4. Ratesetting and Consumer Choice Issues in Electricity Restructuring

Background

Currently, major electric utilities in the United States are vertically integrated, owning generation, transmission, and distribution facilities. These utilities operate as natural monopolies in exclusive franchised areas (awarded by the States) in return for the universal obligation to serve. The bundled rates they charge are determined by the cost-based service provided.⁽⁵⁶⁾

The evolution of the current industry organization and structure results from the legal and regulatory system under which the industry has operated in the past. Since utilities are considered to be natural monopolies, regulation is expected to be a surrogate for a competitive environment with respect to the prices a monopoly could otherwise charge. This conceptual underpinning explains the extensive and comprehensive nature of the regulatory regimes under which the electric utilities have operated since the turn of the century.

Directives contained in FERC Orders 888 and 889 are designed to create an environment conducive to competition in wholesale electricity trade (see boxes). However, the contemplated industry transformation from a regulated monopoly with cost-of-service pricing and an obligation to serve to a fully competitive generation market poses a host of complex and controversial issues.⁽⁵⁷⁾ Stakeholders' views expressed in the workshops organized by the U.S. Senate Committee on Energy and Natural Resources and the House Subcommittee on Energy and Power in 1997 exemplify the range of complexities inherent in the industry transformation process.⁽⁵⁸⁾

Major Provisions of FERC Order 888 on Open Access Functional Unbundling A utility's uses of its own transmission system for the purpose of engaging in wholesale sales and purchases must be separated from other activities. Corporate unbundling is not required. Utilities must take transmission services (including ancillary services) under the same tariff of general applicability as do others. Utilities must state separate rates for wholesale generation, transmission, and ancillary services. Utilities must rely upon the same electronic information network that its transmission customers rely upon to obtain transmission information. Nondiscriminatory Open Access Tariff Requirement By July 9, 1996, jurisdictional utilities that own or control transmission must have filed a single open access tariff that offers both network, load-based services and point-to-point, contract-based services, including ancillary services, to eligible customers comparable to the service they provide themselves at the wholesale level. The rule provides a single pro forma tariff that sets forth minimum conditions for both network and point-to-point services and nonprice terms and conditions for providing those services and ancillary services. Pools and Holding Companies Jurisdictional utilities who are members of tight or loose power pools must file either an individual pro forma tariff or a joint pool-wide pro forma tariff by July 9, 1996. They are not required to take service for pool transactions under that tariff, but are required to file a joint pool-wide tariff no later than December 31, 1996, and begin to take service under that tariff for all pool transactions by that same date. By that date, they must also restructure their ongoing operations and open membership to nonutilities. Public utility holding companies not subject to tight or loose pool requirements are required to file a single systemwide pro forma tariff permitting transmission service across the entire holding company by July 9, 1996. All bilateral economy energy coordination contracts executed before the effective date of this rule must be modified to require unbundling of any economy energy transaction occurring after December 31, 1996. Customer Eligibility Any entity engaged in wholesale purchases or sales of energy or retail purchases is an eligible customer. Reciprocity Transmission customers of jurisdictional utilities who take service under the open access tariff and who own, control, or operate transmission facilities must, in turn, provide open access service to the transmitting utility. This includes municipally owned entities and RUS cooperatives. Services To Be Provided A public utility must offer transmission services that it is reasonably capable of providing, not just those services that it currently provides to itself and others. Six ancillary services must be included in the open access tariff: 1. Scheduling, system control, and dispatch 2. Reactive supply and voltage control from generation sources 3. Regulation and frequency response 4. Energy imbalance 5. Operating reserve—spinning reserve 6. Operating reserve—supplemental reserve The transmission customer must purchase the first two services from the transmission provider. Pricing The rule does not prescribe rates for network, point-to-point, or ancillary services. Instead, utilities may charge current rates or apply for new transmission rates. Utilities can propose to recover opportunity costs and expansion costs. Crediting for customers' transmission facilities will be permitted on a case-by-case basis. Proposed pricing must conform with FERC's Transmission Pricing Policy Statement. Contract Reform The rule does not void any existing requirements contracts. The functional unbundling requirement applies only to transmission services under new requirements contracts, new coordination contracts, and new transactions under existing coordination contracts. Parties to requirements contracts executed on or before July 11, 1994, may seek modification of such contracts on a case-by-case basis, even if they contain a Mobile-Sierra clause. FERC, however, does not take contract modification lightly, and parties seeking to modify contracts will have a heavy burden to demonstrate the need for it. Market-Based Rates Utilities seeking market-based rates for sale of electricity at wholesale from new capacity are no longer required to demonstrate lack of market power in generation. New capacity is that for which construction has commenced on or after the effective date of this rule. For existing generation, FERC will continue its case-by-case approach that includes an analysis of generation market power in first and second tier markets.    Source: Adapted from "FERC Finalizes Electric Industry Restructuring Rule," Public Utility Topics, No. 96-2 (Philadelphia, PA: Coopers & Lybrand, L.L.P., June/July 1996), pp. 4-8.

Sharp differences in the perspectives and priorities of various stakeholders on significant issues contribute to the prevailing uncertainty as regulatory authorities and legislators grapple with issues that need to be resolved. Critics contend that the painless moiety—competition and customer choice—is granted by the Federal Government, but difficult matters have been left to the States to resolve.⁽⁵⁹⁾ It is not surprising that most State regulatory authorities eager to define a framework to promote competition at the retail level find the path they should adopt to be uncharted.⁽⁶⁰⁾ For this reason, most States are in varying stages of information gathering and/or consensus building and view with disfavor any Federal attempt to stipulate a designated date for the commencement of competition at the retail level.⁽⁶¹⁾

Even in areas where the FERC and the States have provided specific guidelines, conceptual and procedural differences remain. As an example, recovery of stranded costs is critical for investor-owned utilities, but estimating utility-specific stranded costs at a given point in time is difficult.⁽⁶²⁾ In addition, low-cost power producers consider this requirement to be an artificially contrived obstacle to delay the benefits of competition.⁽⁶³⁾ Environmental proponents are less concerned with stranded cost issues and more concerned about the pollutants that could be produced by increased generation from low-cost, coal-burning power plants in the Midwest. These opposing viewpoints need to be reconciled so that the transition can proceed smoothly without impairing the reliability, security, and stability of the existing power system.

In the circumstances described, the search for a solution tends to be time-consuming. It also fails to fully satisfy the demands of contending stakeholders. In introducing competition in electricity, "as in so many endeavors, the devil will be in the details."⁽⁶⁴⁾

Stakeholders involved in the transition include utilities, State and Federal governments, legislative interests, traders and investors, environmentalists, public policy program advocates, multiple special interest groups, and various customer class groups (Figure 21). In addition, coalitions (new and old) that either lend or deny support to exclusively defined objectives or special interests play a significant role. The participation of such a large group on any issue complicates the search for quick solutions.

Restructuring Choice Issues

As the wholesale markets open and the requisite institutional infrastructures like independent system operators (ISOs) and the Open Access Same-Time Information System (OASIS) evolve and become operational, the electric utilities will be under considerable pressure to reorganize and restructure. Besides initiating efficiency improvements and securing productivity gains, utilities may also attempt to position themselves strategically to meet competitive challenges. Introduction of retail competition in the States will tend to accelerate industry restructuring as utilities consolidate and expand existing boundaries of business (excluding power generation).⁽⁶⁵⁾ There may also be a trend leading to a convergence between electricity and natural gas companies.

In this environment of industry changes, the range of consumer choices will be determined by basic decisions at the State level.⁽⁶⁶⁾ Of the many variables likely to affect the decisionmaking process, perhaps the most critical (and contentious) issue may be the manner in which the States authorize the recovery of costs likely to be stranded.⁽⁶⁷⁾ The FERC supported full recovery of stranded costs resulting from its promotion of wholesale trade in electricity. Based on the concept of regulatory compact, utilities expect supportive treatment from State regulatory authorities in promoting electricity competition at the retail level.⁽⁶⁸⁾ Where this support is not fully forthcoming, delay in introducing competition becomes a distinct possibility.⁽⁶⁹⁾

This chapter addresses two ratesetting issues: (1) approaches adopted by State regulatory authorities in their treatment of stranded costs and (2) performance-based rates. Other consumer choice issues are highlighted in a discussion of experiments with pilot programs.

Stranded Cost Developments in the Post-888 Era

During the transition to a competitive environment, the FERC noted that some utilities may incur stranded costs as wholesale customers leave to purchase power from alternative sources. Accordingly, Order 888 provided a mechanism for recovery of stranded costs with a view to ensuring an orderly and structured transition to a wholesale market that would increasingly rely on market-based generation rates in the future.

A number of stakeholders—137 in all—filed requests for rehearing and/or clarification of FERC Order 888. Although the Commission's basic tenet, the need to harness the benefits of competitive market forces in electricity pricing, received general acceptance, stakeholders nevertheless raised many issues concerning the legal, technical, and policy implications of Order 888.

The stakeholders' disagreements, for the most part, focused on the mechanics of promoting competition: who should pay the costs of transition and how long should the transition take?⁽⁷⁰⁾ However, the most contentious arguments during the rehearing involved how the FERC should deal with the transition costs associated with moving to competition.⁽⁷¹⁾

Most utilities wanted a guarantee with respect to the full recovery of stranded costs whether caused by loss of wholesale or retail customers. Many customers, however, sought the ability to abrogate existing wholesale contracts without any payment for stranded costs.⁽⁷²⁾ The Commission's Order on Rehearing (Order No. 888-A) issued in early 1997 reflects a reconciliation of two contrasting views on the recovery of stranded costs.⁽⁷³⁾

In its Order 888-A, the FERC (while reaffirming its stranded cost recovery mechanism stated in Order 888) aims to balance a number of critical interests to achieve a fair and orderly transition to competition. These include sustaining the financial stability of the industry, upholding the regulatory bargain under which large investments were made by the industry in the past, and not shifting costs to customers that had no responsibility in causing stranded costs to emerge. The Commission acknowledged that stranded cost recovery may delay some of the benefits of competition but concluded that customers will benefit in the long run from a fair and orderly transition.

The Commission's reaffirmation (in Order 888-A) includes the following key components:

• Utilities will be allowed the opportunity to recover legitimate, prudent, and verifiable wholesale stranded costs associated with (i) wholesale requirements contracts (executed on or before July 11, 1994) that do not contain explicit stranded cost recovery provisions and (ii) costs associated with serving retail-turned-wholesale customers.⁽⁷⁴⁾ This opportunity will be available regardless of whether the customer or the new supplier requests and contracts for transmission service. To accommodate the concept, the definition of "wholesale stranded costs" was revised.⁽⁷⁵⁾
• The opportunity to recover stranded costs, in each case, is limited to situations where there is a direct nexus between the availability and use of FERC-required transmission tariffs and the stranding of costs. Other cost recovery issues are thus excluded from consideration.
• The Commission stated that (under certain conditions) it would be in the public interest to permit amendments to wholesale requirements contracts to include stranded cost provisions.
• The Commission pointed out that provisions of Order 888 provide an opportunity to the utilities to recover stranded costs without offering a guarantee that recovery will be allowed.⁽⁷⁶⁾ To be eligible for recovery of stranded costs, a utility must demonstrate that costs incurred in providing services to a customer were based on a reasonable expectation of continuing services beyond the contract date.
• The Commission reaffirmed the direct assignment of stranded costs to the departing customer as the appropriate recovery method. Adoption of this cost causation approach eliminates the need to defray stranded costs to all transmission users of a utility.
• Instances where retail customers convert to wholesale customers (through municipalization) involve new and complex jurisdictional issues. The Commission will be the forum only in those limited cases where there is a direct nexus between the availability and use of FERC-required transmission access and the stranding of costs.
• The Commission reaffirmed its conclusion that both it and the States have the legal authority to address stranded costs that result when retail customers obtain retail wheeling in interstate commerce to reach a different supplier. The only circumstance in which the Commission will entertain requests (to recover stranded costs caused by retail wheeling) is when the State regulatory authority does not have the authority under State law to address stranded costs when retail wheeling is required. The Commission thus steps in to fill a regulatory "gap" (without any intent to preempt the exercise of any State authority). If a State regulatory authority addresses such costs, the utility(ies) may not then apply to the Commission regardless of whether full or partial or no recovery was allowed.
• The "revenues lost approach" methodology was reaffirmed to be the fairest and most efficient way for calculating stranded costs to be assigned to a departing customer.⁽⁷⁷⁾ The Commission rejected the asset-by-asset valuation approach as being overly complicated and costly.⁽⁷⁸⁾

In reaffirming its stand on various issues pertaining to the recovery of stranded costs, the Commission "struck a reasonable balance that, for certain defined circumstances, permits utilities the opportunity to seek extra-contractual recovery of stranded costs from their departing customers and permits customers the opportunity to make a showing that their contracts should be shortened or terminated."⁽⁷⁹⁾

Treatment of Stranded Costs by States

Electricity is expected to become available at prices below those currently prevailing as a competitive market for electricity develops at the retail level in States.⁽⁸⁰⁾ Evidence of this shift may be more visible in States where average electricity prices are well above the national average than in those where prices are well below the national average.⁽⁸¹⁾ During the transition period prices are to be determined by market forces, and high-cost utilities may be unable to fully recoup the embedded costs of their investments. The amount by which the embedded cost of a utility exceeds the market value of an asset is generally referred to as stranded cost.⁽⁸²⁾

A recent Edison Electric Institute (EEI) report noted that the quickest and most pragmatic way to get competitive power is to offer the incumbent utilities the tools and flexibility to collect their "stranded" or transition costs.⁽⁸³⁾ The EEI maintains that a significant portion of the stranded costs (such as nuclear investments and independent power contracts) is attributable to public policies of the past.⁽⁸⁴⁾ Recovery of stranded costs is thus based on equity and fairness arguments.

