (2005 $) FYs 2007 through 20 benefits were computed prior to the May 3, 2007. 9th Csvwt decision. pl %`G 0 All IOUs 0 All Publics ® Puget Sound Energy t POE PacifiCorp (UP &L) 0 PacifiCorp (PP&L) North Western Energy 0 Montana Light & Power El Idaho Power 0 CP National Arista Corp. • • • All six IOUs elected to execute 2000 REP Settlement Agreements. The state public utility commissions recommended how the benefits of the settlement would be allocated among the IOUs and asked for an additional 100 aMW for FY 2002-2006. BPA's decision making leading to adoption of these recom- mendations involved extensive public review. The publics go to court Within 90 days of the execution of the 2000 REP Settlement Agreements, a number of Northwest public power entities challenged the agreements in the Ninth Circuit Court of Appeals. Some IOUs filed petitions, but the basis for such petitions was resolved shortly thereafter. The petitions were consolidated into Portland General Electric Co. a Bonneville Power Administration. The public agencies alleged the settlements provided more benefits to the IOUs than the Northwest Power Act allowed. The parties argued that BPA lacked statutory authority to settle disputes under the REP as proposed and that the 2000 REP Settlement Agree- ments must comply with Sections 5(c) and 7(b) of the Northwest Power Act. They said that, by executing the settlements, B.PA did not comply because it failed to implement the ASC Methodology, in lieu transac- tions and BPA's PE` Exchange rate based on the 7(b)(2) test. BPA believed it complied with the law because it considered all of these factors in establish- ing the REP settlements. West Coast power crisis shocks region By the summer of 2000, West Coast power prices were escalating rapidly. As a result, public power customers were showing increasing interest in placing substantial amounts of load on BPA for the post -2001 period. By the time contracts were signed in October 2000, it was apparent that BPA would need to acquire approximately 3,000 aMW beyond its existing supply to meet its contractual commitments to public utili- ties, IOUs and DSIs with deliveries to begin in October 2001. 10 In the winter of 2001, wholesale power prices explod- ed. BPA estimated that it would need to raise rates 250 percent if it were to acquire the full 3,000 aMW at the then current prices. In the first six months of FY 2001 alone, BPA spent more than $1 billion buying power. Facing this extreme situation, BPA developed a three- pronged load reduction program that included conservation, reductions in power demand by utilities and load curtailments by DSIs. In May and June of 2001, . BPA executed 2001 Load Reduction Agreements with Pacific and Puget, eliminating BPA's obligation to deliver power for the FY 2002 -2006 period in exchange for cash payments. The IOU agreements were structured so that BPA's payment in FY 2002 was lower than the FY 2003 - 2006 annual payments. These agreements to forego power deliveries in exchange for a cash payment eliminated BPA's need to buy large amounts of more costly power on the market. While the efforts to reduce BPA costs were largely successful, public power utilities still saw their rates go up 45 percent in October 2001. At the same time, IOU REP benefits to Pacific and Puget increased substantially as a result of the load reduction agree- ments. Some public utilities whose rates historically had been much lower than those of neighboring IOUs suddenly found themselves having to raise their residential rates above those of .IOUs. Total benefits flowing to the IOUs' residential and small -farm consumers, including payments to reduce load on BPA, rose to about $370 million annually, compared to $58 million annually in the previous rate period. BPA moves to lower public rates An extended drought in the Northwest made it difficult for BPA to recover financially from the West Coast energy crisis and thus to lower power rates for public utilities. BPA looked for new initiatives that could further lower its costs and bring about rate reductions. B Such cases are often referred to by the name of the first