Arizona

On December 26, 1996, the Arizona Corporation Commission (ACC or the Commission) approved "Electric Competition Rules" (or Rules) setting forth a framework for electricity restructuring in the State and for introducing a phased-in transition to a competitive retail power market beginning in 1999. These Rules also include a wide spectrum of issues, including the treatment of stranded costs. In connection therewith, affected utilities in the State will make available at least 20 percent of their 1995 system retail peak demand to all customer classes in 1999, 50 percent in 2001, and 100 percent by 2003.⁽²³⁶⁾

A special working group was created to develop recommendations for the analysis and recovery of stranded costs.⁽²³⁷⁾ This Group, the Stranded Cost Working Group (the Group), submitted its final report and recommendations in September 1997.⁽²³⁸⁾ The Group's recommendations to the Commission are based on a consensus on various stranded cost issues. However, the Group acknowledges that it achieved consensus on some issues but that many issues remain unresolved.

Consensus was reached on the following issues:

• Components of stranded cost should include generation assets, purchased power agreements, fuel contracts, regulatory assets, employment transition costs, and environmental mandates.

• All customers should pay stranded costs, including those who do not take competitive power.⁽²³⁹⁾ Self-generation, demand-side management activities, or other modes of demand reduction by customers do not warrant stranded cost recovery. Customers should have the option of paying one lump sum in lieu of payments over a period of time.

• The Group noted that the Electric Competition Rules were silent on the subject of the specific recovery mechanism to be implemented. Mechanisms examined include a variable charge based on electricity usage, a fixed fee (including but not limited to an exit fee) independent of usage, and an access fee levied on competitive suppliers. In addition, there could be a nonbypassable usage surcharge with the option of an exit fee, or a fixed fee to be determined on a utility-by-utility basis.

• The Commission should consider some variant of a rate cap as a part of the stranded cost recovery program. In addition, the recovery mechanism should correspond to the prevailing regulatory rate allocation scheme among existing customer classes.

The Group submitted the following for the Commission's further consideration:
 

• Clarification is needed on whether nuclear fuel costs should be included in stranded costs.

• Prudent and reasonable mitigation efforts should be handled on a case-by-case basis. The mitigation costs should be eligible for treatment as stranded costs.

• The "Net Revenues Lost" approach should be adopted for computing stranded costs. Under this approach,future revenue streams assuming continuation of regulations are compared with revenue streams likely to be generated in a competitive market.

• The issue of price determination under competition (including projections) should be carefully studied.

• Estimates of stranded costs should be periodically trued up.

• Stranded cost recovery should be limited to 10 years.

• The Commission should ensure that recoveries made to pay for stranded costs are in fact used to reduce existing liabilities.

• Parties advocating a price cap or the sharing of stranded costs by the equity holders should be asked to provide specific details.

The Group recommended that the Commission clarify rules so that the identification, quantification, and recovery of stranded costs minimizes tax write-offs. In addition, the Commission was requested to analyze issues related to tax-exempt bonds.

While the Commission and the Group have been grappling with stranded cost issues (besides a host of other issues), the two largest investor-owned utilities in Arizona--Arizona Power Service and Tucson Electric Power--filed lawsuits addressing the rulemaking completed by the ACC in December 1996. The Arizona Supreme Court upheld the restructuring rulemaking in a decision issued April 23, 1998.⁽²⁴⁰⁾

Subsequent evaluations made by the ACC staff acknowledge difficulties in recommending a single methodology that can be used by all utilities in the State to determine their stranded costs. Accordingly, the staff recommended three approaches: net revenues lost methodology, divestiture auction, and financial integrity methodology.⁽²⁴¹⁾

Under the net revenues lost option, generation revenues with competition are compared to generation revenues without competition. The difference is treated as potential stranded costs to be allocated among ratepayers. The divestiture auction methodology determines stranded costs through auction of generating assets. The financial integrity methodology calls for financial viability of each utility to be maintained for 10 years following competition. These recommendations await the ACC's decision, after which the utilities have 30 days to file stranded cost plans.

California

In the wake of the Energy Policy Act of 1992, the California Public Utilities Commission (CPUC or the Commission) was one of the first State commissions to initiate electric industry restructuring studies, in early 1993.⁽²⁴²⁾ In April 1994, the CPUC initiated a comprehensive rulemaking and investigation into restructuring and reforming regulation for California's electric service industry.⁽²⁴³⁾

In the policy decision development proceedings that followed, the CPUC recognized "that in the transition to the new industry structure, certain utility generation-related capital and operating costs would prove to be uneconomic and would not be recovered through market revenues."⁽²⁴⁴⁾ These uneconomic or stranded assets, to be called "transition costs," included generation assets, nuclear power plant settlements, power purchase agreements, qualifying facilities contracts, and the reasonable capital costs of early retirement or retraining programs for employees.⁽²⁴⁵⁾ The estimated net book value of the utilities' non-nuclear costs eligible for transition recovery was established by the Commission at approximately $4 billion.⁽²⁴⁶⁾

The Commission proposed that transition costs are to be recovered through a nonbypassable competition transition charge (CTC) to be applied to all customers regardless of whether they get bundled service from their utility.⁽²⁴⁷⁾ Customers opting to use power from alternative suppliers will still be required to pay the CTC to the distribution utility.

The CTC will be based on a customer's power consumption and will appear as a separate charge on the electricity bill. It will be calculated as the difference between the pool energy price, the unbundled cost of distribution and transmission, and the cost of ancillary services and energy tariffs filed by the utilities.⁽²⁴⁸⁾ CTC recovery will start with the commencement of direct access and is projected to continue through a 4-year period until December 31, 2001.

In addition to using the CTC to collect stranded costs, the CPUC approved issuance by the investor-owned utilities of rate reduction bonds (RRBs) to securitize a total of $7.3 billion of stranded costs.⁽²⁴⁹⁾ Issuance of these bonds will permit a rate reduction of 10 percent beginning March 31, 1998, and continuing until March 31, 2002. Rate reductions of 20 percent are anticipated after 2002.⁽²⁵⁰⁾ The Utility Reform Network, a consumer group, has asked the California Supreme Court to overturn the CPUC's approval of the rate reduction bonds.⁽²⁵¹⁾

Utilities in the State were directed to establish their level of transition costs as of the start of direct access by filing applications to the CPUC by September 2, 1996.⁽²⁵²⁾ In determining transition cost levels for each utility, economic assets are to be netted out against uneconomic assets.⁽²⁵³⁾ The CPUC will hold annual proceedings to determine the amount of recoverable stranded costs. With the objective to minimize transition costs, the Commission plans to rely on market forces (to the extent possible) in its determination.⁽²⁵⁴⁾ The CTC level to be recovered will depend on the market-clearing price in the State-wide power exchange on the date direct access begins.⁽²⁵⁵⁾

Divestiture is an important first step in the market-based valuation of assets. Once the assets are divested, the CPUC has a figure upon which to track appropriate stranded cost recovery. Two of the State's utilities--Pacific Gas and Electric and Southern California Edison--were required to divest at least 50 percent of their generating assets.⁽²⁵⁶⁾ The Commission authorized the utilities to go ahead with proposed sales.⁽²⁵⁷⁾ Although not required, San Diego Gas and Electric has announced plans to auction off 2,778 megawatts of capacity and contracts and will ask the CPUC for approval.

For eligible costs that are not divested, their value is "compared to the Power Exchange market clearing price on an ongoing basis in order to determine the uneconomic portion."⁽²⁵⁸⁾ Regardless of whether an asset is market valued through divestiture or comparison, the utilities will track CTC revenue and offset stranded costs through transition accounts. The main account will repay generation-related stranded costs. Revenues above planned levels will be used to pay stranded costs, and as a result stranded cost recovery could take less than the originally planned 4 years. Pacific Gas and Electric, Edison, and San Diego Gas and Electric have been directed to "establish subaccounts as placeholders in their transition cost balancing accounts to track recorded employee related and restructuring implementation costs."⁽²⁵⁹⁾ According to the CPUC, one purpose of these accounts "is to track the going forward costs and market revenues for particular assets and to verify that market revenues which are greater than costs are credited appropriately to the transition cost balancing account."⁽²⁶⁰⁾ Annually, a transition cost proceeding will develop necessary adjustments. Additionally, since all the generation stranded costs are to be recovered by December 31, 2001, they will be deferred until after that date.

For some of the initiatives proposed by the Commission, legislative authority was required for implementation purposes. Assembly Bill 1890, signed into law on September 23, 1996, endorsed the Commission's basic decisions and enlarged upon others. AB 1890 provides for freezing electric rates at the June 10, 1996, levels and recovery of a major share of transition costs over a 4-year period by December 31, 2001. The stipulated rate freeze will end if recovery is accomplished before 2001.⁽²⁶¹⁾ The legislation also provides for additional categories of transition costs to be recovered.⁽²⁶²⁾ Finally, the CPUC was empowered to implement these directives.

Connecticut

Restructuring legislation in Connecticut calls for 35 percent of customers in Connecticut to have electric service provider choice by January 1, 2000, and for all customers to have provider choice by July 1, 2000.⁽²⁶³⁾ Among other issues, the legislation also details how stranded costs in the State are to be handled.

Responsibility for determination of utility-specific stranded costs eligible for recovery rests with the Department of Public Utility Control (DPUC). For utilities to be eligible to recover stranded costs, they are required to submit a plan that includes divestiture of all non-nuclear generating assets through a public auction.⁽²⁶⁴⁾ Utilities are also required to take all possible steps to mitigate potential stranded costs. Subject to these conditions being met to the satisfaction of the DPUC, generation assets (to include nuclear and other generating assets), generation-related regulatory assets, long-term power purchase contract costs, and others qualify for inclusion in stranded cost determinations. A periodic "true-up" process will adjust the assessment annually, or more often if necessary.

Stranded costs will be recovered by imposing a competitive transition assessment (CTA) on all customers, beginning January 1, 2000. The legislation also provides for issuance of rate reduction bonds (RRBs) covering specific stranded costs. Savings from the RRBs must be directly passed on to customers through lower rates. RRBs are to be retired with the proceeds of the CTA prior to December 31, 2011.

Illinois

The Electric Service Customer Choice and Rate Relief Law of 1997 (HB 362), enacted on December 16, 1997, provides choice of electric supplier to non-residential customers by December 31, 2000, and to residential customers by May 1, 2002. All customers will receive rate reductions, with Illinois Power's customers getting the largest reduction of about 20 percent.