Investor-owned utilities hold similar views and claim that they should be entitled to a full and timely recovery of stranded costs. Their arguments rest on the familiar notion that a regulatory compact entitles them to recoup reasonably adequate returns on invested capital.⁽⁸⁵⁾ As this option may no longer be feasible (at least for high-cost utilities) under competition, recovery of stranded costs is deemed necessary to maintain the financial viability and operational reliability of this critically important infrastructure. A subset of the regulatory compact argument also raises issues associated with usurpation of property, which is precluded by law, in the event that stranded cost recovery is denied.⁽⁸⁶⁾

Industrial users are particularly interested in securing lower electricity rates, and they view full stranded cost recovery as an impediment delaying the benefits of competition.⁽⁸⁷⁾ Discussing this subject in the early stages of the restructuring debate, the Electricity Consumers Resource Council (ELCON) outlined a five-step process for the recovery of net stranded costs associated with nonmitigable uneconomic assets resulting from transition to competition at the retail and wholesale levels.⁽⁸⁸⁾ The Electricity Customer Choice Group (ECCG) has recently supported a similar position with respect to the recovery of stranded costs.⁽⁸⁹⁾

Some commercial and residential customers do not support full stranded cost recovery for similar reasons. The National Association of State Utility Consumer Advocates (NASUCA) rejects utilities' claims for full recovery of stranded costs and would prefer that States and State public utility commissions "determine the appropriate recovery by utilities of uneconomic costs that are stranded as a result of retail access."⁽⁹⁰⁾

Independent power producers (IPPs) are in a unique predicament in this debate as existing suppliers to the utilities and also as potential contenders in the emerging competitive market for electricity. IPPs that currently supply power to the utilities at wholesale (in terms of contracts negotiated under the aegis of PURPA regulations) favor stranded cost recovery.⁽⁹¹⁾ These IPPs rely on the sanctity of contractual relationships and are aware that a number of their contracts saddle the utilities with stranded cost liabilities.⁽⁹²⁾ However, IPPs planning to compete in the market may not support stranded cost recovery with equal enthusiasm.

Arguments supporting recovery of stranded costs in the States are familiar. The financial stakes are large. Estimates of nationwide stranded costs (in the median range) fall between $100 and $200 billion.⁽⁹³⁾ The $200 billion estimate of stranded asset valuations is comparable with the aggregate equity of the industry.⁽⁹⁴⁾

States contemplating transition to competition generally start with investigations that involve a wide spectrum of stakeholders to develop a framework incorporating principles, goals, and objectives that need to be sustained as the electric industry transitions to a competitive mode.⁽⁹⁵⁾ In nearly every State where investigations have been completed, perhaps the most critical and contentious issue is the proposed treatment of stranded costs.

Initial estimation attempts at the State level start with defining stranded costs, together with a discussion and identification of contributory factors that lead to the emergence of stranded costs in their jurisdictions. At the same time, States invariably undertake to provide the utilities with a fair or a reasonable opportunity (comparable to that under the existing regulation) for recovery of their stranded costs during a specified transition period prior to the beginning of full competition.⁽⁹⁶⁾

Affirmation to accord the utilities an opportunity to recover stranded costs, as indicated above, is a difficult balancing act for the States. Allowing recovery would in some ways delay the expected electricity price reductions. Rejecting recovery could imperil the industry's financial viability, and could raise issues based on fairness, equity, and other legal considerations. Thus, the regulators require utilities to demonstrate that all practical steps to mitigate stranded costs have in fact been implemented before recovery of just and reasonable stranded costs is authorized.

Additional considerations, with a differing focus in each State, include the following:

• Delineation of components making up stranded costs. These usually include generation assets, purchased power agreements, fuel contracts, regulatory assets, employment transition costs, and environmental mandate costs.⁽⁹⁷⁾ Decommissioning obligations with respect to nuclear power plants and, in some cases, future operating or capital expenses are also included. Of these, only stranded costs relative to generating plants are backed by assets that can possibly be marketed. Thus, a significant portion of stranded costs may be represented by non-marketable assets, and their recovery may no longer be feasible in a competitive environment.
• Estimation of potential stranded costs. A utility can estimate potential stranded costs in one of two ways. It can compute the present value of its assets and compare the resulting valuation with its sunk or historical costs. Alternatively, it can compute the net present value of the aggregate revenue losses to be potentially sustained (for a given number of years) in the future as a function of projected electricity prices in the market. Estimations of stranded costs invariably net the negative value of above-market generating assets against the positive value of below-market costs.

  These basic approaches can be varied, depending on when the estimates are made (i.e., before or after the commencement of competition at the wholesale and retail levels) and whether the estimates are made administratively or are determined by the market. These differing considerations enable categorization of available approaches.⁽⁹⁸⁾

  Regardless of the method adopted, State commissions invariably require utilities to submit estimates of stranded costs that they seek to recover. What follows next is a process similar to a rate case proceeding, in which various stakeholders and the regulators subject a utility's claim to scrutiny and objective assessment.

  Based on recent decisions, a number of States have favored market solutions in preference to adoption of objective administrative determinations.⁽⁹⁹⁾ This explains why some State commissions have sought and secured divestiture of generation assets as a condition for permitting the utilities to recoup stranded costs. Announced divestiture plans by investor-owned utilities (in California, Illinois, Maine, Massachusetts, Montana, New Hampshire, New Jersey, New York, Oregon, Pennsylvania, and Rhode Island) indicate that more than 52 gigawatts of generating capacity was up for negotiated sales.⁽¹⁰⁰⁾ Where an agreement on sale price has been reached, incumbent utilities have sold their non-nuclear generating assets in excess of their book values (as in the case of New England Electric Systems, Boston Edison, and Southern California Edison). Whether divestiture enables a true valuation of generation assets is not, however, universally accepted.⁽¹⁰¹⁾

• Adoption of strategies to mitigate stranded costs.⁽¹⁰²⁾ Cost reduction (or cost containment) efforts and revenue enhancing strategies are the two common strategies. Other mitigation strategies may delay the onset of competition, alter depreciation options, reallocate costs, or restructure rates.⁽¹⁰³⁾

  Not all State regulatory authorities agree with the above approach. The Indiana Utility Regulatory Commission (IURC), for example, contends that there is no sure method for estimating a "recovery number" in advance. Using an estimate of stranded costs as a basis to set up a recovery method, the IURC prefers that the estimates be revised to reflect the impact of any relevant market changes. As an alternative, the IURC supports making stranded cost recovery contingent upon a utility's divestiture of generation assets.⁽¹⁰⁴⁾

• Designation of recovery methods. Several methods have been proposed by the States to recover stranded costs. Generally available options include: a nonbypassable variable charge based on kW/kWh usage; a fixed fee (including but not limited to an exit fee) independent of usage; and an access fee levied on suppliers. Each of these options has advantages and disadvantages associated with its implementation.

  Consider the nonbypassable wires charge. In its support it can be argued that the charge, which is based on demand and energy use, makes collection easy with the aid of existing metering devices. There is an element of transparency in its collection because of its clear link with the restructuring efforts and the associated stranded costs. Arguments against imposition of the wires charge dwell on its regressiveness and potential impacts on demand. In addition, the charge applies only to those who purchase competitive power and may or may not exclude new market entrants.

  Imposition of fixed fees creates a determinate liability, has no direct impacts on levels of consumption, and may minimize chances of an over or under recovery. However, it is unrelated to a customer's ability to pay and may be burdensome to low-end users. It also may distort usage levels.

  In choosing recovery mechanisms, State regulatory authorities tend to be guided by the impacts of such instruments. State regulatory authorities prefer that the recovery mechanisms be assessed for their impacts on rates.⁽¹⁰⁵⁾ The impacts should be fair, equitable, and nondiscriminatory. In addition, recovery mechanisms should promote economic efficiency (resulting in cost improvements) and provide utilities with a reasonable opportunity to recover their stranded costs.⁽¹⁰⁶⁾

• Securitization as an option for financing stranded costs. Securitization is a technique permitting a utility to create intangible transferable transition property rights to be used as collateral for funding instruments issued pursuant to the enactment of enabling legislation by a State. In essence, the process allows the utilities to receive cash now in exchange for revenue streams from a nonbypassable transition charge (that the utility's customers will pay in the future based on their allowed stranded costs) earmarked exclusively for repaying the newly created funding instruments.

  Consider a simplified example. Assume that a utility with $10 billion in assets has $4 billion in strandable assets. Authorizing the utility to securitize its strandable assets implies a reduction in its assets (ratebase) and in its liabilities by $4 billion. This allows the utility to reduce its rates to the customers immediately. In view of this potential, securitization has a seductive appeal to some regulatory authorities even though customers continue to pay for liquidation of amounts securitized through separate charges.

  For securitization to become operational, utilities sell, assign, or transfer the statutorily created property rights to a financing vehicle. Securities can then be sold by a trust or any special-purpose vehicle set up for this purpose. Repayment of securities sold in this manner is supported by future revenue streams specifically designated by a levy on customers, usually known as the competition transition charge (CTC). Over time, the utility collects the CTC and uses the proceeds to liquidate the amount securitized. This process avoids the need for a guarantee by the State to liquidate the liability created, even though the process virtually ensures its eventual liquidation, because the CTC levy becomes irrevocable until the amount securitized is paid.⁽¹⁰⁷⁾

  Some States (including California, Connecticut, Illinois, Montana, New Hampshire, Pennsylvania, and Rhode Island) have in fact adopted legislation designed to make this tool available to the utilities. In California, securitized bonds are called "rate reduction bonds" because the bonds are used to fund a 10-percent rate reduction in the State until the year 2002. Montana requires that savings resulting from securitization be applied to a rate freeze. Financial analysts anticipate that total stranded cost securitization may reach between $50 billion and $75 billion over the next 4 years.⁽¹⁰⁸⁾

  Critics point out that the securitization strategy can be used in multiple situations and is not directly associated with electric industry restructuring. Perhaps the more serious criticism stems from the lack of specific directives regarding utilization of funds by the utilities.⁽¹⁰⁹⁾ Some competitors are apprehensive that the sudden inflow of funds may be used by the utilities to undertake anti-competitive measures rather than to lower asset-related liabilities. There is also the perception that securitization shelters the utilities from both regulation and competition in the future.¹¹⁰⁾ This criticism stems from the inability to revisit securitized costs and determine the appropriateness of future recovery.⁽¹¹¹⁾

• Stipulation of recovery period for stranded costs. A short recovery period may lead to an earlier emergence of full-fledged retail competition than would be feasible under a long recovery period.⁽¹¹²⁾ However, this option enhances the possibility for errors in recovery, because adjustments to estimates become difficult to implement. If the recovery period is long, adjustments to estimates become feasible even though competition may be somewhat delayed.⁽¹¹³⁾ There is, however, no consensus on this issue.

  As States continue to negotiate workable arrangements with stakeholders for a transition to competition, securing a collaborative agreement with respect to stranded cost issues (with jurisdictional utilities) constitutes a critical step toward success. Without guaranteeing full recovery, States strive to design a strategy that minimizes transition costs while according utilities the opportunity to recover stranded costs that were prudently incurred and are verifiable and nonmitigable. In the alternative, States may face non-cooperation from utilities, including legal challenges. Either of these developments can lengthen the proposed transition to a competitive market for power.

  Key details on treatment of stranded costs in various States are included in Table 17. Additional details are provided in Appendix E.

Performance-Based Ratemaking (PBR)⁽¹¹⁴⁾

Under traditional cost-of-service, rate-of-return regulation, the price of electricity charged by a utility includes all of its variable and fixed costs plus a reasonable return on invested capital.⁽¹¹⁵⁾ In this environment, there is little or no incentive to reduce costs by implementing either efficiency improvements or productivity enhancements, because such actions are not likely to improve profitability.⁽¹¹⁶⁾ Economists contend that the cost-of-service regulatory approach produces inefficiencies in the choice of factor inputs, tending to make utilities more capital-intensive than they would be in a competitive environment. This distortion in the allocation of resources is known to economists as the Averch-Johnson effect.⁽¹¹⁷⁾

Performance-based ratemaking (PBR) represents an effort by regulators to decouple the linkage between utilities' prices and their costs under regulation by offering financial incentives to utilities to lower rates or costs.⁽¹¹⁸⁾ Under PBR, good utility performance can be rewarded with higher profits and poor performance can be penalized in some manner. PBR may thus be viewed as an alternative to traditional ratemaking and as a variant of incentive regulation.⁽¹¹⁹⁾ Some others view it as an evolutionary reform that is useful as the electricity generation sector transitions toward complete deregulation.⁽¹²⁰⁾

PBR is not new, having been used extensively in the telecommunications and railroad industries.⁽¹²¹⁾The current revival of interest in PBR is due to its capability to provide incentives that are similar to those provided by competition.⁽¹²²⁾ PBR also permits participants to secure a share of the gains (profits) resulting from improvements in efficiency or gains in productivity. In addition, the implementation of PBR can potentially assist State regulators during the restructuring process by complementing some of the incentives created by competition, or by removing some of the obstacles to customer choice.⁽¹²³⁾

PBR can be tailored to meet different objectives. During the transition to competition in generation, the central objective is to provide customers with lower rates without any diminution in safety, reliability, or quality of service.⁽¹²⁴⁾ To meet this objective, the regulators set a starting point or "baseline" revenue requirement, which can be adjusted (up for inflation or down for efficiency improvements). A package of incentives is then proposed to permit the utility to lower its costs relative to the baseline costs, in which case the realized cost savings are divided between the customers and the equity holders. Implementation hinges on quality control requirements that preclude cost savings at the expense of system reliability or customer service.⁽¹²⁵⁾

Approaches to PBR

It is possible to devise different approaches to tailor PBR mechanisms.⁽¹²⁶⁾ For the most part, these varying approaches can be collapsed into three principal categories: price caps, revenue caps, and sliding scale mechanisms. Note that these approaches are widely known and have been used in the past with respect to electric utilities.⁽¹²⁷⁾

Price Cap

Under the price cap approach, a ceiling price is set by regulatory authorities for a specified period into the future.⁽¹²⁸⁾ The initial price is set in a manner similar to that of traditional cost-of-service rates.⁽¹²⁹⁾ The utility is then allowed the flexibility to set prices below the ceiling without having to seek approval from the regulatory authority. There is also some predetermined price floor, such as the short-run or the long-run marginal costs of providing the service. This approach enables the utility to reap all the benefits of cost reductions while also bearing the cost of upward deviations between the target and the actual cost.