petitioner. • • • In 2003, BPA proposed a global REP litigation settlement with all BPA customers that was designed to provide rate relief for public utilities. The settle- ment was fragile from the start because it required support of nearly 100 preference customers that were parties to various lawsuits. The 2003 Litigation Settlement ROD provided that, among other things, if any preference customer failed to sign the stipula- tion and other settlement documents within 90 days after the effective date (Jan. 21, 2004), the proposed settlement would be void. The proposed settlement would have decreased FY 2004 rates for public utilities by 7 percent (from what they otherwise would have been) by eliminating $200 million in IOU REP benefits and deferring another $270 million of benefits into the five -year rate period beginning in 2007. The proposed settlement also would have settled lawsuits brought by public utility customers regarding the level of benefits going to IOU customers. The settlement proposal failed for lack of sufficient signatures. BPA received support from 86 customers, while six opposed the settlement and others did not respond formally. Settlement "lite" offered After the failure of the proposed global litigation settlement, in 2004 BPA proposed contract amend- ments to the underlying IOU settlements. This came to be known as "settlement lite." In April 2004, SPA. sent a letter asking for comment on a proposal in which Pacific and Puget would waive $160 million of payments between 2004 -2006 and defer another $100 million, plus interest, until FY 2007 -2011 when BPA expected to be on better financial footing. The amendments offered similar terms to the other IOUs, and all six signed agree - ments. In return, the IOUs would receive greater certainty about their benefits. The benefits were defined as financial payments, not power deliveries. The proposed agreement established a floor of $100 million a year with an annual cap of $300 mil- lion for FY 2007 -2011. By removing the $200 million 11. 44:r•:A „k: AZ: .� w,.4.' S.': h A`:�?;i. �.t]��r?_�n �r from power costs, FY 2005 -06 power rates were 6 percent lower than they otherwise would have been. The majority of commenters approved the proposal'. The _IOUs agreed to the new settlement primarily because it gave them greater certainty as to how post - 2006 benefits would be calculated, On May 25, 2004, BPA published the 2004 Agreements Regarding Payment ROD adopting the proposal to amend the underlying agreements. Clark requests exchange In June 2005, Clark Public Utilities, headquartered in Vancouver, Wash., sent BPA a letter requesting exchange benefits. Clark had experienced a sharp rise in its fuel costs for its gas -fired plant. Historically, while the bulk of exchange benefits had gone to IOUs, over the years more than 30 publicly owned Northwest utilities had participated in the program. All previously participating publics either had terminated contracts or settled the amount of their benefits. BPA offered Clark. an RPSA, which Clark signed in August 2005. This initiated the analysis to determine the utility's REP benefits. The following December. BPA and Clark reached a settlement, with exchange benefits scheduled to go into effect in January 2006. As part of the settlement, Clark returned to BPA's control area and replaced its power purchase contract with a partial service product. REP discussed as part of Regional Dialogue Since 2002, BPA. has engaged with the region in a Regional Dialogue aimed at defining B future power sales role after 2011 when current wholesale power contracts with preference customers expire. The future of the REP has been a. prominent part of these discussions involving both public and investor - owned utilities. These discussions, extending over five years, focused on forging a regional consensus on 1° Certain provisions for Avista, Idaho Power, NorthWestern and PGE were different from those in Pacific's and Puget's contracts. a new financial formula to settle REP disputes for the 2012 -2027 period. While no agreement was reached, the parties did narrow their differences and were prepared to continue