NORTHWEST ENERGY REVIEW TRANSITION BOARD
BACKGROUND PAPER
TRANSITION COSTS:
A REVIEW OF PRACTICES AND THEIR POSSIBLE APPLICATION TO BONNEVILLE
JUNE 23, 1997
97-TB8
| Northwest Energy Review Transition Board 851 S.W. Sixth Avenue, Suite 1100 Portland, Oregon 97204-1348 |
John Etchart, Montana Roy Hemmingway, Oregon |
| Phone 503-222-5161 or
1-800-452-5161 FAX 503-795-3370 |
Mike Kreidler, Washington Todd Maddock, Idaho |
TO: Interested Persons
FROM: Transition Board
SUBJECT: Staff Background Paper on Transition Costs and Process for Addressing Bonneville’s Possible Transition Costs
We agree with the view that effective cost controls and a successful subscription process are the best means of preventing Bonneville’s possible transition costs. However, we cannot guarantee success. We have received comments on both sides of the transition cost issue. Some have warned us that addressing transition costs would distract from efforts to bring about a successful subscription process. We have also received comments urging that we not defer discussion of transition costs until the subscription process is complete. In the final analysis, we believe that if the region’s efforts are going to have a positive reception in Washington DC, we will have to incorporate a realistic transition cost recovery mechanism as a contingency.
To respond to these concerns, we intend to carry out a process to discuss Bonneville’s potential transition costs. This process should go forward parallel to but somewhat slower than the subscription process. We hope that will not detract from the subscription discussions. To initiate this process, we have asked staff to prepare the attached background paper. The purpose of this paper is to review the fundamentals of transition costs, how transition costs have been treated in a few relevant examples, and to draw some parallels and distinctions between Bonneville’s situation and the examples. We then intend to proceed by asking staff to work with customer groups and other interests to develop a set of proposed principles that could be the basis for the design of a transition cost recovery process for Bonneville. It is our intent that those principles be presented and discussed at a meeting later this summer. If we can reach reasonable agreement on the principles, we propose to work with the interests to explore and narrow the alternatives for transition cost recovery. Concurrently, we will be asking Council staff in consultation with Bonneville and other interests, to analyze Bonneville’s potential transition cost exposure under a variety of scenarios. Our objective is to reach agreement on a contingent transition cost recovery mechanism by the end of the year.
We understand that many parties would rather not take up the issue of transition costs at this time. While we understand the reasons behind these concerns, we are convinced the region must show some progress on this issue to keep outside interests from taking over the issue. We hope that all parties will participate constructively to resolve this difficult issue.
| Attachment |
TRANSITION COSTS – A REVIEW OF PRACTICES AND THEIR POSSIBLE APPLICATION TO BONNEVILLE
The potential for Bonneville to be unable to fully recover its costs at market prices is one of the most difficult and controversial issues surrounding the transition to a restructured electricity industry in the Northwest. We will refer to those unrecoverable costs as transition costs. The purpose of this background paper is to begin a regional conversation on transition costs. It is intended to: 1) establish a common understanding of what transition costs are and are not; 2) review how the issue has been dealt with in a few instances where transition cost recovery mechanisms have been established; 3) identify some common features of transition cost recovery mechanisms that have been developed; and, 4) describe some of the unique features of Bonneville’s situation which may contrast with the examples in some areas. It is clearly understood that ways in which transition costs have been addressed in other instances may not all be appropriate for Bonneville due to Bonneville’s unique situation. Nevertheless, these are features that should be considered as the region explores this issue. The paper concludes by suggesting some "next steps" that might be taken to resolve the issue for Bonneville. Nothing in this paper is intended to suggest that Bonneville will or will not have transition costs. So long as Bonneville can recover sufficient revenues to cover its costs it does not have transition costs. Consequently, the best transition cost mechanisms are effective cost control and a successful subscription process that prevents transition costs from occurring. However, despite the best efforts of all involved, transition costs could occur. The question this paper begins to address is the contingency – if Bonneville does experience transition costs, how should they be handled?
| What are Transition Costs and Transition Cost Recovery? |
In general, transition costs are a utility’s previously incurred, unavoidable fixed costs or liabilities that cannot be recovered at competitive market prices. They could include investment in generating resources, generation-related liabilities like power-purchase and fuel supply contracts; so-called regulatory assets such as deferred expenses; and costs of public policy programs such as extraordinary environmental costs, DSM programs, or low-income assistance. [ Baxter, Lester, Eric Hirst, and Stan Hadley, "Transition Cost Issues for a Restructuring U.S. Electricity Industry," ORNL/CON-440, Oak Ridge National Laboratories, March, 1997, p 2.]