Once the initial price is set, the ceiling price over time is indexed to changes in inflation less an allowance for productivity improvements. The changes in productivity are sometimes referred to as the "X" factor. In some cases, unanticipated changes in costs not under the control of the utility are allowed to be included in the changes in the ceiling. In the literature on incentive regulation, such changes are called the exogenous factor, or the "Z" factor. Examples of the Z factor include regulatory assets such as deferred investment, expenditures associated with low-income programs, and in some cases, research and development (R&D) costs.⁽¹³⁰⁾

A utility has two incentives to reduce costs under this approach. First, after the initial ceiling price is determined, any reduction in costs will increase the profits of the utility until the end of the PBR period. Second, the period for which the price ceiling is applicable is much longer than the period between rate cases under traditional cost-of-service ratemaking; it is typically three years or more. The infrequency of regulatory reviews again serves to induce the utility to reduce costs, because the utility can keep the additional profits realized from cost reductions without triggering regulatory review during the period.

The inflation rate can be measured through the changes in the consumer price index (CPI), wholesale price, gross domestic product deflators, or an index of electric utility input prices. Productivity changes can be measured with the Bureau of Labor Statistics factor productivity index for the U.S. economy. Sometimes, changes in the productivity of the electric utility are taken into account: the productivity factor is measured as the difference between the national productivity measure and the electric industry productivity growth measure.

Revenue Cap

Under the revenue cap approach, regulatory authorities cap a utility's allowed revenues instead of prices. The cap permits adjustments for customer growth, but it is subjected to an index that takes price and productivity changes into account in computing the revenues allowed for a given time period. The discussion in the preceding section with regard to adjustments for inflation, productivity increases, and the Z factor is also applicable to the revenue cap formulation.

A cap may be applied to revenues in the aggregate or may be associated with revenues on a per customer basis.⁽¹³¹⁾ In the former case, there is an incentive for the utility to expand its electricity sales, assuming that rates are higher than marginal costs. In the latter case, there is an incentive for the utility to reduce its sales per customer. In this sense, the revenue cap is conducive to the promotion of energy efficiency and demand-side management programs.

Some features of revenue caps can decrease their efficacy, objectivity, and simplicity. First, revenue caps may cover only a subset of utility revenues to the exclusion of other costs. Second, revenue caps may not cover the determination of final prices, making it possible for a utility firm to charge more than it could under monopoly conditions.⁽¹³²⁾ Third, it is possible "that a small reduction in revenue cap will produce a large and unpredictable reduction in price."⁽¹³³⁾ Finally, there is also the possibility that a revenue cap may promote incentives to reduce sales regardless of the social benefits.

Solutions to some of these problems can be found by using a hybrid price-revenue cap.⁽¹³⁴⁾ Overall, both the price and revenue cap approaches create incentives to reduce costs. Some studies maintain that the tendency to overinvest in capital goods (the Averch-Johnson effect) can also be eliminated, and that efficiency improvements can be achieved. However, these approaches differ significantly on the subject of promoting or restraining kilowatthour sales. There is a perceived tendency to increase sales under a price cap regime and to minimize sales under a revenue cap regulation. It is possible to eliminate these shortcomings by devising a hybrid system that incorporates parts of both approaches.

Sliding Scale⁽¹³⁵⁾

Under a sliding-scale PBR, a utility's rates for electricity are determined in the traditional cost-of-service manner. However, the earned rate of return on equity is allowed to fluctuate within a specified limit (or a band) around an authorized rate. Electricity prices are adjusted—up or down—to enable the utility to attain its authorized rate of return.⁽¹³⁶⁾

In implementing a sliding-scale PBR, the intent is to track annual earnings (i.e., rate of return) and to share with ratepayers when the returns fall outside the prescribed band. The sharing mechanisms remain inoperative during the period when the utility earns a rate of return within the band. Generally speaking, there is an incentive for the utility to earn a rate of return that is higher than its authorized rate. For this approach to succeed, the range in which rates can oscillate should be wide enough for the utility to seriously consider cost reductions. Problems can arise if the range (within which the rate fluctuations are permitted) is too narrow, in which case adjustments by regulatory authorities would tend to become frequent. This would lower the utility's incentive for reducing costs. For this reason, the sliding-scale PBR is always used in conjunction with a price or revenue cap approach.

Targeted Incentives

Another alternative is for regulatory authorities to target a specific aspect of a utility's operation and provide incentives to improve its cost performance in that specific area. The three components of this approach are: target of the program, the measurement norm, and the associated rewards or penalties.⁽¹³⁷⁾

The performance of designated generating units (such as nuclear power plants) has historically been targeted in the past. Promoting investment in demand-side management programs has been another popular target. In selecting these or other targets, the standard against which performance is to be measured could be based on a utility's historical performance record, the performance of a group of utilities, or any other standard stipulated by the regulatory authorities. Reductions in costs could be passed to the utility. A criticism of this approach is that by focusing on one aspect of a utility's operation it may detract attention from a host of other areas that may also be candidates for improved performance.

PBR and Restructuring

With prospects of restructuring looming in many States, investor-owned utilities have a vested interest in actively participating in PBR programs, given the feasibility of reducing overall costs and improving their competitive edge (and possibly their profits) without having to confront the discipline of the market. Some State regulatory authorities support PBR as a measure that propels the industry toward efficiency and cost reduction without compromising the goals of safe, reliable, and least-cost service.⁽¹³⁸⁾ For example, the Massachusetts Department of Telecommunications and Energy (MDTE) lists five broad classes of benefits associated with incentive regulation: (1) improved X-efficiency, (2) improved allocative efficiency, (3) facilitation of new services, (4) reduced regulatory costs, and (5) reduced administrative costs.⁽¹³⁹⁾

The formulation of restructuring plans is based on the premise that market forces should be allowed to replace regulation. Accordingly, PBR includes those segments in which fully competitive markets do not currently exist (as in the case of power generation) or are not likely to exist in the future (such as distribution and transmission services). State initiatives are, therefore, of interest in providing information where for one reason or the other, implementation of restructuring may not be feasible in the near term. A brief overview of PBR plans that have been implemented in selected States is provided below.⁽¹⁴⁰⁾

Massachusetts⁽¹⁴¹⁾

In September 1994, the Department of Public Utilities—currently called the Massachusetts Department of Telecommunications and Energy (MDTE)—initiated proceedings to investigate whether the implementation of PBR (or incentive regulation) would provide marketplace benefits to customers by promoting more efficient utility operations, cost control, and opportunities for reduced rates in the State. In addition, the MDTE intended to explore whether incentive regulation could improve upon the existing regulatory framework (as prevailing in the State) and accommodate the transition to competition.⁽¹⁴²⁾

The MDTE sought comments on 19 questions in four basic categories: (1) theory and jurisdictional considerations, (2) broad-based versus narrowly targeted incentive programs, (3) effect of incentive regulation on the current regulation of utilities, and (4) procedural considerations concerning implementation. Its review indicated that a broad range of benefits (as indicated earlier) are associated with incentive regulation.⁽¹⁴³⁾

The MDTE did not endorse or adopt a specific PBR mechanism, but instead indicated that it will review PBR proposals on a case-by-case basis. The utilities in the State were required to develop individual proposals based on well-defined standards and filing requirements. For this objective to be achieved, the MDTE provided the following evaluation criteria:⁽¹⁴⁴⁾

• Be consistent with the Department's regulations, statutes, and governing precedents.
• Be consistent with market-based regulation and enhanced competition.
• Safeguard system integrity, reliability, and current policy objectives.
• Reward utility performance and address exogenous costs.
• Focus on comprehensive results.
• Incorporate well-defined, measurable indicators of performance.
• Be consistent with accounting standards and gain acceptance within the financial community.
• Allow the incentive plan enough time to succeed, within a minimum time frame.
• Reevaluate the program at least once during the period of the PBR to monitor goal attainment and make required modifications, as necessary.
• Be administratively simple.

The MDTE recognized that all incentive plans—and especially those that accord increased pricing facilities to utilities—must still be carefully designed. A plan must assign specific benefits that would additionally accrue to the customers either in the form of price or service. The plan should not permit the utility to cross-subsidize different customer classes or undertake anticompetitive behavior. In addition, the plan should hold a promise of higher financial rewards.

In a subsequent Order, the MDTE formulated a set of principles establishing the essential infrastructure of electricity restructuring in Massachusetts. Reiterating its earlier conclusions, one of these principles places reliance on incentive regulation where a fully competitive market cannot or does not exist. Recognizing that transmission and distribution will continue to be monopoly services requiring regulatory oversight, the MDTE directed that the utilities include a plan for incentive regulation for transmission and distribution systems in their respective restructuring plans.^(`45)

More recently, in a statement on restructuring and proposed rules (issued on May 1, 1996), the MDTE proposed that the distribution companies implement PBR in the form of price cap plans.⁽¹⁴⁶⁾ In the proposed PBR, base rates will be allowed to change annually based on inflation, with adjustments for productivity changes and other exogenous factors.⁽¹⁴⁷⁾ In addition, a distribution company will be penalized if it does not meet the specific (minimum) performance standards for safety, service reliability, and customer service.

Support for issuance of a price cap PBR was provided by several commenters,⁽¹⁴⁸⁾ who maintained that the price cap plans:

• Tracked the unit-cost trend of the utility
• Provided an effective mechanism for controlling rates during the transition period
• Provided customers with a predictable price trend that incorporated productivity and efficiency gains.

The MDTE directed that price cap PBR plans should be no less than 5 years in duration and should be evaluated at the end of that period. Distribution companies are to file their rate cap proposals for review at the same time that they file the first general rate case after the final industry restructuring rules become effective.

In submitting its final proposals, the MDTE reiterated its earlier conclusions that price cap plans are preferable to other types of PBR mechanisms and are more likely to achieved the desired objectives.⁽¹⁴⁹⁾ In directing the utilities to include PBR proposals in their restructuring plans, the MDTE did not stipulate that a specific format (such as a price or a revenue cap) be followed in their submissions. However, it did provide three additional guidelines for preparing PBR plans:

• PBR plans should apply only to department-regulated functions at the time of filing.
• PBR plans should not involve the stranded cost issue, which will be addressed separately.
• Any proposal to convert a utility's distribution operations from cost-based to performance-based regulation should include comprehensive quality standards with significant financial incentives to guard against any degradation of traditional service quality and reliability levels.⁽¹⁵⁰⁾

For example, a settlement reached by the affiliates of the New England Electric System (NEES) in February 1997 establishes performance-based rates.⁽¹⁵¹⁾ Among other provisions, the settlement sets a floor of 6 percent and a ceiling of 11 percent on Massachusetts Electric's (NEES's affiliate) rate of return on equity, effective on commencement of retail choice in 1998. Earnings over the ceiling are to be shared equally between the customers and the shareholders, subject to a maximum of 12.5 percent, raising the effective cap on equity to 11.75 percent. In the event that earnings fall below the floor, a surcharge will be allowed to cover the shortfall. Rates for the distribution company of NEES were also set under the settlement.⁽¹⁵²⁾ Other provisions that affect Massachusetts Electric eliminate the adjustments for purchased power and freeze its non-fuel rates until 2001.

The July 1997 filing by Boston Edison Company adopts a somewhat different track. Its filing is an agreement (called a "settlement") reached with the State's Attorney General and the Governor's Energy Commissioner that has been submitted to the MDTE for approval. The settlement envisages PBR within the framework of a standard offer during the transition period from 1998 through 2004 and is contingent on full divestiture of the Company's generating assets, a rejuvenation of energy conservation programs, contributions to the "green" energy supplies, and a separation of its distribution and generation facilities.⁽¹⁵³⁾

During the transition period, Boston Edison's customers will receive a 10-percent price reduction. Equity returns on its distribution operations have a ceiling of 11 percent and a floor of 6 percent, with provisions for adjustment if returns fall below the floor or exceed the ceiling. Boston Edison's delivery business will purchase power from other suppliers to implement the proposed 10-percent reduction.

Maine

Although PBR activities in Maine precede the recent restructuring efforts, they have not been very successful. The State's largest utility—Central Maine Power Company (CMP)—had seen its rates rise annually by about 10 percent during the period from 1990 through 1992. Bangor Hydro-Electric Company (BHE) needed pricing flexibility to be able to compete successfully in the State. Maine Public Service Company (MPS) was facing substantial financial stress. In response to these issues, the Maine Public Utilities Commission (MPUC or the Commission) crafted variants of PBR to suit the specific needs of each utility.⁽¹⁵⁴⁾

In the case of CMP, the Commission devised an alternative rate plan (ARP) in an attempt to counter the utility's frequent request for rate increases and to mirror the effects of competition consistent with the commitment to serve the public interest. The Commission's solution in the form of an ARP imposed a price cap on CMP's operations for a 5-year period from 1995 through 1999.⁽¹⁵⁵⁾

Critical elements of the ARP include:

• Stipulation of a price cap ceiling with profit sharing and price flexibility. The price cap applies to all retail rates, including fuel and purchased power costs of the utility. The profit sharing mechanism adjusts earnings if they are outside a 350-basis-point bandwidth (currently at 7.05 percent to 14.05 percent) around the authorized cost of equity initially set at 10.55 percent.⁽¹⁵⁶⁾
• Development in detail of a price cap formula, including a price index, a productivity offset, a profit-sharing mechanism, sharing benefits from buyouts of power purchase contracts pertaining to qualified facilities, flowthrough items, and recognition of mandated costs.⁽¹⁵⁷⁾
• Empowerment of the utility to set flexible rates for its different customer classes in a manner designated by the Commission. Customer classes include existing customer classes, new customer classes for optional targeted services, and special rate contracts. The utility is thus better positioned to meet competition from other sources.⁽¹⁵⁸⁾
• Establishment of a customer service and reliability index to give the utility incentive to adhere to specified benchmarks without invoking penalties that would otherwise become applicable.
• Fixed targets for demand-side management activities, with penalties for noncompliance.
• Delineation of various accounting provisions for regulatory assets, decommissioning costs, and other items.