discussions. BPA and the IOUs agreed on principles for a new settlement, but further progress was put on hold after the Ninth Circuit decision on May 3, 2007. Ninth Circuit weighs in On that date, the U.S. Ninth Circuit Court of Appeals ruled on two lawsuits that had Residential Exchange implications. The first suit is known as the PGE (Portland General Electric) suit and was filed against BPA by numerous parties challenging BPA's 2000 REP Settlement Agreements with six IOUs (for the FY 2002 -2011 contract period). Public utilities were the primary petitioners, although investor -owned utilities and industrial customers also filed petitions. In the PGE case, the Court held that BPA exceeded its settlement authority and concluded that the settlement was not consistent with Sections 5(c) and 7(b) of the Northwest Power Act, which established the Residen- tial Exchange Program. The Court also said BPA avoided the full statutory scheme of protecting preference customers under Section 7(b)(2). The second lawsuit, known as the Golden Northwest suit, addressed, among other things, BPA's FY 2002 - 2006 power rates. In this case, the Western Public Agencies Group, Public Power Council and Grays Harbor PUD had contended BPA improperly allo- cated costs of the REP settlements to the PF Prefer- ence rate. The Court referred to its ruling in the PGE case, noting that the IOU settlements were unlawful. The Court held BPA should not have allocated costs of the settlement as business costs under Section 7(g) of the Northwest Act. 12 BONNEVILLE POWER At7MiN1STRATION1 DOE/BP-3811. • JUNE 2007 11 The IOUs involved include Portland General Electric, Pacific Power, Rocky Mountain Power, Avista, Puget Sound Energy, Idaho Power and Northwest Energy. At the time of the settle- ment, Rocky Mountain Power was part of PacifiCorp, parent of Pacific Power. At the time of the Court's decision, the IOUs had collectively been receiving about $327 million in annual benefits. As a result of the Court's hearing, BPA formally notified the IOUs " in writing of its decision to suspend REP settlement payments imme- diately due to the uncertainty created by the recent Ninth Circuit Court rulings. BPA certifying officials are personally liable if payments are made that are not consistent with law, and, in this case, the Court's rulings created substantial questions over whether additional settlement payments are consistent with the law. These payments amounted to about $28 million each month to investor - owned utilities for their residential and small -farm consumers. r Presentation Presented by: Terry Mundorf, Partner Marsh Mundorf Pratt Sullivan & McKenzie March 23, 2011 A LOOK AT THE PROPOSED SETTLEMENT OF THE THE IOU RESIDENTIAL EXCHANGE Presentation Overview • Proposed Residential Exchange Settlement Agreement (REP Settlement) will do three things • Settle pending litigation over BPA's prior REP Settlement Agreement • Establish fixed amount of REP benefits to be paid to IOUs through 2028 • Fix the amount of REP cost protection of preference customers through 2028 • Involves interaction between two provisions in Northwest Power Act • Residential Exchange Program (REP) • §7(b)(2) Rate Test Page 1 2 Presentation Overview cont'd • Give you some background on the REP Settlement • Residential Exchange Program (REP) and Rate Test • 2002 REP Settlement Agreement and resulting litigation • Specifics on Proposed REP Settlement • What Is The Deal and What are the Major Features of REP Settlement Agreement • Evaluation of Proposed REP Settlement Agreement • Pros and Cons of REP Settlement • What Happens If You Sign, What Happens if You Do Not Sign The Residential Exchange Program 3 • Genesis of the REP • As loads grew in the 60s and 70s, BPA terminated IOU power supply contracts • IOUs were forced to acquire new resources to serve load, driving up their rates • IOUs sought direct access to federal power • Congress cut a deal in Regional Act - provided the IOUs benefits of federal system without giving them actual access to federal power — the REP • How the REP Works • REP provides wholesale power cost parity between utilities with high