Transition cost recovery typically is a mechanism to facilitate the transition from a monopoly past to a competitive future. In that past, utilities were virtually assured of recovery of prudent investments as a result of their monopoly status. In return for this reduced risk, investor owned utilities were constrained to earning a regulated rate of return that was less than that which might be earned in competitive markets. Consumer owned utilities do not have a rate of return but they too have been considered low risk enterprises. Revenue bonds issued by such utilities have generally been considered to be very secure. The opening of competition changes this situation. In the competitive future, utilities will be constrained to charge market prices. They may be able to earn a profit at those prices. However, they face the risk that the market price may be insufficient to cover all of their fixed and operating costs.
Transition cost recovery allows recovery of some or all of the sunk costs for prudent investment decisions that were made in the past that cannot be recovered at market prices. Typically, recovery is limited to investments made prior to a date when it should have been clear that the utility would become subject to competitive risks. The costs are generally recovered from the utility’s historic customer base (service territory), either on an individual basis or in aggregate. To the extent that transition costs are not recovered from departing customers, they fall on the investors and/or remaining customers. Transition cost recovery prevents or moderates cost shifts from those customers who leave a utility to the utility’s investors and those customers who stay.
The transition cost charge is set to recover the net difference between what the utility would have received had its monopoly been maintained and what it will receive in the competitive future. That is, the difference between revenues based on average operating costs and fixed costs including return on investment, and revenues from sales at market price. [ Transition costs recovery is based on the cost of the entire system rather than individual or only above-market resources. To do otherwise would penalize customers and give the utility an unfair advantage.] This difference is calculated over the useful life of the investments or, alternatively, the period over which the utility could reasonably be assumed to be obligated to provide service. If the situation were one in which a utility were losing customers for whom it had time-limited contracts with no expectation of continued service, transition costs might be figured only over the remaining life of the contract. If there were a reasonable expectation of continued service, the period might be the useful life of the resources. The amount of recovery allowed is capped by the fixed, unavoidable costs the customer would have paid. [ Transition costs recovery might more accurately be called stranded investment recovery. The purpose is to recover past investment, not subsidize operating costs. In a competitive market, competition is on the basis of avoidable operating costs. If a unit’s operating costs exceed the market price, it should not be run. Its unavoidable, fixed costs, however, would still be eligible for stranded cost recovery. ]
It is possible that a utility might have positive transition costs (costs greater than market price) at one time and negative transition costs (costs less than market) at some point in the future. Those negative transition costs might be termed "windfall profits" because, like the losses associated with above-market costs, they would not have been experienced had the market not been opened up to competition. The amount of the transition cost recovery is equal to the estimate of the net present value of the combined positive and negative transition costs. The future profits offset some of the losses from above market costs.
Transition costs can be determined in a one-time, up-front estimate of future costs and market prices or in a periodic determination (e.g., annually or every X years). The up-front estimate can be obtained either administratively – a forecast by some regulatory body – or by market means – for example, auctioning off the system assets to determine their market value. In either process, we are talking about estimates of future conditions and those estimates are likely to be wrong. The advantage of the one-time estimate is certainty for those paying the transition costs and the fact that a one-time determination can give the owner ample incentive to improve efficiency and cut costs. The periodic determination or "true-up" will be more accurate but results in uncertainty regarding the transition cost obligation and possibly reduced incentive to control costs and thereby reduce or mitigate transition costs.
