- Email: [email protected]
Bonneville and West Coast Electric Markets
Bonneville and West Coast Electric Markets A critic of the Bonneville Power Administration is correct that BPA's long-term role deserves prompt review. But there are many better alternatives than the market pricing that he proposes. Jim Harding
I. Introduction
Jim Harding is Director of External Affairs for Seattle City Light. He has also served as special advisor to two members of the California Energy Commission, Director and Assistant Director of the Washington State Energy Office, and Director of Energy Programs for Friends of the Earth. He is also the author or co-author of four books in the energy field. The views expressed in this article are his own and do not necessarily represent those of Seattle City Light.
March 2002
Dick Munson's article on Bonneville in the October 2001 issue of The Electricity Journal makes some worthwhile points, and some that are simply bad public policy.1 It is entirely appropriate to re-examine the role of the Bonneville Power Administration (BPA). But Munson's prescription misses the most important policy issues and alternatives. unson notes that the BPA markets, at cost, about 45 percent of the electricity sold in the Pacific Northwest, mainly from 29 federal dams on the Columbia and Snake rivers. The agency also owns roughly
M
three-quarters of the region's high-voltage transmission. Munson argues that the federal government's defensible role in electricity marketsÐrural electrificationÐis over; that federal electricity should be sold at market price; and surplus income should go to the U.S. Treasury or for development of new renewable resources and salmon recovery in the Northwest. In the absence of such changes, Munson argues that the Northwest will waste electricity, mismanage low-cost electricity resources, and dodge responsibility for salmon recovery. And market pricing will be good for the Northwest:
# 2002, Elsevier Science Inc., 1040-6190/02/$±see front matter PII S1040-6190(02)00266-X
47
No doubt market-based pricing would correct many of BPA's problems. It would send correct price signals, causing consumers to be more ef®cient, thereby reducing waste and pollution. It would provide an incentive for producers to build new generating units, thereby ensuring an adequate supply of electricity. It would enable all residents of the Paci®c Northwest to access what will still be low-cost hydropower. It would end outmoded taxpayer subsidies.
M
unson's recommendation of market pricing Bonneville's output is remarkably untimely and dangerous for West Coast wholesale markets still reeling from two years of market power abuse by operators far smaller and less influential than BPA. The recommendation makes even less sense in the Paci®c Northwest. By authorizing market pricing of Bonneville's hydro capacity, Congress would be creating a market design in the Paci®c Northwest far more vulnerable to abuse of market power than the market structure adopted by the California Legislature in AB 1890. With 45 percent of regional generating capacity and 75 percent of regional transmission, Bonneville dominates Northwest markets. Bonneville operations directly affect an additional 3,700 MW of non-federal run-of-the-river downstream generation. It is dif®cult to imagine that BonnevilleÐor its successorsÐcould pass either the Federal Energy Regulatory Commission's traditional ``hub and spoke'' test for market pricing, or
48
the newly proposed ``supply marginal assessment'' test. In addition, the public purpose objectives of the Columbia River system, including ¯ood control, navigation, and salmon restorationÐall governed by numerous federal statutes and treaties with Canada and Native American tribesÐare impossible to achieve without coordinated river operations. This coordinated operation is at least unseemly, and possible
Munson's recommendation is remarkably untimely and dangerous for markets still reeling from market power abuse. illegal, in competitive markets. Munson is correct that we need to examine some alternatives to the status quo to better align risks and bene®ts to the U.S. Treasury, improve energy ef®ciency, diminish Bonneville's in¯uence in wholesale power markets, and restore endangered salmon runs.
II. West Coast Market Power and Bonneville The West Coast experimented over the last four years with a largely unregulated, highvolume, day-ahead wholesale power market. For the ®rst three
# 2002, Elsevier Science Inc., 1040-6190/02/$ ± see front matter PII S1040-6190(02)00266-X
years, clearing prices in the California Power Exchange approximated the marginal operating cost of gas generation.2 In 2000±2001, prices reached spectacular levelsÐ10 to 20 times higher, on average, and several hundred times higher, on peak, than levels of the previous year. Many factors can be blamed, including California's market design, scarcity, natural gas prices, NOx markets, FERC's late intervention, and physical or economic withholding of divested gas-®red generation. alifornia subsequently took a number of steps to corral the runaway market. Further divestiture of utility generation has been halted. The California Public Utilities Commission (CPUC) specifically rejected Pacific Gas & Electric's proposal to auction roughly 4,000 MWe of Northern California hydro capacity, citing the potential that the merchant owners of these resources could exercise substantial market power.3 The state Department of Water Resources began purchasing electricity for investor-owned utility customers on a long-term basis, reducing exposure to short-term wholesale markets. Retail wheeling was terminated, mainly to provide financial certainty for long-term contracts. A state power authority was chartered. All of these steps were designed to undercut the influence that merchant plant owners might have on California wholesale market-clearing prices and retail rates. FERC responded on June 19, 2001, to the West Coast wholesale
C
The Electricity Journal
market crisis with a generally effective combination of Westwide price caps and must-offer requirements.4 FERC's June 19 Order speci®cally requires merchant plant operators to offer all available capacity in short-term forward markets throughout the West. The agency took this step because of credible evidence of physical and economic withholding of generation from fall 2000 to spring 2001. FERC speci®cally exempted Western hydroelectric capacity from this requirement, because a mustoffer requirement would probably result in operations that are inconsistent with state and federal license requirements, and the multiple uses of hydro reservoirs. Outside California, West Coast public and private utilities with load service obligations generally rebuilt their long-term supply portfolios before FERC's June 2001 Order. This reduced or eliminated their exposure to short-term wholesale market prices, but in many cases locked in high-priced long-term deals.5 Retail competition has been deferred or abandoned in many states and service territories. onneville could play a remarkably powerful role in West Coast wholesale electric markets. The agency controls more capacity (about 21,000 MWe) than all divested merchant generation in California (18,471 MWe peak), and far more than any individual merchant plant owner (less than 4,000 MWe). Its operations directly affect more than
B
March 2002
3,700 MW of downstream, non-federal, run-of-the-river hydro generation. Several years before the current crisis materialized, Jim Bushnell showed that Bonneville, acting singly, and without limits on its pricing ability, could double September wholesale market clearing prices. If BPA's capacity is used in conjunction with some California fossil generation, clearing prices could triple.6
FERC's Order speci®cally requires merchant plant operators to offer all available capacity in short-term forward markets. Bonneville responded by arguing that Columbia River ¯ow requirementsÐfor ®sh, navigation, and water qualityÐand long-term power sales contracts prevent Bonneville from operating in ways that could substantially increase PX clearing prices. This is probably correct. If Congress auctioned long-term rights to BPA output, one would expect the winning bidder to be a merchant plant operator with California fossil-fueled generating capacity, able to exercise market power. Such an operator would be constrained by Columbia River ¯ow requirements, but would probably not be constrained by
BPA's current power sales contracts. Hydroelectric generation, with trivial incremental operating costs and storage, is uniquely able to in¯uence energy and ancillary service markets. Such in¯uence is not easily regulated, particularly when operations may be driven by a number of non-energy market factors, including irrigation requirements, ¯ood control, water quality, salmon restoration, and navigation. The usual remedy for this problem is continuing sale of output at cost or a ``must run'' or ``must offer'' designation. ``Must run'' designations are not easily applied to hydro capacity, as FERC noted in its June 19, 2001 order. In short, generation availability may be impossible to enforce and generation withholding may be impossible to preclude. Any pro®t-maximizing entity, or set of entities, with unencumbered access to Bonneville assets likely would have sold power last year at a much higher price than BPA's actual transactions with the California Power Exchange and Independent System Operator. Continuing sale of the bulk of Bonneville's output at cost is a better long-term approach.