resource costs (IOUs) and those who enjoyed low cost federal power (publics) • BPA pays IOUs for difference between their average cost of power (ASC) and BPA's PF Exchange rate • ASC is calculated for each utility based on their power supply costs • More ASCs exceed the PF Exchange rate, the more REP payments IOUs get Page 2 4 4. The Rate Test • Genesis of the Rate Test • Publics feared that REP costs would erode preference by increasing PF rate • Rate Test ensures publics pay no more in REP costs than they get in Regional Act benefits • How Does it Work • BPA runs the Rate Test in each rate proceeding • If REP costs exceed the Regional Act benefits to publics, Rate Test triggers • REP costs in excess of Regional Act benefits excluded from PF rate • REP costs excluded by Rate Test reduce REP Benefits received by IOUs • REP cost protection under Rate Test comes at expense of IOU REP benefits PAYMENTS UNDER ALL SUBSCRIPTION PROGRAMS /SETTLEMENTS, 2002 2003 2004 2005 2006 $363 $381 $400 $381 $381 Page 3 s Brief History of the REP and the Rate Test Under the Act ACTUAL IOU RESIDENTIAL EXCHANGE PAYMENTS BY YEAR 1982 -2000, 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 $224 $146 $175 $178 $172 $163 $137 $132 $135 $160 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 $170 $187 $146 $148 $120 $167 $79 $56 $48 $49 s Brief History of the REP and the Rate Test Under the Act (cont'd) • Starting in 1996, the Rate Test triggered in a large amounts • Resulted material reduction to IOU REP payments • Caused mostly by precipitous decline in DSI (smelter) loads • DSI load reduction caused REP benefits to fall by eliminating a major Regional Act benefit (DSI reserves) • BPA started to consider ways to provide REP benefits to IOUs that would not be limited by Rate Test 2002 REP Settlement Agreement • BPA replaced declining REP payments under Rate Test with 2002 REP Settlement Agreement • BPA proposed to "settle" its REP obligations to the IOUs • BPA provided IOUs with 1900 aMW of benefits —1000 aMW actual power deliveries at the PF rate and 900 aMW cash payments • The 2002 REP Settlement provided IOUs greater benefits than REP payments permitted by the Rate Test • 2002 REP Settlement costs included in PF rate in WP -02 rate case Page 4 7 8 The Litigation Begins • Initial Litigation Over the 2002 REP Settlement • WPAG sued on 2002 REP Settlement (Portland General Electric v. BPA) claiming it exceeded BPA's statutory authority • WPAG also sued on PF rate from WP -02 case claiming that 2002 REP Settlement costs exceeded Rate Test limits (Golden Northwest Aluminum v. BPA) • The Court found both 2002 Settlement and WP -02 rates unlawful • The Court remanded the WP -02 rates to BPA to redo the rates in accordance with the Courts opinion The Litigation Begins (cont'd) Page 5 s • Proceedings Subsequent to the GAZA and PGE Decisions • In response BPA took determined how much the IOUs unlawfully received, and how much refund the publics were entitled to get back (WP -07S rate case) • Decisions made by BPA increased IOU REP benefits from $48 million (WP -02 case) to about $135 million (WP -07S case) • BPA also decided that PacifiCorp and PSE could keep, and not repay to publics, $650 million in 2002 REP Settlement payments they received • BPA also made some decisions that materially altered the operation of the Rate Test which reduced the REP cost protection it provides to publics • These decisions are on appeal to the 9 Circuit • These are the claims the proposed REP Settlement Agreement would resolve 10 The Proposed IOU REP Settlement Agreement ▪ The Basic Deal - IOU REP Settlement • The IOUs get: • Fixed REP payments of $2.01 billion (8% NPV) for next 17 years • No repayment of unlawful benefits received under prior REP Settlement - $500 million • No payment of Idaho Power deemer balance - $250 million ✓ Avoid claims for additional unlawful benefits under prior REP Settlement - $650 million • Avoid claims that would reduce future REP payments by about 90% • Receive 14% of environmental attributes of FBS • Publics will get under the Settlement • Fixed and known REP payment obligation — shielded from REP cost