Stranded costs are the amount of "revenues lost" by a utility when the electric industry transitions to a competitive environment. These costs will be determined by reviewing net revenues before and after competition, with considerations for mandated rate cuts and mitigation factors. Transition charges will be calculated by taking the base rate and subtracting the following: a 20-percent rate reduction, the mitigation factor,⁽²⁶⁵⁾ the delivery service charge, and the market price of electricity. The transition period will begin at the onset of competition and continue through 2006. However, a utility may petition the Illinois Commerce Commission to allow a 2-year extension if certain criteria are met.

Stranded cost values will be verified by comparing actual and expected revenues, a procedure which "strengthens monitoring of 'lost revenue' recovery."⁽²⁶⁶⁾

Limited securitization is allowed to refinance debt, as long as the bonds mature by the end of 2008.

Maine

Active movement toward electric competition in Maine began in 1995, when a legislative resolve to study the issue was enacted.⁽²⁶⁷⁾ The Maine Public Utilities Commission (MPUC or the Commission) later submitted recommendations to the State legislature in December 1996 detailing their approach to restructuring the electric industry. MPUC's plan provides all ratepayers the option to select their power suppliers by January 1, 2000.

The Commission's recommendations on stranded costs state that "electric utilities should have a reasonable opportunity to recover legitimate, verifiable, and unmitigable costs stranded as a result of retail access."⁽²⁶⁸⁾ The Commission plans to design rates permitting utilities an opportunity for cost recovery comparable to that under the current regulation without providing a guarantee for recovery.

According to the Commission, stranded costs consist of above-market costs associated with utility generation, with generation-related contracts, and with regulatory assets.⁽²⁶⁹⁾ Costs that were incurred imprudently or costs that are not mitigated aggressively will not be entitled to recovery.⁽²⁷⁰⁾ In fact, the Commission expects the utilities to obtain the highest value from their generation assets and contracts. Recovery of stranded costs would generally be limited to obligations incurred prior to March 1995.⁽²⁷¹⁾

The Commission plans to estimate stranded costs (using market information to the greatest extent) for each electric utility in the State prior to 2000.⁽²⁷²⁾ These estimates will be used to develop the stranded cost rates to be charged by each utility for transmission and distribution.⁽²⁷³⁾ Since the market price for power will be a critical element in the estimation of stranded costs, the rates so established may be reexamined and readjusted (in 2003 and 2006) on a going-forward basis for each utility separately.

Stranded cost recovery is predicated on the requirement that the State's investor-owned utilities transfer all generation-related assets and activities to corporations distinct from their transmission and distribution businesses by January 1, 2000.⁽²⁷⁴⁾ Central Maine Power Company and Bangor Hydro-Electric Company are further required to divest all their generation assets by January 2006, or earlier.⁽²⁷⁵⁾ IOUs are required to file divestiture plans by January 1, 1999, and there will be separate proceedings for each plan.

The MPUC plan was used to help craft legislation. "An Act to Restructure the State's Electric Industry" was signed into law May 29, 1997.⁽²⁷⁶⁾ The legislation opens the market to competition by March 1, 2000, and closely follows the recommendations of the Commission. Stranded costs are defined as the "verifiable and unmitigable costs made unrecoverable as a result of the restructuring of the electric industry."⁽²⁷⁷⁾

Estimates of stranded costs in Maine are not yet complete. Maine Public Service Corporation estimates the costs at $68 million, and Central Maine Power Company's estimate is $2 billion.⁽²⁷⁸⁾ These estimates will be subjected to MPUC's review.

Maryland

An initial determination made by the Maryland Public Service Commission (MPSC) in 1995 concluded that retail wheeling was not in the public interest at that time.⁽²⁷⁹⁾ However, in recognition of the rapidly changing nature of the electric industry and issuance of Orders 888 and 889 by the Federal Energy Regulatory Commission, the MPSC opened a staff investigation in October 1996, calling for a detailed report to be submitted by June 1997.⁽²⁸⁰⁾ Based on the recommendations of the staff report submitted in May 1997,⁽²⁸¹⁾ the MPSC opted in favor of a phased-in retail competition beginning in April 1999 and to be fully available to all Maryland residents by April 2001.⁽²⁸²⁾ After the December 3, 1997, order was released, the Maryland Office of People's Counsel filed a Reconsideration Application with the MPSC, raising a number of issues surrounding the Order. The MPSC did reconsider the implementation dates, and changed the phase-in schedule to begin on July 1, 2000, and to be complete by July 1, 2002.

Estimated stranded costs for Maryland investor-owned utilities are relatively low, at about $1 billion. MPSC staff defines stranded costs as "the difference between the book value of a utility asset and what that asset is worth in a competitive market."⁽²⁸³⁾ Recoverable categories of stranded costs include the unrecoverable capital costs of generating assets, regulatory assets (such as social programs and demand-side management initiatives) and finally, restructuring costs. The Staff report opposes inclusion of nuclear plant decommissioning costs as a component of stranded costs, arguing that these costs should be viewed as operating costs to be recovered from the market selling price of nuclear power output.

The market valuation approach to measuring stranded costs is recommended by the MPSC staff, because it avoids errors from projected future market prices. The Order also recommends that the Commission seek legislative authority for the sale of generation assets.

Utilities in Maryland will be directed to file restructuring plans with the MPSC, including a quantification of stranded costs and the proposed time frame and mechanism to recover costs. In addition, the MPSC recommends a "proxy method for stranded cost level determination to be used in the initial phase-in period should adjudication not be complete at that time."⁽²⁸⁴⁾ Utilities may propose any methodology for estimating stranded costs, provided they justify the plan adequately reflects the long-term valuation of assets.

Utilities must exercise all "reasonably available measures to mitigate stranded costs."⁽²⁸⁵⁾ Some suggested mitigation measures include:

• Sale of excess generating capacity

• Sale of SO₂ and NO_x allowances

• Sale of non-developed sites for generating plants included in the rate base

• Accelerated depreciation of assets

• Allowing no new regulatory assets

• Reduced returns on uneconomic assets

• Buyout or renegotiation of existing contractual power purchase agreements with nonutility generators.

The legislature is planning to take up this issue duringthe 1998 session. According to former MPSC Chair Russell Frisby, the MPSC has the "authority to move forward on this order without the General Assembly's explicit approval."⁽²⁸⁷⁾ However, the General Assembly plans to work on legislation during the 1998 session. In the meantime, the Maryland Office of People's Council (OPC) has challenged whether the MPSC has the authority to implement plans for industry restructuring. The MPSC plans to "consider the remainder of OPC's Reconsideration Application at an appropriate time."⁽²⁸⁸⁾

Massachusetts

Restructuring of the Massachusetts electric industry began with an order to investigate electric utility restructuring in 1995. A regulatory order was subsequently issued by the Massachusetts Department of Public Utilities, now known as the Department of Telecommunications and Energy (MDTE), on December 30, 1996.⁽²⁸⁹⁾ Legislation enabling the MDTE to go forward with the order was enacted on November 26, 1997. Customers receive a 10-percent rate cut when competition begins on March 1, 1998.

According to the MDTE, stranded costs are "losses which may result from subjecting electric company generation to the pressures of a competitive market."⁽²⁹⁰⁾ These stranded costs include nuclear decommissioning costs, above-cost purchased power contractual commitments, utility-owned generation assets, and regulatory assets. Stranded cost calculations are to be based on "administrative determinations or market valuation of generating assets, or combinations of the two."⁽²⁹¹⁾

The order allows for full recovery of stranded costs over a 10-year transition period.⁽²⁹²⁾ All stranded costs must be on the books prior to March 15, 1995. However, according to the order, "the obligation of companies to maximize their mitigation of embedded costs is an inseparable component of the Department's policy decision to allow companies a reasonable opportunity to recover stranded costs."⁽²⁹³⁾ Divestiture of assets is preferred by the MDTE since it is the "cleanest way to establish an objective determination of asset value and obtain a maximum level of mitigation."⁽²⁹⁴⁾ Reconciliation of such costs will take place at the end of years 2, 5, and 10 to compensate for market price changes.⁽²⁹⁵⁾

The next step of the MDTE plan required utilities to file restructuring plans, including provisions for stranded costs. Restructuring plans of major utilities in the State have been approved. Massachusetts Electric Company, a subsidiary of the New England Electric System, has an agreement allowing for an initial 2.8 cent per kilowatthour access charge, with this rate being adjusted for changes in the market value of divested assets and estimated costs.⁽²⁹⁶⁾ Commonwealth Energy System affiliates (COM/Electric) introduced "Competitive Challenge," a plan to minimize the amount of stranded costs by selling its 18 power contracts and its generating assets.⁽²⁹⁷⁾ Eastern Edison Company's competition plan, settled January 1997, provides for full stranded cost recovery and requires divestiture of the company's assets. In addition, Eastern Edison must separate its distribution system from the parent company's transmission system.⁽²⁹⁸⁾

Throughout 1997, a legislative joint committee introduced several bills to deregulate the State's electric industry. The Massachusetts Senate passed H.B. 5117 ⁽²⁹⁹⁾ on November 23, 1997, and Governor Paul Cellucci signed the bill into law two days later. The legislation provides a 10-percent cost reduction and allows for the recovery of stranded costs. The MDTE is instructed to complete a comprehensive audit for each investor-owned utility no later than December 31, 1998, to establish what costs are eligible for recovery. Once approved, the transition costs will be subject to a true-up process at least every 18 months, which is a shorter period of time than proposed in the MDTE order. However, the legislation dictates that only the following transition costs be allowed:

• Generation-related assets and obligations that become uneconomic in a competitive electric market

• Nuclear decommissioning costs not recoverable from the funds administered by FERC

• Unrecovered amounts of the reported book balances of generation-related regulatory assets

• The amount of costs over the market price for contractual commitments for purchased power, when the contracts are restructured, renegoti-ated, or terminated

• Employee-related transition costs.

Michigan

The Michigan Public Service Commission (MPSC or the Commission) was directed to review and initiate actions to promote competition in electricity by Governor John Engler in January 1996.⁽³⁰⁰⁾ To meet this requirement, the MPSC staff met informally with numerous interest groups and stakeholders and also held public hearings. These efforts led to the submission of a staff report in December 1996.⁽³⁰¹⁾In June 1997, the MPSC issued its order based on recommendations in the staff report and inputs from stakeholders detailing electricity restructuring promotion in the State.⁽³⁰²⁾A rehearing of the June order was issued January 14, 1998.