III. Northwest Electric Markets and Bonneville If market power is a barrier to market pricing of Bonneville's assets in West Coast markets, it is an even bigger barrier in the Paci®c Northwest for reasons that
# 2002, Elsevier Science Inc., 1040-6190/02/$±see front matter PII S1040-6190(02)00266-X
49
involve Bonneville's generation dominance, Columbia River hydrology, transmission ownership, and federal statutes. oughly 63 percent of Northwest electricity comes from hydropower. The equivalent figure for the rest of the nation is just under 5 percent.7 Hydro systems can and do operate in restructured markets, such as Norway and New Zealand. However, there is one key difference between Northwest hydro and those systems: the vast majority of Northwest electricity comes from one hydrologically interconnected system (the Columbia), not from separate fjords and rivers. The bulk of Northwest storage sits behind the 6,800 MWe Grand Coulee dam and in southern British Columbia; the operation of Grand Coulee alone directly (e.g., through runof-the-river downstream dams) or indirectly (through market conditions) influences the pricing and operation of all hydro and thermal generation in the Northwest. Thus, BPA manages not only the 45 percent of the region's electricity it supplies; it also directly in¯uences an additional 3,700 MWe of non-federal downstream dams and, through power market and transmission conditions, in¯uences all the other generation in the region.8 Because of its very nature, BPA fails both FERC tests for market pricing, whether FERC uses its traditional ``hub-and-spoke'' test (generation market share less than 20 percent) or the recently proposed ``supply
R
50
margin assessment'' test (under which at least some capacity of a single owner must be used to meet regional peak demand).9 There are many possible ways to market price BPA's output, including short- and long-term sales and auctions, with maximum limits on ownership share.10 Some may do a better job than others of minimizing market power, but all require vigilant oversight to prevent abuse. The
Each of many possible ways to market price BPA's output requires vigilant oversight to prevent abuse. speci®c power behind Grand Coulee dam is indivisible. Multi-purpose uses of the Columbia River system also lead to coordination of a sort that would be intolerable in competitive markets. For decades, NorthwestÐincluding CanadianÐhydro and thermal plant operators have coordinated operations to meet a number of non-electric system objectives, mainly ¯ood control, navigation, and more recently, salmon restoration. The inherently centralized management of this system is fundamentally incompatible with a fully competitive wholesale power market.
# 2002, Elsevier Science Inc., 1040-6190/02/$ ± see front matter PII S1040-6190(02)00266-X
It is, in fact, a closely coordinated market that would make any antitrust litigator blush, were it not for the underlying public purpose objectives of the system. Traditionally, Bonneville has sold all its ®rm output (i.e., output in poor water years) at cost under long-term contracts. This still left a dif®cult investment environment for new capacity, with low average electricity prices in the region, very substantial ¯uctuations in the availability of non®rm surplus power, and challenges for load forecasting. The Northwest did a poor job of load forecasting in the 1970s, and an even worse job of building lowcost new capacity to meet need, all of which culminated in the Washington Public Power Supply System (WPPSS) debacle of the late 1970s. ongress addressed these challenges in the 1980 Northwest Regional Power Act. The Regional Act blessed Bonneville's dominant position in Northwest generation and transmission, and directed the agency to leverage that position on behalf of a variety of regional purposes. The Act made BPA potentially responsible for meeting all load growth of public utilities in the Northwest, and all residential and small farm loads of the region's investor-owned utilities. BPA resource additions were to emphasize conservation and renewable resources under the supervision of a regional multistate Northwest Power Planning Council, an interstate compact whose members are appointed by
C
The Electricity Journal
the four Northwest Governors. Northwest aluminum smelters would receive power from Bonneville for a transitional period, after which many contemplated that they would become industrial loads of consumer-owned utilities. The Act moved the region in the direction of a oneutility model, with resource decisions driven by least-cost planning principles, overseen by a regional board. Ratemaking directives of the Act reinforce Bonneville's central role. BPA's power is sold at a melded price, with more than 8,000 average MW of low-cost hydropower averaged in the higher cost of new resources. This feature was speci®cally designed to discourage any possibility of another WPPSS escapade. Any utility would be foolish to invest in higher-cost new generation when Bonneville could deliver the same kWh at a melded price. In addition, a utility that developed its own generation would lose access to the same amount of Bonneville generation. his model arguably worked well until the passage of the 1992 National Energy Policy Act. The 1992 Act exempted the Northwest from its transmission provisions, but this exemption proved impossible to sustain. National policy on competitive wholesale markets and open access transmission is fundamentally incompatible with centrally planned resource acquisition and Bonneville's growing load obligation. In the central planning model, Bonne-
T
March 2002
ville is largely responsible for deciding what kind of plant to build when and where. Utility customers have little, if any, choice. With open access transmission, utility customers can pick and choose, and can bypass Bonneville, leaving potential stranded costs, yet the agency is directed by statute to continue to acquire new resources for custo-
mers that may yet return. All of these issues were to confront the Northwest in the mid-1990s.