increases • REP Settlement payments that are no higher than current REP payments • Dismiss pending claims against BPA — end of litigation • Rate Test suspended during REP Settlement term (until 2028) • Settlement substituted for the REP cost protection provided by the Rate Test The Proposed IOU REP Settlement Agreement (cont'd) • Other aspects of the Settlement • Pending litigation • Signers will dismiss pending legal claims Designed to moot out claims of non - signers whether or not they want them dismissed • Legal challenges to REP Settlement • Signers agree not to challenge the REP Settlement • Signers support Congressional ratification to preclude legal review by non - signers • REP Settlement enforceability d With Congressional ratification — binding arbitration with BPA but no legal review • Without Congressional ratification — no binding arbitration with BPA but get legal review • Waivers if Agree to be bound by REP Settlement even if BPA lacks authority to sign • Contract replaces statute • REP Settlement replaces Rate Test for signers and non - signers alike Page 6 12 Some Ways of Evaluating the Settlement • Evaluating the REP Settlement • Compares REP Settlement with the REP costs without the Settlement under BPA current interpretation of the Rate Test • BPA's current Rate Test interpretations subject to legal challenge • Like comparing settlement offer to outcome where you lose on all counts - settlement always look better • Alternate approach — compare REP Settlement to REP costs under expected litigation outcome • My view of most likely outcome • SPA prevails on most issues • Publics prevail on 2 issues — repayment of unlawful payments to ICUs and conservation treatment in Rate Test • Nothing guaranteed in litigation, but this is the most likely case Settlement Evaluation cont'd $ 700,000 $600,000 $100.000 -- so 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026'2027 2028 Page 7 -°int-0 Business As usual wJBPA Positions ...... ............._. '�i'E.._ Prevailing in Litigation - 3'^^ Probable Outcome -.. =COLIs Posit Cans on LRA & Conservation Prevail In Litigation — — Settlement 23 4 Settlement Evaluation cont'd • Cost of settlement payments = $4.1 billion (nominal) • Additional cost to publics of payments waived: • IOU repayments not yet received = $500 million • Deemer payments not yet received = $250 million • Additional claims waived = $650 million • The cost of REP Settlement = $4.1 billion + $500 million $250 million $650 million • Total REP Settlement cost to publics = $5.5 billion (nominal) Settlement Pros and Cons • Pros of the Settlement Agreement include • Fixed REP payment for 17 yrs, more certain than Rate Test done each rate case • Fixed REP payments protects from IOU ASC increases from carbon tax, RPS • REP Settlement payment in 2028 ($286M) about same current amount ($295M) • Less litigation over REP payments after pending claims (if not dismissed) and challenges to REP Settlement (if no ratification) are done • Rate cases conducted without REP arguments and contention, allows publics to focus on other matters such as preserving FBS, SPA cost control, resources • REP Settlement can be terminated if basic deal (embedded cost rates, ASC above PF rate) changes from outside action and two- thirds publics want out Page 8 15 16 Settlement Pros and Cons cont'd • Cons of the Settlement include • Fixed REP payment shields IOUs from CRACs and BPA cost increases from dam removal, CGS retirement, fish costs. Statutory REP benefits subject to these costs. • Substitutes BPA contract for statutory Rate Test for statutory REP cost protection — precedential implications • Signers stuck with deal even if BPA lacks the authority to sign the REP Settlement • Deprives non - signers of judicial review and current claims (precedent), and in near term will likely generate additional litigation • Certainty of REP Agreement depends on enforceability. With ratification, REP Settlement is enforceable against BPA (with loss of judicial review). No ratification, not enforceable against BPA (with judicial review) • Imposes substantial REP costs on publics to dispose of litigation($5.5 billion