Our investigations over the last several years have made it clear that California's electric rates are high. As we move to rely on competitive markets to supply power and to expand customer choices for power supplies, the Commission must confront and dispose of those costs that both keep rates high and act as an impediment to fair competition. We have found that many of today's high costs result from past regulatory promises made by the Commission regarding the timing of the recovery of depreciation and taxes, past requirements to diversify sources of power by signing long-term contracts that in hindsight have high costs, and the costs incurred by utilities (most notably those associated with QFs and nuclear power) that were reviewed and deemed reasonable when incurred.
Allowing more competition and customer choice in California's electric generation market means a utility may not be able to earn a price for its generation that covers these costs. Our objective continues to be the collection of transition costs in a manner that is competitively neutral, is fair to various classes of ratepayers and does not increase rates.
To achieve that objective, we will institute a nonbypassable charge, called the competition transition charge (CTC), for all customers who are retail customers on or after the date of this decision, whether they continue to take bundled service from their current utility or pursue other options. We recognize that this will require us to coordinate with FERC and may result in recommendations to the Legislature. We will fairly allocate the CTC to avoid cost shifting among classes by using current cost allocation principles. We will protect against rate increases by insuring that rates for customers taking bundled service are capped at the levels established by our January 1, 1996 revenue requirements.
To assure the continued financial integrity of the utilities, and give them an opportunity to be vital market participants in the restructured market following the transition, we will allow them to recover completely costs associated with contracts for power and prior regulatory commitments, called regulatory assets. We will continue to honor regulatory commitments regarding the recovery of nuclear power costs. For other generating plants, we commit to an accelerated recovery of the net book value of those undepreciated assets and other fixed obligations combined with a reduction in the return on those assets which make claims for transitional support.
In particular, we will reduce the imputed cost of capital on generation assets making claims to transitional support by setting the return on the percentage of the undepreciated asset financed by equity to a level of 10% below the long-term cost of debt. This reduced return reflects the reduced risk associated with these assets as we accelerate the return of their net book value through the CTC recovery. The 10% reduction may be eliminated by the utility divesting (spinning off or selling to an unaffiliated entity) at least 50% of its fossil generation. We will allow a 10-basis point increase in equity return for each 10% of fossil plants disposed of through sale or spinoff. Utilities may earn additional profits for fossil plants when operating costs (including capital costs not yet incurred) are below the Exchange clearing price.
We will also allow recovery of other costs we deem to be completely unavoidable. Finally, we recognize that the transition to expanded customer choice and competitive markets can produce hardships for employees who have dedicated their working lives to utility generation and we conclude that costs associated with retraining and early retirement have a claim for recovery as transition costs.
Our methods for valuing the transition costs will rely to the extent possible on market mechanisms and will seek to minimize the transition costs. We will complete the valuation of the assets for inclusion in the transition cost balancing account by 2003. After 2003 no further accumulation of transition costs will be allowed unless derived from existing generation contracts and related ongoing contractual payments that continue beyond that date. With this exception, we will complete the collection of the transition costs by 2005. (Fn. 1)
The primary issues we address in this section are what are, and who should bear the costs of, utility facilities or contracts that are not completely recoverable in the market. If we progress to a competitive framework without addressing this issue specifically, the utilities will bear these costs by default. In unregulated industries, this is precisely what happens: the firm that owns an asset that cannot compete writes off the unrecovered investment in the asset. Many parties, particularly the representatives of customers, urge us to follow this model. The utilities, on the other hand, argue that because these costs were incurred in a regulated industry and in fulfillment of the responsibilities of a regulated firm, they should not be treated the same way as costs incurred by businesses in unregulated industries. We note for clarity that future potential transition costs (with few exceptions) are already embedded in utility rates today; transition costs would simply be identified in a different way than they are today and this change should neither create a new ratepayer cost nor result in a higher revenue requirement.
In this section we address these transition costs. First, we provide a brief background about the elements of transition costs. Second, we explain why these costs should not be allocated to the utilities by default. Next, we consider the arguments regarding recovery and proposals for sharing these costs among affected parties. Finally, we address the recovery mechanism for transition costs.
1. What are Transition Costs?
The definition of transition costs begins with a recognition that the competitive market will classify utility generation assets as either economic or uneconomic, in whole or in part (such as at particular times of the day or year). In simple terms, a utility asset is uneconomic if its net book value (Fn. 2) exceeds its market value, and an asset is economic if its market value exceeds its net book value. For a particular utility, its transition costs are the net above-market costs associated with its assets, both economic and uneconomic.