IV. Growing Tensions between the Regional Act and Wholesale Competition Under the 1980 Regional Act, the Northwest initially pursued the least-cost planning principles in the Act. While retail rates were among the lowest in the nation, Bonneville's resources were limited and new resources, whether fueled by gas, coal, or uranium, were much higher in cost. This created substantial incentives for Bonneville and private utilities to
invest directly in end-use ef®ciency. Ef®ciency investments in the Northwest were not geared to peak demand, but to all sectors and seasons, because the region's hydro system is energy-constrained rather than capacityconstrained.11 Under the direction of the Regional Power Council, Bonneville, public utilities, and private utilities invested heavily in conservation resource acquisition. By the mid-1990s, the West Coast market had changed, with overcapacity in generation and transmission, gas production and pipeline capacity, and FERC's open access rules. Power prices fell to levels below $20/MWh. Regional conservation investments fell substantially. Regional supply investments also disappeared. There was nothing inherently wrong with this outcome; both investments were then less cost-effective and, with huge uncertainties about the pace and scope of state and federal deregulation, much riskier. With the opening of the California Power Exchange in April 1998, the short-term wholesale market grew enormously. The California PX routinely and transparently cleared tens of thousands of MW every hour, compared with the 50±100 MW historically traded at other Western market hubs. The Northwest and California relied increasingly on each other, and a robust wholesale power market, to meet expected demand. From 1995 to 1998, Bonneville's melded wholesale electric price
# 2002, Elsevier Science Inc., 1040-6190/02/$±see front matter PII S1040-6190(02)00266-X
51
was temporarily above levels in the wholesale power market, and the agency lost customers. The Regional Act did not foresee this possibility, and offered little or no guidance on the recovery of stranded costs. With the assistance of then Energy Secretary Hazel O'Leary, the Northwest Governors convened a Regional Review to consider alternatives for Bonneville. The review concluded that it was inappropriate for the federal government, through BPA, to play a dominant and growing role in Northwest electricity markets. Instead, it concluded, existing resources should be allocated through long-term contracts beginning in October 2001 with historical customer groups. With Bonneville prices slightly higher than the West Coast wholesale market, utilities would take a calculated risk that they could pass along higher costs to retail customers, even with state or federally mandated retail wheeling. The review also concluded that BPA's transmission, representing 85 percent of regional high-voltage capacity, should be operated separately from the rest of the agency.12 either the drafters of the Regional Review nor those of the Regional Power Act could foresee the dramatic upheaval in Western power markets, beginning in spring 2000. Suddenly, BPA found that historical customers wanted far more electricity than the agency could reasonably offer. To avoid huge rate increases and involuntary curtailments, a
N
52
number of compromises were struck, including voluntary curtailment of most of the region's aluminum smelters. BPA has largely followed the recommendations of the Governors' Regional Review with regard to new resources; most new load is covered through longterm contracts, although diminished hydro supply and soaring
Western market prices in early 2000 and much of 2001 led BPA to impose a 46 percent across-theboard rate increase for its new round of contracts, which became effective Oct. 1, 2001. Munson's article argues that Bonneville, as a federal agency, made a number of decisionsÐon continuing service to aluminum companies, on resource acquisitions, and on exposure to the wholesale marketÐthat local and state regulated utilities would not make. This may or may not be true. Many public and private utilities, whether long or short on supply and with or without retail access, made decisions during this period that they have learned to regret.
# 2002, Elsevier Science Inc., 1040-6190/02/$ ± see front matter PII S1040-6190(02)00266-X
M
unson's article also makes several points about BPA that deserve response. It is not true that the difference between market price and Bonneville rates amounts to a $16±34 billion federal subsidy to the Pacific Northwest. Many private and nonfederal publicly owned hydro projects in the Northwest deliver extremely low-cost electricity. If there are subsidies embedded in federal Northwest hydro projects, they would arise in two key areas: differences in risk and cost of money between locally and federal financed hydro projects (real, but relatively trivial) and complicated federal accounting treatment for the multi-purpose nature of federal dams. Most Northwest federal hydro facilities were predominantly built for ¯ood control, navigation, and irrigation. Electricity was an important by-product of these projects, but it was not a central motivation. That said, electric ratepayers in the region pay most project costs. Many utilities in the region would agree with salmon advocates that agricultural diversions, particularly in southern Idaho, help neither the hydro system nor salmon recovery. But they remain as statutory objectives, as dif®cult to evaluate in hindsight as the associated accounting. But it is hard to conclude that the Northwest is subsidized to a greater or lesser extent than, e.g., Great Lakes bene®ciaries of the St. Lawrence Seaway. Perhaps ironically, the Northwest and California, despite The Electricity Journal
dramatic differences in the two regions' industry structure, both found themselves dependent on a robust short-term wholesale power market that turned expensive, unreliable, and volatile. Neither region had built capacity in advance of a suddenly dire need. That responsibility was left unresolved in California, and it was confused by and divided between utilities and Bonneville in the Paci®c Northwest.13 Two partially responsible parties may be better than none, but it is hard to escape the conclusion that one may be the better answer. Neither region has yet addressed the central question of responsibility for adding resources in advance of need, and whether this will be done by public agencies, publicly owned utilities, privately owned utilities, or through continued reliance on a merchant plant industry that has generated doubt, litigation, and fear. In the interim, the Northwest and Bonneville need clari®cation on Bonneville's roleÐin particular, on its obligation to serve, on utilities' obligations to take, and on who is responsible for building new generation and transmission resources.