nominal) What Happens If You Sign, What Happens If You Don't 17 • If you sign you accept certain obligations, some before BPA signs and some after • Support adoption of REP Settlement Agreement by BPA in current rate case • Support efforts to dismiss (or stay) pending litigation of signers and non - signers • Support effort to obtain Congressional ratification — can back out of effort if you think it is detrimental • Without Congressional ratification, help defend Agreement if it challenged in court • If you decide not to sign, what happens to you depends • Do not have to support adoption, seek dismissal, support Congressional ratification or defend in court • If nobody challenges Agreement, you get same rates as signers but without the obligations court Page 9 18 What Happens If You Sign, What Happens If You Don't cont'd • Result potentially different for non- signers if Agreement is challenged • If REP Settlement Agreement challenged, all non- signers get outcome determined by - Court whether you challenged the Agreement or not • What that means depends on how challenge turns out • If BPA prevails, get same rates as signers ✓ if challengers prevail, get outcome as determined by the Court which could be • Signers and non - signers get statutory rates ■ Signers get the Agreement rates, non - signers get statutory rates • Court outcome could be better or worse than settlement - depends in part on treatment of pending claims • One last issue— PUD authority to sign REP Settlement • Benton REA legal opinion questioned PUD authority • CowlitzlSeattle /NRU legal opinion says they have authority • Not clear where this particular issue will lead or how it will be resolved • Worth keeping an eye on Page 10 19 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N 2012 REP Settlement and BPA's REP -12 Rates Proceeding Port Angeles City Council and the Utility Advisory Committee March 23, 2011 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N Outline of Today's Discussion • Introduction and Overview • REP Settlement Background and Current Status • REP Settlement and BPA Rates Process Going Forward • Key Elements of the Proposed Settlement • BPA Staff Analysis of the Proposed Settlement • Discussion 2 3/23/2011 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N Background and Current Status • Representatives of Preference Customers, IOUs, BPA, State Regulators and retail customers working on this Settlement since Spring 2010 • Many Preference Customer representatives, IOUs and others signed Agreement in Principle in Sept 2010 • Parties immediately began drafting a binding Settlement Agreement • BPA initiated the REP -12 rates proceeding mid -Dec 2010 based on then - current draft Settlement Agreement • Final (March 1, 2011) signature -ready Settlement Agreement sent to potential signers March 3 3 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N • Signing window closes April 15, 2011 REP Settlement and BPA Rates Going Forward • Critical Mass must sign Agreement for Settlement to move forward • 91 percent of Preference Customer Load • All six regional IOUs • ID, OR, WA regulators • CUB, PPC, NRU, PNGC • If Critical Mass does not sign, then no settlement: • BPA will set power rates based on continuation of current REP and ratesetting approaches • Parties will resume the REP litigation in the Ninth Circuit 4 3123/2011 2 r B O N N E V I L L E P O W E R A D M I N I S T R A T I O N REP Settlement and BPA Rates Going Forward • If Critical Mass of entities sign, BPA will continue its REP -12 proceeding addressing whether or not BPA should sign the Agreement • Settlement becomes effective only if BPA decides to 1. sign the Agreement and 2. set rates for signers and non - signers based on the Agreement for the term of the Agreement (through FY 2028) • BPA's decisions released in REP -12 final ROD in July 2011 If BPA decides to not sign or not set rates for all based on the Agreement, Agreement is void • If BPA signs the Agreement, BPA would withdraw its decisions made in the last two rate cases that are being challenged in the Ninth Circuit 5 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N