The Commission's definition of stranded costs includes costs that were incurred during a regulatory regime and that will be above market prices during competition. In addition, costs that are incurred to facilitate transition will also be included. Costs that become eligible for recovery will be the sum of these two costs.⁽³⁰³⁾

Based on the above definition of stranded (or transition) costs, the Commission stipulated that costs that would become eligible for recovery would be limited to five categories:

• Regulatory assets, including unrecovered costs of demand-side management programs, plant abandonment costs, unfunded pension and health benefit liabilities, deferred tax liabilities, and other similar costs

• Capital costs of nuclear plants⁽³⁰⁴⁾

• Contract capacity costs arising from power purchase agreements

• Employee retraining costs

• Costs related to implementing restructuring, including implementing a direct access program, establishing an independent system operator, and creating new billing and metering systems.

Utilities operating in Michigan made informational filings with the MPSC indicating the amount of stranded costs to be recovered by each, together with the transition charges (with or without securitization) to be imposed. The two largest utilities in the State--Detroit Edison Company and Consumers Energy Company--propose to recover a total of over $5 billion in stranded costs. Claims of two other smaller utilities are less than $100 million in stranded costs.⁽³⁰⁶⁾ In a rehearing of the June 5, 1997, Order, the Commission calculated stranded cost levels for both Detroit Edison and Consumers Energy. Detroit Edison's stranded costs are estimated at $1,755 million, and those of Consumers Energy at $2,483 million.⁽³⁰⁷⁾

Critics fault the approach used in estimating stranded costs for several reasons. They contend that the assumptions used for the market price of power tend to inflate utilities' stranded cost estimates; that "stranded benefits" of low-cost generating plants remain unaccounted; and that incentives to mitigate costs--even though acknowledged--are missing. Several commenters asserted the view that the procedures for stranded cost recovery may result in the guaranteed full recovery of all costs even if they were not prudently incurred.

In its Order, the Commission stated that imprudent costs will not be included in the determination of stranded costs. Plans for a true-up mechanism to adjust stranded cost estimates annually were also initiated by requiring Detroit Edison and Consumers Energy to file proposals for establishing the mechanism. The process involves verifying that estimated stranded costs reflect actual costs. Thus, distortions introduced by lower market prices of power could be eliminated.

An interesting feature of the Commission's Order is the phase-in schedule to be implemented in the State. The Commission's original June 5, 1997, Order envisions that approximately 2.5 percent of each utility's retail load will become eligible in 1997, with an additional 2.5 percent of load eligible in each of the years from 1998 through 2001. By the end of the phase-in period, 12.5 percent of each utility's retail load will be eligible for customer choice. However, in the rehearing of the Order,⁽³⁰⁸⁾ the phase-in schedule was delayed to begin on March 31, 1998. By January 1, 2002, all customers are eligible to participate in this access plan. If a utility receives more applications for load than contemplated in the phase- in, an allocation of the available capacity will take place. The Staff Report recommended "the use of a bidding process in which customers would submit a sealed bid indicating the amount, above or below the stated transition charge, that they would pay instead of that charge until all customers in their class are eligible for direct access. At that time, the customers begin to pay a cost-based transition charge and all bid amounts collected would be used to offset stranded costs."⁽³⁰⁹⁾ Transition charge amounts were determined January 14, 1998. Consumers Energy's charge to its customers will be 1.20 cents per kilowatthour, and Detroit Edison's charge was set at 1.25 cents per kilowatthour. The Commission did not favor a faster phase-in schedule as it would increase the potential magnitude of stranded costs. By 2002, all customers will have the option of choosing an alternative supplier.

The Commission's Order has not been without controversy. Commissioner John Shea filed a dissenting opinion, questioning the Commission's authority to issue the Order. Consumer groups expressed their disappointment at the length of the transition period and phase-in rates. Utilities' informational filings were also contested. The actual "ground rules" for the restructuring were ordered on October 29, 1997. ⁽³¹⁰⁾ Orders on retail access tariffs, stranded cost true-ups, performance-based ratemaking, and power supply cost reviews were approved, with the dissention of Commissioner Shea. The retail access tariff orders for Detroit Edison and Consumers Energy required both to submit revised direct access tariffs within 14 days of the October 29, 1997, order.⁽³¹¹⁾ Both companies are petitioning for a rehearing of the tariff orders and have refused to submit revised tariffs by the deadline of November 12, 1997. Without modifications to the orders, Detroit Edison "declines to participate" in the program as ordered.⁽³¹²⁾ The January 14, 1998, Order requires Consumers and Detroit Edison to file revised tariff sheets by January 28, 1998.⁽³¹³⁾ This rehearing of the June and October 1997 Orders is expected to be appealed by several parties.⁽³¹⁴⁾

It should, however, be noted that the Commission's Order is essentially a first step in the restructuring process. The rest is up to the State legislature, where restructuring legislation has not yet been introduced.

Montana

The Montana Electric Utility Industry Restructuring and Consumer Choice Act, SB 390, was signed into law by Governor Marc Racicot on May 2, 1997. This bill directs the Montana Public Service Commission (PSC) to implement electric competition in Montana no later than July 1, 2002. The legislation also includes a 2-year rate freeze beginning July 1, 1998, and an additional 2-year rate freeze on energy components of bills for residential and commercial customers. Investor-owned utilities must functionally separate their electric supply, transmission, and distribution services, but without the requirement to divest assets.

SB 390 defines "transition" costs as a public utility's net verifiable generation-related and electricity supply costs (including costs of capital) that become unrecoverable as a result of transition to competition.⁽³¹⁵⁾ The legislation gives examples of these transition costs, including:

• Regulatory assets

• Nonutility and utility power purchase contracts, including qualifying facility contracts

• Generation investments and supply commitments

• Costs of renegotiation or buyout of existing nonutility and utility power purchase contracts, including qualifying facility contracts and fees related to issuing transition bonds

• Cost of refinancing and retiring debt or equity capital of the utility.

Valuation of transition charges should be reasonably quantified and determined on a net basis. This determination may be based on (but not limited to) one of the following:

• Estimated future market values of electric energy and ancillary services produced by a utility

• Appraised values by an independent third party

• A competitive bid.

Recovery of transition costs would be limited to a period determined by the PSC on case-by-case basis. SB 390 stipulates the recovery period to begin on July 1, 1998, and to end on July 1, 2002, unless otherwise extended. As stated earlier, utilities will be required to implement a rate moratorium during the transition cost recovery period. During the period of transition cost recovery, utilities have been permitted to exercise certain changes in accounting procedures so that a 9.5-percent return on equity is maintained.

The legislation also permits utilities to apply for recovery of certain transition costs through the issuance of transition bonds or securitization, subject to the PSC's approval on a case-by-case basis. These bonds are to be secured through the revenues of a nonbypassable charge on all customers. In order for the request to issue a bond to be considered, the utility must demonstrate the resulting savings benefit for the ratepayers.

A special legislative session to consider delaying the restructuring of the electric industry was contemplated by some Montana lawmakers. However, the legislature voted not to hold a special session and affirmed the restructuring. In the meantime, Montana Power begins its asset sale during 1998.

Nevada

Electric industry restructuring legislation was enacted in Nevada in July 1997 and sets December 1999 as a target date for electric competition. Assembly Bill 366 empowers a newly reorganized Public Utilities Commission (NPUC) to initiate rulemaking on issues to be resolved prior to the start of competition. "Shareholders of a vertically integrated electric utility must be compensated fully" for past costs that may become unrecoverable in a competitive environment, according to the legislation.⁽³¹⁶⁾ The NPUC is responsible for identifying and estimating unrecoverable past costs.⁽³¹⁷⁾

The legislation requires the NPUC to consider the following in determining the level of "recoverable costs" in Nevada:⁽³¹⁸⁾

• Extent to which the utility was legally required to incur asset and obligation costs

• Extent to which the market value of utility assets and obligations may exceed the embedded costs under competition

• Results of mitigation techniques adopted by the utilities in reducing the recoverable cost levels and the extent to which equity holders have been compensated by NPUC's rate setting policies in the past.

New Hampshire

In May 1996, New Hampshire enacted legislation requiring the New Hampshire Public Utilities Commission (NHPUC or the Commission) to develop and implement a State-wide electric utility restructuring plan.⁽³²¹⁾ The legislation makes retail choice available to all customers by January 1, 1998. For this objective to be achieved, the General Court provided a list of restructuring principles together with guidance regarding implementation.

The legislation also provides the NHPUC with tools and guidance to address stranded cost recovery claims in a manner that balances "the interests of ratepayers and utilities during and after the restructuring process."⁽³²²⁾ New Hampshire's HB 1392 defines stranded costs as "costs, liabilities, and investments, such as uneconomic assets, that electric utilities would reasonably expect to recover if the existing regulatory structure with retail rates for the bundled provision of electric service continued and that will not be recovered as a result of restructured industry regulation that allows retail choice of electricity suppliers, unless a specific mechanism for such cost recovery is provided." The legislation limits elements of stranded costs to include existing commitments or obligations, renegotiated commitments, and new mandated commitments. Procedures to be adopted for recovery of stranded costs are also specified.⁽³²³⁾ Utilities are, however, obligated to take all reasonable measures to mitigate stranded costs.

Following the enactment of HB 1392, the NHPUC issued a Preliminary Plan in September 1996 seeking stakeholder input on various key goals (including the recovery of stranded costs) of industry restructuring in New Hampshire.⁽³²⁴⁾ During the next few months, the Commission reviewed written comments, evaluated briefs, held hearings, and provided information in public forums on various issues with respect to proposed industry restructuring in the State. These activities culminated in issuance of the Final Plan by the Commission on February 28, 1997.⁽³²⁵⁾

The preliminary and the final plans announced by the NHPUC are unique in articulating a policy decision denying full recovery of transition-related stranded costs.⁽³²⁶⁾ The Commission linked recovery of a utility's stranded costs to the average electricity prices in the New England region. Utilities at or below the regional average electricity cost will be allowed a greater opportunity to recover net, verifiable, nonmitigable stranded costs than utilities with electricity prices above the regional average.

Elements of the Commission plan for recovery of stranded costs include the following:

• Recovery of stranded costs is to be based on a determination of responsibility regarding the acquisition of resources (or assets). Full recovery would be permitted only in those cases where the utility management discretion over resource acquisition was reduced or eliminated by government mandates. In all other cases, where utility management was responsible for resource acquisition decisions, stranded cost recovery would be limited.

• The Commission defined stranded cost on the basis of "net" sunk generation cost (including generation-related regulatory assets) that may not be recoverable when consumers are allowed the choice of reaching alternative suppliers.

• After taking into account various approaches to measure stranded costs, the Commission concluded that a sale or spinoff of generation assets would be the most accurate and reliable method.⁽³²⁷⁾

• All jurisdictional utilities in the State are required to submit plans by December 31, 1997, to accomplish divestiture by the end of the 2-year period following the implementation of competition.