Transition costs will be quantified at two points. First, we will require the net book value of all utility generation plants to be measured against the market, a process we refer to as market valuation, within five years. Second, plants that continue to operate temporarily within the regulated framework may incur ongoing transition costs by selling their generation for a market price that is less than the cost of producing that power (including return of and return on investment). Transition costs arise from several sources:
Generation Assets: A particular generation plant's primary contribution to transition costs will be determined when the plant undergoes market valuation. In addition to investment-related costs (the costs of construction and capital improvements and a return on the undepreciated costs), generation-related costs include unavoidable commitments directly related to generation, including nonplant physical assets and contracts for plant parts or services and for fuel or fuel transport. Generation plants may also reveal transition costs in their ongoing operations. Transition costs arise when a plant is unsuccessful in its bid to supply power through the Power Exchange, (Fn. 3) because if it is unable to sell its power, it has no opportunity to recover its fixed investment costs. Even if a plant is successful in selling its generation, transition costs will also accrue if the market price is too low to allow recovery of the plant's fixed costs. We will allow in transition cost 100% of the asset's net book value and any fixed obligation directly related to the asset.
Nuclear Power Plant Settlements: The Diablo Canyon settlement obligates ratepayers to pay a specified cents-per-kilowatt-hour (kWh) price for all energy produced by this plant. To honor this settlement, electricity from this plant will be taken by the grid whenever the energy is produced. To the extent settlement prices are above the prices in the market, as revealed by the Power Exchange, this plant will be uneconomic.
Power Purchase Contracts: Utilities currently purchase power from QFs and from wholesale suppliers. Certain power purchase agreements between utilities and QFs require power to be taken by the utility at specified prices whenever the power is produced, with certain exceptions. As with the Diablo settlement, QF contract prices may be above the revealed market prices, and thus the contract will be uneconomic. Similarly, prices under utilities' contracts with wholesale providers may be higher or lower than the market price. These contracts may either be uneconomic, increasing transition costs, or economic and available to offset other uneconomic costs.
Regulatory Obligations: These costs are primarily related to various deferred costs (including deferred tax assets which are unrecovered, relating to the generating asset only) and outstanding balancing account balances the utility has accrued under the current regulatory framework. These costs have already been approved for recovery and are reflected in current rates as part of utility revenue requirements.
2. Minimizing Transition Costs
We arrive at each utility's net above-market costs after offsetting the benefits associated with economic assets against the excess costs of uneconomic assets. This netting of excess costs and benefits fairly reduces the overall level of the utility's transition costs. This netting of economic and uneconomic assets is also a partial way of compensating ratepayers for the loss of continued dedication to public use of economic assets. Under the old regulatory system, ratepayers would have a claim to the power produced by the utility's generating units, even after a particular plant was fully depreciated. For economic plants, that continued use could provide considerable benefit to ratepayers, and ratepayers deserve compensation for the loss of that continued use. Using the excess value of economic plants to reduce total transition costs is one convenient and accurate way to provide that compensation.
Offsetting uneconomic assets with economic assets is fair in another sense. Under the existing regulatory framework, ratepayers pay a price for electricity derived from the utility's overall revenue requirement. The generation-related portion of that revenue requirement is based on the total reasonable operating and capital costs associated with the utility's mix of generating assets. The rate for electricity is thus an average reflecting the costs of both low-cost (economic) and high-cost (uneconomic) assets. It would be obviously unfair if, as part of our restructuring, we were to require customers to pick up the costs of high-cost generation without at the same time accounting for the benefits of low-cost generation.
b. Deferred Taxes
The calculation of transition costs should also account for deferred taxes. These deferred taxes represent both payments already made by the ratepayers (deferred tax liabilities) and deferred tax receivables yet to be paid by the ratepayers (deferred tax assets). The deferred tax liabilities should reduce the generating asset net book value included in the transition costs. The deferred tax receivable relating to the generating assets should increase the net book value included in the transition costs.
The deferred tax receivable from ratepayers resulted from timing differences between the "book" and "tax" methods of accounting that affect all generating plants that had been subject to depreciation before 1981. The tax benefits of these differences were flowed-through to the ratepayers in lower rates and now must be included in transition costs for those generating plants subject to transition cost recovery.
B. Should Utilities Recover Transition Costs?
Under the current regulatory structure, we have granted utilities monopoly franchises to provide electricity to the consumers in their service territories, and we have required utilities to provide reliable service on a nondiscriminatory basis to all customers within their territories who requested service. In fulfillment of these responsibilities, utilities developed a portfolio of generation assets by investing in power plants and entering into purchase agreements on the understanding, the utilities contend, that reasonable costs would be recovered in rates. They also assumed various other responsibilities related to being monopoly providers of electric services and responded to specific regulatory or legislative mandates and policies.
Utilities argue that these investments were found prudent at the time they were made and therefore they should be entitled to full recovery. The parties to the MOU agreed to the principle that:
as the industry transitions to a new competitive electric market structure, [the utility] should fully recover its prudently incurred past investments and obligations made to fulfill its historical obligation to serve. (Fn. 4)
We conclude that the utilities should be allowed to recover appropriate transition costs. Longstanding regulatory policies, past Commission decisions, and ongoing regulatory effects persuade us of the need, during the transition to full competition, for a process to account for the lingering effects of today's market structure. Thus, we must develop a method to minimize the effects of the high-cost elements in the competitive market structure, while we close the books on past practices. We will identify utility capital investments and contractual obligations, quantify their costs as accurately as possible, and separately identify a charge to recover these costs. Our goal is to get through this transition period as quickly as possible so that full competition can begin with minimal market distortions.