The ARP provisions also protect the utility and its ratepayers against the consequences of adverse operating results on earnings. To evaluate this aspect, the MPUC will  conduct a mid-term and a final review should returns fall outside a designated range.⁽¹⁵⁹⁾ The basic components of the ARP are designed to give CMP the incentive to reduce costs or to risk reduced rates of return on its equity.

The above critical elements of the ARP plan make it a major reform, even though the Commission's oversight continues. Note that the ARP has not fully protected the shareholders from the costs of the Maine Yankee nuclear power plant outage. In 1995, primarily as a result of the outage, the rate of return on equity was 5.7 percent. This loss was equally shared by the ratepayers and the shareholders and prompted the Commission to make adjustments for the mid-point rate of return on equity in its 1997 review. Since Maine Yankee's outage costs could also affect the utility in the future, the Commission could also direct that the utility divest its interests in Maine Yankee.⁽¹⁶⁰⁾

The Commission's PBR for BHE also represents a form of price cap, although it is known as an "alternate marketing plan" (AMP). While the CMP's alternative rate plan focused on a price cap to force the utility to be more efficient, BHE's proposal sought increased flexibility to offer reduced prices and develop related marketing programs. More specifically, BHE sought discretion to reduce any of its rates without approval from the MPUC, subject to the criterion that such prices will be above the utility's short-run marginal costs plus 10 percent depending on circumstances. BHE provided a commitment to attempt to cap electric rates for an extended time period and to eliminate fuel cost accounting, the fuel adjustment clause, and seasonal rate differentials, together with an understanding about the method of amortizing the cost of any future buyout of high-cost purchased power contracts. In addition, the BHE plans also provided a voluntary commitment to avoid traditional rate increases to the extent possible.⁽¹⁶¹⁾

In approving BHE's request, the MPUC directed the utility to file interim marginal cost floors. Various stakeholders could request a proceeding with regard to setting permanent marginal cost floors. The MPUC also encouraged affected stakeholders to resolve various issues arising from the implementation of the AMP.⁽¹⁶²⁾

The third utility in the State, the MPS, also filed a proposed increase in rates and an alternative rate stability plan (RSP), in which it sought to collect increases in rates over a 5-year period. MPS filed a marginal cost study in support of its rate design proposal. The utility's filing was prompted by the loss of its two large customers and the costs of operations at Maine Yankee nuclear power plant.

In its stipulation, the MPUC established a multi-year rate plan that permitted the utility to increase its rates by an agreed-upon percentage. The Commission also established a profit sharing mechanism (with a target rate of return on utility's equity set at 11 percent), so that risks and benefits could be shared by the utility's shareholders and its customers.⁽¹⁶³⁾

California

California's initial experience with incentive-based ratemaking started with the telecommunications industry in 1989 and then continued with the natural gas industry in 1991. In 1993, the California Public Utilities Commission (CPUC) recommended the use of performance-based ratemaking mechanisms as a possible tool to reform the regulatory process in the electric utility industry in the State.⁽¹⁶⁴⁾ CPUC's interest in replacing the traditional cost-of-service ratemaking with PBR was also prompted by the prevalence of electric rates in the State that were significantly higher than the national average.

With the commencement of investigations and rulemaking to consider the proposed restructuring of the electric utility industry in the State, the CPUC in its Blue Book Decision stated its objective of replacing the traditional cost-of-service regulation with PBR where competition had not yet developed.⁽¹⁶⁵⁾ While several factors contributed to this decision, the most critical was the high cost of electric services in the State.⁽¹⁶⁶⁾

In its subsequent Preferred Policy Decision, the CPUC reaffirmed its commitment to continue support for PBR on grounds of encouraging efficient operation and improving productivity to replace the reasonableness reviews and disallowances associated with traditional rate case proceedings.⁽¹⁶⁷⁾ While utility services not subject to competition will continue to be regulated by the CPUC, PBR instead of cost-of-service regulation will be used to give utilities greater flexibility in running their operations. To meet this objective, the State's investor-owned utilities were directed to provide their comments on pending PBR proposals and to file new PBR applications subject to the unbundling of traditional utility services into generation, transmission, and distribution.

The Preferred Policy Decision notes that, as the market structure for the industry continues to be transformed, utility distribution services and utility-owned generation may be only two areas of continued regulatory oversight. A distribution PBR will focus on performance, so that customers can secure nondiscriminatory service without loss of quality. A generation PBR would be consistent with the assumption that utilities will retain some of their generating assets during the transition period. CPUC's subsequent Roadmap Decision delineated major issues to be taken up for discussion in crafting major PBR mechanisms.⁽¹⁶⁸⁾

Even as the above policy decisions were being articulated and reaffirmed, utilities in California had already filed applications for approval of self-designed PBR plans. San Diego Gas and Electric, for example, filed its application proposing a base rate PBR in October 1992, followed by Pacific Gas and Electric in December 1992. Southern California Edison filed its PBR application (modified later to include only its transmission and distribution activities) in December 1993.

A recently released Commission study⁽¹⁶⁹⁾ points out that the base rate PBR plans so far adopted have the following main elements:

• A formula to establish revenue requirements indexed to inflation and adjusted for productivity and changes in cost of capital
• A revenue sharing mechanism allowing shareholders and ratepayers to share any actual revenues that exceed the authorized rate of return on equity
• A reward/penalty system to ensure that employee safety, reliability, and customer satisfaction standards are maintained
• Inclusion of adjustments to capture the influence of exogenous factors
• A monitoring and evaluation program.

As stated earlier, Southern California Edison (SCE) filed for a PBR mechanism in 1993 to determine most of its revenues.⁽¹⁷⁰⁾ SCE subsequently divided its filing between transmission and distribution and power generation (i.e., between generation and nongeneration revenues).⁽¹⁷¹⁾

The CPUC adopted a nongeneration (i.e., transmission and distribution) PBR mechanism for SCE in September 1996, to become effective on January 1, 1997.⁽¹⁷²⁾ Beginning in 1998, the PBR will be applicable only to the nongeneration distribution activities of the utility for the period ending in December 2001.

Key elements of the PBR as applicable to transmission and distribution include a rate indexing formula that takes into account inflation adjusted for productivity enhancements, a revenue sharing mechanism, a cost of capital trigger mechanism, service quality performance incentives, and adjustments for exogenous factors that are not within SCE's control. CPUC has also stipulated safety and safeguard standards that the Company must meet to ensure that costs are not reduced at the expense of safety or quality of service.

The base rate PBR filing by San Diego Gas and Electric Company (SDG&E) in 1992 was adopted by the CPUC in August 1994 for a term from 1994 through 1999.⁽¹⁷³⁾ This PBR is currently applicable to bundled electric service, including generation, transmission, and distribution and gas department base rate revenues.

The utility's PBR has four main components: a revenue cap based on formulas for developing an annual revenue requirement, a revenue sharing procedure, performance indicators, and a program to monitor and evaluate the program.⁽¹⁷⁴⁾ Provisions for suspending the PBR mechanism are also specified in the PBR, depending on whether the rate of return exceeds or falls below the authorized level for a given year.

SDG&E is required to file an annual report providing a summary of the prior year's performance on May 15th of each year.⁽¹⁷⁵⁾ Each year, the CPUC adjusts the revenue cap on the basis of the prior year's cap adjusted for inflation and customer growth, an offset for productivity, and changes in capital costs. Overall, the utility's experience with the PBR has been found to be successful in the area of performance, as evidenced by the awards it has received.

Critics, however, fault the utility's price performance as being ineffective due to the design of the initial PBR.⁽¹⁷⁶⁾ Criticism has also been voiced regarding the manner in which profit sharing has operated in the past. Both these aspects are under review, and steps are being taken to remedy the profit sharing mechanism so that customers receive a reasonable share of the financial benefits resulting from operation of the PBR.⁽¹⁷⁷⁾

As stated earlier, the Preferred Policy Decision directed all utilities in the State to establish generation and distribution PBR plans consistent with the policies outlined in the Decision.⁽¹⁷⁸⁾ In the case of SDG&E, the CPUC authorized continuance of the utility's PBR plan until the transition to a new industry has occurred. The utility is thus to file an electric distribution (and a gas department) PBR.⁽¹⁷⁹⁾ SDG&E filed its electric PBR in December 1997.

The CPUC adopted Pacific Gas and Electric Company's (PG&E) "base rate" PBR in 1993. Under this PBR, PG&E's annual price changes for electricity are based on a cost escalation index offset by productivity gains. Price changes that do not exceed an upper bound (based on a national average) are permitted. Based on the PBR's methodology, PG&E was eligible for a 2.4-percent price increase in 1995. The utility, however, requested a 1.5-percent increase in view of the changing industry conditions.

In July 1996, PG&E filed a PBR application for electric generation services applying only to its hydroelectric and geothermal plants (excluding fossil-fuel plants).⁽¹⁸⁰⁾ The PBR would set revenue requirements for base revenues (including sunk costs) and energy-related costs by using an indexed base revenue formula, with adjustments for shared earnings, fuel costs, performance standards, and extraordinary costs or savings.

PG&E also submitted a preliminary unbundling proposal in July 1996.⁽¹⁸¹⁾ This proposal separates electric costs into five basic components: generation, competition transition charge, transmission, distribution, and public purpose programs. PG&E received authorization to file its distribution PBR proposal on or after December 15, 1997.⁽¹⁸²⁾

Other States

This discussion deals with the recent experience of three States with respect to their PBR plans.⁽¹⁸³⁾ As other States finalize or move ahead in planning industry restructuring, the use of PBR programs may increase to cover activities in areas still being regulated. The Rhode Island restructuring legislation, for example, requires distribution companies to file PBR plans before December 1998.⁽¹⁸⁴⁾ The Michigan Public Service Commission has also expressed its full support for PBR plans, even though it does not have proposals from any of its jurisdictional utilities.⁽¹⁸⁵⁾ Programs in some other States incorporate all the essential ingredients of PBR plans but are labeled differently.⁽¹⁸⁶⁾

State regulators have tended to distance themselves from the traditional rulemaking methodology, promoting PBR to stress efficiency and performance by utilities. To the extent that this effort leads to a potential decline in rates in comparison with those that would otherwise have prevailed, implementation of PBR may be preferable to traditional cost-of-service, rate-of-return regulation. Additional benefits include achievement of allocative efficiency (resulting from pricing flexibility enjoyed by the utilities) and a potential saving in administrative and regulatory costs. The key to securing some or all of these benefits lies in using the PBR as a part of long-term strategy.

Potential pitfalls also exist in the implementation of PBR. If the regulatory focus is primarily on costs of generation and purchased power, other cost and quality of service issues may be overlooked. Provisions pertaining to sharing earnings or absorbing losses could well lead to a dilution of utility incentives. Monitoring and evaluation inadequacies could possibly lead to unintended results not in conformity with the spirit of PBR plans.

Given the short timeframe during which the PBR plans have been in effect, it is difficult to evaluate their impacts in a systematic manner. The lack of performance yardsticks (in acquisition and operation) makes it particularly difficult to measure the success of PRB initiatives overall. In cases where PBR plans incorporate the passthrough of social program costs—such as demand-side management or environmental controls—benefits could be offset by the expenses of the programs. Similar problems would arise in funding low-income programs.

As the electricity generation segment of the industry moves toward competition, the requirement to craft PBR plans for generation activities may gradually decline over time. Utilities will, however, expect revenues pertaining to their transmission and distribution activities on a cost-of-service basis. The extent to which the application of PBR in these segments would reduce costs remains to be seen.⁽¹⁸⁷⁾ Thus, the success of PBR will hinge primarily on its design and implementation to the extent that safety, service, and reliability issues are not compromised in the process.

Pilot Programs

Background

Pilot programs are controlled tests designed to mimic the realities of retail competition in electricity generation. Pilot programs give a selected number of a utility's retail customers the option to buy power from alternative supply sources, to test the hypothesis that market forces produce rates lower than those under regulation.

During the pilot, the new supplier (either a generator or a power marketer) provides electricity, and the incumbent utility provides transmission and distribution facilities to its eligible customers who exercise the option of choosing a new supplier. Participating customers reimburse the new provider and the incumbent utility for the differentiated services.

Traditional billing mechanisms include the costs of generation, transmission, and distribution in a per-kilowatthour rate. A competitive regime commencing with the experimental pilot requires unbundling or a separation of the cost of generation from other cost components, so that the customers can pay the generation rate offered by the new supplier (or provider) and the transmission and distribution rates of the local, incumbent utility. In the process of unbundling, a competitive transition charge component to compensate the local utility for stranded costs that result from losing customers may also be separately included.

During the pilot, the local utility continues to have the obligation to serve customers within its assigned or franchised territory. Regulatory authorities protect customers by monitoring the activities of the incumbent utility and the new suppliers. At the end of the pilot, an evaluation indicates the issues that need to be addressed in the future.

Purpose

Pilot programs are implemented with the objective of gaining experience as the electric power industry transitions toward competition. The New Hampshire Public Utilities Commission (NHPUC) defined the purpose of its pilot as "to create a limited experimental program to examine the implications of retail competition in the electric utility industry."⁽¹⁸⁸⁾ In addition to feedback on operational and logistic issues, the regulatory authorities wish to be assured that narrowing the gap between existing regulated prices and unregulated prices is a feasibility.