• In line with the provisions of HB 1392 (requiring the utilities to pursue maximum mitigation of stranded costs), the Commission stressed options for mitigation strategies, to include: maximization of the value of assets and contracts through sale or spinoff, the financial management of stranded costs, and the application of other company value to reduce residual stranded costs.

• With respect to stranded costs from assets (like regulatory assets) that have no market value, the Commission suggested strategies to include writedowns, reamortization, and securitization.⁽³²⁸⁾ The Commission, however, recommended that the Legislature should carefully weigh the benefits and drawbacks to securitization.⁽³²⁹⁾

• Determination of stranded costs (that jurisdictional utilities will be allowed to recover) would be tied to the competitive regional electric rates in the New England region. Utilities with rates higher than the regional average will not be able to recover all their stranded costs. In prescribing this mode, the Commission made the following points: less than full stranded cost recovery is fair; less than full stranded cost recovery is not economically inefficient; and full recovery of stranded costs has anti-competitive effects.⁽³³⁰⁾
• Based on State legislation, the Commission did not lend its support to imposing exit fees to recover stranded costs. As an alternative, recoverable costs should be allocated fairly and consistently among customer classes. Stranded cost charges--in conformity with the legislative mandate in HB 1392--are nonbypassable and nondiscriminatory. These charges, however, may not apply to self-generation customers leaving the grid.

• Interim stranded cost charges, to be determined for each jurisdictional distribution utility, will be effective for a 2-year period following the implementation of a company's compliance filing. Interim stranded cost charges will be calculated as a function of the prevailing average price in the New England region.⁽³³¹⁾ The guiding principles articulated by the State legislature are to be applied in setting interim stranded costs.⁽³³²⁾

New Jersey

In its April 1997 report presented to the Governor and the New Jersey State Legislature, the New Jersey Board of Public Utilities (BPU) provided specific findings and recommendations to restructure the electric power industry in the State, with the intent to open the electric market to all retail customers by July 2000.⁽³³⁶⁾ In promoting restructuring and the transition to competition, one of the critical issues that confronted the BPU was how to deal with the utilities' stranded costs. These are costs, "related to the generating capacity in utility rates, which the utility is at risk of being unable to recover if the supply market is opened to competition."⁽³³⁷⁾

Stranded costs in New Jersey, according to BPU, are driven by two factors: the high construction and operating costs of nuclear power plants in the State and the long-term, high-cost supply contracts with nonutility generators and independent power producers. Depending on the assumptions made regarding the future market price for electricity in New Jersey, estimates of stranded costs in the State range "from $7 to $17 billion."⁽³³⁸⁾

With a view to prevent a drastic deterioration in the financial health and viability of the utilities, the BPU proposed that the utilities be given an opportunity, for a limited number of years, to recover generation-related stranded costs through electricity rates. Other sources of stranded costs like regulatory assets, social programs, and restructuring costs (including downsizing) were deemed to be not at risk due to the introduction of competition and could be addressed through traditional ratemaking mechanisms. Nuclear decommissioning costs were also excluded, because industry restructuring did not jeopardize this funding in the future.

Without offering 100 percent recovery, eligibility for recovery of stranded costs was qualified by a number of conditions. Utilities operating in the State are required to offer a near-term rate reduction benefit to a minimum of 5 to 10 percent to the State's customers concurrent with unbundling of rates.⁽³³⁹⁾ Subject to this condition being met, determination of the actual levels of stranded costs and the proposed recovery amount will be decided on a case-by-case basis for each utility.⁽³⁴⁰⁾

The State has made modifications to the existing method of tax collection from utilities to permit further lowering of electricity rates. The Energy Tax Reform Bill, enacted on July 14, 1997, reduces existing energy tax rates by 45 percent over 5 years.⁽³⁴¹⁾ Instead of paying the gross receipts and franchise tax, energy consumers in New Jersey will now pay a sales tax, a corporation business tax, and a transitional energy facility assessment (TEFA). The TEFA will then be phased out over 5 years, and by January 2003, energy tax rates should decrease from 13 percent to 7 percent, saving consumers 6 percent on their energy costs. Combined with the mandatory 5- to 10-percent rate reduction and possible securitization, the tax savings should bring consumers total savings of between 10 and 15 percent.⁽³⁴²⁾

Utilities are also obligated to use all possible measures to mitigate the level of stranded costs, including the sale of excess generating capacity, accelerated depreciation of assets, reduced return on uneconomic assets, and the buyout or renegotiation of existing power purchase contracts. Tax implications resulting from such measures are also to be taken into account.

The BPU also considered securitization as a mechanism in addressing stranded costs.⁽³⁴³⁾ The operational impact of introducing this method of mitigation results in significant interest cost savings, which can be passed on to ratepayers in the form of lower rates. The BPU, however, noted that the resulting savings should not serve as the sole source for rate reductions that were projected or being sought.

Implementing securitization would, however, require enabling legislation and would offer only a partial solution to the stranded cost problem. An upper limit would have to be placed on securitized debt. Proceeds from securitized bonds must be used to reduce generation-related stranded costs and not to subsidize any other activity. In the event that securitization is authorized, recovery of necessary revenues will be reflected in a separate surcharge.⁽³⁴⁴⁾

The BPU's position thus envisages recovery of some but not all components of stranded costs. A specific, nonbypassable market transition charge (MTC) established for each utility will be used to recover approved stranded costs, with its duration ranging between 4 to 8 years.⁽³⁴⁵⁾ The MTC will be a separate component of a customer's bill.

Determining an MTC level and period of duration depends on estimates of stranded costs. One process of establishing estimates is to find the market value through a divestiture of utility generation assets. However, the BPU did not mandate this method for adoption even though GPU plans to implement a partial divestiture of its generating assets in Pennsylvania and New Jersey.⁽³⁴⁶⁾

Enabling legislation is required for the BPU to implement its recommendations, because the Board does not have the authority to establish competitive rates. Herbert Tate, BPU President, has said that "we would like to see the legislation supporting the new competitive marketplace enacted no later than July of 1998."⁽³⁴⁷⁾

New York

The New York Public Service Commission (NYPSC or the Commission) commenced proceedings to investigate the future regulatory regime for the provision of electricity in the State in early 1993.⁽³⁴⁸⁾ Within the framework of proceedings that followed, the Commission found stranded costs to be the most contentious issue.

On May 20, 1996, the Commission's investigations led to the issuance of a decision aimed to increase competition in the electric industry in the State.⁽³⁴⁹⁾ Stranded costs are defined as "those costs incurred by the utilities that may become unrecoverable during the transition from regulation to competitive market for electricity."⁽³⁵⁰⁾ These include "prudent and verifiable expenditures and commitments made pursuant to [utilities'] legal obligations" in a regulatory environment.⁽³⁵¹⁾ This characterization enables the inclusion of operation and maintenance expenses, fuel costs, and purchasing power costs (in addition to investments that are prudent and verifiable) that may also become unrecoverable in a fully competitive market.

However, full recovery of stranded costs is not guaranteed. Rather, the Commission's focus is on the reasonable expectations of utility shareholders in obtaining recovery of their past investments.⁽³⁵²⁾ In addition, the Commission expects utilities and independent power producers to creatively reduce the amount of strandable costs before they are considered for recovery. For example, Niagara Mohawk Power Corporation plans to sell its $1 billion fossil-fueled and hydroelectric generating assets to decrease debt.⁽³⁵³⁾ The adoption of mitigation strategies assumes a critical role in the recovery process. Stakeholders and the Commission have suggested a variety of creative ways to reduce (or mitigate) potentially strandable costs. Establishment of incentives and restructuring of above-cost power purchase contracts are included as possible options.⁽³⁵⁴⁾

While the Commission recognized alternative ways of measuring strandable costs, it also noted that the State's investor-owned utilities differ considerably in strandable costs, mostly due to the level of investment in nuclear plants and the amounts of above-market power purchase contracts. Accordingly, the "calculation, the amount to be recovered from ratepayers, and the timing of the recovery" would be left to individual rate cases beginning in 1996.⁽³⁵⁵⁾ As such, the level of stranded cost recovery will depend on the specifics of each utility. In adopting this approach, the Commission's objective is to create a balance between customer and utility interests and expectations.

Recognizing that the long-run projections of market prices and asset valuations become "highly contestable" beyond a 3-year point, the Commission recommended that calculations of reasonable and verifiable strandable costs be subjected to revisions at specific intervals.⁽³⁵⁶⁾ Such revisions of stranded costs would permit modification and implementation of mitigation strategies to conform to opportunities arising with the passage of time.

Recovery of nonmitigable stranded costs will be accomplished by a nonbypassable access charge or wires charge imposed by the distribution company.⁽³⁵⁷⁾ Exit fees were not considered due to their perceived anticompetitive effects.⁽³⁵⁸⁾ Keeping the recovery period as short as possible in order to accelerate the advent of market prices was a preferred option recommended by the Commission staff.⁽³⁵⁹⁾

The Commission's method of handling stranded costs did not find favor with the State's utilities. In September 1996, the Energy Association (EA) of New York State and its seven electric utility members filed a petition in the New York Supreme Court challenging the Commission's decision regarding the treatment of stranded cost recovery (among other issues). EA claimed that the utilities were entitled, as a matter of law, to recover all competitive losses, implying that the utilities should be able to recover every dollar lost in transition to competition. The Supreme Court ruling rejected EA's claims on November 25, 1996.⁽³⁶⁰⁾ This ruling has been appealed. In the meantime, the Commission is continuing to move the restructuring effort forward as planned.

The preliminary NYPSC estimate of total stranded costs is $16.8 billion, including $3.1 billion for utility generation assets, $6.4 billion associated with power purchase contracts, and $7.3 billion for regulatory assets.⁽³⁶¹⁾ For various reasons, however, the accuracy of these estimates is difficult to establish due to the assumptions used in their derivation. Other estimates of strandable costs in New York range from $14 billion to $25 billion.⁽³⁶²⁾ Securitization has been discussed as a possible option to reduce the level of transition costs. Legislation supporting securitization was proposed in June 1996. The proposal would securitize nonmarketable, intangible expenditures into "intangible property."⁽³⁶³⁾ The cost of repaying securitized debt would be added to the cost of providing transmission and distribution services to all users. Enactment of the legislation would allow utilities to borrow money on the strength of a State guarantee, lowering the interest rate. This would permit rates to be lowered immediately as the cost of borrowing for the utilities declines.⁽³⁶⁴⁾

Critics view the legislative proposal to securitize differently and observe that the bill has a number of problems as initially submitted, including the perpetuation of high rates and a delay of competition.⁽³⁶⁵⁾ The magnitude of projected rate savings attributable to securitization is also stated to be questionable. The legislation failed to secure passage but is likely to be introduced again.