Mitigation of transition costs is an important principle of transition cost recovery. The dollars involved in transition costs are potentially large. If customers are to see lower costs in the near term as a result of competition, efforts must be made to see that transition costs are kept as low as possible. One obvious mitigation is to maximize the revenues from marketing any energy and capacity freed-up by customers who leave. One approach is to allow those who will be subject to the transition cost charge the ability to market the freed up energy and capacity. They clearly have every incentive to get the greatest price for it. The other side of the equation is reducing the utility’s costs – re-negotiating above market purchase contracts, refinancing high interest rate debt, instituting operating efficiencies, and so on. Operating in a monopoly environment has probably not resulted in every possible efficiency improvement to be wrung out of the system. It is incumbent upon whoever establishes the allowable transition cost recovery to ensure that those kinds of cost reductions are incorporated in the transition costs estimates or that there is some true-up mechanism to credit such savings against the transition cost charge. Many argue that a market estimation of the value of the system is likely to more fully reflect the opportunities for increasing revenues and reducing costs. [ See Lesser, Jon and M. Ainspan, "Using Markets to Value Transition costs," The Electricity Journal, October, 1996, pp. 66-74.]
An often-heard criticism of transition cost recovery is that it distorts competition, i.e., confers a competitive advantage on the utility allowed transition cost recovery. This does not need to be the case. [ This argument is discussed in detail by Paul Joskow in "Does Stranded Cost Recovery Distort Competition?" Electricity Journal, April, 1996 pp. 31-44.] [ See also Tye, William B. and Frank C. Graves, "Stranded Cost Recovery and Competition on Equal Terms," The Electricity Journal, December, 1996, pp. 61-70.] In a competitive market, competition is based on avoidable costs. Sunk costs are sunk costs. They are going to be paid, whether by customers or utility owners or creditors; the only question is by whom. The transition cost recovery mechanism decides that question. Once the transition cost charge is established, the owner has every incentive to operate that plant as efficiently as possible and not operate it if its avoidable costs are above the market. These are exactly the same incentives as if there were no transition cost recovery. Competitors operate if they can recover their avoidable going forward costs and earn anything to contribute to fixed costs.
Transition cost recovery can be inequitable. The transition cost allowance may be overly generous and or overly parsimonious, resulting in greater cost transfers than are equitable to customers or stockholders. The efficiency of the market, however, is not adversely affected. Competition will still be on the basis of the avoidable costs. If, however, periodic true-ups of the transition costs are allowed and those true-ups are not limited to those factors that are completely beyond the control of the owner, the incentive to operate as efficiently as possible would be reduced.
| How have Transition Costs Been Treated? |
The following sections review the provisions that have been established to deal with transition costs in three separate instances. They are: the Federal Energy Regulatory Commission’s (FERC) stranded cost rule; the transition costs provisions in AB 1890, the law opening California’s retail electricity markets to competition; and the final restructuring order of the New Hampshire Public Service Commission. While none of these examples exactly replicates Bonneville’s financial and regulatory situation, there are enough commonalities in the examples that the experiences may contain important insights.
The FERC transition costs provisions are contained in FERC Order 888 (April 24, 1996) and 888a (March 3, 1997). The orders implement the open access provisions of the National Energy Policy Act of 1992. This section is not meant to imply that Bonneville is necessarily subject to the transition cost provisions of 888. It is meant merely to be illustrative of an approach.
These provisions are focused on wholesale transactions and transition costs created by the Commission’s opening of access to a utility’s transmission system. [ Transition costs created by a wholesale customer availing itself of an alternative transmission path or self-generation would not be eligible for recovery because those opportunities were not created by the Commission’s open access order.] The Commission states its determination that "the recovery of legitimate, prudent and verifiable stranded costs" created as a result of customers leaving a utility’s generation system through commission-ordered open-access tariffs or Federal Power Act Section 211 orders should be allowed. Generally, speaking, only costs included in the utility’s revenues for the three years prior to the customer’s departure would be eligible for recovery. In order to recover these costs, the utility must demonstrate it had a reasonable expectation that it would continue to serve the customer. Contracts entered into after July 11, 1994 and not having explicit transition cost provisions would not be subject to transition cost recovery.