V. Long-Run Alternative Roles for Bonneville Munson is correct that BPA's long-term role deserves prompt review. But there are many better alternatives than market pricing. March 2002
I
t is probably fair to look at three principal options. The status quo is one of them. BPA could ``grow'' the system through contracts and resource acquisition under the terms of the Regional Power Act. Alternatively, BPA could stop growing, and allocate existing resources, presumably to its historical customers. Finally, BPA or its output could be sold on
a very long-term basis, either at cost or at market. (1) Status quo: This state of affairs is difficult to defend, but easy to explain. BPA has a growing regional retail load obligation that it is increasingly unable to meet. It does not meet current ``public'' and ``regional'' preference loads that public and private utilities in the region place upon it. It also does not have sufficient generation to meet the optional requirements of direct service industries. In the best case, the agency would continue to invest in regional efficiency improvements, renewable resources, transmission, and provide lowcost backup or supplementary
generation for new wind projects. But the agency is properly nervous about acquiring several thousand MW to meet currently unmet and growing regional demands, especially for loads that could shift to other providers if Western power markets go through another boom-and-bust cycle. BPA's full compliance with Orders 888, 889, and 2000, and creation of a successful RTO, may be difficult without significant statutory changes. A growing BPA would also need explicit direction on recovery of potential stranded costs. The agency would also become increasingly dependent on an annual appropriations process that provides little security for the long-term investments the region will require, most urgently in transmission expansion. (2) Allocate generation output to historical customers. This option more easily accommodates national policy on transmission and generation than the status quo. It is also consistent with the evolution of other federal power market administrations. It does require difficult decisions on how the federal power resource is allocated. Under the terms of the Northwest Power Act, this would imply preferential service to public utilities and residential and small farm customers of investor-owned utilities. BPA resources could also be allocated on a basis proportional to population, or to historical dependence on BPA's resources. One promising model, incorporated in new contracts effective Oct. 1, 2000, is
# 2002, Elsevier Science Inc., 1040-6190/02/$±see front matter PII S1040-6190(02)00266-X
53
termed slice of the system. Unlike traditional contracts, slice contracts do not grow with load, but are instead fixed for the life of the contract. Utilities buy a share of the output of the federal system for a share of total costs. They bear responsibility for matching output to customer loads, and must acquire their own supplemental resources to address drought or growth. This model meets one longstanding and probably legitimate concern of the Northeast Midwest CoalitionÐthat the ratemaking directives of the Northwest Power Act put a federal agency in the position of serving new industrial loads at prices below marginal cost.14 A long-term solution would probably require amendments to the Northwest Power Act, at least on obligation to serve, ratemaking directives, and separation of transmission assets from the general obligations of the agency.15 (3) Finally, BPA could be sold, either to the region's utilities or at auction. The auction option raises all the market power and multipurpose use issues raised earlier. The resource is worth the most if sold intact to an unregulated merchant plant operator with fossil resources, able to exercise market power in Northwest or West Coast markets. The resource is worth least if sold to regional utilities that pledge to resell at cost to customers. It is difficult to imagine resolution of these issues, without insuperable conflicts between Congress, FERC, and the Northwest Congressional 54
delegation. There are also the difficult question of governance, given the irreducible federal interest in a number of non-electric system Columbia River issues, including tribal and Canadian treaties, navigation, flood control, and irrigation. rom a Northwest perspective, the most attractive of these options is probably alloca-
F
resource additions is still challenging, particularly for capacity additions in advance of dire need that can remove some volatility from wholesale prices and restore greater stability to West Coast wholesale power markets.& Endnotes: 1. Richard Munson, Rethinking Bonneville, ELEC. J., Oct. 2001. 2. California Energy Commission, Wholesale Electricity Price Review, 1998± 2000. 3. Many reasons underlie the discomfort with further divestiture, but effects on energy and ancillary service market power could have been substantial and, given the multi-purpose nature of these facilities, extremely difficult to police. FERC acknowledges this point in its June 19, 2001 Order, specifically exempting Western hydro facilities from the requirement to offer all available capacity to the California ISO.
tion, perhaps as an interim step to some form of regional acquisition. This step could be compatible with open access transmission, the development of regional transmission organizations, and a more competitive wholesale power market. It would reduce BPA's central involvement in the Northwest wholesale market, and clarifies that utilities cannot choose between BPA and the market to meet future needs. The federal agency would remain essentially a transmission provider and passive allocator of electricity. Northwest utilities would bear the responsibility for investment in new resources and efficiency improvements. But the investment environment for new
# 2002, Elsevier Science Inc., 1040-6190/02/$ ± see front matter PII S1040-6190(02)00266-X
4. Federal Energy Regulatory Commission, Order on Rehearing of Monitoring and Mitigation Plan for the California Wholesale Electric Markets, Establishing West-Wide Price Mitigation, and Establishing Settlement Conference, June 19, 2001. 5. Most utilities with load service obligations for what appeared to be very tight market conditions in summer and fall 2001 bought long term supplies in spring at significantly higher prices than now prevail. 6. James Bushnell, Water and PowerÐ Hydroelectric Resources in the Era of Competition in the Western U.S., POWER Working Paper 056r, 1998, University of California Energy Institute, Program on Workable Energy Regulation. Bushnell also found that a BPA with market pricing authority would reduce output in a variety of ways that are impossible to police: ``a profit-maximizing BPA may find it generally profitable to convert water to power less efficiently than if it were a price-taking firm. Although efforts to `spill' water around turbines would be
The Electricity Journal
easy to detect, they could be justified, or even required, by environmental restrictions on river system operations. Other far more subtle techniques to manage river flows and reservoir head heights to minimize, rather than maximize, the efficiency of the energy conversion would be virtually impossible to detect.'' 7. U.S. Department of Energy, Energy Information Administration, State Electricity Profiles, 1999. 8. Non-federal run of the river dam capacity below Grand Coulee totals 3,742 MWe, including Wells (774 MWe), Rocky Reach (1,213 MWe), Priest Rapids (855 MWe), and Wanapum (900 MWe). 9. Federal Energy Regulatory Commission, Order on Triennial Market Power Updates and Announcing New, Interim Generation Market Power Screen and Mitigation Policy, Nov. 20, 2001. 10. An annual auction of output to Northwest load-serving entities, with price capped at marginal cost and
operational decisions remaining in federal hands, is probably the best approach for limiting market power. But this injects substantial planning uncertainties and offers no compelling long-term benefits. 11. Even in the difficult 1990s, regional conservation efforts saved about 750 average MW, equal to about 4 percent of total demand. This was about half the level achieved in the previous decade. Some utilities, e.g., Seattle, maintained conservation programs in the 1990s that effectively cut load growth in half. 12. BPA transmission assets are encumbered by the general obligation of the agency. It is difficult to do full separation without resolution of the responsibility that BPA's transmission might have for many future system costs, including salmon recovery and WPPSS debt. Meanwhile, it is difficult for regional investor-owned utilities to participate in an RTO with BPA knowing that these obligations are unresolved.
13. BPA's statutory responsibility to meet net loads of public utility and residential and small farm loads of investor-owned utilities is clear in statute, but the obligation is not as binding as a retail utility's obligation to serve. BPA meets all public preference in the region, but only about one-third of the residential and smallfarm loads of regional investor-owned utilities. 14. This is not an unusual ratemaking practice for public or private utilities anywhere in the U.S. There is merit in asking whether it is an appropriate federal role. 15. Almost no one in the Northwest wants to go through the experience of amending the Regional Power Act, whether the changes are surgical or sweeping. The assistance of the Northeast±Midwest Coalition (of which Dick Munson is Executive Director) in achieving a reasonable resolution could contribute substantially to needed improvements.
None of the acts' drafters could foresee the dramatic upheaval in Western power markets.