In the meantime, utilities have filed their restructuring plans with the Commission.⁽³⁶⁶⁾ Each utility included adiscussion of the stranded costs that they request be recovered. Most would like to dedicate earnings in excess of a given rate to be used in writing down asset valuations. Consolidated Edison Company, New York State Electric and Gas Company, Niagara Mohawk Company, and Orange and Rockland Utilities will divest assets in order to determine stranded costs stemming from generating facilities. Rochester Gas & Electric, however, is not required to divest, but will use revenues over a certain percentage to offset stranded costs. Assets for Long Island Lighting Company are expected to be acquired by the Long Island Power Authority. These plans differ in details and are based on the specifics of each case. How these plans will be treated if the legislation fails to enact securitization remains to be seen.

Oklahoma

Oklahoma Governor Frank Keating signed S.B. 500 into law on April 25, 1997, mandating retail choice for all customers by 2002.⁽³⁶⁷⁾ The bill sets goals and forms a framework for a restructured electric industry in Oklahoma. In addition, the legislation directs the Oklahoma Corporation Commission (OCC) to undertake studies of various relevant subjects pertinent to the transition of the industry. Reports will be completed by task forces within the OCC and are due in 1998, 1999, and 2000.

The legislation recognizes problems stemming from the existence of stranded costs. Defining stranded costs as investments and contracts which may be unrecoverable under competition, the legislation directs that procedures for the identification and quantification of such costs be established by the OCC. It further directs that mechanisms be proposed for recovery of an appropriate amount of prudently incurred, unmitigable, and verifiable stranded costs and investments. Each utility will be required to propose a recovery plan including a limited recovery period. The plans are subject to the requirement that the proposed recovery does not lead to an increase in electric rates and that recovery costs be paid for by all customers, not just those switching suppliers.⁽³⁶⁸⁾

Direct access by retail customers to the competitive market for generation is to be implemented by July 1, 2002. As such, the OCC has until the end of 1999 to submit its final reports. Many significant changes could take place in the intervening period.

Pennsylvania

The Electricity Generation Customer Choice and Competition Act enacted in December 1996 provided a detailed legislative scheme for electricity restructuring in Pennsylvania.⁽³⁶⁹⁾ This legislation, among other things, allows one-third of Pennsylvania retail customers to choose their electricity suppliers starting January 1, 1999, two-thirds by the year 2000, and all customers by January 1, 2001.

To facilitate this transition to competition, all utilities in the State are required to file restructuring plans with the Pennsylvania Public Utilities Commission (PPUC or the Commission) between April 1, 1997, and September 30, 1997.⁽³⁷⁰⁾ The utilities must also unbundle their services for transmission, distribution, and generation services.

The legislation establishes procedures and standards for recovery of stranded costs. "Transition or stranded costs" are costs related to supplying electricity that utilities can recover under regulation but may not be recoverable in a competitive generation electric market.⁽³⁷¹⁾ Utilities will be given the opportunity to recover these costs subject to legislation that does not guarantee full recovery.

For each utility, the recovery mechanism takes into account the process that led the utility to incur the stranded costs that it claims. Recovery is subject to mitigation and will be allowed for costs stemming from mandated regulatory actions, including:

• Regulatory assets

• Other deferred charges (like the unfunded portion of a utility's projected nuclear decommissioning costs and cost obligations with nonutility generating projects)

• Prudently incurred costs related to renegotiation of nonutility generation.⁽³⁷²⁾

Aggregate mandated and discretionary stranded costs as determined by the Commission become eligible for recovery provided utilities adopt mitigation strategies to reduce stranded costs.⁽³⁷⁴⁾ Mitigation strategies recommended for adoption in the legislation include:⁽³⁷⁵⁾

• Acceleration of depreciation and amortization of existing rate base generation assets

• Minimization of new capital spending for existing assets

• Reallocation of depreciation reserves

• Reduction of book assets

• Maximization of market revenues from existing ratebase generation assets.

Based on the composition of stranded costs and their determination by the Commission, recovery is proposed through a competitive transition charge (CTC) that each customer accessing the transmission or distribution network pays to the appropriate incumbent distribution company. Allocation of CTC will be designed to prevent cost shifting among customer classes.

Unless otherwise determined by the Commission, CTC recovery may not exceed 9 years after the effective date of the legislation.⁽³⁷⁶⁾ The legislation caps the customers' total charges at their 1997 levels during the first 54 months of the recovery period (January 1997 to mid-2001) if a utility is still collecting stranded costs via the CTC. After mid-2001, and until the end of 9 years, the cap applies only to the generation portion of the rates. Circumstances allowing the Commission to grant exceptions to these provisions are also stipulated in the legislation. During the time a utility collects the CTC, it continues to be the supplier of last resort.

After the Commission has made its determination of the stranded costs that a utility is entitled to recover, it can issue a qualified rate order authorizing the utility to collect a guaranteed nonbypassable charge called an intangible transition charge (ITC) from every retail customer.⁽³⁷⁷⁾ This action will permit the utilities to issue (with PPUC approval) transition bonds with a maturity of 10 years or less. Proceeds from the issuance of transition bonds could be used to reduce stranded costs and related capitalization.⁽³⁷⁸⁾ In addition, the utility could reduce its rates or its CTC to reflect the impact of issuing transition bonds.

While restructuring plans have been submitted by all utilities within the stipulated time period, the Commission has so far acted on a securitization application filed by the PECO Energy Company.⁽³⁷⁹⁾ In its order issued in May 1997, the Commission concluded that PECO is permitted to securitize an amount of $1.1 billion and that this amount may be recovered from PECO's customers through an intangible transition charge as provided in the legislation.

The above decision was contested, and a consumer advocacy group filed a lawsuit challenging the constitutionality of the electric competition decision, seeking to overturn the May 1997 decision on securitization. In August 1997, PECO reached a negotiated settlement with various interveners in an attempt to end the litigation. The settlement provides consumers with a 10-percent rate reduction and full retail competition for all customers by the year 2000.⁽³⁸⁰⁾ In addition, PECO would also write off $2 billion in stranded costs, thereby defusing the most contentious issue. In response to this rate reduction, the consumer groups dropped the litigation. Approval by the Commission of the consumer settlement has been complicated by other developments, and the matter was reviewed in December 1997.⁽³⁸¹⁾ Larger savings will be realized by consumers in light of the PPUC's December 11, 1997, decision. This revised plan will give consumers up to a 15-percent rate decrease. A revised settlement, approved May 14, 1998, permits PECO to recover $5.26 billion in stranded assets through 2010 and permits securitization of up to $4 billion. Final decisions on remaining restructuring filings are due from the administrative law judge during the first half of 1998.

Rhode Island

Rhode Island was the second State to enact legislation ordering a move from electric utility monopolies to a competitive electric market.⁽³⁸²⁾ The Utility Restructuring Act of 1996, enacted August 7, 1996, opens the electric market in Rhode Island for competition. The phase-in schedule is gradual, and by July 1, 1998,⁽³⁸³⁾ all consumers will have access to a competitive electric market. Stranded costs are defined as "transition costs associated with commitments prudently incurred in the past pursuant to their legal obligations to provide reliable electric service at reasonable costs," according to one of seven findings by the Rhode Island State Legislature. The following transition costs are authorized by the legislation:⁽³⁸⁴⁾

• Above-market payments associated with power purchase contracts, plus buyout or buydown payments

• Regulatory assets, including those of fuel suppliers, and obligations for post-retirement health care costs

• Nuclear obligations, including decommissioning costs and costs independent of operation

• Net unrecovered costs of generating plants. ⁽³⁸⁵⁾

Stranded costs will be recovered through a nonbypassable transition charge paid by all electric customers. An initial transition charge of 2.8 cents per kilowatthour was set for July 1, 1997, through December 31, 2000. Nuclear stranded costs will be accounted for separately. After the year 2000, the transition charges recoverable from customers will be adjusted for any over or under recoveries of the contract termination fees occurring during July 1, 1997, through December 31, 2000. These transition costs can be collected until December 31, 2009.

After the initial 3 years have passed, 15 percent of the utilities' generation assets must be sold. The value of the assets as determined by the sale will be used to adjust the stranded investment recovery amount for later years.⁽³⁸⁶⁾ However, active divestiture beyond the required 15 percent is encouraged. New England Electric System and Narragansett Electric announced in August 1997 that an affiliate of Pacific Gas and Electric is buying its 18 power plants for $1.59 billion.⁽³⁸⁷⁾ The Utility Restructuring Act of 1996 required utilities to file their market valuation implementation methodology. Narragansett Electric Company, jointly with the New England Power Company (NEP), filed their proposal with the PUC. Instead of simply finding methods to evaluate stranded costs, they decided to sell all of their non-nuclear generation assets. This approach was approved by the PUC, which will now monitor the process of divestiture as the transition period continues.⁽³⁸⁸⁾ The State Assembly also passed a securitization bill on June 27, 1997, allowing utilities to finance "contract termination fees" through transition bonds.⁽³⁸⁹⁾

Vermont

The Vermont Public Service Board (PSB or the Board) organized a working group to study electric industry restructuring in December 1994. Two years later, on December 31, 1996, a final regulatory order was completed, opening Vermont's electric market to competition. Since many key features of this plan could only be accomplished with legislative action, the State Senate introduced S. 62, An Act Relating to Electric Industry Restructuring and Electric Price Stabilization. The Act passed the Senate in March 1997, but stalled in the House. It is expected that the legislation will be revisited in the 1998 session.

The Board's plan evolved after 2 years of meetings, workshops, and conferences involving utility managers, business leaders, consumer advocates, government officials, and other technical experts. The final order contains nine restructuring principles, one of which is to "provide equitable treatment of stranded costs."⁽³⁹⁰⁾ Stranded costs are defined "as the value of existing regulated utility assets that are in excess of their fair market value."⁽³⁹¹⁾ The stranded cost subcommittee developed a State-wide analysis of the level of stranded costs. The preliminary figures ranged from $352 million to $1.4 billion, depending on the market price of electricity. Approximately 60 percent of the stranded costs are the result of purchase power contracts.⁽³⁹²⁾ The order promotes various mitigating actions, such as innovative financing, renegotiation of above-market contractual commitments, and asset sales. According to the order, "companies that succeed in mitigating a significant portion of their current, legitimate above-market costs and that can commit to competitive prices will have the greatest likelihood of recovering their total remaining stranded cost exposure."⁽³⁹³⁾

The order calls for a three-step plan to guide the transition period, with stranded cost recovery to be completed no later than December 31, 2001. The first step is to estimate stranded costs for each utility, using a "bottom-up" approach. Utilities must submit their stranded cost estimates, and "each claim for recovery of stranded costs will be balanced against the potential to mitigate those costs."⁽³⁹⁴⁾ Step two, the adjusting of stranded cost estimates, will begin once the market is open to competition. In this phase, the initial administrative estimates of stranded costs will be adjusted for other factors, including mitigation efforts (such as the sale of generation assets) and electricity prices. By the start of 2001, a final valuation of stranded costs will be completed.