The Commission directly assigns the transition costs to the departing customer in the form of an exit fee or a surcharge on transmission service to that customer. In so doing, it specifically rejected the idea of a broad-based charge to all transmission users or to stockholders. The inequities and the adverse effect on the efficient use of the transmission system of a broad-based transmission charge were compelling arguments against such a charge. A "transmitting utility" like Bonneville could, if its transition cost recovery were based on the FERC ruling, only use the transmission surcharge approach. This is because FERC does not have jurisdiction over BPA’s contracts and is not, therefore, able to impose exit fees on the contracts, unlike the case of public utilities regulated under sections 205 and 206 of the Federal Power Act.
FERC requires what it calls the "revenues lost approach." This is a one-time, up front determination. The transition cost obligation (SCO) is:
SCO = the lesser of:
1) the average annual contribution to fixed costs that would have been made by the departing customer; or
2) NPVL (RSE-CMVE), where
NPVL = net present value over the length of the obligation;
RSE = revenue stream estimate – the annual revenues the utility would have received from the departing customer based on the three years of revenue prior to leaving, less the annual transmission revenues the utility will continue to receive. The assumption is that the rates the customer pays include all the costs of providing service; and, since the rates have been approved by regulators, the costs have been judged to be prudent, legitimate and verifiable.
CMVE = competitive market value estimate — either what the utility estimates it can receive by selling the power freed by the loss of the customer OR the cost to the customer of the equivalent power services from its new supplier. Alternatively, the customer has the option of marketing or brokering the released energy and capacity itself.
The determination of the length of the obligation is critical. The key question is whether the utility had a reasonable expectation of continuing to serve a customer. The expiration of the contract or the presence of notice provisions creates a rebuttable presumption that the utility had no reasonable expectation that the customer would remain a customer. It would be up to the utility to demonstrate to FERC that it did have a reasonable expectation of continuing to serve. [ FERC Orders 888 and 888a do not treat what happens when transition costs cannot be recovered from the leaving utility. In their initial stranded cost notice of proposed rule making, the commission suggested that it anticipated that utilities would seek to have such costs reallocated to its remaining customers.]
FERC believes that its method encompasses mitigation of potential transition costs. This is accomplished by reducing the amount of transition cost recovery by the competitive market value of the energy and capacity released and by giving the departing customer the option of marketing or brokering the released energy and capacity. There does not appear to be much explicit mitigation on the cost side. The FERC approach takes the revenue stream based on current rates and assumes that since those rates have passed regulatory scrutiny, the costs must have been prudently incurred. The ability of the utility to reduce its costs does not appear to enter into the consideration.
The Commission expects the parties to attempt to resolve disputed issues. In the event they fail to do so, the parties may seek a determination from the Commission. When FERC exercises oversight over a utility’s transition cost determination, there are evidentiary standards that must be met; and a set body of procedures for establishing transition costs which are intended to ensure full recovery of legitimate, prudent and verifiable transition costs while requiring the utility to mitigate transition costs.
| California | Back to the top |
Assembly Bill 1890 (AB 1890), passed by the California Legislature in August 1996 and signed into law September 23, 1996, codified the results of the industry restructuring effort begun in 1994 with the publication of the California Public Utilities Commission’s (CPUC’s) "Yellow Book." The law provided for, among other things, the recovery of costs stranded by retail open access through a non-by-passable competition transition charge (CTC). The law primarily addressed the investor-owned utilities (though there were provisions for publicly owned utilities) and the following does as well, unless specifically noted.
Several major categories of costs are eligible for recovery. The first is costs of generation facilities, generation-related regulatory assets, and power purchase contracts that were being collected in CPUC-approved rates as of December 20, 1995. A second is costs incurred after that date for capital additions to previously existing generation that are necessary to maintain the facilities through December 31, 2001 and are approved by the CPUC. Generally, the transition costs described above are only allowed to be recovered prior to December 31, 2001, with specific extensions primarily for certain employee transition costs and for power purchase contract obligations. There is also an extension associated with recovery of cost not recovered due to a mandatory rate reduction, described below.
A third major category of costs is nuclear decommissioning costs, which are to be recovered as a non-by-passable charge until they are fully recovered, with no limit on the recovery period.