We also emphasize, as we mentioned in Section II, that maintaining the financial integrity of the utilities is an important goal of this proceeding, and a goal we will pursue in making the transition to a more competitive marketplace. Investors' uncertainty about the recovery of transition costs may harm the utility's ability to raise capital and may result in a higher cost of debt. If we do not provide for adequate transition cost recovery, the move to competition may threaten the utilities' financial stability. If the utilities were required to write off the entire amount of above-market levels of investments, they could face a financial disruption that might lead to lower system reliability and inefficient operation.
C. Transition Cost Recovery for Remaining Net Investment Should be at a Reduced Rate of Return
Throughout this proceeding numerous parties provided arguments in support of some level of transition cost sharing between ratepayers and shareholders. Most parties believe that the Commission is not obligated to guarantee full recovery of the costs the utilities have incurred to construct uneconomic assets. In comments filed in response to the MOU, two sets of parties state these views in different ways:
The maximum percentage of "stranded costs" which are eligible for recovery from customers by the utility through CTC must be less than 100%. Allocating stranded costs in this manner is consistent with regulatory precedent, and will provide the utilities with clear and strong incentives to mitigate the amount of costs to be treated as "stranded." (Fn. 5) Shareholders should bear a fair share of the burden of stranded costs. Fair allocation should recognize that the problems of today's utility are neither entirely of their own making nor entirely beyond their control and responsibility. Fair allocation should recognize that utility shareholders have been compensated for business and competitive risks for many years. (Fn. 6)
We derive two principles from the discussion of how to allocate transition costs.
The first is that ratepayers should benefit, at least to some degree, from our treatment of transition costs. Some of our main themes in this restructuring effort have been to give customers choice and to introduce competition with the goal of reducing rates. It would be inappropriate to require ratepayers to bear the same costs they would have borne in the absence of this reform effort, especially when those costs tend, in the new competitive framework, to distort market prices and signals.
The second is that shareholders should recover somewhat lower revenues as transition costs than they would under cost-of-service regulation. Under traditional regulation, utilities would have the opportunity to recover the amount of the original construction cost of a plant over the plant's expected useful life, plus a reasonable return tied to risk, as long as the plant remained used and useful for public utility purposes. Allowing this level of recovery in the transition to competition produces several undesirable effects. Of greatest concern is that the assurance of full recovery gives the utility no incentive to minimize transition costs. This is counter to our goal of keeping transition costs as low as possible, but it has even worse implications. If the utility is indifferent to the level of transition costs, it would in turn have an incentive to bid low in offering its generation assets' output to buyers in the Power Exchange, with the foreseeable effects of depressing the market-clearing price, squeezing the profit margins of competitors, and further increasing transition costs.
These two principles--benefits for ratepayers and proper incentives for utilities--can be accommodated in a recovery mechanism that reduces the return on investment-related transition costs. Recovery of transition costs imposes a significantly lower risk for recovery of these costs because, once an asset is market-valued, the utilities will not be subject to the risk that the plants will be found no longer to be used and useful. Thus, if we apply a reduced rate of return to these transition costs, we will appropriately reflect the lower degree of risk the utilities face.
This approach also provides benefits to ratepayers in two ways: First, consistent with the lower risk involved, it reduces the transition cost revenues associated with generation plants from the levels that ratepayers would otherwise pay in rates under cost-of-service ratemaking. Second, reduced revenues will also reduce taxes that would otherwise be reflected in rates.
We note that we are not required to guarantee full transition cost recovery. We are required only to design a rate structure the total impact of which provides the utilities with the opportunity to earn a fair return on their investment. (Duquesne Light Co. V. Barasch (1988) 488 U.S. 299.) We are allowing the utilities the opportunity to recover generation plant-based transition costs and providing an appropriate risk-based rate of return until those costs are recovered. There is a strong likelihood that utilities will be able to recover all transition costs, but in the future, competitive pressures may lead utility managers to discount the transition cost rate element or to forgo a portion of recovery, in the exercise of their business judgment. We propose to apply a reduced rate of return to investment-related transition costs. As modified and if accepted, the settlement in the SCE general rate case (A.93-12-025/I.94-02-002) provides that the net book value of SONGS should be recovered with a rate of return for the debt component equal to the utility's embedded cost of debt and a rate of return reduced by 10% for the equity component.