REP Settlement and BPA Rates Going Forward BPA's REP -12 Initial Proposal staff recommendation is that BPA Administrator adopt the proposed Settlement • BPA's staff analysis: • Settlement results in lower expected costs to BPA Preference Customers than no settlement under a variety of scenarios • Settlement provides much greater certainty to IOUs and Preference Customers • Settlement has potential to reduce litigation • BPA Supplemental Initial Proposal issued Feb 25: Changes since the mid - Dec draft do not change staff analysis or recommendation 6 3/23/2011 3 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N Key Elements of the Settlement • REP benefits are fixed under Settlement, capping Preference Customers' exposure to higher REP costs. • Individual IOUs' Lookback Obligations are replaced by Refund Amount credits on Preference Customer bills: $76.5 million per year for next eight years ▪ Preference Customer Refunds allocated 50 percent based on current PF -02 Revenue Share approach and 50 percent based on future BPA Tier One purchases, with proviso regarding Grant PUD • IOUs continue to file ASCs; ASCs used to determine if an IOU qualifies for benefits and how total REP benefits are allocated among IOUs; REP implementation continues largely unchanged Key Elements of the Settlement • BPA pays IOUs Interim Agreement True -Up payments already recovered in PF rates, but currently held in the BPA fund • IOUs would get 14 percent of future RECs and Carbon Credits that Might become available from resources serving BPA Tier 1 loads • Idaho Power Deemer obligation extinguished • Signers agree to seek legislation that would affirm the Settlement But any signer can cease seeking legislation and oppose legislation if it believes legislation could result in material harm 7 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N • If PF rates are no longer set based on embedded costs and this results in an average PF rate greater than 79 percent of average IOU ASCs, Agreement terminates a 3/23/2011 4 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N • Signers: • Agree not to challenge the Settlement • Will petition Court to dismiss current REP litigation • Will ask Court for expedited review if Settlement is challenged by non - signers • Retain all rights to make arguments and claims in response to legal challenges by non - signers If non- signers challenge Settlement and Court rules BPA cannot set rates the same for signers and non - signers, all non - signers get alternative rates treatment whether or not they challenged the settlement • Rates and refunds for non- signers could be higher or lower than signers; difference increases or decreases payments to ICUs • When Settlement terminates end of FY 2028, Signers free to pursue legal challenges of 7(b)(2) rate test and other prospective issues • Settlement is not an admission or concession by signers on the merits of any disputed issues affecting going forward REP benefits and BPA rates. B o N N E V I L L E P O W E R A D M I N I S T R A T I O N $500,00000: •--- -..___ $400 • $350,070.30 . ac 1 ;s25O.000:ou r` 5200 Key Elements of the Settlement 'Payments to IOUs through the Residential Exchange Program or Settlement Agreements:. (2009 Sl $150. 000.00 $100,000_11o - $50,000,00 • - - - - , Yeas of69 REP Bentfes Paid f38orcf+lsApplied bs Lr3a eS[ 9 3/2312011 5 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N Payments to IOUs through the''Resideratial Exchange Program .or'Settlement Agreements: (2009 3) $450,00000 $400,00000 . 6rs. 1 5050.000 00 $3O0, 00.00 5�m000,00 - 1- r x+$200,000. $1500,000 00 $700000 -0o 0,000.00. • - i - E i g • r+. r~. rv s rr n ov cn � nP � rti - N M_ J / 3V • 6V hl S�1 cV 'S'e ! r' Ci J M. P' CAF 1 fV hl i^e CY S'J.. 1 , CV tV. fv• wear 1: 91CI■ REP E:neeits Paid NREPSettemerd a eme it ApiI A Laokpac, 1 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N Rowel: REP Senefirs Exrreme Scenarios u_. r - 5...;"1,n1.... 5..11 ..w 1.11. n. w.e p.d 1.rw . re Yr..P Po ala..6krn PA1 Lead p ..1.1W%-11 1 ., Fo;. 1.1.3..q CO. Fn<.4aJJd s [ddad.n • 2.4 12 3/23/2011 6 1 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N a ca 3940[0 • 25Q00) ' ipnme ?