Types and Categories of Pilot Programs

Pilot programs may be started by utilities on their own initiative, by order of regulatory authorities, or by legislative enactments.⁽¹⁸⁹⁾ Pilot programs in Washington State were sponsored by the utilities.⁽¹⁹⁰⁾ Among the early pilots implemented, only the New Hampshire pilot (designed by the NHPUC) was the result of a legislative mandate.⁽¹⁹¹⁾ Regulatory authorities in New York contributed to the establishment of pilot programs as a part of the restructuring process in the State.

Pilot programs fall into two broad categories: those designed for large customers (usually industrial or commercial firms) and those designed for residential and small business customers. The first category of program (for large customers) will usually have a small number of customers.⁽¹⁹²⁾ For such customers, the price of power often represents a significant element of the cost of their operations, and they have an incentive to save in order to maintain a competitive edge. For small customers, the penetration of retail choice depends on effective education and outreach efforts by the utilities and the regulatory authorities.⁽¹⁹³⁾ Most recent programs submitted by utilities include all customer classes, but pilots designed to meet sectoral needs are not rare.⁽¹⁹⁴⁾

Participation in Pilot Programs

Participation in pilot programs varies among customer classes. The larger customers are more sophisticated in energy matters and have a vested interest in reducing their costs. They could be represented by trade organizations in the pilot design process or they could secure concessions by virtue of their size. In contrast, smaller customers may view the pilot program with apathy, because the savings, if any, may not be large enough to justify transaction costs.

Pilot Goals

Pilots initiated by utilities aim to gain experience of what the competitive market would be like in the future, to learn the technical and administrative details of retail access, and to get ready for the transition. The unbundling requirement forces the utility to get ready for competition, to seek appropriate remedies for costs that have the potential of being stranded, and to formulate a framework that ensures system reliability and quality of service.⁽¹⁹⁵⁾

Pilots initiated by legislative enactments or regulatory orders have wider considerations. Regulatory authorities and lawmakers can evaluate the implications of and obstacles to retail competition, the impact on rates, patterns   of customer responses, and the possible magnitude of inroads that outside suppliers can make within a franchised territory. It is also possible to evaluate the extent to which free markets would tend to support activities that are not directly related with generation but would still need to be sustained.⁽¹⁹⁶⁾ Estimates of financial impacts on utilities are also feasible.

Besides gaining experience in promoting pilot programs, State regulatory authorities specify goals expected to be achieved in the process. For example, the Pennsylvania Public Utility Commission (PPUC), in directing jurisdictional utilities in the State to file electric retail access pilot proposals, established specific goals to be attained. An added requirement obligates utilities in Pennsylvania to explain how specified goals will be achieved by implementing the pilot proposals they file.

Goals set by the PPUC are:⁽¹⁹⁷⁾

• To encourage development of a robust competitive retail market for electric generation and capacity
• To promote customer awareness of benefits and risks of competition and prepare customers to fully participate in retail competition through effective education and experience
• To encourage customer participation through choice of competitive options
• To foster safe and reliable service
• To preserve customer access to existing customer protection
• To test the effectiveness of integrated transmission system technical, physical, and commercial operations involving increased numbers of generation sources and transmission customers
• To ensure accurate, concise, and timely information exchange between local distribution suppliers and control area operators
• To establish fair business practice requirements to promote a broad array of qualified market sellers and willing buyers
• To assess and communicate pilot process results to the public.

Pilot Parameters

Stipulation of goals, as enumerated above, is invariably undertaken in conjunction with the specification of well-defined parameters that govern submission and approval of utility filings. In Pennsylvania, requirements for compliance include:⁽¹⁹⁸⁾

• Pilot size to represent approximately 5 percent of a utility's peak load of each customer class.
• Pilot length to be at least 1 year.
• Pilot participation to be open to all customer classes.
• Pilots should describe the process by which electricity suppliers may participate and the operational standards required of them.
• A utility may offer competitive generation services to its traditional customers on the same basis as other suppliers. Options for eliminating anti-competitive behavior in such cases are examined. A code of conduct for utilities to observe is also provided.
• Utility tariffs to unbundle generation from jurisdictional transmission and distribution (T&D). The utility's terms and rates for transmission and distribution services to all other retail customers should be comparable to the utility's own use of its system.
• Rates for transmission access should be consistent with rates contained in the Federal Energy Reg-ulatory Commission (FERC) tariff.
• Recovery of stranded costs may be included in the pilot programs.
• Electric generation supply agreements to meet reasonable operational standards.
• Consumer education and protection issues (including service safety and reliability) to be addressed in the pilot.

Regulatory Concerns

Even though the regulatory authorities set goals and define parameters for utilities to observe, there are still some legal issues that are of concern to them. Some of the issues that the NHPUC considered are listed below.⁽¹⁹⁹⁾

• Authority to order retail wheeling. This authority is either implicit in the regulations governing public utilities in States or legislatively provided to the regulatory authorities where necessary. NHPUC contended that the FERC had no legal authority to prevent States from ordering retail wheeling.
• Stranded cost recovery. Most States offer utilities the opportunity to recover prudently incurred and nonmitigable stranded costs. Imposing constraints on this approach—as was done in New Hampshire—has delayed the transition to competition in the State.
• Jurisdiction over interstate transmissions. States have the jurisdiction to regulate the rates, terms, and conditions of distribution services in the State. However, the jurisdictional boundaries on transmission are far from clear according to NHPUC.
• "Filed Rate" doctrine. The issue here is whether the State regulatory authorities can "deny utilities with FERC-approved purchase power contracts the right to full recovery of power costs shifted to non-participating customers" through the application of adjustments to fuel and power costs. The NHPUC upheld the view that utilities will not be able to shift costs from pilot participants to nonparticipants.

There are also other operational issues that State commissions have to deal with in establishing pilot programs. Guidelines for unbundling are needed to ensure that suppliers get transmission service comparable to that which the utilities secure for themselves, letting customers know that they bear the responsibility for consequences of their choice, and finalizing rules for customer selection and supplier eligibility, billing, metering, and the sharing of customer-related data.

Size and Duration of Pilot Programs

Most pilot programs are small, ranging from a low of 2 megawatts in Washington to a high of 422 megawatts in Pennsylvania. For participating utilities, this represents a small fraction of their peak load. The duration of pilot programs varies from 1 to 5 years, with a majority having a 2-year term. Recent programs approved in Pennsylvania and Massachusetts have been for a 1-year period awaiting the introduction of direct retail access for all customers. The only program for a 5-year term was approved in Illinois for the Central Illinois Light Company in 1996. The potential loss of revenues, assuming maximum participation, is accordingly small in comparison with the potential for strandable costs in the event that direct access becomes universal.

Selection of Customers

Selection of customers depends on whether the pilot program includes all customer classes or targets only a specified class of customers. Where small customers (mostly residential and commercial business customers) are involved, it is common to define the geographic area of choice for their participation. Load limitation and the possibility of load aggregation may be factors in this decision. These considerations do not apply where large industrial or commercial customers are involved. The New York Public Service Commission, for example, approved a retail access pilot program in 1997 for qualified farmers and food processors in upstate New York, covering service territories of its four jurisdictional utilities.⁽²⁰⁰⁾ Under this program, more than 17,000 farms and 600 food processors will be able to use the pilot to make choices about their power requirements based on the eligibility criteria instituted for the purpose.

Small residential and commercial business customers joining the pilot may or may not be allowed to leave the program at will. Some programs, as in New Hampshire, allow customers to switch to an alternative supplier as often as desired, but customers may not leave the pilot and then re-enter. Large customers usually sign up for a longer term, as in the case of the pilot set up by the Idaho Power Company, in which customers sign for loads ranging from 5 to 10 megawatts for a 3-year period.⁽²⁰¹⁾

Eligibility of Suppliers and Providers

In recent years, electricity suppliers and marketers have proliferated. Encouragement is offered to a wide range of organizations that meet the eligibility requirements to participate in pilot programs.⁽²⁰²⁾ Regulators invariably stipulate a set of requirements and criteria that suppliers have to meet to be eligible. The requirements vary by State.⁽²⁰³⁾ Suppliers may be required to register with the regulatory authorities and provide evidence of their financial and technical capability to provide electricity to customers.⁽²⁰⁴⁾

Suppliers may be exempt wholesale generators, qualifying facilities, marketers and brokers, or jurisdictional utility marketing affiliates and nonaffiliates within or outside a State. Participation by local utilities through affiliates may be subject to approval by regulatory authorities. It is also not unusual to use a bidding process in choosing suppliers to meet the requirements of a selected group of customers.⁽²⁰⁵⁾

Other Issues

A host of issues need to be taken into account in establishing pilot programs. Metering, billing, marketing, customer education, and treatment of transition costs are among the issues on which directives are provided by regulatory authorities.

Evaluating Pilot Programs

Most pilot programs have only recently been implemented and are still ongoing (see Table 18). These two factors make it difficult to evaluate their impacts. Two recent studies make the following observations:⁽²⁰⁶⁾

• Pilots are valuable in providing the participants (including the incumbent utilities) the experience they need prior to the commencement of full-scale competition.
• Development of technical procedures to implement the pilot is critical to its success. Pilot program design has been evolutionary, involving significant cross-fertilization.
• Customer acceptance response has been mixed. Large customer loads were fully subscribed. In fact, some of the large customers or their trade organizations often participated in the design development process, as in Illinois and Massachusetts. Residential and small business customers exhibited a lack of enthusiasm despite inducements in the form of guaranteed lower rates.⁽²⁰⁷⁾
• Low participation rates among residential and small commercial business customers could be attributed to insufficient savings, inadequate program promotion efforts, and complex or burdensome participation procedures. Where the size of the program is small, there may be no incentive for potential suppliers to participate.⁽²⁰⁸⁾
• Participating customers have generally been satisfied with the pilot programs. Price reductions needed to induce the customers were offered by the incumbent utilities. Some marketers sold power below cost.
• Factors influencing customer selection of suppliers generally include price and environmental considerations. Preference for local suppliers is also a contributory factor.
• Actual cost-saving benefits accrue across customer classes and programs. Overall, the percentage of savings secured by larger customers was higher than those secured by smaller and residential customers.⁽²⁰⁹⁾ These differences could be attributed to the better bargaining strength of the industrial customers.
• Suppliers participating in the pilot programs are interested in gaining market share and experience rather than in making profits in the initial stages. This may explain why some of the suppliers charged prices that were lower than those anticipated (as in New Hampshire).
• Marketing electricity from renewable sources has not been a significant component of the pilot programs so far established. Programs in New Hampshire and Massachusetts that attempted to foster renewables indicate that customers may be willing to pay more for electricity from sources that are less polluting than conventional fossil-fired generating power plants. It is, however, unlikely that pilot programs in these States brought forth any new generation resources, and the assumption that existing resources were merely repackaged may be appropriate. To make the choices more transparent for customers, plans in the future may call for a complete disclosure of a supplier's generation profile, a breakdown of fuel sources, and a means to verify this information.
• Reliability did not emerge as an issue in the pilots, presumably due to the relatively small loads involved and the adequate reserve capacity.
• Customer service provided by the incumbent utilities should improve overall as pilots increase in any territory and competitive pressures increase. Included in this category are the billing and metering services that need revamping.

Unresolved Issues

As stated earlier, pilot programs are a mechanism for testing and experimentation so that regulators, utilities, and suppliers can all learn profitably. There are, however, issues that have not yet been fully resolved. Treatment of utility affiliates (and their ability to compete in the associated utility's territory) is one such issue.⁽²¹⁰⁾

The tax impacts of pilot programs have not yet become an issue because of their relatively small size. However, as retail access choices become universal, revenue losses by incumbent utilities will become significantly more likely. If out-of-State suppliers play a dominant role, State revenues will be affected. Such losses could be offset by changes in the tax code, but this has yet to be done. Rules regarding regulatory certification of suppliers in a given territory may also need tightening to prevent potential abuses.

Conclusion

It is possible that additional issues will emerge as universal retail access gains momentum in the States and the overall demand for power continues to grow, eliminating the capacity excess that currently prevails systemwide. The success of fully competitive markets depends on the ability of the system to add capacity without undue constraints. Opening generation to competitive forces while concurrently retaining the current siting and licensing powers of regulatory authorities for new power plants and transmission lines may possibly limit the accrual of benefits that competition can bestow. Should shortages, therefore, develop either as a result of capacity or transmission constraints, it is difficult to rule out the possibility that some current generation or transmission owners will be able to augment economic rent collection.

End Notes

56. For an overview of the electric power industry in the United States, refer to Energy Information Administration, The Changing Structure of the Electric Power Industry: An Update, DOE/EIA-0562(96) (Washington, DC, December 1996), pp. 3-28.

57. Statement by James Hoecker, FERC Chairman, at the National Association of Regulatory Commissioners Summer Meetings in San Francisco, CA (July 1997), reported in Electric Utility Week (July 28, 1997), p. 1.

58. The U.S. Senate Committee on Natural Resources organized four workshops in early 1997 to gather information about stakeholders' views on issues dealing with "competitive change in the electric power industry." The Committee's main objective in arranging these workshops was to define a fair pathway (with supporting Federal legislation where deemed necessary) in implementing competition so that its benefits accrue to all customers. The House Subcommittee on Energy and Power undertook a similar effort by holding a series of field hearings on the subject of "electric power to choose" during the same time period. Additional details regarding these workshops and field-hearings can be found on the respective home pages of the Committees. See web sites www.senate.gov/~energy/competit.htm and www.house.gov/commerce/releases/electric/handbook.htm.

59. Rep. Clifford Sterns, "Haste Can Lay Waste to Industry," Roll Call (February 24, 1997). The "painless moiety" (i.e., the relatively straightforward part of the restructuring process) refers to the actions initiated by the FERC, leaving a host of other controversial issues to be sorted out by the States.