In the past, this Commission has considered at least two cases in which generation units reached the end of their usefulness (i.e., were no longer used and useful) before sunk costs had been fully recovered: the Humboldt Bay Unit III nuclear power plant and the San Onofre Nuclear Generating Station Unit I (SONGS I). In both cases the Commission provided shareholders less than full recovery of the combination of sunk costs and rate of return at the weighted cost of capital. In D.92-08-036 (45 CPUC 2d 276), the Commission adopted a settlement which allowed a 48-month amortization of remaining net investment in SONGS I. After the unit was shut down, remaining unamortized investment was allowed to earn a rate of return at the authorized embedded cost of debt. In D.83-05-051 (11 CPUC 2d 538), regarding the unfinished Humboldt Bay Unit III, the Commission excluded capital expenditures plus unamortized nuclear fuel from rate base and terminated further accumulation of Allowance for Funds Used During Construction. The Commission eventually allowed PG&E to recover all capital costs at a lower rate of return.
We expect that some utility plants will no longer be used and useful in the future restructured energy marketplace. Allowing recovery of remaining net investment associated with the SONGS I plant at the embedded cost of debt was reasonable at the time, given the then-current regulatory structure. However, today's decision decreases the risk associated with recovery of remaining net investment (now part of transition costs), due to the imposition of a nonbypassable charge on distribution customers (as described in greater detail below) which decreases utility business risk. We will adopt 90% of the embedded cost of debt as a reasonable rate of return on the equity portion of the net book value to reflect the reduced risk. We will set the return on the debt portion of net book value at the embedded cost of debt.
This mechanism will provide utility management with an incentive to minimize the level of transition costs, and as a result to reduce rates. At the same time, allowing this lower rate of return on the equity portion is appropriate in light of the reduced risk and will not adversely impact the utility's financial stability.
D. Calculation of Transition Costs
We have previously identified three primary sources of transition costs: uneconomic utility generating assets, further subdivided into nuclear and other, nonnuclear facilities; existing power purchase obligations, consisting of QF contracts and wholesale contracts; and regulatory obligations.
Parties have suggested ways of calculating transition costs that may be characterized as either administrative or market-based. Under an administrative approach, we would attempt in our proceedings to assemble reliable information that would help us calculate an estimate of transition costs. Market-based approaches derive an estimated value from observation of the collective actions of buyers and sellers.
We concur with most of the parties' view that a market-based approach to calculating transition costs associated with utility assets will produce superior results to an administrative approach. An administrative approach to valuing utility assets introduces forecasting error and necessarily relies on numerous assumptions that would likely be contested. For example, this approach requires long-term forecasts of market prices and assumptions about existing and future QF obligations, discount rates, capacity factors, and other variables. The estimates of overall transition costs presented by the utilities and other parties, using their versions of an administrative approach, ranged from negative $8 billion to $32 billion. (Fn. 7) To avoid the potential for forecast errors of this magnitude in the transition cost calculation, market-based, observational methods for quantifying transition costs for the uneconomic portion of the utility's generation assets should be employed as much as possible. However, we will use an appropriate administrative approach as necessary to calculate the level of transition costs during the period prior to market valuation of the assets.
In the following pages we discuss in detail our approaches to calculating transition costs. This calculation will be made in connection with two occurrences. First, when an individual asset undergoes market valuation, using one of the approaches described below, we will compare the resulting market value with the asset's undepreciated book value. Second, we will make annual calculations of other types of transition costs.
We propose to establish a transition cost account for each utility. This account will be credited and debited annually and adjusted after each utility generation asset receives its market valuation (sale or spinoff). We will review each asset's market valuation and the associated adjustment to the transition cost account in conjunction with the utility's application for a finding that the asset is no longer "necessary or useful" for the provision of utility service ( 851) and thus may be used for other purposes. This account will also record transition costs resulting from the operation of nuclear power plants and power purchases under existing wholesale and QF contracts. Transition costs for these resources will be calculated annually over the terms of the settlements and contracts or until the authorized transition cost recovery has been completed. Transition costs associated with regulatory obligations will also be included in this account as authorized by the Commission. This account will also include reasonable costs of early retirement or retraining programs that seek to ease the labor force disruptions associated with this transition. As we have discussed, interest on the balance in the transition cost account related to recovery of the uneconomic portion of generating assets will reflect the lower rate of return previously discussed. Interest on other transition costs recorded in the account, such as the costs of purchased power and certain regulatory assets, should reflect a rate appropriate to the term over which these accounts are financed, but no higher than the long-term cost of debt. (Fn. 8)
There are three primary ways to calculate transition costs. The first approach is to calculate transition costs on an ongoing basis by comparing the authorized revenues associated with the plant to the actual revenues earned in the market. The second approach will be used when the utility chooses to divest an asset. Transition costs will be calculated by comparing the asset's net book value to the market value as measured by the sale price, or the stock market value of shares issued to effect a spinoff. The third approach will be used if the utility chooses to retain the asset, in which case transition costs will be calculated by comparing the market value established through an appraisal to the net book value.