March 2002
# 2002, Elsevier Science Inc., 1040-6190/02/$±see front matter PII S1040-6190(02)00266-X
55
I. Introduction
Jim Harding is Director of External Affairs for Seattle City Light. He has also served as special advisor to two members of the California Energy Commission, Director and Assistant Director of the Washington State Energy Office, and Director of Energy Programs for Friends of the Earth. He is also the author or co-author of four books in the energy field. The views expressed in this article are his own and do not necessarily represent those of Seattle City Light.
March 2002
Dick Munson's article on Bonneville in the October 2001 issue of The Electricity Journal makes some worthwhile points, and some that are simply bad public policy.1 It is entirely appropriate to re-examine the role of the Bonneville Power Administration (BPA). But Munson's prescription misses the most important policy issues and alternatives. unson notes that the BPA markets, at cost, about 45 percent of the electricity sold in the Pacific Northwest, mainly from 29 federal dams on the Columbia and Snake rivers. The agency also owns roughly
M
three-quarters of the region's high-voltage transmission. Munson argues that the federal government's defensible role in electricity marketsÐrural electrificationÐis over; that federal electricity should be sold at market price; and surplus income should go to the U.S. Treasury or for development of new renewable resources and salmon recovery in the Northwest. In the absence of such changes, Munson argues that the Northwest will waste electricity, mismanage low-cost electricity resources, and dodge responsibility for salmon recovery. And market pricing will be good for the Northwest:
# 2002, Elsevier Science Inc., 1040-6190/02/$±see front matter PII S1040-6190(02)00266-X
47
No doubt market-based pricing would correct many of BPA's problems. It would send correct price signals, causing consumers to be more ef®cient, thereby reducing waste and pollution. It would provide an incentive for producers to build new generating units, thereby ensuring an adequate supply of electricity. It would enable all residents of the Paci®c Northwest to access what will still be low-cost hydropower. It would end outmoded taxpayer subsidies.
M
unson's recommendation of market pricing Bonneville's output is remarkably untimely and dangerous for West Coast wholesale markets still reeling from two years of market power abuse by operators far smaller and less influential than BPA. The recommendation makes even less sense in the Paci®c Northwest. By authorizing market pricing of Bonneville's hydro capacity, Congress would be creating a market design in the Paci®c Northwest far more vulnerable to abuse of market power than the market structure adopted by the California Legislature in AB 1890. With 45 percent of regional generating capacity and 75 percent of regional transmission, Bonneville dominates Northwest markets. Bonneville operations directly affect an additional 3,700 MW of non-federal run-of-the-river downstream generation. It is dif®cult to imagine that BonnevilleÐor its successorsÐcould pass either the Federal Energy Regulatory Commission's traditional ``hub and spoke'' test for market pricing, or
48
the newly proposed ``supply marginal assessment'' test. In addition, the public purpose objectives of the Columbia River system, including ¯ood control, navigation, and salmon restorationÐall governed by numerous federal statutes and treaties with Canada and Native American tribesÐare impossible to achieve without coordinated river operations. This coordinated operation is at least unseemly, and possible
Munson's recommendation is remarkably untimely and dangerous for markets still reeling from market power abuse. illegal, in competitive markets. Munson is correct that we need to examine some alternatives to the status quo to better align risks and bene®ts to the U.S. Treasury, improve energy ef®ciency, diminish Bonneville's in¯uence in wholesale power markets, and restore endangered salmon runs.
II. West Coast Market Power and Bonneville The West Coast experimented over the last four years with a largely unregulated, highvolume, day-ahead wholesale power market. For the ®rst three
# 2002, Elsevier Science Inc., 1040-6190/02/$ ± see front matter PII S1040-6190(02)00266-X
years, clearing prices in the California Power Exchange approximated the marginal operating cost of gas generation.2 In 2000±2001, prices reached spectacular levelsÐ10 to 20 times higher, on average, and several hundred times higher, on peak, than levels of the previous year. Many factors can be blamed, including California's market design, scarcity, natural gas prices, NOx markets, FERC's late intervention, and physical or economic withholding of divested gas-®red generation. alifornia subsequently took a number of steps to corral the runaway market. Further divestiture of utility generation has been halted. The California Public Utilities Commission (CPUC) specifically rejected Pacific Gas & Electric's proposal to auction roughly 4,000 MWe of Northern California hydro capacity, citing the potential that the merchant owners of these resources could exercise substantial market power.3 The state Department of Water Resources began purchasing electricity for investor-owned utility customers on a long-term basis, reducing exposure to short-term wholesale markets. Retail wheeling was terminated, mainly to provide financial certainty for long-term contracts. A state power authority was chartered. All of these steps were designed to undercut the influence that merchant plant owners might have on California wholesale market-clearing prices and retail rates. FERC responded on June 19, 2001, to the West Coast wholesale
C
The Electricity Journal
market crisis with a generally effective combination of Westwide price caps and must-offer requirements.4 FERC's June 19 Order speci®cally requires merchant plant operators to offer all available capacity in short-term forward markets throughout the West. The agency took this step because of credible evidence of physical and economic withholding of generation from fall 2000 to spring 2001. FERC speci®cally exempted Western hydroelectric capacity from this requirement, because a mustoffer requirement would probably result in operations that are inconsistent with state and federal license requirements, and the multiple uses of hydro reservoirs. Outside California, West Coast public and private utilities with load service obligations generally rebuilt their long-term supply portfolios before FERC's June 2001 Order. This reduced or eliminated their exposure to short-term wholesale market prices, but in many cases locked in high-priced long-term deals.5 Retail competition has been deferred or abandoned in many states and service territories. onneville could play a remarkably powerful role in West Coast wholesale electric markets. The agency controls more capacity (about 21,000 MWe) than all divested merchant generation in California (18,471 MWe peak), and far more than any individual merchant plant owner (less than 4,000 MWe). Its operations directly affect more than
B
March 2002
3,700 MW of downstream, non-federal, run-of-the-river hydro generation. Several years before the current crisis materialized, Jim Bushnell showed that Bonneville, acting singly, and without limits on its pricing ability, could double September wholesale market clearing prices. If BPA's capacity is used in conjunction with some California fossil generation, clearing prices could triple.6
FERC's Order speci®cally requires merchant plant operators to offer all available capacity in short-term forward markets. Bonneville responded by arguing that Columbia River ¯ow requirementsÐfor ®sh, navigation, and water qualityÐand long-term power sales contracts prevent Bonneville from operating in ways that could substantially increase PX clearing prices. This is probably correct. If Congress auctioned long-term rights to BPA output, one would expect the winning bidder to be a merchant plant operator with California fossil-fueled generating capacity, able to exercise market power. Such an operator would be constrained by Columbia River ¯ow requirements, but would probably not be constrained by
BPA's current power sales contracts. Hydroelectric generation, with trivial incremental operating costs and storage, is uniquely able to in¯uence energy and ancillary service markets. Such in¯uence is not easily regulated, particularly when operations may be driven by a number of non-energy market factors, including irrigation requirements, ¯ood control, water quality, salmon restoration, and navigation. The usual remedy for this problem is continuing sale of output at cost or a ``must run'' or ``must offer'' designation. ``Must run'' designations are not easily applied to hydro capacity, as FERC noted in its June 19, 2001 order. In short, generation availability may be impossible to enforce and generation withholding may be impossible to preclude. Any pro®t-maximizing entity, or set of entities, with unencumbered access to Bonneville assets likely would have sold power last year at a much higher price than BPA's actual transactions with the California Power Exchange and Independent System Operator. Continuing sale of the bulk of Bonneville's output at cost is a better long-term approach.