60. Note that only a small number of States (California, Connecticut, Illinois, Maine, Massachusetts, Montana, Nevada, New Hampshire, Oklahoma, Pennsylvania, Rhode Island, and Virginia) have enacted legislation to promote competition at the retail level.

61. According to a press release dated July 9, 1997, from the House Commerce Committee, the Pennsylvania Congressional delegation sent a letter requesting a Federal date for the State implementation of competition in the electricity markets. Other States that have already implemented legislation may or may not be in a position to support this request. Other States (like Florida and Georgia) have urged Congress not to adopt legislation that mandates retail access.

62. FERC defines wholesale stranded costs as any legitimate, prudent and verifiable costs incurred by a public utility or a transmitting utility to provide a service to a wholesale requirement customer that subsequently becomes, whole or in part, an unbundled transmission services customer of that public utility or transmitting utility." Refer to Federal Energy Regulatory Commission, Notice of Proposed Rulemaking (NOPR) and Supplemental Notice of Proposed Rulemaking March 29, 1995). The NOPR is made up of two dockets: (i) Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities, Docket No. RM95-8-000, and (ii) Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Docket No. RM94-7-001. An unbundled transmission services customer, as defined in the NOPR, is one who purchases transmission as a product that is separate from the purchase of generation. According to FERC, the onus of identifying recoverable wholesale costs rests on utilities. Treatment of stranded costs by States is discussed on pages 59-69 and in Appendix E, pages 145-166.

63. Organizations like the Electricity Consumers Resource Council (ELCON) have opposed stranded cost recovery since the very beginning. A newly formed coalition named "Stop the Bailout" is actively opposed to the recovery of stranded costs. Its members include the Heritage Foundation, the Competitive Enterprise Institute, Citizens for a Sound Economy, Friends of the Earth, Public Citizen, the Safe Energy Communication Council, and the U.S. Public Interest Research Group. See Electricity Week (August 11, 1997).

64. C.B. Curtis, "The Devil is in the Details of Electricity Deregulation," Roll Call (February 24, 1997). Also, E. Hirst and B. Kirby, "Restructuring—The Devil Is in the Details," Electricity Journal (December 1995), pp. 12-18.

65. "The obligation to serve will convert to an obligation to connect. Utilities will simply energize the wires." Statement attributed to Scott Neitzel, Member, Wisconsin Public Service Commission, in an article "Network Trouble" in Public Utility Fortnightly (March 15, 1996).

66. The possibility that some States may decide to defer or even reject competition in retail trade in electricity should not be overlooked.

67. The emerging competitive market for electricity envisions that the existing utility customers will be able to secure power from alternative, lower-priced suppliers. When this occurs, the utility that originally supplied power to a departing customer may not be in a position to market the power to an alternative customer. The utility thus suffers a financial loss due to structural changes in the industry, leading to the creation of stranded costs. Note, however, that explaining the emergence of stranded costs in this manner masks complexities inherent in defining the term.

68. The term "regulatory compact" should not be construed to be an agreed-upon contractual relationship between the utilities and their regulators. Rather, the regulatory compact is an evolutionary relationship involving a judicious balancing of utilities' rights and responsibilities. In return for the exclusive franchise (implying protection from competition), the utilities have an obligation to serve, to provide safe and reliable service, and to charge prices that are just and reasonable (determined by regulation) but not discriminatory. For additional information, refer to the National Regulatory Research Institute, An Economic and Legal Perspective on Electric Utility Transition Costs (Ohio, July 1996), pp. 39-72. Also, California Public Utilities Commission, California's Electric Services Industry: Perspectives on the Past, Strategies for the Future (California, February 1993), pp. 7-15.

69. The New Hampshire Pubic Utilities Commission (NHPUC), for example, limited recovery of stranded costs where the responsibility for resource decisions and the associated asset acquisitions could be attributed primarily to utility management. In all other cases, where State utilities' decisions were not compromised by the New Hampshire legislators or the regulators, the utilities were to be allowed an appropriate opportunity for full recovery. This decision (as well as the methodology used in computing stranded costs) led the Public Service Company of New Hampshire (PSNH) to secure a restraining order preventing the NHPUC from moving forward with any part of its restructuring plans.

70. Order 888-A, p. 6.

71. Ibid., p. 6.

72. The National Association of Utility Consumer Advocates (NASUCA), American Public Power Association (APPA), and Electricity Consumers Resource Council (ELCON) are among some of the organizations that opposed recovery of stranded costs. Low-cost utilities and industrial units (that use electricity intensively) also provide support for this position. The Edison Electric Institute (EEI) and organizations linked with independent power producers demand recovery of stranded costs that include additional items besides uneconomic generating assets.

73. Federal Energy Regulatory Commission, Docket Nos. RM95-8-001 and RM94-7-002; Order No. 888-A (Order on Rehearing) Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities (March 4, 1997), p. 490.

74. In terms of the provisions of Order 888, the Commission was to be the primary forum for addressing the recovery of stranded costs caused by retail-turned-wholesale customers. This decision was based on a clear nexus between the FERC-jurisdictional transmission access requirement and the exposure to nonrecovery of prudently incurred costs. However, FERC had also stated that it would not be the primary forum in instances where an existing municipal utility annexes territory served by another utility or expands its territory. On rehearing, the Commission reserved the right to address such situations on a case-by-case basis. Commissioner Massey dissented with this decision by the Commission just as he had dissented with the notion of FERC being the primary forum for recovery of stranded costs in case of municipalization.

75. Wholesale stranded cost, as defined in Order 888, means any legitimate, prudent, and verifiable cost incurred by a public utility or a transmitting utility to:

  (ii) a retail customer, or a newly created wholesale power sales customer, that subsequently becomes, in whole or in part, an unbundled wholesale transmission services customer of such public utility or transmitting utility.

  Order 888-A modifies (ii) to read as follows:

  (ii) a retail customer that subsequently becomes, either directly or through another wholesale transmission purchaser, an unbundled wholesale transmission services customer of such public utility or transmitting utility.

76. On this issue, the Commission stated that "allowing full recovery of stranded costs under Order 888 is not equivalent to allowing 100 percent recovery of the costs of all uneconomic assets," Order 888-A, p. 578.

77. FERC's determination of recoverable wholesale stranded costs takes the following form:

78. Order 888-A, pp. 711-762.

79. Federal Energy Regulatory Commission, Docket Nos. RM95-8-001 and RM94-7-002; Order No. 888-A (Order on Rehearing), Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities (March 4, 1997), p. 6.

80. Note that generation and distribution prices will be unbundled from the total electricity price, and the ratesetting methodology may vary between the two prices. In the short run, generation, transmission, and distribution may continue to be cost-of-service-based rates. In the long run, however, generation prices will begin to approximate their long-run marginal costs.

81. Average electricity prices in July 1997 ranged from a low of 3.8 cents per kilowatthour in Idaho to 11.9 cents per kilowatthour in New Hampshire (with the national average being 7.28 cents per kilowatthour). Energy Information Administration, Electric Power Monthly, DOE/EIA-0226(97/10) (Washington, DC, October 1997), Table 53, p. 60.

82. Most States define stranded costs using this basic concept with some minor changes. As an example, the Public Utilities Commission of Texas defines stranded investment as the "historic financial obligations of utilities incurred in the regulated market that become unrecoverable in a competitive market." Note, however, that the term "stranded cost" is difficult to define.

83. Note that stranded costs are also known as stranded investments, stranded commitments, transition costs, excess costs over market, embedded costs exceeding market prices, uneconomic sunk costs, or costs without a customer.

84. Edison Electric Institute, The Path of Least Resistance: Accelerating the Movement to Electric Industry Competition through Transition Cost Competition (Washington, DC, November 1997).

85. The term regulatory compact is used to describe an implicit relationship existing between the utilities and the regulators. In return for grant of franchises, utilities maintain that they accepted an obligation to serve, develop, and maintain the requisite electricity infrastructure in exchange for an opportunity to recover the reasonable costs of financial commitments incurred to meet public service obligations. This viewpoint is, however, challenged by some stakeholders. R. S. Hartmen and R. D. Tabors, The Regulatory Contract and Its Relevance to Stranded Assets Under Restructuring : A Modest Proposal (Cambridge, MA: Cambridge Economics Inc., October 1996).

86. W. J. Baumol and J.G. Sidak, Transmission Pricing and Stranded Costs in the Electric Power Industry (Washington, DC: The AEI Press, 1995), pp. 98-114.

87. Testimony of Pete Mehra at the Senate Energy and Natural Resources Committee Workshop (March 6, 1997) on "Competitive Change in the Electric Power Industry—What Are the Issues Involved in Competition?" Mr. Mehra testified on behalf of Ford Motors, the Electricity Consumers Resource Council (ELCON), and the Electricity Customer Choice Group (ECCG). Both ELCON and ECCG represent large industrial users of electricity.

88. The five steps suggested by ELCON include: determination of extent of uneconomic assets, determination of sharing mechanism between shareholders and customers, negotiation of recovery mechanisms, setting recovery period, and a truing-up of recoverable costs. Refer to Electricity Consumers Resource Council, Blueprint for Customer Choice-Road Map for the Transition (Washington, DC, December 1995).

89. In its Policy Statements, the ECCG states that retail transition costs should be determined by the States within Federal guidelines. The recently formed organization represents a broad range of manufacturing interests across the United States. Extracted from the ECCG web site at www.eccg.org on January 5, 1998.

90. Testimony of Irwin A. Popowsky, Consumer Advocate of Pennsylvania, on October 22, 1997, before the U.S. House of Representatives, Committee on Commerce, Subcommittee on Energy and Power, Hearings on H.R. 655, Electric Consumers' Power to Choose Act, on behalf of NASUCA.

91. According to recent estimates provided by Resources Data International, stranded costs attributable to power purchase contracts account for about $54 billion out of a total of $202 billion. "Shorts and Transients," The Electricity Journal (April 1997).

92. In 1996, nonutility generators owned 73.2 gigawatts of capacity and generated 382.5 million kilowatthours of electricity. Deliveries to the utilities totaled 224.7 million kilowatthours. Energy Information Administration, Electric Power Annual 1996, Volume II, , DOE/EIA-0348(96/2) (Washington, DC, December 1997), Table 53, p. 93.

93. Energy Information Administration, The Changing Structure of the Electric Power Industry: An Update, DOE/EIA-0562 (96) (Washington, DC, December 1996), pp. 78-82. More recent estimates from Data Resources Inc. project the net value of the stranded assets to be $203.8 billion. Refer also to DRI/McGraw Hill, World Energy Service: U.S. Outlook (Spring 1997), pp. 119-121.

94. Aggregate equity investments of investor-owned electric utilities, as of December 31, 1996, were $193.2 billion. Energy Information Administration, Financial Statistics of Investor-Owned Electric Utilities, DOE/EIA-0437(96/1) (Washington, DC, December 1997).

95. The initial investigation may be undertaken at the request of the State regulatory authorities or of the State legislature. In some cases, the process may be initiated at the request of utilities.

96. No State has yet accorded an absolute guarantee for recovery of stranded costs, even though assurances for full recovery are invariably included. The New Hampshire Public Utility Commission, which linked the recovery of stranded costs to regional price levels of electricity, is currently embroiled in a legal challenge filed by the Public Service Company of New Hampshire.

97. Regulatory assets include deferred expenses (permissible under Financial Accounting Standard No. 71) that appear as assets on the balance sheet. Utilities have reasonable assurance to recover these assets in electric rates charged to customers in the future. This category could include any costs which could or would have been otherwise expensed under standard accounting conventions. Examples of its components include: regulatory tax assets recoverable through future rates, deferred finance charges, deferred environmental charges, unamortized property losses, unamortized demand-side management expenditures, certain post-retirement benefit costs, canceled plants for which unamortized costs have been allowed, and others.

98. These categories generally are bottom-up versus top-down, ex ante versus ex post, and administrative versus market. For a summary of these approaches, refer to Energy Information Administration, The Changing Structure of the Electric Power Industry: An Update, DOE/EIA-0562(96) (Washington, DC, December 1996), pp. 143-145. For additional details, refer to Niagara Mohawk Power Corporation's filing with the New York Public Service Commission in Case Nos. 94-E-0098 and 94-E-0099, Phase II, Multi Year Electric Rate, Restructuring and Retail Access Proposal (Syracuse, NY, October 6, 1995). Also, refer to San Diego Gas and Electric Company, Comments of San Diego Gas and Electric Company on Proposed Policy Governing Restructuring Electric Services Industry and Reforming Regulation, submitted to the California Pubic Utility Commission, Docket No. R-94-04-031 (San Diego, CA, June 8, 1994). Additionally, refer to L. Baxter, E. Hirst, and S. Hadley, Transition Cost Issues for a Restructuring Electricity Industry (Oak Ridge, TN: Oak Ridge National Laboratory, March 1997), and W. Marcus and J. Hamrin, A Guide to Stranded Cost and Valuation Methods (San Francisco, CA: JBS Energy Inc., February 1997).

99. Where administrative methods are used, stranded cost valuations hinge on the forecasting methodology adopted. In this process, the quality of data used and the assumptions with respect to a number of other variables become critically important. With a view to reduce forecast errors, true-up mechanisms enabling adjustments for over or under collections become necessary. Also, M.H. Rothkopf, "On Misusing Auctions to Value Stranded Assets," Electricity Journal (December 1997), pp. 10-17.

100. Electricity Journal, April 1998, p. 6.

101. It is not clear whether the purchase price of assets being divested reflects the true market value of the generating plants sold. Refer to the Virginia State Corporation Commission, Draft Working Model for Restructuring the Electric Utility Industry in Virginia (Richmond, VA, November 1997), Chapter 4.

102. Note that a significant portion of stranded costs consists of embedded costs or obligations. These by definition cannot be mitigated. States, therefore, attempt to reallocate or offset them among stakeholders in a manner that reduces the potential loss to the equity holders.