1. Ongoing Transition Cost Calculation
Prior to market valuation of the utility generation assets, transition costs will be calculated annually. This calculation will include the transition costs associated with the operation of the utilities' generation assets, contractual obligations, and regulatory obligations.
a. Nuclear Generation Facilities
California currently has two operating nuclear generating stations. Diablo Canyon is owned and operated by PG&E. SONGS is owned by SCE and SDG&E; SCE owns approximately 80% and is responsible for its operation. SCE also owns approximately 16% of the Palo Verde Nuclear Generating Station in Arizona.
(1) San Onofre Nuclear Generation Station
The method for calculating transition costs for SONGS will depend on the outcome of our consideration of a settlement presented in SCE's pending general rate case, A.93-12-025. The proposed settlement would provide incentive ratemaking for SONGS. In the MOU, SCE indicated that it would petition to modify our decision approving the settlement proposed in the general rate case to incorporate the alterations related to plant shut-down incorporated in the MOU. If we approve the settlement, we will consider SCE's requested modification when it is presented, and today's decision does not prejudge that issue.
(2) Diablo Canyon
Under our proposal, the ISO will schedule power from Diablo Canyon on a must-take basis. Ongoing transition costs will be calculated as that portion of the settlement payments in excess of market value, as determined by the Power Exchange price. This calculation will be performed over the term of the settlement or until transition cost recovery is completed. These costs will be entered in the transition cost account as part of our annual review.
We are concerned that the disparate ratemaking treatment of Diablo Canyon and SONGS may create inequities for ratepayers in different parts of the state. We will order PG&E to file an application within 100 days after the date of this decision with its proposal for ratemaking treatment for the Diablo Canyon facility that would price its output at market rates by 2003 and complete recovery by 2005. The application must also be consistent with the principles for recovery stated at the beginning of this section, including no rate increases above January 1, 1996 levels, and must include at least one alternative similar to the SONGS settlement.
(3) Palo Verde
In the MOU, SCE states its intention to file a proposal for a new rate mechanism for Palo Verde. We direct Edison to file this application within 100 days and to include a proposal for ratemaking treatment comparable to the ratemaking treatment ultimately adopted for SONGS for rates effective on or before 1997. Transition costs for Palo Verde will be calculated and recovered the same way as all other generation assets that remain under the utility's ownership unless and until we approve SCE's application or otherwise change our method of calculation.
b. Contractual Obligations
(1) QF Contracts
Under our proposal, existing QF contracts will be honored by the remaining electric distribution utility. The utility will retain its obligation to administer its QF contracts in the best interests of its customers and in a manner that maximizes systemwide benefits and minimizes transition cost accrual. The dispatch of some QFs is governed by contractual provisions, and QFs with firm contracts (Standard Offer No. 2 and Interim Standard Offer No. 4) are subject to certain performance requirements. These contractual provisions give the purchasing utility a limited ability to influence the scheduling of QF energy deliveries.
Transition costs will be calculated by comparing the contract price with the market-clearing price established in the Power Exchange for each time increment when the QF delivers power. We intend to set short-run avoided cost energy payments at the Exchange's clearing price as soon as we are confident the Exchange is functioning properly. Therefore, CTC that accumulates after 1998 will flow primarily from the capacity payments and fixed energy payments.
We recognize that both and utilities may have incentives to renegotiate their contracts. (Fn. 9) Utilities will need to minimize costs to remain competitive and QFs may have an incentive to renegotiate as a result of our consideration of ways to revise our short-run avoided cost methodology for QF energy payments to reflect the prices established in the Power Exchange. The May proposals recommended establishing monetary incentives to facilitate contract renegotiation. Most parties commenting on this proposal support incentives as a means of reducing transition costs and releasing QFs from contract obligations to allow them to compete in the generation market, although few commented on the specific recommendations for either a 20% or 50% sharing of cost savings between ratepayers and shareholders. Rather, the comments stress the importance of voluntary, nondiscriminatory negotiations on this issue. The MOU recommends standard options and preapproved guidelines for voluntary negotiations. (Fn. 10) Similarly, the California Cogeneration Council (CCC) recommends that we establish generic options for the "buy down" of QF contracts. We endorse an approach that involves both a monetary incentive to shareholders and conditions which foster voluntary, nondiscriminatory negotiations. We will allow shareholders to retain 10% of the net ratepayer benefits resulting from a renegotiation, which will be reflected by an adjustment to the transition cost total. Modification of QF contracts will follow our existing principles (Fn. 11) that the modifications are voluntary on the part of the QF and should provide ratepayer benefits relative to the most probable stream of payments for that QF without the modification, and should benefit from the flexibility that non-standard, arm's length negotiations have previously revealed. We will continue to preapprove modifications. We also look forward to the recommendations of the sponsoring parties to the MOU.