A nonbypassable competitive transition charge (CTC) will be collected from all retail customers in Vermont to pay for the recovery of identified stranded costs. Securitization is under consideration, with the report and order concluding "we believe that a substantial portion of the final stranded cost recovery amount can be financed through specially-authorized utility revenue bonds, secured through the assignment of CTC receipts."⁽³⁹⁵⁾

The Board's plans now await further action of the legislature to begin full implementation of this plan. A committee of the Vermont House of Representatives voted against crafting retail competition legislation in October 1997. The legislature, did, however call for a bill to be developed for performance-based ratemaking.

Virginia

A roadmap for restructuring Virginia's electric power industry was set in place through the enactment of An Act to Establish a Schedule for Virginia's Transition to Retail Competition in the Electric Utility Industry. This legislation is effective July 1, 1998, and it opens Virginia's electric market to competition beginning January 1, 2002. By January 1, 2004, the transition to full competition will be complete. This roadmap does not provide all details on how this transition will take place, but future legislation by the Virginia Assembly and Orders from the State Corporation Commission (SCC) will ensure the details leading to competition are in place.

Just and reasonable net stranded costs will be recoverable and appropriate consumer safeguards related to stranded costs will be implemented. Estimates of stranded costs, recovery mechanisms, mitigation strategies and other stranded cost related issues still need to be determined.

Endnotes

236. Arizona Corporation Commission, In the Matter of the Competition in the Provision of Electric Services Throughout the State of Arizona, Decision and Amended Rules on Electric Competition, Opinion and Order, Docket No. U-0000-94-165, Decision No. 59943 (December 26, 1996).

237. As defined in Title 14, Section R14-2-1601 of the ACC Competition Rules (December 1996), "stranded cost" means the variable net difference between:

239. These options were provided by the Recovery Mechanism Subcommittee in its report submitted to the Group on June 30, 1997. This Group, however, recommended that those remaining in the system and those opting out should be treated differently. In addition, the stranded cost charge should reflect energy and demand charges of the underlying stranded cost.

240. Arizona Commission Corporation Press Release, "Supreme Court Rejects Attack on Corporation Commission Authority to Restructure the Electric Industry" (April 23, 1998).

241. Recommendations by ACC Hearing Officer entered on May 6, 1998 under Docket No. RE-00000C-94-0165.

242. California Public Utilities Commission, Division of Strategic Planning, California's Electric Services Industry: Perspectives on the Past, Strategies for the Future (February 1993). This publication--known as the Yellow Book--provides an in-depth discussion of the industry and the need for regulatory reform.

243. California Public Utilities Commission, Order Instituting Rulemaking on the Commission's Proposed Policies Governing Restructuring California's Electric Service Industry and Reforming Regulation, Docket No. R.94-04-031, and Order Instituting Investigation on the Commission's Proposed Policies Governing Restructuring California's Electric Service Industry and Reforming Regulation, Docket No. I.94-04-032 (April 20, 1994).

244. California Public Utilities Commission, Decision 97-06-060 (June 11, 1997).

245. Uneconomic cost (or asset) was defined as the difference between the book value and the market value of an asset at the time of divestiture, spinoff, or appraisal. Ongoing uneconomic costs were those that were greater than the market clearing price at the power exchange.

246. An independent audit was performed to estimate the level of non-nuclear stranded costs for each of the three investor-owned utilities. For Pacific Gas and Electric Company (PG&E), $2.8 billion, Southern California Edison Company (SCE), $1.1 billion, and San Diego Gas & Electric Company (SDG&E), $130 million. California Public Utilities Commission News Release (November 19, 1997).

247. California Public Utilities Commission, Preferred Policy Decision, D.96-01-009 (January 10, 1996), p. 109.

248. A market rate forecast of 2.4 cents per kilowatthour will be used to estimate transition costs for 1998. This rate may be useful to the utilities in developing rate reduction bond proposals.

249. Bond issue authority was issued as follows: PG&E, $3.5 billion, SCE, $3.0 billion, SDG&E, $0.8 billion (CPUC Press Release, September 3, 1997, CPUC 123). PG&E's stranded cost estimates are between $8 and $14 billion (CPUC Decision 97-09-055). SDG&E and Edison estimate their stranded costs as at least "four times greater than the aggregate principal amount of the proposed issuance of RRBs," according to CPUC Decisions 97-09-056 and 97-09-057. In each case, "a bond sizing model would be applied. . .to determine the precise amount of rate reduction bonds needed to finance a 10-percent rate reduction for residential and small commercial consumers" (CPUC Decision 97-09-054).

250. The RRBs are to be repaid by an additional charge of less than 2 cents per kilowatthour on residential and small business customers. Despite this charge, estimated net savings of up to $970 million are projected over approximately a 10-year period. California Public Utilities Commission Press Release, CPUC-096 (September 3, 1997).

251. "Group Petitions California High Court to Disallow Rate Reduction Bonds," Electric Utility Week (October 27, 1997), pp.14-15.

252. January 1, 1998, was the original date for electric restructuring to begin in California. Note that the filing date for transition cost estimations was changed to August 31, 1997.

253. Valuation of generation-related assets must be completed by the year-end 2001.

254. The Commission viewed this approach to be superior to other ways of calculating transition costs. The market-based approach, which derives its value from observation of the collective actions of buyers and sellers, eliminates the need for forecasting based on assumptions that can be contested. Note that estimates of overall transition costs in California range from a negative $8 billion to $32 billion. California Public Utilities Commission, Decision 96-01-009 (January 10, 1996).

255. Direct access was originally planned to begin January 1, 1998, but due to operational problems, the date was delayed until March 31, 1998.

256. Pacific Gas and Electric Company plans to auction and sell its Morro Bay Power Plant, Moses Landing Power Plant, and Oakland Power Plant. These plants have a combined generating capacity of 3,632 megawatts--about 45 percent of the utility's fossil generation capacity (California Public Utilities Commission Press Release, September 3, 1997, CPUC 74 and CPUC 553). Southern California Edison Company sold 10 of 12 of its gas-fired electric generation plants for $1.1 billion, more than twice their book value. The utility still has plans to sell the two remaining plants ("Edison Unloads 10 Gas-Fired Plants for $1.1 billion," San Diego Union-Tribune, November 25, 1997).

257. California Public Utilities Commission, Press Release (September 3, 1997), CPUC 553 and 74.

258. California Public Utilities Commission, Interim Opinion, Decision 96-08-001 (September 19, 1997), p. 20.

259. California Public Utilities Commission, Decision 96-08-001, Interim Opinion: Transition Cost Eligibility (September 19, 1997), p. 4.

260. Ibid., p. 54.

261. This requirement is primarily for recovery of transition costs relating to generation-related assets and obligations. However, if costs to implement direct access, the power exchange, and the independent system operator reduce the ability of the utilities to collect generation-related transition costs by December 31, 2001, these may continue to be recovered with no set time limit. Costs associated with power purchase contracts, including contracts with qualified facilities in place as of December 31, 1995, are to be collected for the duration of the contract.

262. AB 1890 includes the following additional categories: transition cost recovery of Biennial Resource Proceeding Update settlement costs, capital additions for units existing as of December 20, 1995 and which the CPUC may consider necessary for maintaining until 2002, Southern California Edison's fixed fuel contracts, and an expanded definition of employee-related transition costs.

263. Connecticut HB 5005, Public Act 98-28, An Act Concerning Electric Restructuring (April 29, 1998).

264. Utilities may not be able to divest all non-nuclear generation units even with an auction. It is also possible that the non-nuclear assets may sell for more than their embedded cost. Resulting gains are to be used as offsets in determining total recoverable stranded costs. In addition, the legislation stipulates that all generating assets (including nuclear generation assets) be divested by 2004.

265. The mitigation factor is applied to the base rate less the 20-percent rate reduction. Residential mitigation factors are: 2002, 6 percent; 2003 and 2004, 7 percent; 2005, 8 percent; 2006, 10 percent. Non-residential mitigation factors are 8 percent for the years 1999 through 2002, 10 percent for the years 2003 and 2004, 11 percent for 2005, and 12 percent for 2006 (Illinois Commerce Commission, Summary of HB 362, December 1997).

266. Ibid.

267. Resolve 1995, Chapter 48, "Resolve to Require a Study of Retail Competition in the Electric Industry," directed the Maine Public Utilities Commission to develop a retail competition plan.

268. FONT> Maine Public Utilities Commission, Docket No. 95-462, Electric Utility Restructuring: Report and Recommended Plan (December 31, 1996), p. 105.

269. FONT> According to the MPUC, not all costs that become unrecoverable are "stranded" by retail competition. Customers may undertake conservation, self-generation, fuel-switching, or production cutbacks without the initiation of competition at the retail level.

270. Among the various options indicated by the MPUC, sale of generation assets offers an opportunity to reduce stranded costs. Note that this approach enables sale of assets that command valuation higher than their book valuation to provide a relief. The Commission did not recommend bankruptcy as a tool to reduce costs.

271. Exceptions include the creation of regulatory assets and obligations mandated by the Commission or after the March 1995 date.

272. The MPUC plans to conduct adjudicatory proceedings to determine stranded costs for each utility and establish transition charges for recovery. These proceedings are to be completed by July 1, 1999. Rate design is to be completed by October 1, 1999.

273. MPUC stated that it would not establish exit fees or similar charges during restructuring. Depending on the total level of stranded costs determined, customers could see "a half-cent per kilowatt hour credit" or "an additional 1.5 to 2 cents per kilowatt hour charge," according to The Bangor Daily News (August 27, 1997).

274. Maine has three investor-owned utilities (IOUs): Central Maine Power Company, Bangor Hydro-Electric Company, and Maine Public Service Company. The first two are required to sell the rights to the capacity and energy associated with their power purchase contracts. Maine Public Service Company would transfer these rights to its generation affiliate. Consumer-owned utilities in the State are not required to divest or structurally separate generation from transmission and distribution activities. However, certain limitations on their operations have also been imposed.