103. For a detailed discussion of mitigation strategies, refer to Energy Information Administration, The Changing Structure of the Electric Power Industry: An Update, DOE/EIA-0562(96) (Washington, DC, December 1996), Appendix E, pp. 143-157.

104. Indiana Utility Regulatory Commission, Energy Report: Public Policy Considerations, submitted to the Regulatory Flexibility Committee of the Indiana General Assembly (November 1997).

105. Recovery mechanisms that are integrated with performance-based ratemaking have also been advocated. Refer to K. Rose, An Economic and Legal Perspective on Utility Transition Costs (Columbus, OH: National Research Regulatory Institute, July 1996). Also, P. Joskow, "Does Stranded Cost Recovery Distort Competition," The Electricity Journal (April 1996).

106. Arizona Corporation Commission, Stranded Cost Working Group Report to the Commission (September 30, 1997).

107. W.H. Hall II, "Securitization and Stranded Cost Recovery," Energy Law Journal, Vol. 18, No. 2 (1997), pp. 363-404.

108. K.G. Baker and B.D. Fabrikant, Stranded Utility Costs: Legislation Jolts the ABS Market (Moody's Investor Service, February 28, 1997).

109. D. Moody, "IOU Tricks for Securing Their Futures," Public Power (September/October 1997), pp. 37-38. Also, J.R. Hodowal, "The Securitization Swindle: Bailout for the Utilities, Bad Deal for Consumers," Electricity Journal (October 1997), pp. 44-53.

110. New York State Assembly, Shedding Light on Securitization: A Briefing Paper on Moving to Competition in the Electric Industry (January 1997).

111. Dr. Kenneth Rose, National Regulatory Research Institute, points out that utilities may use the cash to buy back stock or retire debt for investment in foreign countries, or "to buy land in Freedonia." Presentation at the National Association of Regulatory Utility Commissioners (July 1997).

112. California, for example, has a 4-year period for recovery of stranded costs with respect to utility-owned generation assets.

113. A utility's fixed costs are prone to decline over time. In addition, competitive pressures may lead to efficiency improvements. The impact of these two factors may lead to a possible reduction of stranded costs over time. In some cases, stranded costs may even become negative. L. Baxter, E. Hirst, and S. Hadley, Transition Cost Issues for a Restructuring U.S. Electricity Industry (Oak Ridge, TN: Oak Ridge National Laboratory, March 1997), pp. 67-74.

114. This section is based on a recent study undertaken by Dr. Jeff Fang of the National Renewable Energy Laboratory with funding and direction from the Energy Information Administration. National Renewable Energy Laboratory, Selected Topics in Electric Industry Restructuring (Washington, DC, February 1998).

115. Proposals regarding level and rate structure changes are submitted by utilities to State public utility commissions well in advance of their effective dates. State commissions may allow or disallow changes requested. Under certain conditions, commissions may also order a utility to change the level and structure of its rates. These proceedings, commonly known as rate cases, determine the rate of return a utility is authorized to earn. Since rate case proceedings are initiated only at discrete intervals, the actual rate of return a utility earns may be above or below the rate of return it is authorized to earn.

116. Critics point out that utilities may inflate operations and maintenance costs, over- or underinvest, be slow to adopt changes in technology, and be saddled with inefficiencies in management and compliance costs. Taken together, these factors contribute to a loss of competitive power.

117. A hypothesis developed by Averch and Johnson demonstrates that subjecting a profit-maximizing firm to an overall regulatory constraint on rate of return leads the firm to employ more capital and less labor (in a two-factor input industry) so that it can reap higher profits. This results in an inefficient allocation of resources. Refer to H. Averch and L.L. Johnson, "Behavior of the Firm Under Regulatory Constraint," American Economic Review (December 1962), pp. 1053-1069.

118. The decoupling is done by decreasing the frequency of rate cases, employing external measures of cost for rate setting, or a combination of these two approaches. Refer to Lawrence Berkeley National Laboratory, Performance-Based Ratemaking for Electric Utilities: Review of Plans and Analysis of Economic and Resource Planning Issues, Volume I, LBL-37577 (Berkeley, CA, November 1995).

119. Note that the terms "performance-based ratemaking" and "incentive regulation" are often used interchangeably to connote the same basic concepts.

120. P. Navaro, "The Simple Analysis of Performance-Based Ratemaking: A Guide for PBR Regulator," The Yale Journal of Regulation, Vol. 13, No. 105 (1996), pp. 105-161.

121. G.A. Comnes, S. Stoft, et al., "Six Useful Observations for Designers of PBR Plans," Electricity Journal (April 1996), pp. 16-23. A recent report prepared for the National Association of Regulatory Utility Commissioners points out that PBR, which is as old as utility regulation itself, has been in vogue since 1906. Refer to National Association of Regulatory Utility Commissioners, Performance-Based Regulation in a Restructured Electric Industry, report prepared by Synapse Energy Economics Inc. (Cambridge, MA, November 1997), pp. 12-14.

122. Besides setting utility rates, PBR has also been used "to lower fuel costs, encourage conservation, increase resource mix diversity, improve capacity factors and heat rates, reduce pollution, and reward good management practices." P. Navaro, "The Simple Analysis of Performance-Based Ratemaking: A Guide for PBR Regulator," The Yale Journal of Regulation, Vol. 13, No. 105 (1996).

123. National Association of Regulatory Utility Commissioners, Performance-Based Regulation in a Restructured Electric Industry, report prepared by Synapse Energy Economics Inc. (Cambridge, MA, November 1997), p. 4.

124. Other objectives may include promoting conservation mechanisms or the promotion of renewable technologies. An additional listing of objectives can be found in T. Woolf and J. Michals, "Performance-Based Ratemaking: Opportunities and Risks in Competitive Electricity Industry," Electricity Journal (October 1995), pp. 64-73.

125. A simple model can be used to present the basics of performance-based ratemaking and incentive regulation. Consider the relationship:

    Revenues = actual (ex post) revenues received

    a = fixed payment, set ex ante

    b = ex ante sharing fraction, 0<b<1

    Costs = ex post costs

Economists contend that "a firm's incentive to minimize costs is inversely proportional to the magnitude of the sharing fraction b. In other words, a firm's risk for cost overruns and its ability to keep any costs savings increase as b decreases." For additional discussion of this approach, see Lawrence Berkeley National Laboratory, Performance-Based Rate Making for Electric Utilities: Review of Plans and Analysis of Economics and Resource Planning Issues, Vol. I, LBL-37577 (Berkeley, CA, November 1995), p. 3.

126. The description in this section is based on L.J. Hill, A Primer on Incentive Regulation for Electric Utilities, ORNL/CON-422 (Oak Ridge, TN: Oak Ridge National Laboratory, October 1995). See also, Lawrence Berkeley National Laboratory, Performance-Based Rate Making for Electric Utilities: Review of Plans and Analysis of Economics and Resource Planning Issues, Vol. I, LBL-37577 (Berkeley, CA, November 1995).

127. For an excellent discussion of the role of incentive regulation (prior to the start of current restructuring initiatives), refer to P.L. Joskow and R. Schmalensee, "Incentive Regulation for Electric Utilities," Yale Journal on Regulation, Vol. 4, No. 1 (1986), pp. 1-49. This article also contains a summary of incentive programs initiated in States during the late 1970s and early 1980s.

128. The period for which the cap will remain in operation is sufficiently long so as to preclude the possibility that utilities will file rate cases frequently. Note that during the 1970s, rate cases were more frequent and that automatic adjustment clauses for fuel costs were critically important.

129. Prices under regulation are based on cost of service. They also tend to be inflexible. Since the cost-price relationship and the inflexibility are concerns, the real challenge is to develop a mechanism that does not adhere to a correspondence between prices and costs as is normally done in cost-of-service regulation. Refer to Oak Ridge National Laboratory, A Primer on Incentive Regulation for Electric Utilities, ORNL/CON-422 (Oak Ridge, TN, October 1995), pp. 7-11.

130. In its most general form, the automatic adjustment of the ceiling price can be represented by the following equation:

where P_n,t and P_n,t-1 are the ceiling prices for the n basket of goods in this year and last year, respectively; I is the inflation rate; P_G and P_E are productivity for the economy in general and for the electric utility respectively; and Z stands for the exogenous factors. When no distinction is made between the productivity of the economy in general and the electric utility industry, the (P_G - P_E) term in the equation is replaced with a single productivity measure.

131. The formula for adjusting the revenue ceiling can be expressed either in total revenue terms (equation a) or on a total revenue-per-customer basis (equation b):

  (b) (REV_n,t / CUST_n,t)= (REV_n,t--1 /CUST_n,t--1 ) (1 + I - P ),

where REV is total revenues; P=productivity; I=inflation; G=growth rate in sales; CUST=number of customers.

132. M.A. Crew and P.R. Kleindorfer, "Price Caps and Revenue Caps: Incentives and Disincentives for Efficiency," in Proceedings: Eighth Annual Seminar on Public Utility Regulation (Western Conference) (San Diego, CA, July 1995).

133. Lawrence Berkeley National Laboratory, Performance-Based Rate Making for Electric Utilities: Review of Plans and Analysis of Economic and Resource Planning Issues, Vol. I, LBL-37577 (Berkeley, CA, November 1995), p. 81.

134. Ibid., p. 82. The study, however, points out that there are many questions pertaining to the use and application of revenue caps that remain unanswered.

135. Variations of this PBR are the rate-of-return bandwidth regulation and the earnings sharing mechanisms. Lawrence Berkeley National Laboratory, Performance-Based Ratemaking for Electric Utilities: Review of Plans and Analysis of Economic and Resource-Planning issues, Vol. I, LBL-37577 (Berkeley, CA, November 1995).

136. The automatic adjustment of the rate of return can be expressed as follows:

where r_t and r_t-1 are the rate of return for years t and t-1, respectively; k is the sharing factor; and r* is the authorized rate of return. Accordingly, during the period in which the authorized rate of return is in effect, the new authorized rate will be equal to the previous-year approved rate adjusted for the difference between last year's approved rate of return and the current approved rate of return. It will account for the sharing of benefits among shareholders and ratepayers. The sharing factor will be assigned a value of zero if the earned return is within the allowable band. As an example, assume that the utility can earn a rate of 1 percent more or less around an authorized rate of 10 percent. For any returns between 9 and 11 percent, k (the sharing factor) assumes the value of zero. For values that are either less than 9 or higher than 11, k may have an assigned value of 0.5. Refer to Oak Ridge National Laboratory, A Primer on Incentive Regulation, ORNL/CON-422 (Oak Ridge, TN, October 1995), pp. 12-13.

137. Ibid., p. 13.

138. Another study prepared for the National Association of Regulatory Utility Commissioners asserts that regulators can remove obstacles to effective customer choice in the following areas: mitigation of stranded costs, preparing for market realities, pricing flexibility, treatment of generation and purchased power, risk allocation, mergers, targeted incentives, nuclear power, and divestiture. The study discusses each of these benefits in modest detail. Refer to B. Biewald and T. Woolf, Performance-Based Regulation in a Restructured Electric Industry (Cambridge, MA: Synapse Energy Economics, Inc., November 1997), pp. 33-37.

139. Massachusetts Department of Telecommunications and Energy, D.P.U. 94-158, Investigation by the Department on Its Own Motion in the Theory and Implementation of Incentive Regulation for Electric and Gas Companies under Its Jurisdiction (February 24, 1995), pp. 51-52. Note that X-efficiency is broadly defined as the degree to which a firm maximizes the production of goods and services with any given combination of inputs. This is commonly understood as "doing more with less."

140. Note that most States in the process of restructuring have instituted PBR in some form. The examples presented here are illustrative of the activities undertaken by selected States.

141. MDTE had initiated electric generating unit performance incentive as early as 1989, when it approved an incentive mechanism for Boston Edison's Pilgrim Nuclear Power Station as part of a three-year settlement agreement to resolve an open base rate proceeding and pending generating unit performance reviews. More recently, in 1993, the MDTE approved an incentive mechanism permitting benefits between customers and shareholders in the case of Boston Gas Company (D.P.U. 92-259).

142. Massachusetts Department of Telecommunications and Energy, D.P.U. 94-156, Investigation by the Department on Its Own Motion in the Theory and Implementation of Incentive Regulation for Electric and Gas Companies under Its Jurisdiction (February 24, 1995).

143. Ibid., p. 10.

144. Ibid., pp. 56-65.

146. This discussion is based on Massachusetts Department of Public Utilities, D.P.U. 96-100, Statement and Proposed Rules, Investigation by the DPU upon Its Own Motion Commencing a Notice of Inquiry/Rulemaking, Establishing the Procedures To Be Followed in Electric Industry Restructuring by Electric Utilities (May 1, 1996), pp. 71-76, and Appendix A, pp. A.8-A.11.

147. The price cap formula is as follows:

PCI is the price cap index, which is initially set to be 1.0 and will be adjusted annually. P represents an inflation index. X represents the productivity offset, which will be either the productivity of the electric industry or the difference between the productivity of the U.S. economy and the electric industry. Z represents exogenous cost changes that are beyond the distribution company's control and are not captured in any other component of the price cap formula. The proponent of the Z-factor adjustment has the burden of proof to demonstrate that the specific changes are not captured in the P factor.

148. Massachusetts Department of Telecommunications and Energy, D.P.U. 96-100, Electric Industry Restructuring Plan: Model Rules and Legislative Proposal (December 30, 1996), p. 111.

149. Ibid., Section VI. F.

150. Ibid., p. 113.

151. Note that the NEES and Eastern Edison Company had submitted their filings for settlement earlier. Boston Edison filed its electric restructuring plans in July 1997.