(2) Other Wholesale Power Purchase Agreements
As with QF contracts, other existing wholesale power purchase agreements will continue to be honored by the utility and should be administered in a manner which maximizes systemwide benefits and minimizes transition costs. To the extent that the purchasing utility can influence the amount and timing of power deliveries, we will expect and require the utility to fully exercise its ability to do so for the benefit of its ratepayers. We also encourage the utilities to renegotiate these contracts whenever possible and appropriate in order to reduce transition costs. Calculation of transition costs will occur in the same manner as for QF contracts; that is, contract costs will be compared with market value.
c. Regulatory Obligations
The transition costs that arise from regulatory obligations are related to various deferred costs and outstanding balancing account balances the utility has accrued under cost-of-service regulation. In most cases, we have already approved recovery of these costs, and they are reflected in outstanding balances of balancing accounts. Examples of these types of costs include deferred operating expenses, deferred taxes, unamortized loss from sale of assets, unamortized debt expense, costs associated with issuing or reacquiring debt, and nuclear decommissioning expenses. We also will allow reasonable employee costs incurred as part of the transition to competition, including early retirement and retraining costs, to be recovered through the transition cost account.
We plan to evaluate specific account balances and determine the amounts that will be included as part of transition costs during the implementation phase of this rulemaking, but these amounts should relate only to the generation assets affected by this restructuring. Once we identify and approve these costs for transition cost treatment, they will be credited or debited to the transition cost account and recovered in the same manner as other transition costs.
The cost of future decommissioning of nuclear facilities requires special consideration. These costs require a significant amount of capital, and we will ensure that adequate funds continue to be collected to cover the costs of nuclear decommissioning. Therefore, we will continue to oversee and monitor the existing trust funds to ensure that they are adequately maintained. In the event that a nuclear plant changes ownership, the existing trust fund balances would follow the asset to the new owner. The new owner would be obliged to comply with Nuclear Regulatory Commission regulations to continue funding for decommissioning. If the distribution company retains ownership of the nuclear facilities after market valuation, costs for the decommissioning trust fund will be added into the transition cost account.
d. All Other Generating Assets
(1) Fossil fueled units
Prior to market valuation, utilities will be able to recover 100% of their fossil fueled units' undepreciated, book value (existing rate base) through the CTC. Generation plant clearly includes the facility, but may also include other long-term obligations used solely for generation, so that the undepreciated net book value will be fully recovered by the end of 2005. We will allow the embedded cost of debt for the debt portion of the utility's capital structure associated with these plants. The return for the remaining share (equity) will be 90% of the embedded cost of debt.
All other costs of running these units, including capital costs not yet incurred, will be subject to recovery through the prices received from the Exchange, with one limited exception. For those units that are primarily needed for reactive power/voltage control, if the costs of running these units (including capital costs not yet incurred) exceed the Exchange clearing price, utilities may seek partial recovery of operating costs up to the year 2003, subject to performance-based ratemaking, until or unless market based prices are established for reactive power/voltage control by the FERC. Further, if no recovery for reactive power/voltage control is sought, and the Exchange clearing price exceeds the costs of running these units (including capital costs not yet incurred), utilities may retain profits providing up to 150 basis points above their authorized return for distribution rate base. Any further profits will be used to reduce CTC.
(2) Other Units--Hydroelectric and Geothermal
Each distribution utility will retain ownership of its hydroelectric and geothermal generating assets. These assets will remain subject to rate-of-return regulation and will continue to provide their electric output to the distribution utility through the Power Exchange. Any surplus revenues from these sales (above the revenue requirement associated with these units) will be credited toward reducing transition costs. Each utility will be encouraged to submit an appropriate generation-related PBR for these assets. The Commission may consider either the sale or spinoff of these assets at some future date and the resulting gain would also reduce transition costs.
2. Transition Cost Determination and Market Valuation for Sale or Spinoff of Assets
If the utility chooses to sell an asset, we will require the utility to make its intent widely known, so that all potentially interested buyers are notified of the proposed sale. Our purpose in requiring this notice is to ensure that the highest possible price is obtained for the asset. We are for similar reasons concerned that negotiations are conducted at arm's length and that the resulting sale price is generally consistent with other market information. Once these conditions are satisfied, we would accept the sale price as a reasonable reflection of market value. Transition costs would be calculated by comparing the asset's net book value with the sale price.
The MOU recommended that the utility should be able to bid when its own asset is put up for sale. Subject to the concerns stated in the preceding paragraph, it may be possible for the utility to participate in the sale, and if it is the highest bidder, it may retain the asset, perhaps under the ownership of an affiliate. The utility should not, however, have an automatic right to match the winning bid if the winning bid does not exceed the utility's bid by some margin, as called for in the MOU, because the existence of reserved right will tend to depress bidding and increase transaction costs. If the utility wants such a right, it should pay in advance an appropriate price reflecting the value of this right. Any such payment will be added to the winning bid to increase the market value of the asset.