275. Maine's utilities will not be required to divest ownership in Maine Yankee--a nuclear power plant--unless its operating life extends significantly beyond 2008.

276. State of Maine Legislature, H.P. 1274-L.D. 1804 (May 29, 1997).

277. Ibid., § 3208, 2 (A,B,C).

278. United States Securities and Exchange Commission, Form 10-K, Maine Public Service Company (September 30, 1997), and Form 10-Q, Central Maine Power Company (March 31, 1997).

279. Maryland Public Service Commission, Order No. 72136, Case No. 8678, In the Matter Of the Commission's Inquiry Into The Provision And Regulation of Electric Service, 1995 Regulatory Policies Order (August 18, 1995).

280. Maryland Public Service Commission, Order No. 72938, Case No. 8678, In the Matter Of the Commission's Inquiry Into The Provision And Regulation of Electric Service, 1996 Initiating Order (October 9, 1996).

281. Maryland Public Service Commission Staff Report, A Framework for Customer Choice and the Future Regulation of Electric Services in Maryland, Case No. 8738 (May 30, 1997).

282. Maryland Public Service Commission, Order No. 73834, Case 8738, In the Matter of the Commission's Inquiry into the Provision and Regulation of Electric Service (December 3, 1997).

283. Ibid., p. 74.

284. Ibid., p. xvi.

285. Ibid., pp. 76-77.

286. Ibid., p. 86.

287. "Maryland Panel Acts to End Electric Monopolies," The Washington Post (December 4, 1997), p. E1.

288. Maryland Public Service Commission, Case No. 8738, Order No. 73901, In the Matter of the Commission's Inquiry Into the Provision And Regulation of Electric Service (December 31, 1997), p. 5.

289. Massachusetts Department of Public Utilities (now known as the Department of Telecommunications and Energy), Electric Industry Restructuring Plan: Model Rules and Legislative Proposal, Order 96-100 (December 30, 1997).

290. Ibid., p. 222.

291. Ibid., p. 289.

292. The plan acknowledges that "there is no clear legal entitlement to stranded cost recovery." According to the Decision (96-100), "costly litigation of the electric companies' legal challenges to any attempted denial of stranded costs would significantly delay the benefits of competition for consumers."

293. Ibid., p. 298.

294. Ibid., p. 297.

295. Ibid., p. 309.

296. Department of Telecommunications and Energy, DPU Docket Nos. 96-100 and 96-25, "Restructuring Settlement Agreement" (February 26, 1997).

297. Com/Electric Press Release, "Commonwealth Energy System Affiliate Moves 'Competitive Challenge' Ahead to Offer Customer Choice in Power Supply" (April 10, 1997).

298. Eastern Utilities Press Release, "Massachusetts Approves Settlement Agreement for Eastern Edison Competition Plan" (January 5, 1998).

299. State of Massachusetts, Bill Relative to Restructuring the Electric Industry in the Commonwealth, Regulating the Provision of Electricity and Other Services, and Promoting Enhanced Consumer Protection Therein, H.B. 5117.

300. Michigan Jobs Commission's report--A Framework for the Electric and Gas Utility Reform--submitted to Governor Engler in December 1995 identified the cost of power in Michigan as a negative factor discouraging new businesses from moving into the State. With a view to remedy this situation, the report contained recommendationsto be adopted by the Michigan Public Service Commission. It was this report that the Governor forwarded to the MPSC for review and action. (Letter dated December 20, 1995, from the Michigan Jobs Commission to Governor John Engler and letter dated January 8, 1996, from the Governor to the MPSC.)

301. Staff of the Michigan Public Service Commission, Staff Report on Electric Industry Restructuring (December 19, 1996).

302. Michigan Public Service Commission, In the Matter, on the Commission's Own Motion, to Consider the Restructuring of the Electric Utility Industry, Case No. U-11290 (June 5, 1997).

303. The Staff Report states that the stranded (or transition) costs include " regulatory assets, societal costs (costs incurred for various social programs), restructuring costs (those incurred specifically to allow competition to proceed, such as the cost of creating an independent system operator), and above-market cost of purchased power contracts previously approved by the Commission, and power supply facilities acquired under the "obligation to serve" principle. Staff of the Michigan Public Service Commission, Staff Report on Electric Industry Restructuring (December 19, 1996), p. 13.

304. According to the Commission, the combination of performance-based regulation and mitigation efforts during the transition period would render it unnecessary to recognize the capital costs of other plants.

305. Various operational procedures need to be in place for securitization to function besides the establishment of a trust fund and a legislative mandate for issuance of bonds. The Commission did not take a position on many of the issues associated with securitization other than conceding that it may be a viable option subject to certain requirements being met. Refer to Michigan Public Service Commission, In the Matter, on the Commission's Own Motion, to Consider the Restructuring of the Electric Utility Industry, Case No. U-11290 (June 5, 1997), p. 16.

306. Consumers Energy and Detroit Edison were required to submit informational filings prior to March 7, 1997, to give the MPSC a clear view of the status of stranded costs in Michigan. Other utilities were not required to file, but could file if they chose. In addition to the two required filings, Alpena Power Company and Wolverine Power Corporation voluntarily submitted reports.

307. Michigan Public Service Commission, In the Matter, on the Commission's Own Motion, to Consider the Restructuring of the Electric Utility Industry, Case No. U-11290 (January 14, 1998), p. 14. These figures assume the market price of electricity to be 2.9 cents per kilowatthour and that all residents of Michigan will choose to participate in the open access plan.

308. Ibid., p. 10.

309. Michigan Public Service Commission, In the Matter, On the Commission's Own Motion, to Consider the Restructuring of the Electric Utility Industry, Case U-11290, Opinion and Order (June 5, 1997).

310. Michigan Public Service Commission News Release (October 29, 1997). Orders were issued in six contested cases in order to continue introducing competition into the Michigan electric market.

311. Michigan Public Service Commission, Decisions 11451 and 11452 (October 29, 1997).

312. "Detroit Ed., Consumers Energy Attack PSC Retail-Access Orders, Ask Review," Electric Utility Week (November 17, 1997), pp. 13-14.

313. Michigan Public Service Commission, In the Matter, on the Commission's Own Motion, to Consider the Restructuring of the Electric Utility Industry, Case No. U-11290 (January 14, 1998), p. 30.

314. "S&P Update on Michigan Electric Utility Restructuring," Business Wire (January 16, 1998).

315. SB 390, The Montana Electric Utility Industry Restructuring and Consumer Choice Act, Section 3, No. 22 (A-B) (May 2, 1997).

316. "Past Costs" are costs that have not yet been recovered and were incurred in the past for customers whom the utilities were legally obligated to serve. Past costs and unrecoverable costs both are terms used in place of the more widely used term "stranded costs."

317. Known as Public Service Commission of Nevada prior to October 1997.

318. Assembly Bill 366, An Act Relating to Governmental Administration, Enacted Version (July 16, 1997), Section 46.

319. A study undertaken by the NPUC includes the following categories of costs: generation and power supply contract costs, regulatory assets, and public policy costs. The Structure of Nevada's Electric Industry: Promoting the Public Interest, Chapter 6 (June 1996).

320. Public Service Commission of Nevada, Docket No. 97-8001 (October 1997).

321. New Hampshire House Bill 1392 (RSA Chapter 374-F), An Act Restructuring The Electric Utility Industry in New Hampshire and Establishing a Legislative Oversight Committee, was enacted on May 16, 1996. HB 1392 consists of policy principles that the NHPUC is required to implement. Critical among the issues are system reliability, customer choice, unbundling of services and rates, recovery of stranded costs, environmental improvement, and near-term rate relief.

322. New Hampshire HB 1392, Chapter 374-F:3.

323. Two recovery mechanisms--for the long and short term--by which stranded costs could be recovered are also detailed in the legislation.

324. New Hampshire Public Utilities Commission, Docket No. 96-150, Restructuring New Hampshire's Electric Utility Industry: A Preliminary Plan (September 10, 1996).

325. New Hampshire Public Utilities Commission, Docket No. 96-150, Restructuring New Hampshire's Electric Utility Industry: Final Plan (February 28, 1997).

326. The Final Plan advocates a market structure to provide customers with the opportunity to purchase their electricity directly from competitive suppliers. Stranded cost and public policy issues are the two critical adjuncts of the proposed transition.

327. The Commission claims that applying this approach allows elimination of vertical market power.

328. Writedowns and reamortization involve changing the timing and return on collections. Securitization aims to reduce stranded cost charges by off-balance-sheet financing with higher debt security and consequently lower cost financing. Securitization may be used to reamortize indebtedness as well.

329. One of the main benefits of securitization is that it permits the utilities to lower costs immediately due to a reduction in financing costs. It also lends them security with regard to recovery of assets with no market value. On the negative side, it reduces incentives for mitigation in the future. NHPUC noted that securitization further institutionalizes costs which could otherwise be mitigated or absorbed during a possible industry reconsolidation (mergers or acquisitions).

330. The Commission released an extensive legal analysis (as an adjunct to the Final Plan documentation) that supports limiting recovery of stranded costs by applying the regional average price in New England utilities as a benchmark. The operational impact of this procedure is to allow jurisdictional utilities with rates lower than the regional average in the New England region to fully recover their stranded costs. The Commission, however, agreed to permit full recovery of nonmitigable costs of purchasing power from small power producers unless the purchases were discretionary.

331. On October 16, 1996, the NHPUC determined in Order 22,364 that the setting of interim stranded costs involved issues of facts and as a result would be the subject of adjucative style hearings. The Commission also retained La Capra Associates--a consulting firm--to provide estimates of long-term and interim stranded costs for each jurisdictional utility in New Hampshire. See La Capra Associates, Estimates of Electric Utility Stranded Costs Associated with the Introduction of Retail Competition in the New Hampshire Generation Service Market (Boston, January 3, 1997).

332. HB 1392 authorizes that the stranded cost charges are to be determined in the context of rate proceedings and must be: (a) equitable, appropriate and balanced, (b) in public interest, and (c) substantially consistent with restructuring principles contained in HB 1392. For purposes of setting interim stranded cost charges, the legislation permits the Commission to make preliminary determinations

333. Note that the overall level of estimated long-term stranded costs for all electric utilities in the State range from $2.0 billion to $2.6 billion depending on the assumptions made. However, nearly 78 percent of these costs are recoverable by the PSNH, with the remaining amount unevenly distributed among four other utilities. Refer to La Capra Associates, Estimates of Electric Utility Stranded Costs Associated with the Introduction of Retail Competition in the New Hampshire Generation Service Market (Boston, January 3, 1997), pp. 35-36.