152. Securities and Exchange Commission, New England Electric System 10-K report (March 1996).

153. Boston Edison Co, Restructuring Settlement Agreement filed with the Massachusetts Department of Public Utilities on July 9, 1997. (Note that the Department is now known as the Department of Telecommunications and Energy.) The filing was in response to the directives contained in D.P.U. Docket Nos. 96-100 and 96-23.

154. Maine Public Utilities Commission, Docket No. 92-345 (II), Central Maine Power: Alternative Rate Plan (ARP) (January 10, 1995); Docket No. 94-125, Investigation of Flexible Pricing for Bangor Hydro-Electric Company: Alternative Marketing Plan (AMP) (February 14, 1995); and Docket No. 95-052, Maine Public Service-Rate Stability Plan (RSP) (November 30, 1995).

155. According to the Commission, a multiyear plan provides many benefits: electricity prices continue to be regulated in a predictable manner, rate predictability and stability become more likely, regulatory administrative costs are reduced, risks can be shifted away to shareholders, and efficiency improvements can bring about improvements in profitability.

156. The Commission provided for a 50/50 sharing of profits or losses outside the 350-basis-point bandwidth (plus or minus) between the ratepayers and the shareholders. The bandwidth is wide enough to ensure that only extreme swings in earnings will be shared. It follows that, for oscillations in earnings within the bandwidth, the shareholder will bear the resulting gains or losses within the bandwidth.

157. The inflation index is reduced by the sum of two productivity factors: a general productivity offset and a second formula-based offset to reflect the effect of inflation on power purchase costs during the currency of the ARP.

158. This argument does not take into account other operational constraints that the utility may encounter.

159. CMP's filing for the mid-term in 1997 did not seek any significant changes to the ARP. The MPUC did, however, make modest changes in parameters for pricing flexibility and in increasing the mid-point return on equity in June 1997. Refer to Central Maine Power Company, Quarterly Report (Form 10-Q) submitted to the Securities and Exchange Commission for the period ending June 30, 1997.

160. For a further discussion on this issue, refer to National Association of Regulatory Utility Commissioners, Performance-Based Regulation in a Restructured Electric Industry (Cambridge, MA: Synapse Energy Economics, Inc., November 1997), pp. 18-20.

161. Bangor Hydro-Electric Company, 1996 Annual Report (March 19, 1997), p. 35.

162. Maine Public Utilities Commission, Docket No. 94-125, Investigation of Flexible Pricing for Bangor Hydro-Electric Company: Alternative Marketing Plan (AMP) (February 14, 1995).

163. Maine Public Utilities Commission, Docket No. 95-052, Maine Public Service: Rate Stability Plan (November 30, 1995).

164. California Public Utilities Commission, Electric and Gas Utility Performance Based Ratemaking Mechanisms (December 1997).

165. California Public Utilities Commission, Docket No 94-04-032, Order Instituting Rulemaking on the Commission's Proposed Policies Governing Restructuring California's Electric Service Industry and Reforming Regulation (April 24, 1994).

166. Ibid., pp. 34-36.

167. California Public Utilities Commission, Decision 95-12-063 (December 20, 1995) as modified by Decision 96-01-009 (January 10, 1996), Order Instituting Rulemaking on the Commission's Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation (January 10, 1996).

168. Major issues include: existing PBRs, establishing new PBRs for reactive power/voltage control, establishing new PBRs for distribution, Diablo/Palo Verde ratemaking proposals, and interaction with transition costs, hydro and geothermal assets. California Public Utilities Commission, Decision 96-03-022, The Roadmap Decision (March 14, 1996).

169. California Public Utilities Commission, Energy Division, Electric and Gas Utility Performance Based Ratemaking Mechanisms (December 1997).

170. California Public Utilities Commission, Application of Southern California Edison Company to Adopt a Performance Based Ratemaking Mechanism Effective January 1, 1995, Decision 96-09-092 (September 20, 1996).

171. According to the SCE, power generation ratemaking was assigned to other mechanisms. Subsequently, SCE filed a PBR proposal covering its hydroelectric facilities and some fossil plants in 1996.

172. California Public Utilities Commission, Decision No. 96-09-092, Application of Southern California Edison Company to Adopt a Performance Based Ratemaking Mechanism Effective January 1, 1995, Application No. 93-12-029 (September 20, 1996). This Decision requires that the SCE separate its transmission portion from the nongeneration PBR beginning 1998. This action was taken so that any directives by the Federal Energy Regulatory Commission could be complied with.

173. California Public Utilities Commission, Decision No. 94-08-023 (August 3, 1994) and Energy Division's Resolution E-3512 (December 16, 1997).

174. California Public Utilities Commission, Energy Division, Electric and Gas Utility Performance Based Ratemaking Mechanisms (December 1997).

175. The utility has filed three annual performance reports for the years 1994, 1995, and 1996. In addition, it has also filed a 1997 summary of the past 3 years' experience. The CPUC's mid-term review of the utility's PBR, conducted since December 1996, has since been terminated together with the elimination of the need for a general rate case hearing in 1999. California Public Utilities Commission, Energy Division Resolution E-3512 (December 16, 1997).

176. Note that electric rates have been frozen in California since January 1, 1997. As a result, the electric price comparison component of the PBR has since been suspended by the CPUC, leaving the other components of the PBR in effect. All utilities in the State have been directed to file applications in January 1999 proposing ratemaking mechanisms which they believe should be in place at the end of the rate freeze period. California Public Utilities Commission, Decision No. 97-10-057 (October 22, 1997).

177. On the subject of revenue sharing, the Energy Division of the CPUC recently noted that during the 3 years since the start of the PBR, SDG&E shareholders have received benefit of over $90 million, while the ratepayers were allocated a benefit of $2.5 million. Concern was also expressed with the utility's nondisclosure of certain accounting changes that affected the utility's writeoff levels and the methodology used to calculate performance component awards. California Public Utility Commission, Energy Division Resolution E-3512 (December 16, 1997).

178. The utilities were given an extension for the filing date until the Federal Energy Regulatory Commission provided further guidance on the separation of transmission and distribution functions.

179. SDG&E's PBR requires that the utility file a general rate case for a 1999 test year. This requirement has been vacated by the CPUC in view of the directive that the utility file a distribution PBR plan.

180. For fossil generation, PG&E requested that sunk costs be recovered directly through the competition transition charge (CTC) with components of rates consistent with CPUC's stated policy. PG&E also stated that a substantial portion of its generating plants will be divested or spun-off during the transition period. Revenues for some fossil units that may be needed to provide ancillary services to the independent system operator (ISO) should be calculated using the traditional cost-of-service approach. Other fossil plants not needed by the ISO would remain fully at risk subject to revenues being recovered from the power exchange. Sunk costs of all such plants would be recovered through the CTC.

181. A final proposal was submitted in December 1996. California Public Utilities Commission, Decision No. 97-08-56 (August 1, 1997).

182. Activities related to ratesetting issues that include PBRs and unbundling are still being discussed in California. Refer to California Public Utilities Commission, Decision No. 97-08-056 (August 1, 1997) and Decision No. 97-10-057 (October 22, 1997). The first decision resolves issues relating to the allocation of costs between the various functions of the utilities and also allocates revenues between customer classes within each function and establishes certain rate design principles. The second decision provides an interim opinion while addressing several issues related to streamlining electric utility tariffs and regulatory accounts. Several issues stemming from these Decisions await resolution.

183. For a summary of electric utility PBR plans existing in 1995, refer to Lawrence Berkeley Laboratory, Performance-Based Ratemaking for Electric Utilities: Review of Plans and Analysis of Economic and Resource-Planning Issues, Vol. II: Appendices (Berkeley, CA, November 1995).

184. The Rhode Island Utility Restructuring Act of 1996 (H-8124 Substitute B3), enacted on August 7, 1996.

185. Michigan Public Service Commission, History: Michigan Electric Utility Restructuring: A Chronology of Events. (Revised Version as of February 12, 1998). Extracted from the Internet at http://ermisweb.cis.state.mi.us/mpsc/electric/restruct/history.htm, on March 6, 1998.

186. A moratorium on rate increases or a rate freeze is another popular option that regulatory authorities invoke in lieu of PBR plans. States with a rate moratorium or a rate freeze include Oklahoma, Montana, and Nevada. Rate decreases—as in the case of Illinois—are called for in many States as a part of the restructuring process.

187. Revenues from transmission assets (based on the sunk costs in transmission infrastructure) in the future will accrue to the utility through the intermediation of independent system operators. The applicability of PBR plans for transmission thus becomes a moot issue.

188. New Hampshire Public Utilities Commission, DR 95-250, Order No. 22,033, Order Establishing Final Guidelines and Requiring Compliance Filings (February 28, 1996).

189. States with pilot programs (voluntary or mandatory) include Idaho, Illinois, Massachusetts, Missouri, New Hampshire, New Jersey, New York, Pennsylvania, Oregon, and Washington. Note that where utilities take the initiative, regulatory approval is still necessary.

190. Electricity rates in Washington State are among the lowest in the Nation. In sponsoring pilot programs, the investor-owned utilities in the State may be testing their strengths in a competitive environment.

191. The first six pilot programs were introduced in Illinois, Massachusetts, New Hampshire, New York, and Idaho. With the exception of the program in New Hampshire, the programs are utility specific. Participating utilities are Central Illinois Light Company, Illinois Power Company, Massachusetts Electric Company, Orange and Rockland Utilities , Inc., and Washington Water Power Company. The program in New Hampshire was mandated by the State legislature and designed by the New Hampshire Public Utilities Commission. For additional information and utilities participating in the pilot programs, refer to Edison Electric Institute, Retail Pilot Programs: The First Six (Washington, DC, 1997).

192. For example, Central Illinois Light Company had only eight eligible customers in its pilot.

193. Deborah Schachter (for the National Consumer Law Center and the Regulatory Assistance Project), Public Outreach and Education in Electric Utility Restructuring (Boston, MA, August 1996).

194. An example is the "Farm and Food Processors Electric Retail Access Program," which is a 2-year pilot program in upstate New York that permits eligible farmers and food processors to choose electric service providers. The program was proposed by the Dairylea Cooperative and supported by the State's Department of Public Utilities. Four upstate investor-owned utilities participate in this sector-specific program.

195. Besides the unbundling of rates and metering and billing protocols, customer information (or educational issues), customer protection, scheduling and power pool settlement process, and system reliability issues have also been dealt with.

196. A number of activities fall into this category: social and environmental protection programs, low-income assistance programs, demand-side management, conservation and efficiency efforts, and use of renewables.

197. Pennsylvania enacted the Electric Generation Customer Choice and Competition Act (Act 138 of 1996) on December 3, 1996. Also, see Pennsylvania Public Utilities Commission, Docket No. M-00960890, Retail Access Pilot Programs-Guidelines (January 16, 1997).

198. Note that the dividing line between goals and parametric constraints imposed on utilities is not as clear cut as indicated above. The New York Public Service Commission views "allying concerns about market power" as a goal to be achieved.

199. New Hampshire Public Utilities Commission, DR 95-250, Order No. 22,033, Order Establishing Final Guidelines and Requiring Compliance Filings (February 28, 1996).

200. New York Department of Public Service, Case 96-E-0948, Petition of Dairylea Cooperative Inc. to Establish an Open-Access Pilot Program for Farm and Food Processors Electricity Customers (June 10, 1997). The utilities involved are Niagara Mohawk Power Corporation, Central Hudson Gas and Electric Corporation, Rochester Gas and Electric Corporation, and New York State Electric and Gas Corporation.

201. The Idaho Public Utilities Commission, Case No. IPC-E-96-25, Order No. 26872, In the Matter of Idaho Power's Application for Approval of Tariff (Schedule 20) Providing For Optional Market Based Service to Customers from 5 to 10 MW (April 7, 1997). Note that this program designed for industrial customers does not envisage new providers but primarily accords the customers the choice of market-based rates during the currency of the contract, estimated to be 3 years.

202. The pilot program set up for industrial customers in Idaho by Idaho Power is an exception. In this pilot program, outside providers do not participate.

203. Eligibility requirements in New Hampshire are said to be more stringent than those in other States. In addition to meeting other criteria, New Hampshire requires that suppliers be members of the New England Power Pool (NEPOOL) or have a contract with a NEPOOL member.

204. Regulatory authorities invariably specify a list of conditions that need to be met before a supplier is licensed in the State to supply power.

205. The Massachusetts High Technology Council (MHTC), consisting of nearly 200 large business customers in the service area of Massachusetts Electric Company (MECO), entered into an agreement to establish a pilot program with MECO. MHTC chose to issue requests for proposals for supply of power. Out of 12 companies that submitted bids, MHTC made its selection based on considerations of economical supply of power, reliability and flexibility in accommodating loads, and cost control efforts. Refer to Edison Electric Institute, Retail Pilot Programs: The First Six (Washington, DC, 1997).

206. Edison Electric Institute, Retail Pilot Programs: The First Six (Washington, DC, 1997); and Electric Consumers' Alliance, The New Hampshire Retail Competition Pilot Program: A Preliminary Evaluation (Indianapolis, IN, July 1997).

207. Participation rates for residential customers range from a low of 3 percent in the case of Orange and Rockland Utilities in New York State to a high of nearly 60 percent in New Hampshire. National Renewable Energy Laboratory, Selected Topics In Electricity Restructuring (February 28, 1998).

208. State of New York, Department of Public Service, Status of Orange and Rockland Utilities PowerPick Retail Access Pilot as Reported to the Commission at the April 9 Session in Albany, NY (May 15, 1997).

209. In New Hampshire, for example, the average bill savings for residential customers ranged from 12 to 16 percent, in comparison with a range of 15 to 20 percent for large commercial and industrial customers. The New York pilot program shows similar results.

210. The concern is that the relationship between the utility and the affiliate (if the latter is allowed to compete in the same market as the parent/incumbent utility) is such that market abuses can flourish. An example would be for the affiliate to exercise the market power enjoyed by the incumbent utility and to retain market share by predatory prices. Any losses that might result could be passed on to the parent company.

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