If the utility chooses to spin off its assets, market valuation for the assets will be determined by multiplying the stock price of the new company owning the generation asset during some reasonable period after the spinoff by the number of outstanding shares. Transition costs will be equal to the difference between the net book value of the generation asset and the market value determined after a reasonable period of time.
The market value of the spun-off generation asset can be directly identified by observing changes in the stock prices of the spun-off and original companies. (Fn. 12) However, because of stock price fluctuations, it is appropriate to observe the stock prices over a period of time. A clearer sense of the market value might be gained by observing the average stock prices over, for example, the first 30 or 100 trading days, or even longer, after the announcement or completion of the spinoff. Transition costs from market valued assets will be entered into the transition cost account once they have been reviewed and approved by the Commission in conjunction with the utility's application under 851.
If a plant is shut down because the utility believes (and the Commission agrees) the plant has little or no market value in the new restructured electricity market (and thus is no longer "used and useful"), transition costs associated with these assets will be subject to review under 455.5. In many cases, transition costs will be equal to the difference between the net book value and the net salvage value of that generation asset. As we have discussed, the salvage value of a generation asset would consider the value of the site for potential repowering of the unit or for new generation facilities.
3. Appraisal Valuation
For assets that remain under the utility's ownership or that are handled through an accounting separation, we will use an appraisal valuation to determine transition costs. Market valuation of assets through an appraisal approach will provide results superior to an administrative approach because the appraisal approach relies on independent industry experts rather than experts hired to support each party's position, as is common in regulatory proceedings. However, the MOU's recommendation to have the IOUs submit a list of qualified appraisers to perform the market valuation would minimize this advantage. We generally support this approach, but we think a preferable process is for all affected parties--primarily the utilities and ratepayer representatives--to develop an agreed-on list of impartial and qualified appraisers, from which we would select no more than three, as the MOU provides. This appraisal process should only occur after the Exchange has operated a reasonable time to allow for greater Exchange price certainty.
Under the MOU proposal, the utility would have the right to accept or reject the appraised valuation, and if the utility chose to reject the appraisal, the utility would have to spin-off or sell the asset. This recommendation of the MOU must be modified to allow for the Commission's review of the appraisal. If the utility accepts the appraisal, it must still apply for the Commission's determination that the asset is no longer "necessary and useful" for public purposes under 851. That application will also create a forum for our review of the appraisal. If the utility chooses to reject the appraisal and to spin off or sell the generating asset, the spinoff or sale will also require a 851 application, which will provide a forum for us to determine the amount of transition cost associated with the transaction. This oversight allows us to ensure that the utility does not improperly reject an appraisal and then receive a lower sale price, thus increasing the level of transition costs.
E. The Competition Transition Charge (CTC)
1. Jurisdiction to Collect Transition Costs
In the MegaNOPR, the FERC reaffirms the view expressed in its original NOPR on stranded cost recovery that utilities are entitled to recovery of legitimate and verifiable stranded costs from increased competition in and entry to the wholesale market. (The FERC's "stranded costs" are similar to the transition costs associated with uneconomic assets.) The FERC determined to leave retail transition cost recovery to the states. (Fn. 13) The FERC pointed out that states have mechanisms to recover retail transition costs, including the ability to impose charges on facilities or services used in local distribution. (Fn. 14)
We agree that recovery of retail transition costs should be subject to state jurisdiction. Jurisdiction over retail transition costs is well-defined under the Federal Power Act and lies exclusively with state authorities. The FERC has no jurisdiction over costs incurred at the state level to serve retail customers, regardless of whether or not those costs are rendered uneconomic by our new market structure. State jurisdiction over retail transition costs extends, in our view, to costs stranded by retail customers converting to wholesale status, and we will exercise our jurisdiction to recover those costs, either through exit fees or through some other mechanism. It may be desirable to have state legislation to enhance our authority over recovery of retail transition costs from customers who change their status from retail to wholesale.
2. Collection of the CTC
We will authorize utilities to recover their retail transition costs through an end-user surcharge that will apply to sales to both retail procurement and utility customers on a utility service territory basis. The utilities should ask the FERC to confirm that delivery services to both retail procurement and utility customers contain some elements of local distribution. In addition, we adopt the MOU's recommendation that direct access customers must, as a condition of the utility's retail distribution tariff, sign an agreement to pay their share of transition costs and thereby waive any jurisdictional objection they might otherwise raise in any forum. Allowing utilities to recover legitimate transition costs is an essential element of the new market structure and a precondition to direct access.
To that end, we also will require utilities to modify the Preliminary Statement of their tariffs to provide all current and new customers with notice of our intent to authorize collection of retail transition costs. Whether further customer notice, such as a bill insert, is required is an implementation issue to be developed by utilities and other interested parties through the Working Group. Issues surrounding enforcement and collection of the CTC for departing customers will also be referred to the Working Group to develop consensus recommendations if possible.