PG&E has filed a request with the CPUC to be allowed to recover certain costs associated with ongoing and upcoming hydro relicensing efforts. These costs, including required environmental mitigation costs, have not yet been incurred. The request is not open-ended and a specific amount of money to cover these costs has been estimated and is part of the filing before the CPUC. This request may fall under the capital additions section of AB 1890.
Transition costs are to be recovered from all customers, generally in proportion to customer class recovery of similar costs as of June 10, 1996. The mechanism is to be a usage-based non-bypassable charge. The rates including the CTC are to be determined by the CPUC, and are subject to several other provisions that require rate freezes, or in the case of residential and small commercial customers, rate reductions of at least 10 percent through March 31, 2002. This is to be accomplished by securitizing the rate reduction portion of the transition cost obligations of these customers into bonds to be sold by another state agency, repayable over a longer period of time by the same customers.
Most transition costs are to be determined by a calculation that will net the negative value of all above-market costs against the positive value of all below-market costs. Generally transition costs exclude operating costs, except for those related to specific operations of certain plants necessary for local voltage-support and to certain employee transition costs. The market value of generating assets is to be determined no later than December 31, 2001, based on appraisal, sale or other divestiture. After that date, these assets are subject to market risk, and there is no more transition costs recovery for these assets. Certain other categories of transition costs can be recovered over longer periods of time.
Prior to that date, generation transition costs are either recovered directly as a competition transition charge or implicitly as the difference between the frozen retail rate and a specific set of costs, including market priced power supply costs represented by purchases from the Power Exchange for those retail customers who continue to purchase power from the utilities.
Nuclear decommissioning costs are separately recoverable and are not subject to the calculation of net value described above.
There is no separate provision for mitigation in the California law. Incentives for mitigation exist by virtue of the limited recovery period. In addition, the equity return that is allowed on undepreciated assets subject to transition cost recovery is reduced to 90 percent of the embedded cost of long-term debt, which directly mitigates the effect on customers.
The CPUC determines the size of the transition costs.
| New Hampshire | Back to the top |
In May of 1996, the New Hampshire legislature directed the state utilities commission to develop a restructuring plan for the utilities in the state leading to open access for all customers by January 1, 1998. The plan was adopted by the Commission this January. [ Information on the New Hampshire plan was obtained from DR 96-150, the Statewide Electric Utilities Restructuring Plan, February 28, 1997. The Summary and the full plan can be obtained at http://www.state.nh.us/puc/dr96150.html.] Their plan includes provisions for recovery of transition costs. Implementation of the final order, however, has been held up by a restraining order because one of the utilities affected contends that it would result in under-recovery of transition costs and could lead to bankruptcy for its subsidiaries doing business in New Hampshire. Like California and unlike FERC, New Hampshire’s transition cost provisions are tied to the opening of retail competition.
The Commission found the most appropriate definition of transition costs to be "net" sunk generation costs (including generation-related regulatory assets) that ordinarily would not be recovered if retail consumers were allowed access to alternative generation resources. Not all transition costs, however, would be eligible for recovery. Where management is found to be primarily responsible for the resource decisions leading to transition cost, recovery of the related transition costs will be limited. Where it is found that management discretion over resource decisions was either reduced significantly or eliminated by government mandate, utilities will be provided an appropriate opportunity for full recovery of the related transition costs. Costs of decommissioning nuclear power plants should be included in the transition cost charges. Responsibility for the resource decisions which led utilities to acquire assets which are now or are likely to become uneconomic must be determined on a utility specific basis.
The commission found that less than full transition cost recovery is fair, not inefficient and that full recovery can have anti-competitive consequences. Consequently, unlike the FERC and, to a somewhat lesser extent, California, New Hampshire would allow less than full transition cost recovery. In New Hampshire, the legislature charged the commission with achieving post-restructuring rates that were at least as low as the regional average. Transition cost recovery is at least partially the vehicle chosen to achieve this. Specifically, utilities with rates that currently exceed the regional average will not be allowed full stranded recovery, although each utility will have an opportunity to explain why its shareholders had legitimate expectations of full recovery.