�iA 2032 2470 2044 Flgtrre Benefits Extreme Srenarfas Lau Casa '1fa 5adan:ear fJ'sitatir 5asak ana !Anna Baansar AaIaILS1aa Wrap IOU Bair Alnararkra. Iel is b gm.. mas Sati IBP, RA, klaakan y45L Eti.lasid x 1afIa kii - F!'. .4 ,Wtt 5 ""2.1111araafl �tE .eaaEaa+Gw 2012 2013 231+1 2715 2016 2011 2015 20•14 2320 2021 2022 2023 2024 2025 2026 2427 2023 13 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N F7rture'1: REP Benefits Extreme Se 6.9 <.1,..14. Italaarae L@..klmrk•5aod a 4 Ida osxldt Aedlydaan IEWA.? WV' Bret IaNF iaaa low% 'Se% IISP.54ti saJl kW COSA'IEacala[rL a Inflation • r .:1 2015 2035 2017 2013 3013 202 inn lac . 2022 2022 2032 20 24 2025 2026 2023 2028 14 3/23/2011 7 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N 1,000.000 800.500 600,000 700,000 000,000 500,500 400,000 200,0011 100,000 1,000,000 000,000 700 000 600,000 590,000 - figure 2: REF Benefits Lookback Scenarios wrote Based on Reference Case REP Benefits and Assuming Idaho Deemer Reduction IOU Load growth met 50% IRP. 50% Market. COSAfscefeted at Inflation ± 2 %. ^^ -^^ -1 - Na Lookback 2 - Largo Lodkhaek wfe LRSC (no 50% Met .""" Reference Casa - Battlement B O N N E V I L L E P O W E R A D M I N I S T R A T I O N 2012 2013 2014 2015 2016 2017 2016 2019 2020 2021 2022 2023 2024 2025 2026 2527 2028 figure 3: REP Benefits Other Scenarios errata Base Case "No Settlement" Lookback Setoff and Idaho Deemer Reduction IOU Load g n o0*t met 50% IRP. 50% Market, COSA Escalated at Inflation . 2% ` Case — - Conservation n Gen Req- w/o Coate. 0 - Conservation • Can. Req. w1 Cows --7. Single Royaynlent Study ^^""^'t - 1l Id-C [n Stack -- — 9 - Ra 7(557) to Surplus • ' 10 - Identical Sscand. y Cr.. • - 12 - F.._... ...Jon Rea. Gapmallzed — • 11- No Exclusions 15. Disc. Rate • inflation ®19 - 0leeeunt Rate • Inreetmeni ��9etiian5a;q 2 - Largo Lookback w/o LOS. 100% rule) — 3 - Large Lookback w1 LRRe (50% rule} — — 3 - Lsr00 Looktrack w7 LRA. (no 50% nits] • 2012 2013 2914 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2026 15 16 3/23/2011 8 54 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N 1,000,000 800,000 700,000 600000 500,000 400,000 300,000 200.000 100,000 1,000,000 900,000 800,000 700,000 000,000 500,000 400,000 300,000 200,000 - ^ ""Roterence Case -- High ASC; Low PF • Risk Figure 4: REP Benefits Risk Scenarios errata Base Case "No Settlement" Lookback Setoff and Idaho Deemer Reduction IOU Load growth met 50% IRP. 50% Market. COSA Escalated at Inflation + 2 %. -- • High ASC; Low PF Low ASC; High PF - Low ASC; High PF • Risk r�Set0ement • 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2020 2027 2028 "°`""'""Rotoronce Case Figure 5: REP Benefits Brief Scenarios erreh Base Case "00 Settlement" Lookback Setoff and Idaho Deemer Reduction (Except IOU Beef) IOU Load growth met 50% IRP. 60% Market, COSA Escalated at Inflation • 2 %. -z1 • COU Beef Case - - 22 •IOU Beef Case Settement • • 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 17 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N 18 3/23/2011 9 B O N N E V I L L E P O W E R A D M I N I S T R A T I O N 1 Port Angeles, City of <= select cou 5E9 [nets In PF Rate 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Status Quo (5 /MWh) S 2.31 1 S 2.26 1 S 2.401 S 2.02 1 S 2.38 1 S 4.761 S 5.18 1 5 5.93 1 S 6.07 1 S 5.68 1 5 5.931 S 5.77 1 5 6.14 1 5 7.08 I S 7.541 S 7.891 S 8.31 Settlement I S 2.26 I S 2.261 S 2.481 5 2.481 5 2.711 5 2.711 S 2.961 S 2.961 S 3.441 5 3.441 S 3.641 S 3.641 5 3.841 5 3.841 $ 4.021 S 4.021 5 4,021 Delta $ /MWh 5 (0.04) $ 0.00 5 0.08 $ 0.46 5 0.33 5 (2.05) S (2.21) 5 (2.97) $ (2.63) $ (2.24) $ (2.29) 5 (2.13) $ (2.30) S (3.24) $ (3.52) $ (3.87) $ (4.30) % Delta of Tier 1 Rate -0.1% 0.0% 0.2% 1.3% 1.0% -68% -6.5% 4.5% -7.5% -6.1% -6.2% -5.4% -60% 4.3% -8.9% -9.0% -9.9% Total REP Costs (FY 2012 -FY 2028) $60,178,338 <= Status Quo $37,568,297 <= Settlement - $22,610,041 <= Total Delta (Nominal $) $9.00 �.. $8.00 $7.00 $6.00 .. $5.00 $4.00 - $3.00 52.00 1- $1.00 REP Costs in PF Rate 201710132 014201520162017 2018201920202021202222023202420252026202fl028 Status Quo Settlement 3/23/2011 10