The CTC will be a percentage surcharge on the dollar amount of each bill of each customer, including those served under contracts with nonutility suppliers, of the distribution utility. The surcharge will be designed to amortize the balance in the transition cost account over a reasonable period (not to exceed 2005 for generating assets), and the level of the surcharge will be adjusted annually to reflect changing account balances, amortized over the remaining years to 2005.
3. Allocation of the Competition Transition Charge
Transition costs will be allocated to all customer classes using an equal percentage of marginal cost (EPMC) methodology, unless specific circumstances justify a different approach. Marginal cost pricing for electric services using the EPMC methodology is well established, and using this approach for the allocation of transition costs ensures a fair allocation among all customer classes and prevents inter- and intraclass cost-shifting. Using this approach also preserves the cost allocation that we have previously reviewed and approved.
4. Period for Collection of the CTC
One of the goals of this proceeding is to lower the price consumers pay for electricity. Recovery of transition costs frustrates this goal because it is possible that the surcharge will exceed price decreases in a given year, resulting in higher electricity-related costs for consumers. To avoid this result, we will cap transition cost recovery so that the price for electricity does not rise, on a kWh basis, above current rate levels in effect as of January 1, 1996 without adjustment for inflation. This cap may mean that transition cost recovery will extend over a period of several years. As previously discussed, transition costs will be calculated on ongoing basis and will be entered into a transition cost account.
The total level of transition cost compensation each year will depend on the amount in this account and the level of the rate cap. However, our goal is to complete the recovery of transition costs in the shortest possible amount of time, consistent with our goal of not increasing electricity prices. Therefore, we will complete the recovery of transition costs by 2005, except for ongoing contractual payments related to contractual obligations entered into before January 1, 1996.
F. Transition Cost Filings
The utilities are authorized to establish a transition cost balancing account. Each utility will have an annual proceeding to address adjustments to the account. In these proceedings utilities will also show that our principles for CTC collection are reasonably expected to be met: that CTC collection will be complete by 2005 and that rates will be at or below 1996 levels. The first applications should be filed by September 1, 1996 to set the CTC for the beginning of transition cost collection when the new market structure begins, not later than January 1, 1998.
Interest on the various components of the account will be calculated as we have discussed in this section. Transition costs associated with contractual obligations and assets that have not undergone market valuation will be recorded in this account on an ongoing basis and will be subject to review in our annual proceeding. Upon market valuation of an asset, utilities shall file a 851 application to initiate review of the market price, transfer of the asset, and removal of the costs from the PBR benchmark.
1. We recognize that competitive forces will influence the utilities' business plans over the transition period. Utilities may complete collection earlier, particularly if they choose to forgo collection any transition costs that we are providing them with the opportunity to recover.
2. By "net book value," we mean the original cost recorded in the company's books for a particular asset less any accumulated depreciation and adjusted for deferred taxes, and any other asset or liability account which relates to the asset.
3. Certain nuclear facilities and plants that have undergone market valuation will operate under different conditions, as discussed in the market structure section and below.
4. MOU, p. 10. In their filed comments, both PG&E and SDG&E agreed with this principle.
5. Framework, p. 5.
6. Customer statement of principles on electric restructuring response to the Memorandum of Understanding, filed October 2, 1995, by the Association of California Water Agencies, Agricultural Energy Consumers Association, California Department of General Services (DGS), California Farm Bureau Federation, California Hotel and Motel Association, California Industrial Users, California League of Food Processors, California Restaurant Association, California Retailers Association, DRA, and School Project for Utility Rate Reduction.
7. We do not adopt or endorse any of these estimates, but this wide range of estimated costs illustrates our reservations about the administrative approach. Estimates vary significantly due to assumptions used in the calculations.
8. Our decision to have different returns for the debt and equity portions of investment-related transition costs and for other types of transition costs will require the establishment of subaccounts within the transition cost account for the imputed debt and equity portions of the net book value of each generating asset.
9. Our policy of establishing a requirement for purchases of generation powered by renewable sources and allowing trading in renewable credits, discussed in Section VI, will introduce an incentive for renewable QFs to renegotiate their contracts.
10. Sponsoring parties to the MOU indicate that they will develop details for renegotiations and standard options by the end of 1995.
11. We previously considered guidelines on negotiations to restructure some QFs' contracts to avoid some of the consequences of the end of the fixed-priced energy period under the contract. (D.94-05-018. See D.93-01-048, 47 CPUC 2d 772.)
12. If the spun-off company is new, it may be hard to determine market value from stock price unless generation assets are the only assets of the new company. We might need to observe changes in the price of the original company's shares, which will reflect the market value of the loss of the asset, in the period following the public announcement of the planned spinoff.
13. The FE The FERC has distinguished between wholesale and retail stranded costs for jurisdictional purposes. RC asserted exclusive jurisdiction over allowing utilities to recover costs incurred to serve wholesale customers which are then stranded due to the wholesale customer's ability to take advantage of open transmission to obtain access to another wholesale supplier.
14. MegaNOPR, mimeo. at 250.