III. Northwest Electric Markets and Bonneville If market power is a barrier to market pricing of Bonneville's assets in West Coast markets, it is an even bigger barrier in the Paci®c Northwest for reasons that
# 2002, Elsevier Science Inc., 1040-6190/02/$±see front matter PII S1040-6190(02)00266-X
49
involve Bonneville's generation dominance, Columbia River hydrology, transmission ownership, and federal statutes. oughly 63 percent of Northwest electricity comes from hydropower. The equivalent figure for the rest of the nation is just under 5 percent.7 Hydro systems can and do operate in restructured markets, such as Norway and New Zealand. However, there is one key difference between Northwest hydro and those systems: the vast majority of Northwest electricity comes from one hydrologically interconnected system (the Columbia), not from separate fjords and rivers. The bulk of Northwest storage sits behind the 6,800 MWe Grand Coulee dam and in southern British Columbia; the operation of Grand Coulee alone directly (e.g., through runof-the-river downstream dams) or indirectly (through market conditions) influences the pricing and operation of all hydro and thermal generation in the Northwest. Thus, BPA manages not only the 45 percent of the region's electricity it supplies; it also directly in¯uences an additional 3,700 MWe of non-federal downstream dams and, through power market and transmission conditions, in¯uences all the other generation in the region.8 Because of its very nature, BPA fails both FERC tests for market pricing, whether FERC uses its traditional ``hub-and-spoke'' test (generation market share less than 20 percent) or the recently proposed ``supply
R
50
margin assessment'' test (under which at least some capacity of a single owner must be used to meet regional peak demand).9 There are many possible ways to market price BPA's output, including short- and long-term sales and auctions, with maximum limits on ownership share.10 Some may do a better job than others of minimizing market power, but all require vigilant oversight to prevent abuse. The
Each of many possible ways to market price BPA's output requires vigilant oversight to prevent abuse. speci®c power behind Grand Coulee dam is indivisible. Multi-purpose uses of the Columbia River system also lead to coordination of a sort that would be intolerable in competitive markets. For decades, NorthwestÐincluding CanadianÐhydro and thermal plant operators have coordinated operations to meet a number of non-electric system objectives, mainly ¯ood control, navigation, and more recently, salmon restoration. The inherently centralized management of this system is fundamentally incompatible with a fully competitive wholesale power market.
# 2002, Elsevier Science Inc., 1040-6190/02/$ ± see front matter PII S1040-6190(02)00266-X
It is, in fact, a closely coordinated market that would make any antitrust litigator blush, were it not for the underlying public purpose objectives of the system. Traditionally, Bonneville has sold all its ®rm output (i.e., output in poor water years) at cost under long-term contracts. This still left a dif®cult investment environment for new capacity, with low average electricity prices in the region, very substantial ¯uctuations in the availability of non®rm surplus power, and challenges for load forecasting. The Northwest did a poor job of load forecasting in the 1970s, and an even worse job of building lowcost new capacity to meet need, all of which culminated in the Washington Public Power Supply System (WPPSS) debacle of the late 1970s. ongress addressed these challenges in the 1980 Northwest Regional Power Act. The Regional Act blessed Bonneville's dominant position in Northwest generation and transmission, and directed the agency to leverage that position on behalf of a variety of regional purposes. The Act made BPA potentially responsible for meeting all load growth of public utilities in the Northwest, and all residential and small farm loads of the region's investor-owned utilities. BPA resource additions were to emphasize conservation and renewable resources under the supervision of a regional multistate Northwest Power Planning Council, an interstate compact whose members are appointed by
C
The Electricity Journal
the four Northwest Governors. Northwest aluminum smelters would receive power from Bonneville for a transitional period, after which many contemplated that they would become industrial loads of consumer-owned utilities. The Act moved the region in the direction of a oneutility model, with resource decisions driven by least-cost planning principles, overseen by a regional board. Ratemaking directives of the Act reinforce Bonneville's central role. BPA's power is sold at a melded price, with more than 8,000 average MW of low-cost hydropower averaged in the higher cost of new resources. This feature was speci®cally designed to discourage any possibility of another WPPSS escapade. Any utility would be foolish to invest in higher-cost new generation when Bonneville could deliver the same kWh at a melded price. In addition, a utility that developed its own generation would lose access to the same amount of Bonneville generation. his model arguably worked well until the passage of the 1992 National Energy Policy Act. The 1992 Act exempted the Northwest from its transmission provisions, but this exemption proved impossible to sustain. National policy on competitive wholesale markets and open access transmission is fundamentally incompatible with centrally planned resource acquisition and Bonneville's growing load obligation. In the central planning model, Bonne-
T
March 2002
ville is largely responsible for deciding what kind of plant to build when and where. Utility customers have little, if any, choice. With open access transmission, utility customers can pick and choose, and can bypass Bonneville, leaving potential stranded costs, yet the agency is directed by statute to continue to acquire new resources for custo-
mers that may yet return. All of these issues were to confront the Northwest in the mid-1990s.