334. "New Hampshire Concedes to Higher Stranded Cost Recovery for PSNH," Electric Utility Week (October 13, 1997), p. 11.

335. New Hampshire Public Utilities Commission, Decision 96-150, Order No. 22,875 (March 20, 1998).

336. New Jersey Board of Public Utilities, Restructuring the Power Industry in New Jersey, Findings and Recommendations, Docket No. EX94120585Y (April 30, 1997).

337. Ibid., p. 9.

338. Ibid., p. 10.

339. Utilities may also be allowed to finance rate reductions through securitization as approved by the State Assembly.

340. Ibid.

341. New Jersey Board of Public Utilities Press Release, "BPU Implements Energy Tax Reform Law That Will Cut Energy Tax Rates by 45 Percent Over 5 Years," December 17, 1997.

342. New Jersey Board of Public Utilities, Restructuring the Electric Power Industry in New Jersey: Findings and Recommendations, Docket No. EX94120585Y (January 16, 1997), p. 12.

343. Ibid., p. 11. Securitization involves, as discussed elsewhere in this report, the financing of stranded costs, up to a specified limit, by issuance of debt and subsequently liquidating it through a surcharge on the utility's customers.

344. In restructuring plans submitted in July 1997, "all four of New Jersey's power providers--Public Service Electric & Gas Co., GPU Inc., Atlantic City Electric Company, and Rockland Electric Company--support the idea of borrowing to recoup stranded costs." The bulk of the securitization is proposed by Public Service Electric & Gas Co., which filed to securitize $2.5 billion of its estimated $5.5 billion in stranded costs." "New Jersey's Private Utilities May Use Debt to Cushion Stranded Costs," American Banker (July 18, 1997).

345. Utilities will no doubt prefer a surcharge that would coincide with the life of outstanding power purchase contracts. Where such contacts cannot be renegotiated, extensions to the MTC charge may be necessary.

346. GPU opened an auction for 5,320 megawatts of 26 fossil and hydro plants in Pennsylvania and New Jersey on April 15, 1998. See "GPU Markets Its Power Generation Assets to Bidders," Asbury Park Press (April 16, 1998).

347. A.S. Twyman "Energy Deregulation Has Language All Its Own for New Jersey Lawmakers," The Star-Ledger (December 31, 1997).

348. New York Public Service Commission, Case 93-M-0229, Proceedings on Motion of the Commission to Address Competitive Opportunities Available to Customers of Electric and Gas Service and Develop Criteria for Utility Responses, Order Instituting Proceeding (March 19, 1993). The case number was subsequently changed to 94-E-0952 to reflect that the subject matter is limited to electric service.

349. New York Public Service Commission, Case 94-E-0952, In the Matter of Competitive Opportunities Regarding Electric Service, Opinion and Order (May 20, 1996).

350. Ibid., p. 46.

351. New York Public Service Commission, Case 94-E-0952, In the Matter of Competitive Opportunities Regarding Electric Service, Opinion 95-7: Opinion and Order Adopting Principles to Guide the Transition to Competition (June 7, 1995), Appendix C, p. 2.

352. New York Public Service Commission, Case 94-E-0952, In the Matter of Competitive Opportunities Regarding Electric Service, Staff Position Paper (October 25, 1995), p. 38.

353. The auction is part of the restructuring plan worked out with Niagara Mohawk in October 1997 and filed with the Public Service Commission on December 1, 1997. The NYPSC approved the restructuring plan in February 1998.

354. The Commission staff estimated that the above-market costs of power purchase contracts (by the utilities in the State) account for nearly 38 percent of the estimated stranded costs. Somewhat lower estimates of above-market power purchase costs were provided by the Energy Association. See New York Public Service Commission, Case 94-E-0952, In the Matter of Competitive Opportunities Regarding Electric Service, Recommended Decision (December 21, 1995), Vol. I, p. 77.

355. New York Public Service Commission, Case No. 94-E-0952, In the Matter of Competitive Opportunities Regarding Electric Service, Recommended Decision (December 21, 1995), Vol. I, p. 108.

356. As an example, the Commission staff and the Energy Association presented independent estimates of the magnitude of strandable costs in the State from transition to competition. These two estimates initially indicated an approximate difference of nearly $12.5 billion. Refer to New York Public Service Commission, Case 94-E-0952, In the Matter of Competitive Opportunities Regarding Electric Service, Brief on Exceptions (January 19, 1996), p. 33 and Appendix B-2.

357. The Commission rejected a clarification sought by the Municipal Electric Utilities Association that recovery of stranded costs be through a distribution surcharge on a departing customer. Rather, the Commission would prefer to retain the flexibility to design a mechanism for recovery in accordance with the specific situation existing with each utility. State of New York Public Service Commission, Case 94-E-0952, In the Matter of Competitive Opportunities Regarding Electric Service, Opinion No. 96-17: Opinion and Order Deciding Petitions and Clarification and Rehearing (July 17, 1996), p. 11.

358. New York Public Service Commission, Case 94-E-0952, Recommended Decision, In the Matter of Competitive Opportunities Regarding Electric Service, Volume I, p. 77.

359. New York Public Service Commission, Case 94-E-0952, In the Matter of Competitive Opportunities Regarding Electric Service, Recommended Decision (December 21, 1995), Vol. I, p. 80.

360. In the Matter of The Energy Association, et al. vs. Public Service Commission, New York State Supreme Court, Decision 5830-96 (November 25, 1996).

361. New York Assembly, "Competition Plus: Energy 2000" (March 1996), p. 15.

362. New York Public Service Commission, Case 94-E-0952, In the Matter of Competitive Opportunities Regarding Electric Service: Brief on Exceptions (January 19, 1996), Appendix B-1.

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

364. In testimony before the New York State Senate Energy Committee, the New York State Consumer Protection Board stated that securitization would bring about a 5- to 10-percent rate cut.

365. A number of arguments opposing the proposed bill can be found in the Assembly briefing paper. Refer to New York State Assembly, Shedding the Light on Securitization: A Briefing Paper on Moving to Competition in the Electric Industry (January 1997).

366. Lilco was not required to file a plan due to its pending merger with Brooklyn Union. The merger has since been approved.

367. Oklahoma State Senate Bill 500, Electric Restructuring Act of 1997 (April 25, 1997).

368. Oklahoma Constitutional Article 9, Section 18, OCC Rules 165:35 discusses rules when more than one utility is eligible to service customers in an incorporated town. When a customer in this service area decides to switch electric companies, the new utility must pay exit fees to the old utility. In March 1996, the Oklahoma Supreme Court ruled this practice unconstitutional, setting precedent for the plan to have all customers share in paying for stranded costs through a nonbypassable charge.

369. Enacted as House Bill 1509, Sections 3-4, Title 66 Pennsylvania Consolidated Statutes, Sections 2801-2812 (December 3, 1996). Section 4 of the House Bill 1509 amends Title 66 by adding a Chapter 28 entitled "Restructuring of the Electric Utility Industry." This is now known as the "Electricity Generation Customer Choice and Competition Act" or the "Customer Choice Act." Note that the legislation was the product of investigations, comment and negotiations involving various stakeholders and the legislators in the State. Refer to Pennsylvania Public Utility Commission, Report and Recommendation to the Governor and General Assembly on Electric Competition (July 3, 1996).

370. Each utility plan, which would be subject to review and approval by the PPUC, would describe how the utility would allow its customers to choose their electricity suppliers.

371. Title 66 of the Pennsylvania Consolidated Statutes, Section 4, The Electricity Generation Customer Choice and Competition Act, Chapter 28: Restructuring of the Electric Utility Industry, Section 2802, p. 4.

372. Renegotiation may include cancellation, buyout, or buydown of nonutility generation projects.

373. Other costs are a catch-all for all costs that a utility may not be able to recover due to transition. The legislation currently provides for transition costs related to employees and costs associated with plants that are no longer used and useful.

374. The legislation is silent on the methodology to be used by utilities in determining the level of stranded costs each may be allowed to recover.

375. Each utility plan would be subject to review and approval by the PPUC would describe how the utility would allow its customers to choose their electricity suppliers (Section 2806, p. 51).

376. The effective date of legislation is January 1, 1997.

377. The revenue from the ITC will pay principal, interest, and other costs of transition bonds.

378. The utilities are required to provide information regarding the planned use of proceeds from securitization.

379. Pennsylvania Public Utility Commission, Opinion and Qualified Rate Order, Docket Nos. R-00973877, R-00973877C0001, and R-00973877C0002 (May 22, 1997). PECO's application for securitization was filed in advance of the final approval of its restructuring plan in January 1997.

380. R. Heidorn,"PECO: Settlement to Include 10 Percent Rate Cut Next Year," Philadelphia Inquirer (August 28, 1997).

381. However, the PPUC is reviewing its May 1997 decision in view of a subsequent counter offer by Enron Corporation, which promises a 20-percent savings for Pennsylvania customers in addition to reimbursing PECO for $5.41 billionin stranded costs.

382. New Hampshire passed legislation in May 1996. Rhode Island enacted legislation in August 1996.

383. By July 1, 1997, the following will be able to select nonregulated power producers: all new commercial and industrial customers with an average annual demand greater than 200 kilowatts, all existing manufacturing customers with an average annual demand of 1,500 kilowatts or greater, and all accounts in the name of the State of Rhode Island. Choice is expanded to all customers in Rhode Island "within three months after retail access is available to 40 percent or more of the kilowatt-hour sales in New England." If retail access is not available in New England, then all customers will be able to choose their power producer by July 1, 1998. State of Rhode Island, 96-H 8124 B, An Act Relating to the Utility Restructuring Act of 1996, Section 39-1-27.2(a-b) (August 7, 1996).

384. State of Rhode Island, 96-H 8124 B, An Act Relating to the Utility Restructuring Act of 1996, Section 39-1-27.3.

385. Ibid.

386. Transition cost and recovery information is found in Section 39-1-27.3 of the Utility Restructuring Act of 1996.

387. New England Electric System Press Release, "New England Electric System Sells Generating Business to PG&E Corporation's U.S. Generating Company" (August 6, 1997).

388. Public Utilities Commission, In RE: Narragansett Electric Company and New England Power Company-Market Valuation Implementation Methodology, Docket 2540 (May 2, 1997).

389. H. 7003, An Act Relating to Public Utility Securitization (June 27, 1997).

390. State of Vermont Public Service Board Final Report and Order, Docket 5854 (December 31, 1996), p. 11.

391. Ibid., p. 51.

392. Ibid., p. 53.

393. Ibid., p. 12.

394. Ibid., p. 80.

395. Ibid., p. 87.

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