Those transition costs that are allowed to be recovered from consumers are to be recovered from all customers in an unbundled, non-discriminatory, non-bypassable charge. The charge would be kWh based but charged to the consumer no matter who supplied the electricity. The costs are to be allocated fairly among rate classes.
The Commission found that the sale or spin-off of generating assets was the "most accurate and straight forward way to determine their [assets] net worth." Divestiture is to be accomplished within two years of the opening of competition. An interim administrative estimate is used in the intervening period. Although New Hampshire cannot order divestiture for utilities based out of state, they would prohibit those utilities from serving their New Hampshire distribution companies.
The primary means of mitigation is ensuring that divestiture is accomplished in such a way as to recover maximum value for the divested assets. If deferring a sale of some assets would increase the value ultimately received, the commission might allow that. The commission would oversee a utility’s efforts to see that any costs of purchase contracts have been reduced to minimum practicable levels after all cost-effective and legally permissible buy-downs or buyouts have been completed.
The commission is the arbiter of what costs will be allowed, whether mitigation is sufficient and so on.
| Common Elements of Transition Costs Recovery Mechanisms | Back to the top |
In the previous section, we examined several examples of transition cost recovery mechanisms. On the basis of these and other examples, it is possible to identify several elements that are common to most if not all approaches. Care should be taken to remember that, at base, these elements derive from an examination of what is equitable in light of the circumstances under consideration. Their application to Bonneville’s situation might have to be tempered by considerations unique to Bonneville. Some of those unique considerations are discussed in a subsequent section. None-the-less, looking at some of the generally common elements of transition cost recovery mechanisms may be instructive. These elements are:
How is Bonneville’s Situation Different? |
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The common elements described above are derived from specific examples that are responsive to a set of conditions relevant to the particular situation being addressed. In some respects, Bonneville’s situation may be quite similar. In other respects it is probably different. Those differences may well affect how transition cost recovery might be addressed for Bonneville. Some of the key differences are discussed below.
Bonneville, as a federal agency, does not have stockholders who are in the business of bearing risk and making profits, and who might expect to shoulder part of the transition costs, should that be determined to be appropriate. The taxpayers of the United States, as represented by the U.S. Treasury, are closer to the position of mortgage holders for Bonneville. The taxpayers do not usually think of themselves as bearers of risk for Bonneville and because Bonneville is constrained to selling at cost, taxpayers have no opportunity for reward. An argument can be made that the Treasury should bear some of the risk. For example, the non-power purposes of the original dam authorizations suggest that either Treasury or the beneficiaries of those other purposes should shoulder some of the risk. Whatever the logic, whether the Treasury would actually accept more risk or write off or defer recovery of some transition costs is a political question.
For most utilities, the expectation to serve a wholesale customer is limited by the duration of a contract with that customer. Bonneville also has time-limited contracts with its customers expiring in 2001. If a contract contains an expiration date, there is a rebuttable presumption under FERC’s rules that the utility’s expectation of service does not extend beyond the expiration date. Unless BPA were able to overcome this presumption by evidence that it did have a reasonable expectation of service, strict application of FERC rules would mean that Bonneville transition cost recovery would not be allowed.
However, Bonneville also has a lengthy history, legislative and otherwise, that arguably suggests an expectation of continued service to its historical customer base beyond the terms of the current contracts. For example, the federal projects were financed over 50 years, a period much longer than the contracts in place at the time and extending, in many cases, beyond 2001. Similarly, the net billing agreements under which the Washington Public Power Supply System projects financed were entered into with durations that went well-beyond the life of contracts in place at the time and, for that matter, the length of the subsequent contracts authorized in the Northwest Power Act. Senator Henry Jackson, when speaking in the Senate on the Northwest Power Act said, "Reduced to one sentence, the heart of the regional power bill is the authority for BPA to acquire from non-federal entities additional electric power resources, including conservation, to meet the electric needs of Northwest consumers." [ Congressional Record – Senate, November 19, 1980, p.105. ] This suggests that as late as 1980, there was the expectation on the part of Congress that Bonneville must be able to meet the future needs of regional electricity consumers. Indeed, BPA’s 20-year 1980 power sales contracts are repeatedly referred to as "initial" contracts in section 5(g) of the Northwest Power Act. Section 5(g) is the section that directed BPA to offer the 1980 power sales contracts. In addition, unlike other marketers at the wholesale level, BPA is subject to an obligation to serve by section 5(b) of the Northwest Power Act.