IV. Growing Tensions between the Regional Act and Wholesale Competition Under the 1980 Regional Act, the Northwest initially pursued the least-cost planning principles in the Act. While retail rates were among the lowest in the nation, Bonneville's resources were limited and new resources, whether fueled by gas, coal, or uranium, were much higher in cost. This created substantial incentives for Bonneville and private utilities to
invest directly in end-use ef®ciency. Ef®ciency investments in the Northwest were not geared to peak demand, but to all sectors and seasons, because the region's hydro system is energy-constrained rather than capacityconstrained.11 Under the direction of the Regional Power Council, Bonneville, public utilities, and private utilities invested heavily in conservation resource acquisition. By the mid-1990s, the West Coast market had changed, with overcapacity in generation and transmission, gas production and pipeline capacity, and FERC's open access rules. Power prices fell to levels below $20/MWh. Regional conservation investments fell substantially. Regional supply investments also disappeared. There was nothing inherently wrong with this outcome; both investments were then less cost-effective and, with huge uncertainties about the pace and scope of state and federal deregulation, much riskier. With the opening of the California Power Exchange in April 1998, the short-term wholesale market grew enormously. The California PX routinely and transparently cleared tens of thousands of MW every hour, compared with the 50±100 MW historically traded at other Western market hubs. The Northwest and California relied increasingly on each other, and a robust wholesale power market, to meet expected demand. From 1995 to 1998, Bonneville's melded wholesale electric price
# 2002, Elsevier Science Inc., 1040-6190/02/$±see front matter PII S1040-6190(02)00266-X
51
was temporarily above levels in the wholesale power market, and the agency lost customers. The Regional Act did not foresee this possibility, and offered little or no guidance on the recovery of stranded costs. With the assistance of then Energy Secretary Hazel O'Leary, the Northwest Governors convened a Regional Review to consider alternatives for Bonneville. The review concluded that it was inappropriate for the federal government, through BPA, to play a dominant and growing role in Northwest electricity markets. Instead, it concluded, existing resources should be allocated through long-term contracts beginning in October 2001 with historical customer groups. With Bonneville prices slightly higher than the West Coast wholesale market, utilities would take a calculated risk that they could pass along higher costs to retail customers, even with state or federally mandated retail wheeling. The review also concluded that BPA's transmission, representing 85 percent of regional high-voltage capacity, should be operated separately from the rest of the agency.12 either the drafters of the Regional Review nor those of the Regional Power Act could foresee the dramatic upheaval in Western power markets, beginning in spring 2000. Suddenly, BPA found that historical customers wanted far more electricity than the agency could reasonably offer. To avoid huge rate increases and involuntary curtailments, a
N
52
number of compromises were struck, including voluntary curtailment of most of the region's aluminum smelters. BPA has largely followed the recommendations of the Governors' Regional Review with regard to new resources; most new load is covered through longterm contracts, although diminished hydro supply and soaring
Western market prices in early 2000 and much of 2001 led BPA to impose a 46 percent across-theboard rate increase for its new round of contracts, which became effective Oct. 1, 2001. Munson's article argues that Bonneville, as a federal agency, made a number of decisionsÐon continuing service to aluminum companies, on resource acquisitions, and on exposure to the wholesale marketÐthat local and state regulated utilities would not make. This may or may not be true. Many public and private utilities, whether long or short on supply and with or without retail access, made decisions during this period that they have learned to regret.
# 2002, Elsevier Science Inc., 1040-6190/02/$ ± see front matter PII S1040-6190(02)00266-X
M
unson's article also makes several points about BPA that deserve response. It is not true that the difference between market price and Bonneville rates amounts to a $16±34 billion federal subsidy to the Pacific Northwest. Many private and nonfederal publicly owned hydro projects in the Northwest deliver extremely low-cost electricity. If there are subsidies embedded in federal Northwest hydro projects, they would arise in two key areas: differences in risk and cost of money between locally and federal financed hydro projects (real, but relatively trivial) and complicated federal accounting treatment for the multi-purpose nature of federal dams. Most Northwest federal hydro facilities were predominantly built for ¯ood control, navigation, and irrigation. Electricity was an important by-product of these projects, but it was not a central motivation. That said, electric ratepayers in the region pay most project costs. Many utilities in the region would agree with salmon advocates that agricultural diversions, particularly in southern Idaho, help neither the hydro system nor salmon recovery. But they remain as statutory objectives, as dif®cult to evaluate in hindsight as the associated accounting. But it is hard to conclude that the Northwest is subsidized to a greater or lesser extent than, e.g., Great Lakes bene®ciaries of the St. Lawrence Seaway. Perhaps ironically, the Northwest and California, despite The Electricity Journal
dramatic differences in the two regions' industry structure, both found themselves dependent on a robust short-term wholesale power market that turned expensive, unreliable, and volatile. Neither region had built capacity in advance of a suddenly dire need. That responsibility was left unresolved in California, and it was confused by and divided between utilities and Bonneville in the Paci®c Northwest.13 Two partially responsible parties may be better than none, but it is hard to escape the conclusion that one may be the better answer. Neither region has yet addressed the central question of responsibility for adding resources in advance of need, and whether this will be done by public agencies, publicly owned utilities, privately owned utilities, or through continued reliance on a merchant plant industry that has generated doubt, litigation, and fear. In the interim, the Northwest and Bonneville need clari®cation on Bonneville's roleÐin particular, on its obligation to serve, on utilities' obligations to take, and on who is responsible for building new generation and transmission resources.
V. Long-Run Alternative Roles for Bonneville Munson is correct that BPA's long-term role deserves prompt review. But there are many better alternatives than market pricing. March 2002
I
t is probably fair to look at three principal options. The status quo is one of them. BPA could ``grow'' the system through contracts and resource acquisition under the terms of the Regional Power Act. Alternatively, BPA could stop growing, and allocate existing resources, presumably to its historical customers. Finally, BPA or its output could be sold on
a very long-term basis, either at cost or at market. (1) Status quo: This state of affairs is difficult to defend, but easy to explain. BPA has a growing regional retail load obligation that it is increasingly unable to meet. It does not meet current ``public'' and ``regional'' preference loads that public and private utilities in the region place upon it. It also does not have sufficient generation to meet the optional requirements of direct service industries. In the best case, the agency would continue to invest in regional efficiency improvements, renewable resources, transmission, and provide lowcost backup or supplementary
generation for new wind projects. But the agency is properly nervous about acquiring several thousand MW to meet currently unmet and growing regional demands, especially for loads that could shift to other providers if Western power markets go through another boom-and-bust cycle. BPA's full compliance with Orders 888, 889, and 2000, and creation of a successful RTO, may be difficult without significant statutory changes. A growing BPA would also need explicit direction on recovery of potential stranded costs. The agency would also become increasingly dependent on an annual appropriations process that provides little security for the long-term investments the region will require, most urgently in transmission expansion. (2) Allocate generation output to historical customers. This option more easily accommodates national policy on transmission and generation than the status quo. It is also consistent with the evolution of other federal power market administrations. It does require difficult decisions on how the federal power resource is allocated. Under the terms of the Northwest Power Act, this would imply preferential service to public utilities and residential and small farm customers of investor-owned utilities. BPA resources could also be allocated on a basis proportional to population, or to historical dependence on BPA's resources. One promising model, incorporated in new contracts effective Oct. 1, 2000, is
# 2002, Elsevier Science Inc., 1040-6190/02/$±see front matter PII S1040-6190(02)00266-X
53
termed slice of the system. Unlike traditional contracts, slice contracts do not grow with load, but are instead fixed for the life of the contract. Utilities buy a share of the output of the federal system for a share of total costs. They bear responsibility for matching output to customer loads, and must acquire their own supplemental resources to address drought or growth. This model meets one longstanding and probably legitimate concern of the Northeast Midwest CoalitionÐthat the ratemaking directives of the Northwest Power Act put a federal agency in the position of serving new industrial loads at prices below marginal cost.14 A long-term solution would probably require amendments to the Northwest Power Act, at least on obligation to serve, ratemaking directives, and separation of transmission assets from the general obligations of the agency.15 (3) Finally, BPA could be sold, either to the region's utilities or at auction. The auction option raises all the market power and multipurpose use issues raised earlier. The resource is worth the most if sold intact to an unregulated merchant plant operator with fossil resources, able to exercise market power in Northwest or West Coast markets. The resource is worth least if sold to regional utilities that pledge to resell at cost to customers. It is difficult to imagine resolution of these issues, without insuperable conflicts between Congress, FERC, and the Northwest Congressional 54
delegation. There are also the difficult question of governance, given the irreducible federal interest in a number of non-electric system Columbia River issues, including tribal and Canadian treaties, navigation, flood control, and irrigation. rom a Northwest perspective, the most attractive of these options is probably alloca-
F
resource additions is still challenging, particularly for capacity additions in advance of dire need that can remove some volatility from wholesale prices and restore greater stability to West Coast wholesale power markets.& Endnotes: 1. Richard Munson, Rethinking Bonneville, ELEC. J., Oct. 2001. 2. California Energy Commission, Wholesale Electricity Price Review, 1998± 2000. 3. Many reasons underlie the discomfort with further divestiture, but effects on energy and ancillary service market power could have been substantial and, given the multi-purpose nature of these facilities, extremely difficult to police. FERC acknowledges this point in its June 19, 2001 Order, specifically exempting Western hydro facilities from the requirement to offer all available capacity to the California ISO.
tion, perhaps as an interim step to some form of regional acquisition. This step could be compatible with open access transmission, the development of regional transmission organizations, and a more competitive wholesale power market. It would reduce BPA's central involvement in the Northwest wholesale market, and clarifies that utilities cannot choose between BPA and the market to meet future needs. The federal agency would remain essentially a transmission provider and passive allocator of electricity. Northwest utilities would bear the responsibility for investment in new resources and efficiency improvements. But the investment environment for new
# 2002, Elsevier Science Inc., 1040-6190/02/$ ± see front matter PII S1040-6190(02)00266-X
4. Federal Energy Regulatory Commission, Order on Rehearing of Monitoring and Mitigation Plan for the California Wholesale Electric Markets, Establishing West-Wide Price Mitigation, and Establishing Settlement Conference, June 19, 2001. 5. Most utilities with load service obligations for what appeared to be very tight market conditions in summer and fall 2001 bought long term supplies in spring at significantly higher prices than now prevail. 6. James Bushnell, Water and PowerÐ Hydroelectric Resources in the Era of Competition in the Western U.S., POWER Working Paper 056r, 1998, University of California Energy Institute, Program on Workable Energy Regulation. Bushnell also found that a BPA with market pricing authority would reduce output in a variety of ways that are impossible to police: ``a profit-maximizing BPA may find it generally profitable to convert water to power less efficiently than if it were a price-taking firm. Although efforts to `spill' water around turbines would be
The Electricity Journal
easy to detect, they could be justified, or even required, by environmental restrictions on river system operations. Other far more subtle techniques to manage river flows and reservoir head heights to minimize, rather than maximize, the efficiency of the energy conversion would be virtually impossible to detect.'' 7. U.S. Department of Energy, Energy Information Administration, State Electricity Profiles, 1999. 8. Non-federal run of the river dam capacity below Grand Coulee totals 3,742 MWe, including Wells (774 MWe), Rocky Reach (1,213 MWe), Priest Rapids (855 MWe), and Wanapum (900 MWe). 9. Federal Energy Regulatory Commission, Order on Triennial Market Power Updates and Announcing New, Interim Generation Market Power Screen and Mitigation Policy, Nov. 20, 2001. 10. An annual auction of output to Northwest load-serving entities, with price capped at marginal cost and
operational decisions remaining in federal hands, is probably the best approach for limiting market power. But this injects substantial planning uncertainties and offers no compelling long-term benefits. 11. Even in the difficult 1990s, regional conservation efforts saved about 750 average MW, equal to about 4 percent of total demand. This was about half the level achieved in the previous decade. Some utilities, e.g., Seattle, maintained conservation programs in the 1990s that effectively cut load growth in half. 12. BPA transmission assets are encumbered by the general obligation of the agency. It is difficult to do full separation without resolution of the responsibility that BPA's transmission might have for many future system costs, including salmon recovery and WPPSS debt. Meanwhile, it is difficult for regional investor-owned utilities to participate in an RTO with BPA knowing that these obligations are unresolved.
13. BPA's statutory responsibility to meet net loads of public utility and residential and small farm loads of investor-owned utilities is clear in statute, but the obligation is not as binding as a retail utility's obligation to serve. BPA meets all public preference in the region, but only about one-third of the residential and smallfarm loads of regional investor-owned utilities. 14. This is not an unusual ratemaking practice for public or private utilities anywhere in the U.S. There is merit in asking whether it is an appropriate federal role. 15. Almost no one in the Northwest wants to go through the experience of amending the Regional Power Act, whether the changes are surgical or sweeping. The assistance of the Northeast±Midwest Coalition (of which Dick Munson is Executive Director) in achieving a reasonable resolution could contribute substantially to needed improvements.
None of the acts' drafters could foresee the dramatic upheaval in Western power markets.
March 2002
# 2002, Elsevier Science Inc., 1040-6190/02/$±see front matter PII S1040-6190(02)00266-X
55