Typically, the transition cost recovery mechanisms described above are for recovering previously incurred costs. As noted above, some jurisdictions (but not FERC) have included previously obligated but not yet incurred costs, nuclear decommissioning costs, in the determination of transition costs. Bonneville also faces future nuclear decommissioning costs. However it also faces other, possibly significant, additional future costs in the costs of salmon recovery. Some would argue that since those costs have not been incurred, they should not be included in determining transition costs. However, one could also argue that salmon recovery costs are analogous to nuclear decommissioning costs — an environmental obligation that was not fully known at the time of construction but an obligation none-the-less that is tied to an existing resource. If so, future unavoidable (i.e., those that Bonneville has no discretion to avoid) fish and wildlife costs should be included in the determination of transition costs. The inclusion of such future costs, however, could mean that the period over which Bonneville cannot recover its costs at market prices is extended. In addition, this would intensify the debate over which fish and wildlife costs BPA must bear financial responsibility for.
For most utilities, the transition is from a monopoly, where they are constrained to offering cost-based rates, to competition, where they can sell at market rates with all the potential risks and rewards that competition implies. After what is usually a relatively short transition period, the utility’s owners are clearly risk takers.
In Bonneville’s case, the transition is from a period in which the market may prevent Bonneville from fully recovering its costs to a future with possibly higher market prices and/or lower costs in which Bonneville can again recover its costs. There are, however, no guarantees. After the transition period, Bonneville still does not have risk-taking owners. It could again be faced with conditions under which it cannot fully recover its costs, while at the same time being subject to requirements that it offer power at cost.
Bonneville’s situation is generally like the situation addressed by FERC – transition costs created by the opening of transmission access for wholesale transactions. However, unlike other wholesale utilities, FERC’s current jurisdiction over Bonneville is limited with respect to its regulation of power and transmission rates, the application of the open access provisions and transition costs. Specifically with respect to transition costs, FERC Order 888 states that its application to BPA is only with respect to mandatory transmission requests under section 211 of the Federal Power Act. Order 888A recognized that BPA’s other statutory responsibilities would need to be taken into account by FERC if it were faced with a BPA stranded cost recovery issue under section 211. Even if Bonneville were to seek transition cost recovery under FERC Order 888 for post-2001 contracts, it could only get recovery to the extent that customers agreed to transition cost recovery in the contracts. It is not clear how many customers would volunteer. The absence of contract provisions would then force FERC to deal with the problem of general BPA cost recovery since FERC has a responsibility to ensure that BPA’s rates are based on BPA’s total system costs and assure repayment to the U.S. Treasury over a reasonable number of years.
Alternatively, Bonneville would have to try to use whatever other authority it may have to recover transition costs through an increase in transmission rates in some fashion. Bonneville believes it has that authority under its statutory requirements to make all its revenues, transmission and generation, available to meet its costs. It also believes it has the authority to, if necessary, raise transmission rates to recover generation costs that cannot otherwise be recovered through power rates. Assertion of these authorities, however, would likely be vigorously contested by parties before FERC and in the courts, creating significant uncertainty over BPA cost recovery for a period of years.
Even if we assume that Bonneville does have the authority to address transition costs, there would still not be the degree of independent regulatory oversight of the transition costs determination as there is in all of the examples discussed above. Bonneville’s rate setting under the Northwest Power Act would be reviewed by FERC, but the standards of review are limited to seeing that the rates sufficient to recover costs, are based on Bonneville’s total system costs, and that transmission costs are allocated equitably between federal and non-federal power utilizing the system. [ Northwest Power Act, § 7(a)(2).] The notion of an independent regulator that is seeking to aggressively mitigate transition costs is absent. FERC’s review authority over BPA is significantly expanded in the case of a section 211 request, but its responsibility to ensure BPA cost recovery may temper efforts to ensure transition costs are mitigated.
Next Steps |
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The foregoing is intended as background for regional discussion. The necessary next steps include: