Executive Summary






Definition of Stranded Costs



Components of Stranded Costs



Mitigation of Stranded Costs



Calculation Methodology



Calculation Period



Market Clearing Price



True-Up Mechanism



Cost Allocations



Recovery Mechanism



Accounting, Tax & Finance Issues



Appendix A List of Working Group Participants



Appendix B Summary of Meetings Held



Appendix C Voting Roster



Appendix D Dissenting Comments


Report of the Stranded Cost Working Group
Executive Summary
The purpose of this report is to present to the Arizona Corporation Commission ("Commission") the findings and recommendations of a special working group assembled to address the issue of stranded costs in the context of introducing retail competition in the electric utility industry in the State of Arizona. In general terms, stranded costs are costs that utilities have incurred or will incur in connection with the provision of regulated monopoly service that will likely not be recoverable in a competitive market.
In December 1996 the Commission issued Decision No. 59943 approving rules (the "Rules") for a phased-in transition to a competitive retail electric power market beginning January 1, 1999. In connection therewith, the Rules require the creation of a special working group (the "Working Group") to develop recommendations for the analysis and recovery of stranded costs for inclusion in a special report to the Commission. Such a group was created at a meeting of interested parties held in the Commission's Phoenix Hearing Room on March 4, 1997. This is the report required of that Group.
At the initial meeting of the Working Group it was generally agreed by the attendees that the most efficient way to proceed would be through subcommittees established to examine specific issue areas. Three such groups were established: a Calculation Methodology Subcommittee, a Recovery Mechanism Subcommittee, and an Accounting Tax and Finance Subcommittee. Each subcommittee met on several occasions to analyze issues and develop recommendations for the Working Group.

Another matter addressed at the kickoff meeting of the Working Group was the manner by which it would be determined whether a consensus exists among the participants with respect to any issue brought before them. For that purpose, twenty parties, representing a balanced, cross-section of participating stakeholders were given voting authority. Ten votes represented the interests of parties involved in the generation, transmission, or distribution of electricity. Five votes were reserved for parties representing consumer interests, and five for public interest groups and governmental agencies. It was further agreed by the participants that consensus would be said to exist when a two-thirds super majority, based on the number of votes cast, was received.

While consensus on some issues was achieved, it is disappointing to report that many issues remain unresolved. This reflects the overall complexity of the stranded cost issue, the substantial dollar amounts involved, and the diversity of participating stakeholder interests. The following is a summary of the issues upon which consensus was achieved using the agreed upon voting procedure:

Historically, utility regulatory policy in Arizona has been created through the rate case decisions and other orders issued by the Commission, based on recommendations developed and advanced by the Utility Division Staff ("Staff"). In keeping with its traditional responsibility, Staff coordinated the efforts of the Working Group and its subcommittees in addressing the multitude of issues relating to the definition, quantification and recovery of stranded costs, and in developing the recommendations being conveyed herein. Although not a voting party for purposes of establishing the extent to which consensus on issues exists, Staff was an active participant in this process and performed extensive analyses of the issues. In connection therewith, Staff has developed its position on a number of the issues, many of which have not achieved consensus within the Working Group or its subcommittees. The following recommendations of the Staff are submitted for the Commission's consideration:

For purposes of preparing and distributing this report, it was agreed in the Working Group that, when the Utilities Division had completed drafting the report, copies would be distributed to all participants for comments about any significant omissions, misstatement of facts, typographical errors, or spelling mistakes. The parties providing responses to the draft were: APS, TEP, AEPCO, and Energy Strategies, Inc. It was further agreed that when the report was in final form, it would be sent to all participants who would then be given an opportunity to file dissenting comments for inclusion in the report. Such comments appear as Appendix D to the report. The comments contained therein are an integral part of the report.
Stranded Cost Working Group
September 30, 1997
The purpose of this report is to present the findings and recommendations of a special working group assembled to address the stranded costs that will occur with the introduction of retail competition in the electric utility industry in the State of Arizona.
On December 26, 1996, the Arizona Corporation Commission (the "Commission") issued Decision No. 59943 which approves rules (the "Rules") that specifically provide for a phased transition to a competitive retail power market. In connection therewith, the affected utilities are required to make at least 20% of their 1995 system retail peak demand available for competitive generation supply to all customer classes on January 1, 1999. The required eligibility will increase to 50% on January 1, 2001. Full competitive generation is scheduled to occur no later than January 1, 2003.
As will be more fully explained elsewhere in this report, stranded costs represent amounts previously spent in connection with the provision of traditional regulated utility service that are not likely be recoverable in a competitive power industry with prices set by the market, not elected or appointed regulators. Almost without exception this has been the most contentious issue in every state addressing retail electric competition. The Commission recognized the likelihood of the occurrence of stranded costs by including in the Rules a definition of this phenomenon associated with public utility deregulation (R14-2-1601.8), and also by including a specific section (R14-2-1607) addressing the recovery of stranded costs of affected utilities.
Rule R14-2-1607.C requires the creation of a working group comprised of representatives of all stakeholders and coordinated by the Director of Utilities, to develop recommendations for the analysis and recovery of stranded costs. Such a working group was created on March 4, 1997 at a meeting of interested parties in the Commission's Phoenix Hearing Room. As summarized in Appendix A attached hereto, more than fifty parties were represented in the Working Group and its subcommittees.
Rule R14-2-1607.D lists the key items that the Commission felt should be included within the scope of analyzing the stranded cost issue. These are:

When considering the above and other key issues surrounding stranded costs and their recovery at the first meeting of the Working Group, it was generally agreed that a more efficient approach would be obtained by establishing subcommittees to examine specific issue areas. Three such groups were created: a Calculation Methodology Subcommittee, a Recovery Mechanism Subcommittee, and an Accounting, Tax and Finance Issues Subcommittee. The latter was given responsibility for assessing the accounting, tax and financial implications of findings and recommendations of the other two subcommittees. A list of the meetings conducted by the Working Group and the subcommittees appears in Appendix B.
It should be noted that the scope of the investigation undertaken by the Stranded Cost Working Group and its subcommittees did not include any consideration of the legal issues (i.e. the "regulatory taking" issue or whether a legal contract actually existed with respect to the traditional "regulatory compact") relating to stranded costs. Such matters were addressed by the Legal Issues Working Group. The issue discussions and recommendations contained herein reflect solely the analyses performed by members of the Working Group and Staff's knowledge of traditional public utility regulation and ratemaking in Arizona, and electric restructuring activities currently underway throughout the nation.
Each of the subcommittees was required to submit a report to the Working Group at the conclusion of their analyses. The reports reflect the results of analyses and discussion of various issues papers presented by subcommittee participants. Such reports were the basis for discussion of the issues and subsequent votes taken by the Working Group.
Rule R14-2-1607.B states that the Commission shall allow recovery of unmitigated stranded costs by affected utilities. Although there was a clear recognition by working Group participants of the need for and propriety of stranded cost recovery in order to achieve an equitable and efficient transition to retail competition, there was considerable diversity of opinion with respect to the manner in which it should be quantified, the extent to which it should be recoverable, and the recovery mechanism to be used.
Rule R14-2-1607.E requires the Stranded Cost Working Group to file a report on its activities and recommendations by September 30, 1997. This report includes such findings and recommendations. To determine the extent to which a consensus exists with respect to any issue, a voting procedure was agreed upon by the Working Group. For that purpose, twenty parties representing a balanced cross-section of participating stakeholders were given voting authority. A voting roster is attached hereto as Appendix C. As indicated thereon, ten votes were to be from parties involved in the generation, transmission or distribution of electricity, five votes from parties representing consumer interests, and five votes from public interest groups and governmental agencies. It is noted that, pursuant to direction from the Chairman, the Utilities Division ("Staff") was not a voting party. It was further agreed by the participants that consensus would be said to exist when a two-thirds super majority, based on the number of votes cast, was received.
Throughout the remainder of this report are summaries explaining in detail the various issues analyzed by the Working Group and related subcommittees, along with findings and recommendations. While consensus on some issues has been achieved, it is disappointing to report that many issues are yet unresolved. Incorporated as Appendix D to this report are the comments of parties not agreeing with the information contained herein. Such dissenting comments are intended to speak for themselves. This reflects the overall complexity of the stranded cost issue, the substantial dollar amounts involved, and the diversity of participating stakeholder interests. As in most of the other states considering retail competition, the Commission will likely have to decide among competing interests on many key issues.
Traditionally, public utilities have operated under licenses and franchises granting them the exclusive right to operate in specific geographic areas. This monopoly status was desirable because utilities are typically highly capital intensive, requiring a comparatively large plant investment relative to annual revenues. By eliminating the element of competition, it was believed that costs to the consumer were minimized, by avoiding the unnecessary duplication of services. To guarantee that such monopoly power was not abused, regulation was substituted for competition to bring about fulfillment of the objective of having an adequate supply of utility service at a reasonable price.
One of the primary tools of regulators was the ability to set prices for utility service through the determination of revenue requirements in public hearings. A utility has traditionally been permitted an opportunity to collect revenues equal to its prudently incurred costs of providing safe, reliable service to all that request it under the obligation to serve. In setting rates, utility regulators are not required or obligated to guarantee that the companies will achieve their authorized returns, but only to be given a fair opportunity to do so.
Under their traditional obligation to serve, utilities have incurred certain long-term costs, which may not now be fully recoverable in a competitive generation market, with prices based on marginal costs. In the transition to retail competition, the utilities that undertook such investments must have an opportunity to recover the prudent cost of uneconomic assets and obligations which were made under a different set of circumstances.
Stranded costs typically arise when a customer leaves his host utility to buy power from another supplier and the cost savings the utility realizes by not having to meet the demand and energy needs of the departing customer cannot compensate for the revenue it loses because the customer is no longer paying regulated rates for power. They may also occur if the host utility must discount tariffed rates to a customer to retain that customer's business. The recovery of legitimate stranded costs is necessary to prevent cost shifting between customer classes, to treat utility investors fairly, and to promote efficient competition. Stranded cost recovery is mandated by the FERC in its wholesale competition rules, was affirmed in the 1996 Economic Report of the President, and has been endorsed by all the states moving toward retail competition.
This Commission properly recognized the potential for significant stranded costs to occur, and the need for the establishment of a mechanism for their recovery that is fair and workable to assure the development of efficient competition beneficial to all customers, by including consideration thereof in the Rules covering retail electric competition.
Rule R14-2-1601 contains ten key definitions relevant to electric industry restructuring. Included therein is the following:
"Stranded Cost" means the verifiable net difference between:


The value of all prudent jurisdictional assets and obligations necessary to furnish electricity (such as generating plants, purchased power contracts, fuel contracts, and regulatory assets), acquired or entered into prior to adoption of this Article, under traditional regulation of Affected Utilities; and


The market value of those assets and obligations directly attributable to the introduction of competition under this Article.

One issue visited by the Calculation Methodology Subcommittee of the Stranded Cost Working Group was whether the current definition in the Rules was adequate. A number of parties' position papers indicated a preference for a definition that considers stranded costs as an aggregation of uneconomic costs incurred under the obligation to serve, rather than focusing on specific assets and liabilities of the affected utilities that may be recorded at amounts other than their current fair market values as is indicated in the existing definition. The proposed substitute definition tends to reflect expected reductions in future revenue streams when market-based revenues replace the traditional cost-based regulated revenues.
Staff also had difficulty in accepting the existing definition as written. As may be seen in the examples below, there are significant unrecorded assets and liabilities that may become stranded during the transition to retail competition. Staff views the existing Rule as ambiguous and possibly too limiting in that respect.
Over the years, this Commission has made certain "promises" in ratemaking, both explicit and implicit, to utilities under its jurisdiction that some current expenditures would be recoverable through future rates. Generally, current expenditures deferred for future rate recovery are reflected as some type of "regulatory asset" on the respective utility's balance sheet. There are, however, instances where such amounts are not allowed under Generally Accepted Accounting Principles to be deferred for financial accounting and reporting purposes; thus, they are required to be charged to expense as incurred, regardless of the regulatory promise.
As an example, in Decision Nos. 57586 and 58497, this Commission required Tucson Electric Power Company to defer for future rate recovery certain portions of the non-fuel operations and maintenance expenses, depreciation and property taxes incurred at Unit No. 2 at the Springerville Generating Station. Such amounts represented what the Commission believed to be "excess capacity" costs, and were not recoverable in rates until after a later date when the unit became fully used and useful. Due to the uncertainty surrounding the date upon which recovery of these deferred costs would commence and over what period such recovery would occur, current accounting rules denied the recognition of a regulatory asset and required the Company to charge the respective amounts to expense in their entirety, notwithstanding the Commission's previous orders for deferral. As a result, that Company has a significant unrecorded regulatory asset that will likely become stranded during the transition to competition.
Another example of an unrecorded regulatory asset on the books of utilities in this State is that associated with postemployment benefits other than pensions. Until very recently, the Commission denied utilities' requests to adopt for ratemaking purposes the accrual method of accounting for such costs as has been required since 1993 under Statement of Financial Accounting Standards No. 106. Instead, it only allowed in rates the recovery of current amounts paid for retirees' benefits, with the implicit promise that, as current accrued liabilities under SFAS No. 106 are ultimately paid in the future, they will be allowed in rates at that time. As a result, since the utilities in this State adopted SFAS No. 106 in 1993, they have had to charge to expense all related amounts not allowed in current rates, including both the difference between current accruals and cash payments, and the amortization of a transitional obligation as required under the Standard. For the affected utilities this has created another significant unrecorded regulatory asset.
In addition to unrecorded regulatory assets, there may also be unrecorded and potentially strandable contingent liabilities. These contingent liabilities can become recognizable liabilities under certain conditions, which thereby become a strandable cost to be allowed recovery. These could include take-or-pay obligations under existing fuel contracts and future demand charges under purchased power agreements that become uneconomic in a competitive environment, as well as the remaining, yet unrecognized portions of the obligations that will be incurred in connection with the closure of existing generating units at the end of their useful service lives.
Based on the foregoing, and in order to remove a potentially significant controversial ambiguity from the definition, Staff recommended to the Calculation Methodology Subcommittee that the phrase "both recorded and unrecorded" be included parenthetically immediately following the words "jurisdictional assets and liabilities" in the definition. The parties in attendance supporting retention of the definition in its existing form prevailed. When the issue was placed before the Stranded Cost Working Group, the current definition received support from fifteen of the eighteen voting members present. There appears to be a clear consensus to leave the definition of Stranded Costs in the Rules unchanged.
Rule R14-2-1607.G requires affected utilities to file estimates of unmitigated stranded costs. Such estimates are to be fully supported by analyses and by records of market transactions undertaken by willing buyers and willing sellers. A key consideration in the quantification of stranded costs is the categories of expenditures that should be included. This topic was thoroughly addressed by the Calculation Methodology Subcommittee.
Stranded costs resulting from the transition to a competitive electric industry may take many forms. There was general agreement among the Subcommittee members with respect to the types of costs that may be considered as strandable. These include:

Clearly the most significant stranded costs are those incurred in connection with the generation of electricity, since that is the business sector which is being opened to competition. That includes utility-owned generation assets which may be comprised of net plant in service, construction work in progress, common plant associated with generation-related activities, fuel inventories and handling facilities, and applicable materials and supplies. Such amounts may be offset by related accumulated deferred income taxes, unamortized investment tax credits or other related balance sheet reserves. Some utilities may also have leased generating assets that will become stranded. The calculation of stranded costs should reflect all generating units and other sources of power supply, whether above or below market. Fairness and equity demand that the benefits from units that may have bus bar costs lower than the market be used to offset the stranded costs of uneconomic units.
Potential stranded costs associated with generating facilities include not only the current capital costs of the facilities, but also the cost of their physical removal at the end of their respective service lives. Such amounts for the decommissioning of nuclear plants and disposing of nuclear waste are very significant. While clearly not as great, the costs of properly removing and disposing of fossil plants at their retirement from service may nevertheless be substantial. It is noted that, under the existing Rules, nuclear decommissioning costs are recoverable as part of the Systems Benefit Charge, rather than a stranded cost charge.
Purchased Power Agreements (including contracts with Qualified Facilities) under which utilities procure a portion of their capacity and energy supply requirements are another category of potential stranded costs. When the previously approved costs incurred under these contracts exceed market-based rates, otherwise unrecoverable costs will be incurred. It is appropriate to also consider within the context of stranded costs all obligations and commitments under existing fuel and transportation contracts.
Regulatory Assets are another type of potentially stranded costs. They represent current expenditures that have been deferred on the utilities' balance sheets for future expense recognition for accounting and ratemaking purposes. Such treatment is consistent with the long-standing principle followed by this Commission and other regulatory bodies in attempting to effectively synchronize ratepayer benefit with cost recovery. Regulatory assets may also be created for moderating the rate impact of uncontrollable or non-annually recurring events, or for promoting utility involvement in public policy initiatives. Examples of Regulatory Assets having stranded cost implications include:

Another type of stranded costs is employee-related restructuring costs. Commissioner Irvin specifically requested that the Working Group consider the propriety of including such costs in stranded cost calculations. Included in this category may be the cost of retraining employees to perform their present tasks more efficiently or to perform new tasks to properly transition the workforce for competition. This category may also include costs incurred to retrain or otherwise effectively and fairly prepare for separation of those employees that may not be retained as a result of company reengineering or downsizing to accommodate retail competition. Clearly a burden of proof would exist for the respective utilities to demonstrate that such costs would not be incurred absent the industry restructuring. Thus far, the regulators in the States of California, Michigan, New Jersey, Maine and Pennsylvania have provided for the inclusion of such expenditures in stranded cost recovery.
The final category of stranded costs identified by the Calculation Methodology Subcommittee is that associated with environmental mandates. This would include capital expenditures made to accommodate environmental regulations such as those occurring as a result of compliance with the Clean Air Act.
In identifying the types of costs to consider as being potentially strandable, it is noteworthy that several members of the Calculation Methodology Subcommittee were of the opinion that no capital costs added after December 26, 1996, the date of the Commission's Decision creating the Electric Restructuring Rules, should be allowed for inclusion in stranded cost calculations. The parties believe that the Commission's Decision effectively put the utilities on notice that such subsequent investments should be considered to be at risk in the marketplace. This is not unlike the position of the FERC in Order No. 888 whereby utilities will be allowed to recover wholesale stranded costs associated with contracts executed after July 11, 1994 (the date of the initial FERC stranded costs rulemaking notice) only if specific stranded cost provisions are contained in the contract.
Although the focus of this analysis was directed toward potentially strandable generation costs, Staff believes that it is appropriate to recognize that, to the extent any portion of the affected utilities' distribution business (i.e. customer metering and billing) is similarly removed from the scope of regulation, additional stranded costs may result.
At the voting meeting of the Stranded Cost Working Group, a very strong consensus (16 for, none against, with 2 abstentions) was achieved with respect to the list of possible components of stranded costs previously identified above, and with the Calculation Subcommittee's recommendation that a burden of proof is on the affected utility to justify all requests for stranded cost recovery. It was also clear that a strong consensus exists with respect to the position that any interested party may oppose or challenge the inclusion of any particular element of an affected utility's stranded cost calculations.
Staff recommends that the Rules be modified to more clearly reflect these positions.
As an additional clarification of the Rules, Staff also recommends that the Commission state its intent of whether nuclear fuel disposal costs are to be part of the nuclear decommissioning costs recovered in the System Benefits Charge as provided in R14-2-1608.A, or whether they should be considered as stranded costs. There were differing interpretations among Working Group participants.
Rule R14-2-1607.A requires affected utilities to "take every feasible, cost-effective measure to mitigate or offset Stranded Cost by means such as expanding wholesale or retail markets, or offering a wider scope of services for profit, among others." As part of its analyses, the Calculation Methodology Subcommittee considered the issue of mitigation and the ways that mitigation could occur. Although no specific recommendation by the Subcommittee was made to the Working Group, there was general agreement among the parties that utilities should aggressively pursue ways to mitigate or otherwise reduce stranded costs. The participants had various views on the different mitigation techniques available.
In considering the development and adoption of mitigation strategies, it is important to consider that a significant portion of stranded investment represents sunk costs or obligations which, by definition, cannot be mitigated. They can only be reallocated or offset by additional revenues. Accordingly, many mitigation proposals are merely targeted to shift the obligations between utility investors, consumers, taxpayers, wheeling customers or independent power producers. As a result, not all mitigation strategies being advanced are necessarily based on considerations of fairness or equity when the ultimate bearer of this financial responsibility is identified.
Mitigation can be achieved in two primary ways: cost reduction and containment efforts and revenue enhancement strategies. Mitigation can occur when affected utilities reduce and bring generation and operating costs in line with those of the market. This may be accomplished by reducing operating costs (both labor and non-labor) through productivity and efficiency gains, and by repowering or retrofitting plants and replacing inefficient generating units and equipment as well as improvements that facilitate fuel switching. Another mitigation tool available with significant cost reduction potential is the renegotiation or buy-out of above market, or otherwise uneconomic, fuel, transportation, or purchased power contracts.
Stranded cost mitigation may also occur when affected utilities are able to generate additional sources of revenue. Such efforts may include the development of new energy sales opportunities at prices above the respective utility's actual variable fuel and O&M costs, the sale of existing excess utility-owned capacity and purchased capacity rights, and the sale of emission (SO2 and NOx) credits. It is believed by Staff that utilities with substantial transmission capacity will find marketing to be a more effective strategy than will utilities without sufficient interconnection possibilities. It should be noted that there exists substantial disagreement between the utilities and other members of the Subcommittee with respect to the extent to which revenues from non-utility activities of the companies or their affiliates may be considered as sources of funds for mitigating stranded costs. The utilities do not believe non-utility revenues should be considered as available for mitigating stranded costs, while other parties believe such was intended by the language appearing in R14-2-1607.A. For example, TEP believes that profits from activities that are unrelated to the provision of electricity in Arizona, that do not require the use of assets that were required to serve electric customers in the State, and that are at risk to the utility's shareholders (but not ratepayers) should not be considered as a source of funds to offset stranded costs. Energy Strategies, on the other hand, feels that mitigation measures may include any activity that can reasonably be expected to reduce stranded costs. If the retail access environment provides an Affected Utility with the opportunity to provide new or expanded services, such as home security services, they believe that any net revenues derived therefrom should be an offset to stranded costs.
A third way that stranded costs may be mitigated is through the accelerated depreciation of generation assets or the accelerated amortization of regulatory assets. Unless, however, the accelerated expense recognition is accompanied by commensurate cost recovery, this mitigation is merely a transfer of wealth from utility investors to consumers. One way for this technique to achieve true mitigation is for it to be accomplished via some type of existing rate freeze or negotiated earnings sharing agreement between the respective utility and its regulators.
Another hybrid approach intended to "mitigate" stranded generation costs can be seen in accounting gimmickry proposed by several large utilities attempting to offset "overvalued" net generation assets with existing investments in transmission assets. Implicit in such proposals is an assertion that the companies' transmission assets are grossly undervalued relative to their current replacement costs. Such under-valuation arguably may be attributed to difficulties in replacing transmission facilities because of: growing environmental and health concerns, problems associated with acquiring new rights-of-way, and decreased availability of land. By offsetting over-valued generation with undervalued transmission, a mitigating effect was said to occur. In its proposal to the Michigan Public Service Commission, Consumers Power requested approval for the simultaneous creation of an additional $635 million of transmission assets (based on a study of reconstruction costs), and reduction of a like amount of the Company's embedded investment in generation assets. Somewhat similar proposals were also submitted by Southern Cal Edison and South Carolina Gas & Electric to their respective state regulators. Although the Michigan PSC did permit Consumers to do some recasting of book depreciation provisions between generation and transmission assets, this offsetting technique has not been widely accepted by regulators, either Federal or state, as a mitigation strategy.
Among the positions taken by Subcommittee participants with respect to the mitigation of stranded costs was that of Salt River Project who believes any such consideration must recognize efforts already taken by affected utilities. Representatives of the large industrial consumers opined that utilities seeking to recover stranded costs should be required to file a mitigation plan outlining their program. AEPCO expressed concerns that because Arizona cooperatives are also regulated by the Rural Utilities Service and operate under extensive Federal rules, their flexibility is limited.
Staff believes that it is not unreasonable to require an affected utility to take appropriate and prudent measures to mitigate stranded costs. However, because the circumstances of what constitutes reasonable and prudent mitigation efforts can be expected to vary widely between companies, a generic approach for analysis should be avoided. Mitigation efforts should be evaluated on a case-by-case basis. Moreover, it is important to note that mitigation efforts themselves may generate additional strandable costs. Accordingly, Staff recommends that the Rules be modified with respect to stranded cost mitigation only to the extent that they will permit each Affected Utility to independently demonstrate that their mitigation efforts were reasonable and cost-beneficial, based on all relevant facts and circumstances. Moreover, Staff recommends that amounts prudently spent in connection with mitigation be properly considered as a recoverable stranded cost.
The principal objective of the Calculation Methodology Subcommittee of the Stranded Cost Working Group was to evaluate and respond to the Retail Electric Competition Rules as they presently exist, relative to possible stranded cost calculation methodologies. In their present form, the Rules contain no specific guidance with respect to the manner in which stranded costs should be quantified; however, included among the factors for the Working Group to consider in developing our recommendations is the ease of the calculation (R14-2-1607.D.9).
It was agreed by the participants that an acceptable calculation methodology had to have the following characteristics:

Stranded costs will vary significantly between both utilities and those parties attempting to quantify stranded costs. This is attributable not only to actual or perceived differing facts and circumstances existing between the companies, but also to the assumptions made with respect to critical variables in the process. Assumptions having a significant effect on stranded cost quantifications include categories of includible costs, retail market share, the market clearing price for power, and the number of years implicit in the calculation process.
Two predominant approaches exist for quantifying stranded costs. Administrative approaches essentially represent negotiations between utilities and their regulators. They are an attempt to quantify stranded costs on the basis of estimates and other expectations of the future market prices and asset values. Market valuation methods use observed valuation of assets in a current market context, such as through auctions, asset sales or the divestiture of assets. In both cases, the market value (administratively determined or actual) is compared with regulated value to determine the level of stranded costs. Thus far, it is clear that no one broadly accepted and recognized methodology has emerged in the industry.
The Subcommittee participants advanced two administrative methodologies for quantifying stranded costs and two market-based approaches. The administrative methods are the Net Revenues Lost approach and Replacement Cost Valuation approach. The market valuation methods include Auction and Divestiture and Stock Market Valuation.
Net Revenues Lost
The "Net Revenues Lost" approach is a top-down quantification method that compares the expected future annual revenue requirements for the affected utility's generation business under traditional cost-based regulation with the annual revenues expected to be recovered in a competitive generation market with prices based on marginal cost. It recognizes that utilities that made multiple investment decisions under the traditional regulatory paradigm expected a revenue stream from customers to cover the cost of such investments over their useful lives. Under this scenario, stranded cost is measured as the net present value of the annual differences between the expected revenues under a continuation of regulation and those likely to be received after the introduction of retail competition. It is the manner by which the FERC in its Order No. 888 has directed companies subject to its jurisdiction to quantify wholesale stranded costs.
Within the Calculation Methodology Subcommittee the principal advocates of this approach were the investor-owned utilities, SRP, and AEPCO. The chief opponents were the independent power producers and consumer representatives.
Among the principal advantages cited supporting the use of this approach are:

The major difficulty in applying the revenues-lost approach is that it is highly dependent on current estimates of the future market clearing price of power, market share, and assumptions about off-system sales over the calculation period. As more fully explained later in this report, the market clearing price is influenced by a number of difficult-to-predict factors.
Replacement Cost Valuation
A second administrative methodology that may be used to quantify stranded costs is that which intends to compare an estimate of the market value of generation assets with their actual recorded net book value. The key is to arrive at a fair and reasonable estimate or appraisal of the fair market value. Among those parties advocating this calculation method were industrial consumers, the Public Interest Coalition on Energy, and the Land and Water Fund of the Rockies.
One such approach advanced in the Subcommittee was "Replacement Cost Valuation." Under this methodology, stranded cost is computed on a bottom-up, asset-by-asset basis, as the difference between the reported net book value of generation assets and their current replacement value (a proxy for market value) based on the most cost-effective technology available in the market, a gas-fired combined cycle combustion turbine. The current market value of regulatory assets would be presumed to be zero.
This approach produces a direct measurement of asset values at a single point in time, as compared with the annual calculations required under the revenues-lost method. This was the approach used by the California utilities in their filings for estimated 1998 transition costs. As with any of the four methods discussed herein, there are both advantages and disadvantages to cite. The perceived advantages include:

Auction and Divestiture
One of two market valuation methods is the "Auction and Divestiture" approach advanced by Citizens Utilities. The basic procedure would have the utilities actually submit their assets for bidding and sale in an independent auction. Stranded costs would then be measured as the difference between sales proceeds and reported net book values.
A key result will be that successful bidders bear all risks of forecast errors. This method has been used in other states such as Massachusetts, Vermont and at least to a certain extent in California. Recently, the New England Electric System reached an agreement to sell 18 power plants while Pacific Gas & Electric announced an upcoming auction of three of its fossil generating plants. It must be noted, however, that such action was not only to address stranded costs, but in some instances to also mitigate market power in generation. Under the California restructuring plan, PG&E and Southern Cal Edison are required to sell enough of their fossil-based power plants to ensure they compete fairly with other power suppliers in the State without having an edge in the generation market.
The advantages cited by those advocating this forced sale of assets include:

The reasons given by parties for opposing auctions and divestitures are many, including:

Stock Market Valuation
The other market-based valuation method considered by the Calculation Methodology Subcommittee was offered by the Goldwater Institute. Using the "Stock Market Valuation" approach to quantify stranded costs, utilities would be required to split their common stock into two new classes. Each existing common share would be exchanged for one share of Class A Stock and one share of Class B stock. The traditional stockholder benefits and rights would continue for the Class A shares. The Class B shares would give holders sole claim against any stranded costs to be recovered by the respective utility. After some appropriate predetermined stabilization period (i.e. six months), stranded costs for the company would be computed as follows:

Net Book Value of the Company
Average Market Value of Class A Stock
= Measured Stranded Costs

The party advocating this methodology suggested that, prior to the stock split, it be established that the actual stranded cost payments to be made to Class B shareholders would be something less than a full 100% of the above amount in order to encourage the mitigation of stranded costs, and to remove any incentives for the possible "exaggeration of stranded costs through lowering the value of the stock prior to the stranded settlement determined under this formula."

At the voting meeting of the Working Group, the four methods were presented to the participants to ascertain the extent to which any consensus may exist. The eighteen voting parties present cast their ballots in the following manner:

Net Revenues Lost

9 votes

Replacement Cost Valuation

7 votes

Auction and Divestiture-

1 vote

Stock Market Valuation-

1 vote

Based on the foregoing, according to the agreed upon criteria previously described, there is no clear consensus among the members of the Working Group as to the recommended method for Affected Utilities to use in computing their stranded costs. It is clear, however, there is a strong preference (i.e. sixteen of the eighteen votes cast supported one of the two administrative methods) by the participants for use of an administrative approach.
It is Staff's belief that, notwithstanding the lack of a clear consensus, the preferred method for computing stranded costs, and that which we recommend for the Commission to incorporate into the Rules, is the Net Revenues Lost method. While it did not receive a super majority, it was the method receiving the greatest support of those voting members present. No method is without disadvantages or probable significant controversy. It is, however, a method that has been adopted by the FERC and other states, and is one which most closely mirrors the ratemaking process with which all parties involved in traditional utility regulation in this State are familiar.
There are two time periods warranting consideration in connection with stranded costs. The first is the period over which stranded costs are computed when using administrative approaches. The second is that over which stranded costs may be recovered. The former will be addressed here, while the latter is considered later herein.
The time period over which stranded costs are computed will affect their overall quantification. With respect to wholesale stranded costs, the FERC applied a reasonable expectation standard in determining whether a utility reasonably incurred costs on behalf of departing customers. In arriving at the exit fee to be charged to departing customers, the difference between average annual revenues over the three years prior to the customer's departure and either the utility's estimate of revenues it can receive by selling the released capacity and energy, or the average annual cost to the customer of replacement capacity and energy under commitments with new suppliers, is multiplied by the number of years the utility could have reasonably expected to continue to serve the departing generation customer. Such provision is applicable to wholesale power contracts executed before July 11, 1994, that do not contain specific exit fees or other stranded cost provisions. For contracts executed after that date, stranded costs are recoverable only if they are provided for explicitly. This reflects the FERC position that, under the former, there was a reasonable expectation of the utility continuing to serve the customer beyond the current contract term, while the latter reflects the position that FERC effectively put companies on notice of fundamental changes in the industry with its initial stranded cost rulemaking proposal in 1994.
Reasonable expectation, in Staff's opinion, is also relevant in quantifying retail stranded costs. The focus, however, should not be on individual customers, but the entire retail load. In determining the appropriate time period over which such computations should be made, a principal consideration is the fact that, under the traditional obligation to serve, utilities incurred significant obligations on behalf of their customers. Using very long planning horizons, companies undertook construction programs to assure there was sufficient and reliable capacity over the long term. These costs were incurred by the respective utilities to fulfill their retail franchise obligations to serve customers directly under the promises that competing entities would not provide direct retail service, and that there would be a fair opportunity to recover the prudent investments that had been made. Under traditional ratemaking, the costs of long-term investments were spread over their estimated useful service lives, with the intent of properly synchronizing cost recovery with ratepayer benefit. Under this traditional paradigm, there was a reasonable expectation that utilities would be given a fair opportunity to recover such costs over the periods the assets would be used in connection with the provision of retail service. The accurate quantification of stranded costs must appropriately consider the expected remaining cost recovery periods associated with such assets that were anticipated and reflected in the traditional ratemaking process. Imposing some limit on the period for quantifying stranded costs would not only deny the Affected Utilities a reasonable opportunity for full cost recovery, but would also deprive ratepayers of the potential benefits from recognizing the declining net rate base investments occurring over time. If ratepayers are required to pay these costs, they should receive the benefit of lower costs as the asset becomes more fully depreciated and its fixed costs are lower. For the same reasons that stranded cost recovery is deemed appropriate, Staff believes that recognizing the full expected cost recovery period is also appropriate when quantifying stranded costs. That would mean reflecting the remaining estimated service lives implicit in currently approved book depreciation rates for generation assets, the remaining contract periods under existing purchased power agreements, and the remaining scheduled amortization periods for all regulatory assets.
The period over which stranded costs should be computed was not discussed in any great detail in the Calculation Methodology Subcommittee, nor was it voted upon by the Working Group. Accordingly, no consensus with respect to this issue has been established. Staff recommends that the Rules be expanded to clarify that, in connection with the use of administrative methods to quantify stranded costs, the expected remaining cost recovery periods implicit in current service rates, be considered.
The most critical variable in attempting to quantify stranded costs is that of the expected market clearing price of power over the calculation horizon. It is implicit in most stranded cost calculation methodologies. Estimates of the market price are necessary for projecting future annual revenues under the Net Revenues Lost approach. Moreover, if one may assume that a prudent investor factors future revenue streams into the process of deciding upon the extent to which funds are to be committed, then estimates of the market clearing price for power may reasonably be assumed as being implicit in the bids that would be offered in connection with the Auction and Divestiture approach.
There are significant risks in estimating the market price for power. If the estimates are too high, the quantification of stranded costs will be understated. Conversely, if the estimates are too low, then the quantification will be overstated. The party ultimately bearing the risk of such estimates will largely be dependent upon the calculation method selected and whether there will be opportunities for subsequent revisions to the estimates.
Conceptually, in a deregulated electric industry, the market clearing price will approach long-run marginal cost. Attempting to forecast such prices is a most difficult undertaking. Among the factors affecting the market price are: customer demand, market structure, generation and transmission capacity availability, generation fuel mix and costs, business decisions made by competing independent generators, interest rates and inflation, developments in technology, and new laws and regulations. Moreover, a clear definition of what constitutes the relevant market has yet to be decided. Any current estimate will be speculative at best.
Other states considering retail competition have considered a variety of ways to establish the market price for power for purposes of quantifying stranded costs. In California, for example, the utilities will use a market rate of 2.4 cents/kilowatt-hour to estimate transition costs in 1998. It represents estimated short-run avoided costs for the year, and will be trued-up at a later date. Ultimately, the California Power Exchange price will be used once that market is established.
In Michigan, the stranded cost recovery plan to be used by Detroit Edison is based on a 2.5 cents/kilowatt-hour market clearing price for 1997, based on a regional cost analysis using data from the Michigan Electric Coordinated System. The Michigan PSC requires such estimates to be trued-up annually.
Several members of the Calculation Methodology Subcommittee had opinions as to how the market clearing price for power should be determined for purposes of quantifying stranded costs. Energy Strategies believes that, for the short term, market price should be established by use of an index of retail electricity prices in markets (including California) open to the Affected Utility. For the long term, it should be based on the long-term replacement cost of generating capacity and forecasts of future fuel and operating costs. The Land and Water fund urges caution in using any single price at a given time as representing the "market." AEPCO mentioned the possibility of using a published index (i.e. Dow Jones Palo Verde electricity index) to define a market clearing price. However, they caution against use of such an index since during the transition to competition, as some present indices may reflect unreasonably low current prices of new participants trying to establish a foothold in the market. As a starting point, they suggest using an average base, computed by summing all electric revenues for capacity and energy annually for the State of Arizona and dividing that number by kilowatt-hours sold during the same time frame. Fort Huachuca opines that the market clearing price should reflect actual market transactions. If feasible, an Arizona power flow/price model should be developed to assist in the forecasting process. Staff would urge caution in the use of today's wholesale power market prices as being reflective of future prices. Distortions in the market have created pricing trends that are likely unsustainable in the long run.
There was no consensus established within the Calculation Methodology Subcommittee as to the most appropriate way to measure or project the market price for power, nor was any vote on this issue taken by the Working Group. Staff is of the opinion that the parties should continue to study this matter. For purposes of the required stranded cost filings to be made by the Affected Utilities, they should bear a strong burden of proof as to the reasonableness of whatever estimation method they may incorporate into their respective applications. Such burden of proof should be tempered by the extent to which there will be an opportunity for subsequent, periodic true-up. As retail competition becomes firmly established in Arizona, a standard measure of market price that can be used by all Affected Utilities in quantifying stranded costs may be adopted.
As noted previously, there is considerable uncertainty in attempting to quantify stranded costs. Not only is the estimated market price of power critical to the process, but other factors may affect the outcome as well. These include output supplied, success of mitigation efforts undertaken, and length of the calculation period. As a result of such uncertainty, the quantification of stranded costs is subject to a wide range of outcomes. This is particularly true with respect to the use of administrative calculation approaches where the Affected Utility retains ownership of the stranded assets. A key question is whether it is reasonable to lock utility customers or investors into a single up front forecast of stranded costs.
The obvious solution to such concerns is the use of some type of periodic revisiting of the stranded cost calculations. An ongoing approach reduces the risks of estimation. Moreover, where such factors as market price indices, production profiles, and avoidable benchmark values are reconsidered, the result is a fairer, more accurate stranded cost recovery process. To the extent that the use of some type of true-up mechanism is agreed upon, the next questions to ponder are the frequency of the revisiting and the components of the calculation subject to updating.
The positions of the Calculation Methodology Subcommittee were varied. AEPCO, APS, Fort Huachuca, TEP, and SRP supported a true-up in one form or another, while the Arizona Consumers Council felt a true-up could "skew the numbers," and that it was important for all parties to know in advance what their obligation would be so they could adequately plan for retail competition. For those parties recommending auctioning or divesting stranded generation assets, this inquiry was moot.
As for the frequency of such an undertaking, AEPCO felt biennial revisits would suffice, while SRP believed annual true-ups would be more appropriate.
The opinions on the factors to be considered in a periodic update were also varied. AEPCO believes that, in addition to changes in the market price of power, other adjustments might include depreciation lives or amortization periods, the effect of changes in maintenance practices, and other cost savings. They also believe that over- or under-recoveries should be subject to prospective inclusion in recomputed stranded cost charges. APS recommends that adjustments to stranded cost estimates be prospective and only reflect material changes in assumptions. It is their opinion that dollar-for-dollar true-ups would take away the incentive to improve. This is counter to the position of Fort Huachuca who recommends that all valuation factors, regardless of method used, should be subject to change at the time of true-ups. SRP feels that true-ups should focus on three areas: 1) adjusting forecasted sales to actual, 2) adjusting forecasted market price to actual, and 3) adjusting costs downward only.
The subject of periodic true-ups to the stranded cost calculations was presented to the Working Group for consideration and voting to establish whether any consensus of position exists among the participants. Specifically, two issues were put to a vote. First, the voting members were asked: "Should there be a periodic true-up of quantified stranded costs?" The response included seven in favor, five opposed, with six abstentions. While there was a simple majority, under the agreed upon threshold, there was no consensus. The second issue placed before the voting members was "If there is to be a periodic true-up, at what interval shall that occur?" The response was quite mixed:

One year

1 vote

Two Years

2 votes


6 votes


9 votes

Clearly there exists no widespread agreement within the Working Group as to whether there should be any revisiting of the stranded cost calculations once made and accepted by the Commission.
Staff strongly supports the concept of a periodic true-up as being necessary to assure that electric restructuring in Arizona is carried out in a manner that protects the public interest. Such a revisiting does not have to guarantee a dollar-for-dollar recovery, but at a minimum, should enable prospective adjustments of the stranded cost charge to reflect major uncontrollable variables, particularly the market clearing price for power. We believe that a true-up mechanism will guarantee that any unanticipated variances are corrected on a timely basis and that the stranded cost charge to be paid by consumers is equitable. Rule R14-2-1607.L, which states that the Commission may order regular revisions to stranded cost estimates, should be clarified to provide for annual revisiting of the stranded cost calculations.
Once stranded costs have been properly computed, the next step before developing a recovery mechanism and charge is to establish the manner by which such costs are to be allocated jurisdictionally and between customer classes. The jurisdictional allocation is necessary to properly segregate the Affected Utility's stranded costs between its wholesale business activities subject to FERC regulation, and its retail business subject to jurisdiction by the Arizona Corporation Commission and regulators in any other state in which the company operates. Once the Arizona retail portion is known, it is then necessary to properly and equitably distribute the costs between the various customer classes such as residential, commercial, and industrial.
The principal concern with respect to the cost allocation issue is that there be no inappropriate cost shifting between jurisdictions or customer groups. The method used must be fair and reasonable. It is noted, however, that over time allocation ratios will change as the underlying embedded costs and customer composition and usage patterns change. Such changes may be included within the scope of any true-up mechanism that might be adopted by the Commission in connection with stranded cost calculation and recovery.
Of the various matters addressed by the Working Group and its subcommittees, there was greater unity on this issue than any other. The Recovery Mechanism Subcommittee made the following recommendation to the Working Group: 

Stranded costs should be allocated to jurisdictions and classes in a manner consistent with the specific company's current rate treatment of the stranded asset in order to effect a recovery of stranded costs that is in substantially the same proportion as the recovery of similar costs from customers or customer classes under current rates. (For example, stranded generation assets should be allocated using the demand allocation method used for production plant.) Updated rate design to correct flaws in current design would be acceptable.

At its voting meeting the Working Group specifically considered the above recommendation as written. It received an overwhelming majority of nineteen of the twenty voting members present. Accordingly, Staff recommends that the Commission incorporate into the Rules a requirement that stranded costs be allocated jurisdictionally and between customer classes in the manner described above.
In establishing an appropriate mechanism for the recovery of stranded costs, there are a number of key considerations. These include the type of charge to be made, the parties to whom it will be assessed, and the time period over which it will be levied.
In addressing this issue, the participants in the Recovery Mechanism Subcommittee of the Working Group agreed that the stranded cost recovery mechanism should:

Stranded cost recovery mechanisms fall into two principal categories: direct customer assignment and global. The direct customer assignment approach calculates the level of stranded costs directly assignable to each customer leaving the system. This is based on the principle of cost causation and is the method adopted by the FERC for recovery of wholesale stranded costs. At the wholesale level it is feasible to effectively administer this method because of the relatively small number of contracts involved. A global approach involves some type of across-the-board charge or a general tax, based on the concept that electric restructuring will bring overall benefits to society in general. In other words, all consumers will ultimately benefit. This theory is consistent with the manner in which stranded costs were spread in the deregulation of the gas pipeline industry, and the way in which the interstate portion of the costs of non-traffic sensitive plant was assigned when the interexchange business segment of the telephone industry was deregulated. It is also implicit in the current property tax mechanisms in most states whereby some portion of all citizens' tax payments support the public schools, whether or not the taxpayers actually have children attending school.
The Rules are silent with respect to any specific recovery mechanism. Rule R14-2-1607.H permits an Affected Utility to request Commission approval of "distribution charges or other means of recovering unmitigated stranded costs from customers who reduce or terminate service from the Affected Utility as a direct result of competition.." Rule R14-2-1607.I provides that "The Commission shall...determine for each Affected Utility....appropriate Stranded Cost recovery mechanisms..." Finally, Rule R14-2-1607.J states "Stranded Cost may only be recovered from customer purchases made in the competitive market using the provisions of this Article".
The Subcommittee considered three mechanisms for recovering stranded costs: a variable charge based on kW/kWh usage, a fixed fee (including but not limited to, an exit fee) independent of consumption, and an access fee levied on competitive suppliers.
Many of the participants preferred the first alternative. TEP believes a wires charge applied to all customers on a per kWh basis, based on the last three years of consumption for a particular customer class, is consistent with the objectives. APS feels the charge should be spread over as wide a base as possible and should be based on a $/kW or cents/kWh, or a combination thereof, depending on the customer class. SRP also stated a preference for a non-bypassable kW/kWh usage charge, but with no exit fees. Fort Huachuca took a similar position, but recommends an exit fee option for customers with demands exceeding one MW.
Several of the consumer groups also stated a preference for a wires charge, but consistent with the Rules, they believe it should only apply to those parties choosing to enter the competitive market. They also recommend that some of the stranded costs be borne by the utilities' investors and new entrants into the power generation market.
PG&E Energy Services stated their opposition to stranded costs being assessed to new competitive power providers by asserting it would create barriers to market entry. That position was echoed by Energy Strategies who also stated that such assessment is inappropriate because there is no cost causation justifying such treatment. Staff notes that there is some historical basis for such far-reaching assignment of costs between customers and new market participants as competition is introduced to a portion of a traditionally regulated industry. As the long distance segment of the telephone business was deregulated, the interstate portion of the costs of the non-traffic sensitive local loop was assigned to both the end users (as a subscriber line charge) and competing long distance carriers (as a carrier access line charge). It is noted, however, over time, the obligation of the competing carriers has been reduced with a larger share being assumed by the end user customers.
To summarize the parties' positions, the principal advantages cited for a non-bypassable across-the-board kW/kWh charge to all consumers were:

The principal disadvantages are:

Support for a non-usage based, fixed fee for stranded cost recovery was provided by Citizens Utilities and the Goldwater Institute. Both believe that a usage based recovery mechanism does not comport with sound economic principles and may result in future adverse effects on consumption, thereby exacerbating the stranded cost problem. Notwithstanding its stated preference, TEP indicated it would not oppose a fixed charge recovery mechanism, such as a meters charge, as long as it was established consistent with customer class cost characteristics and usage patterns. The major factors supporting a fixed fee cited by the parties include:

The principal disadvantages cited include:

Any determination of an appropriate stranded cost recovery mechanism should also consider the effect of and on new customers, departing customers, self-generating customers, interruptible customers, special contract customers, and municipalization.
With respect to new customers, there was general agreement within the Subcommittee that they should pick up their fair share of stranded costs in the same manner as if they had been served all along. Otherwise, a gross inequity may occur, or there may be an incentive created for customers to attempt to bypass stranded cost obligations by trying to appear as though they are "new" customers.
The key consideration with respect to departing customers is whether they are truly leaving the system. Consumers discontinuing service from their host utility should not be subject to paying an exit fee if they are truly relocating from the service territory. Not only may attempting to levy an exit fee be impractical in such circumstances, it may be of questionable legality. Moreover, to a certain extent, the departures will be offset by the addition of new customers of the utility who will assume their respective stranded cost burdens, thus adding some degree of balance or symmetry to the process.
As for those customers that depart their host utility to self-generate, several Subcommittee participants believe there should be a continuation of the stranded cost obligation. TEP believes that new self-generators should not be immune from bearing stranded costs, particularly those that have historically been customers of the host utility and for whom the facilities were built. AEPCO takes a similar position, as do the representatives of the various residential and low-income consumer groups. Several parties commented that stranded costs should be a part of the charge for stand-by or back-up service requested by self-generators. Calpine Energy is of the opinion that, while new self-generators may be subject to the stranded cost obligation, those self-generating before the issuance of the Commission's Rules should be exempt.
Interruptible customers create an interesting stranded cost implication. By definition, interruptible service applies to energy made available (i.e. freed-up) at times of high system demand under agreements (typically with large industrial customers) which permit the curtailment of service by a supplier in return for lower service rates. The interruptible rates are usually developed to reflect the full cost of service, less some credit representing the higher peaking capacity costs avoided when service to the respective customer is suspended. Clearly, the stranded cost implications for such customers are different from those of full service, firm customers. APS feels that interruptible customers should not bear any capacity-related stranded costs, but should be allocated energy-related stranded costs. SRP recognized a distinction between varying types of interruptible service customers. They believe a review of the Affected Utility's planning process is critical to a determination of the extent to which interruptible customers should be charged for stranded costs.
Whether to charge special contract customers for any stranded costs was also discussed by the Subcommittee. The Fort Huachuca representative opined that special contract customers, as a class, should be assigned a portion of the overall stranded cost estimate, but whether they are actually recoverable should be an item for negotiation between the customer and the utility. According to the Fort, the general body of ratepayers should not bear the stranded cost obligation of special contract customers.
Municipalization, where a current retail customer becomes a wholesale customer, also received some consideration by the Recovery Method Subcommittee. Sham municipalizations to avoid wholesale stranded costs were a major concern of the FERC and specific provisions with respect thereto were incorporated in Order No. 888. There is some feeling that this Commission should take similar precautions to minimize the possibility of such tactics being undertaken to evade responsibility for stranded costs. Staff believes that whatever recovery mechanism may ultimately be decided upon by this Commission, it should not create incentives for self-generation or municipalization by creating a loophole through which customers can avoid their fair share of stranded costs.
After considering the various issues surrounding recovery methods and the parties that should ultimately pay stranded cost charges, the Subcommittee was unable to establish a clear preference. In its report to the Working Group, it recommended three options concerning stranded cost payment responsibilities:

Option A:

The second sentence of Section R14-2-1607(J) of the Competition Rules should remain in effect, but this Section should be amended to allow all customers to pay stranded costs, including customers who remain on standard offer rates. However, the charge to standard offer customers should account for contributions that are already being made toward stranded costs.

Option B:

The second sentence of Section R14-2-1607(J) of the Competition Rules should remain in effect, but this Section should be amended to allow all customers to pay stranded costs, including customers who remain on standard offer rates. However, the charge to standard offer customers should account for contributions that are already being made toward stranded costs and should not cause customers' prices to increase.

Option C:

No change should be made to the rules regarding who should pay for stranded costs.

In addition, the Subcommittee recommended that the recovery mechanism should be either a non-bypassable kW/kWh surcharge with the option of an exit fee, or a fixed fee, to be determined on a utility by utility basis.
The length of the recovery period is primarily a function of the size of the stranded investment to be recovered and the extent to which the parties are interested in concluding the transition period as rapidly as possible. The shorter the recovery period, the greater the stranded cost charge and likelihood it will be recovered. The longer the recovery period, the smaller the periodic charge, but the greater the uncertainty and delay until retail competition is fully achieved. Most of the Subcommittee members recommended relatively short recovery periods. Citizens Utilities calls for a recovery period as short as possible. TEP initially recommended a period of 4 or 5 years to the extent feasible, but later expressed concern that this may put too much pressure on total prices to consumers. AEPCO believes the period should be company-specific, based on relevant circumstances. APS suggests a period of 4 to7 years, with the former mirroring the current competition phase-in schedule and the latter providing a smaller surcharge burden on consumers. A similar recommendation was made by the representative of Fort Huachuca. SRP suggested a period of 5 to 7 years, but said that extended recovery may be warranted for certain costs such as nuclear decommissioning. The residential and low-income consumer representatives felt the recovery period should be as long as possible, while the major industrial customers opined that the recovery period for stranded cost recovery should be as short as practical in order to expedite the transition and to minimize market distortions. Calpine Energy recommended a period of five years to coincide with programs in other states.
None of the above recommended recovery periods are out of line with what has been decided in other states. For example, California has established a five-year recovery period for all stranded costs, except nuclear decommissioning. Michigan has established a ten-year recovery period, while stranded costs in Oklahoma are to be recovered over a 3 to 7 year period.
In deciding upon an appropriate recovery period, it must be recognized that the recovery of stranded costs relating to very long-lived assets over a shorter period produces a greater annual cost. This may be seen in a comparison of the monthly payments on an 8%, $100,000 home mortgage over different loan periods. For a thirty-year loan, the monthly payment is $734, but for a fifteen-year loan, the payment is $956.
This creates a particular problem with the current restriction in the Rules denying stranded cost recovery from parties not taking competitive sources of power. It is mathematically impossible to not increase rates in the aggregate and have full stranded cost recovery, when the recovery period is shorter than the average remaining service lives/amortization terms of the underlying assets, and no opportunity exists to assign stranded costs to parties other than those taking competitive power. Staff believes there needs to be a change in the Rules in this respect.
Another factor to consider in connection with the determination of a proper recovery period is the fact that nuclear decommissioning costs have been removed from stranded costs and will be included as a component of the System Benefits charge. Given the magnitude of projected decommissioning costs, combined with the fact that the Palo Verde Units have nearly twenty-eight years remaining of their projected forty-year lives, it is likely that the period for recovering system benefits will necessarily have to be quite long.
The Subcommittee's recommendation to the Working Group included two options with respect to the recovery period. Under Option A, the time period would depend on the level of stranded costs and be as short as possible, perhaps 3 to 7 years. The period would be fixed prior to the implementation of retail competition, and no stranded cost recovery would be allowed after the expiration of that period. Under Option B, the time period for recovery would balance the goals of minimizing the impact on rates, the shortest recovery period practicable, and a reasonable opportunity for utilities to recover unmitigated stranded costs.
At the Working Group voting meeting, several matters relating to stranded cost recovery were brought before the attendees. One dealt with selecting an actual recovery period, with alternatives of three years, five years, seven years, ten years, or some other more appropriate period being available. The Group declined to vote on this issue, stating their desire to know the magnitude of stranded costs before stating a recovery period preference. By a vote of 12 ayes, 4 nays and 2 abstentions, the Group established a consensus that the Commission's Rule limiting stranded cost recovery to just those parties taking competitive power should be changed. Another matter voted upon was "If stranded costs are to be recovered from standard offer customers, should they be recovered at the same rate as that being charged to customers taking competitive power. The result was 10 ayes, 0 nays, and 8 abstentions. According to the agreed upon voting procedure, this did not constitute consensus on the issue.
The voting members were also asked to consider "How should stranded costs be recovered from ratepayers?". None preferred solely an energy charge, four voted for a fixed charge, none supported an exit fee, and fifteen supported a charge with both an energy and/or demand component. There was one abstention.
With respect to ratepayer payment options, the participants of the Working Group were asked whether customers should have the opportunity to make a lump sum payment in lieu of an on-going stranded cost charge. Nineteen voted for the proposal, while only one party voted against it. There is a clear consensus supporting this ratepayer option.
Finally, the voters were specifically asked to consider Option B of the three stranded cost payment responsibility proposals advanced by the Subcommittee that were previously described in this section of the report. The proposal received support from fourteen of the twenty voting members present, thereby establishing consensus under the voting procedures agreed upon.
With respect to all of the various matters voted upon, notwithstanding the decision to table the vote on a recovery period, Staff strongly believes that there must be some specificity in this regard incorporated into the Rules. We prefer a period of ten years, as reflecting a proper balance of all relevant factors. We do note that, given the magnitude of nuclear decommissioning liabilities, it is highly likely the Systems Benefits Charge will be assessed to consumers for at least that length of time. Staff further supports an amendment of the Rules to place some obligation on all power users (including new customers, self-generators, interruptible customers, and special contract customers) for the stranded costs of the Affected Utilities, but we would not oppose a distinction in charges between parties taking competitive power and those not, insofar as such difference reflects the fact that the parties not taking alternative source power are paying for stranded costs in rates, and differences reflecting the costs of serving interruptible customers. With respect to a recovery mechanism, Staff supports a charge that properly reflects the demand and energy characteristics of the underlying stranded costs, and would not oppose granting the ratepayers an option to settle their stranded costs obligation on a lump-sum basis.
Finally, the Rules are silent with respect to any constraints placed upon the Affected Utilities' use of the proceeds from stranded cost charges. This topic received little attention in the deliberations of the Working Group or its subcommittees. Staff believes that the Rules should contain some specific requirement that such proceeds be used to extinguish the utilities' existing obligations, whether financial, such as debt or equity securities, or operating, such as long-term fuel and purchased power contracts.
In addition to the foregoing, four other matters should be addressed herein. First, several of the parties recommended that utility investors should bear some responsibility for stranded costs through some type of sharing mechanism. The position paper filed by the Arizona Community Action Association, the Arizona Consumers Council, and Arizona Citizens Action states their desire that some portion of the stranded costs should be borne by utility investors. Energy Strategies, representing major industrial consumers, also recommend that stranded costs be split between customers and investors. None of the parties' position papers contained any substantive explanation or justification for requiring utility investors to assume any of the stranded costs.
While some absorption by the Affected Utilities' investors would undoubtedly reduce the stranded cost burden for consumers to ultimately bear, the Staff is unaware of any legal or regulatory basis for doing so. Presumably, the prudence of expenditures underlying existing service rates has already been established, and no justification for a revisiting of prudence or any other basis for assigning some or all of the stranded cost responsibility to investors was provided by any party. Moreover, nothing has been advanced by any party indicating that the introduction of retail competition has relieved the Commission of its traditional responsibility to provide the utilities under its jurisdiction a reasonable opportunity to recover its costs of providing service plus a fair return on prudently invested capital.
A second issue warranting some discussion herein is that of "asset securitization" as a tool to address stranded costs. Although there was only token discussion about this topic in the Working Group and subcommittees, it is something that is gaining national prominence and should, therefore, at least be acknowledged in this report to the Commission. In states such as California, Pennsylvania, Michigan, New Jersey, and Rhode Island a concept has been introduced whereby the state would create a new entity for the purpose of issuing tax exempt debt backed by a pledge of the expected revenues to be received by the electric utilities under their respective stranded cost recovery plans. In theory, the up front lump-sum proceeds from the bonds would be used by the utilities to reduce stranded costs and related obligations, with the debt service to be paid from stranded cost recovery revenues. In California, a portion of the proceeds will also be used to fund an immediate 10% rate reduction for residential and small business customers at the commencement of retail competition.
Those advocating this approach assert that it balances the interests of all stakeholders, is consistent with the traditional regulatory compact, and will facilitate the transition to competition. Since the bonds are likely to be favorably received by the rating agencies, the interest rates are expected to be less than the rates on the utilities' other borrowings, and by paying off some of the higher cost capital, the companies' overall cost of capital will be reduced. Parties opposing this concept argue that, since this is done on a one-time up front basis, there is substantial risk that stranded costs may be over recovered. They further allege that such a policy could have significant anti-competitive effects and, therefore, may violate anti-trust laws and undermine the competitive process by providing incumbent utilities an unfair advantage over their competitors. The method is also not without significant accounting and tax hurdles to overcome. Implicit in the plan is the assumption that the utilities will not be required to recognize the securitization bonds as liabilities on their balance sheets. Under new accounting standards recently issued by the Financial Accounting Standards Board, however, the companies may likely have to recognize the new bonds as their own. Moreover, there are key assumptions about the IRS treatment of the interest payments on the securitization bonds and the utilities' use of the proceeds. Although at the time of this writing the California utilities anticipate a favorable IRS response, any unfavorable rulings could derail the process. At this point, Staff is taking no position on the concept of securitization as a tool to address stranded costs, other than to inform the Commission that, to the extent they desire to investigate the matter further, we believe that such an inquiry should be jointly conducted with members of the legislature and other affected State agencies.
An additional matter warranting discussion in this section of the report is the request by some parties that, as part of this Working Group's activities, the Affected Utilities should be required to perform, and make available to their fellow participants, estimates of their retail stranded costs. For several reasons, Staff has not supported this request. First, the overriding objective of this Working Group is to develop recommendations for Rules covering the procedures to be used in connection with the quantification and recovery of stranded costs, not an actual quantification of stranded costs. As they presently exist, the Rules contemplate the Affected Utilities filing formal estimates of their stranded costs prior to the commencement of retail competition. Given the present schedule for that to occur on January 1, 1999, it is most obvious that such filings will likely be made in the near future. The actual estimates will be available at that time. Second, as may be obvious from reading this report, such an undertaking is highly complicated and based on a wide range of assumptions and methodologies for which no universal acceptance among the parties has yet been achieved. Changes in assumptions can affect the results by orders of magnitude. Given such uncertainty, it is highly likely that estimates prepared now will change significantly by the time the Companies' formal estimates are filed with the Commission. Substantial public confusion will most certainly occur if two sets of significantly different estimates for a given Affected Utility were published within a very short period of time. Third, much of the information upon which such calculations are based has become of competitive value. The utilities should not be forced to disclose such information publicly, any more than requiring the independent power producers to provide estimates of their market prices for the next ten years. Fourth, some parties allege that estimates of stranded costs must be known, in order to fairly assess the reasonableness of the stranded cost recovery plan. While Staff agrees that the magnitude of stranded costs can affect the amount of the customer charge, if the process for quantifying and recovering stranded costs is sound, then we believe the result of that process, by definition is sound. Finally, for those parties who believe they have a strong need to have some indication of the utilities' stranded costs, it should be noted that such entities as Fitch Investors' Services, Moody's, and Resource Data International, have published estimates for most investor-owned utilities.
A final issue is that of imposing a price cap. Several parties recommend that the Commission establish a Rule requiring some form of price cap. Although no one supplied any significant details of such a plan, the concept received overwhelming support from nineteen of the twenty parties voting on this issue at the last meeting of the Working Group. Price caps are an issue that has been addressed in other states. Some states, such as California, have been able to accomplish this by the use of the asset securitization bonds as previously described herein. No such undertaking has yet been planned by this Commission. Given the Commission's existing responsibility to permit the utilities a fair opportunity to recover their costs of providing regulated service, and lack of authority to set prices for services that are no longer regulated, it is unclear how any unilateral action could take place whereby price caps are imposed on the Affected Utilities. Staff believes this may only occur through some mutual agreement to which the companies are a party, such as the existing rate agreements with APS and TEP.
Although stranded costs have very significant accounting, tax and finance implications, the Rules are relatively silent in this area. R14-2-1607.I.3 requires that the Commission shall consider the impact of stranded costs on the Affected Utilities' ability to meet debt obligations. Beyond that, there are no specific requirements. As a result, a special subcommittee to the Working Group was established to address such implications insofar as they relate to the issues and recommendations being developed by the Calculation Methodology and Recovery Mechanism Subcommittees. The Subcommittee identified several key issues in each of the three areas for consideration. Although the following recommendations were submitted by the Subcommittee to the Working Group, no specific consensus was established thereon.

The following is a discussion of the key topics addressed in the various issue areas.

The accounting issues identified and addressed by the Subcommittee included:

The Federal Power Act of 1935 provided the Federal Power Commission (predecessor to the FERC) authority over rates, service, and security issuances by entities providing interstate electric service. As part of its rate authority, the FPC issued its Uniform System of Accounts ("USOA") for use by electric utilities under its jurisdiction in maintaining their accounting and in their published financial statements. The accounting principles embedded in the USOA are generally comparable with Generally Accepted Accounting Principles.
The key accounting standard that must be addressed is Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, ("SFAS No. 71"), which defines a regulated entity and contains standards that must be complied with in preparing financial statements issued by pubic utilities. SFAS No. 71 applies to an enterprise that has regulated operations that meet all the following criteria:

Under SFAS No. 71, the most important difference between the accounting used by regulated entities and unregulated businesses is the ability of regulators to create assets ("Regulatory Assets") by deferring to future periods (and therefore recoverable in future rates) certain current costs which would otherwise be charged to expense under Generally Accepted Accounting Principles. With their legal authority to identify the types and amounts of costs to be recoverable in rates, regulators have traditionally been able to provide the necessary level of assurance through rate orders that such amounts deferred meet the criteria to properly be reflected as assets in published financial statements. The parties responsible for setting accounting standards have long recognized and accepted the distinction between accounting and reporting by utilities and other entities. Many of the stranded costs of the Affected Utilities are a direct result of the application of the FERC USOA and SFAS No. 71.
With the emergence of competition and deregulation in the utility industry, many of the utilities previously subject to SFAS No. 71 discovered that they no longer met the criteria stated for categorization as a "regulated enterprise". In response thereto, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 101, Accounting for Discontinuation of Application of SFAS No. 71. The thrust of the new standard is that, when an enterprise ceases to meet the criteria of SFAS No. 71, it must discontinue its application, and eliminate from its books of account and financial statements the effects of the actions by regulators that would not have been recorded by enterprises in general. Generally, that means writing off all regulatory assets and liabilities. For the Affected Utilities of Arizona that would mean having to immediately write-off (and charge to retained earnings) all generation-related regulatory assets, which currently represent a significant portion of stranded costs.
In 1995, an additional accounting standard having significant negative implications on stranded costs was issued. Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, addressed concerns that arose within the accounting profession and in the financial community, particularly with respect to reported assets of utilities, given the extent to which restructuring and deregulation was occurring in the industry. SFAS No. 121 lists certain events, (including a significant change in the regulatory climate in which a company operates), the occurrence of which requires the respective company to consider whether any of its assets may have become impaired. For this purpose, the carrying amount of the affected asset must be compared to the expected future undiscounted value of related net cash flows. If the recorded amount exceeds the projected cash flows, an impairment must be recognized and book value of the asset reduced to its fair market value (i.e. discounted net cash flows).
Any analysis of the accounting implications of stranded costs and their recovery must consider the requirements and potential implications of SFAS Nos. 71, 101, and 121.
Earlier this year, the Securities and Exchange Commission sent a letter to the three major investor-owned electric utilities in California: Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric, containing a message informing them that, with the establishment of deregulated generation scheduled for a date certain (January 1, 1998), the three companies may no longer meet the criteria for SFAS No.71 for the generation segment of their businesses. Specifically, the SEC Staff raised two concerns. First, the service rates to be used after the introduction of competition do not appear to be consistent with the traditional ratemaking process envisioned under SFAS No. 71. Second, there may not exist the degree of reasonable assurance of cost recovery required under SFAS No. 71.
The major impact on the three utilities of being forced to go off of SFAS No. 71 would be the requirement that they immediately write-off all generation-related regulatory assets, notwithstanding the legislated provisions for stranded cost recovery in that State. Then, to the extent that the generating assets are impaired, further write-offs would be required under SFAS No. 121. Essentially, all stranded costs would have to be charged to retained earnings.
The letters to the California companies initiated intensive discussions between the utilities, the SEC Staff, the Emerging Issues Task Force of the FASB, the AICPA Public Utility Subcommittee, and the Accounting Subcommittee of the NARUC. Among the critical issues discussed were:

Within the past couple of months, some resolution of these issues has been achieved. The Emerging Issues Task Force of the FASB has determined that the appropriate date to go off of SFAS No. 71 would be when a date certain for deregulation is firmly established. Moreover, with respect to whether the nature of an asset may change due to the characteristics of its ultimate cost recovery, it was tentatively agreed that could occur. This is a very significant point in connection with stranded cost recovery. Where stranded costs are to be fully recoverable and collected through a distribution charge, an existing stranded generation asset or generation-related regulatory asset that would otherwise have to be written off due to the discontinuance of SFAS No. 71, may continue to be carried on the books of the utility as a distribution-based regulatory asset.
Specific accounting guidance from the FERC with respect to the proper accounting for stranded costs or related revenues has been relatively sparse. The FERC requires utilities to recognize stranded cost revenues in the period in which the related costs are charged to expense. This is consistent with the traditional matching principle of accounting, and will prevent double recovery, cost shifting, and inappropriate financial reporting. The FERC also requires utilities to submit their proposed accounting for stranded costs and related revenues as part of their stranded cost rate filings.
Specifically addressing some of the parties' concerns, TEP feels that, because of its recent financial history and current equity position, the effect of any adverse accounting consequences could result in negative equity, which would be financially devastating for the Company. Other parties raised similar concerns about being required to discontinue using SFAS No. 71.
Staff strongly recommends that the Commission's Rules be completely clear with respect to stranded cost identification, quantification, and recovery, such that the potential for required write-offs is minimized. Moreover, the Affected Utilities' stranded cost filings anticipated under R14-2-1607.G should be required to include detailed descriptions of the companies' proposed accounting for stranded costs and related revenues.
The introduction of retail competition creates significant tax issues. These include not only the tax effects on the Affected Utilities, but also the effect on state and local governments. The Subcommittee identified seven potentially critical tax issues:

Of the seven issues identified above, the first two relate to the effect of income taxes in traditional public utility ratemaking. The next four relate primarily to the potential effect of retail competition on corporate income taxes, both Federal and State, that the Affected Utilities will have to pay. The final issue is one, the resolution of which is largely beyond the Commission's scope of authority. Nevertheless, the level of awareness of the public and affected governmental authorities can be raised. Only the latter received any significant attention in the meetings of the Subcommittee.

  1. Income Taxes in Ratemaking. To address the first two issues, it is first necessary to consider the effect of income taxes in traditional public utility ratemaking and financial reporting. As a major operating expense, income taxes are a significant component of the cost of providing service. They affect revenue requirements in two principal ways. First, they are an allowed operating expense comprised of three elements: current income taxes, deferred income taxes, and net investment tax credits. Second, the net accumulated benefits of accelerated tax depreciation and investment credits appear in utilities' financial statements as balance sheet reserves and may be used to reduce the net rate base to which the rate of return is applied in computing required operating income in ratemaking. It should be noted that alternative ratemaking options do exist with respect to the investment tax credits.

    Current income taxes represent the computed liability for a given rate case test year as though actual tax returns are prepared based on computed revenues and expenses. Deferred income taxes represent the computed tax effect of book-tax differences that balance out over time. The use of accelerated depreciation for tax purposes and straight-line depreciation for ratemaking and book purposes is the largest such difference experienced by utilities. The Investment Tax Credit permitted taxpayers a reduction in their income tax liabilities based on a percentage of amounts spent currently for certain classes of plant and equipment. Utilities account for such credits by deferring them on their balance sheets, and amortizing them as a reduction of income taxes over the lives of the assets that gave rise to the credits. Traditionally, the income tax category "net investment tax credit" represented the difference between the tax credits deferred in the current period and the current period amortization of credits deferred in prior years. Since the Tax Reform Act of 1986 terminated the Investment Tax Credit, this income tax expense category today generally reflects only the amortization of prior years' credits.
    Both accelerated depreciation and investment credits were intended by the Congress to enable corporate taxpayers to reduce their current federal tax liabilities and invest the tax savings in new plant and equipment, thereby creating new jobs and expanding the economy. Initially, there were no restrictions placed on utility regulators with respect to the treatment of accelerated depreciation or tax credits in ratemaking. As a result, most regulators "flowed through" these benefits directly to ratepayers in the form of lower service rates. Eventually, the Congress became alarmed that such ratemaking treatment not only defeated the purpose for which the benefits were initially created, but that it also significantly reduced the Federal tax receipts due to the reductions in utilities' gross revenues and taxable incomes. Accordingly, legislation was enacted which is now incorporated into the Internal Revenue Code and IRS regulations that severely restrict the options available to regulators.
    The concept of reflecting deferred income taxes and investment credits in ratemaking is labeled "normalization". One of the key directives governing the normalization of accelerated depreciation is the "consistency requirement" in Code Section 168 (i)(9)(B). This requires that a ratemaking authority use an estimate or projection of a regulated company's tax expense, depreciation expense, and balances of accumulated deferred income taxes that are all consistently determined with respect to each other and with respect to rate base. A similar consistency requirement exists for the Investment Tax Credit in Code Section 46 (f)(10). Basically, these serve to limit regulators' ability to consider in ratemaking the deferred tax and investment tax benefits associated with a particular asset or group of assets. To the extent all or a portion of the cost of an asset is temporarily or permanently excluded from ratemaking, an equivalent portion of the related tax benefits similarly may not be considered in developing revenue requirements under the consistency rules. During the past few years there have been numerous IRS Private Letter Rulings addressing utility phase-in plans, cost disallowances, and assets removed from the scope of regulation. In all instances, the IRS found that when any such capital adjustment is made to regulated rate base, a similar adjustment must be made to the related tax benefits. Although technically, Private Letter Rulings may not be cited as precedents, they are useful in showing the IRS position on certain issues. With respect to this matter, the IRS position has been totally consistent. Such information is relevant to this report in that, it is clear that the consistency standard must be properly considered in connection with the quantification and recovery of stranded costs. For example, to the extent that any portion of the cost of stranded generation assets for which an Affected Utility has taken accelerated depreciation and/or investment tax credit is not allowed to be recovered, there must be a corresponding adjustment to the related tax benefits.
    Staff recommends that the Rules be expanded to clearly indicate that all requirements of the Internal Revenue Code and IRS Regulations should be considered and properly complied with in connection with the quantification and recovery of stranded costs of the Affected Utilities.
  2. Corporate Taxes. The introduction of retail competition will affect the corporate income taxes of the Affected Utilities in several ways. First, any write-off of generating plant assets will have no immediate tax consequences unless it is accompanied by a physical abandonment of the asset. Under Section 165(a) of the Internal Revenue Code, an Affected Utility will be permitted a Federal tax deduction based on the unrecovered tax basis of the asset disposed of.
    Second, to the extent utilities actually sell generation assets (i.e. under the Auction and Divestiture Approach) any gains or losses will have income tax consequences. Gains typically will be taxed as ordinary income to the extent of accelerated depreciation taken, with the excess subject to capital gains treatment. This is known as "depreciation recapture". Losses generally will be available to offset other taxable income.
    Third, amending or severing fuel, transportation, or purchased power agreements (one of the stranded cost mitigation strategies previously identified) will create tax benefits. Costs incurred with canceling contractual arrangements are generally currently deductible. Costs of modifying existing contracts are generally ratably deductible over the term of the new arrangement.
    Fourth, if Affected Utilities experience reduced revenues and taxable income after the introduction of competition, their Federal and state tax liabilities will correspondingly decrease. To the extent they have available tax attributes, their value may be diminished.
    Finally, in addition to the income tax effects above, taxes other than income taxes will undoubtedly feel the impact of retail competition. Property taxes based on net book costs may decline if stranded costs have to be written off. Sales and gross receipts may decline where the price of electricity is reduced due to the effects of competition and the level of consumption is not increased by at least a corresponding percentage.
    When considering corporate taxation issues, it must be noted that several of the entities that will be participating in competitive power markets are not subject to income taxes. In its filed comments, AEPCO described its current exemption from income taxes under Section 512(c)(3) of the Internal Revenue Code, limiting revenue from non-members sources to 15% of total revenue. To the extent that limit is exceeded, the tax exemption could be in jeopardy. Resolution of tax issues associated with the introduction of retail competition must appropriately consider the effect on those entities currently not subject to income taxes.
    As stated, the Rules are silent with respect to income and other types of taxes. Staff recommends that the Commission consider incorporating additional language that assures changes in tax liabilities are properly treated in the quantification, mitigation and recovery of stranded costs of the Affected Utilities, such that no parties are unjustly enriched or unfairly detrimented.
  3. Effect of Retail Competition on State and Local Taxes. Of the various tax issues, this received the greatest scrutiny by the Subcommittee. State regulators and taxing authorities around the nation are beginning to realize that the introduction of retail electric competition has the potential to significantly adversely impact tax collections.
    Without changes, there will be potential tax revenue reductions and an unlevel playing field between utilities and non-utility competitors. Significant tax-related policy questions will have to be answered prior to the current January 1, 1999 date established by this Commission for the transition to full competition to begin.
    State and local governments have historically taxed utilities heavily and disproportinately. Utilities, on average, pay twice the amount of taxes as other businesses. This chiefly occurred over the years for political expedience. It is unlikely this can continue in a deregulated generation market. A competitive market cannot bear an inequitable assignment of the tax burden. Competition increases the incentive to reduce costs and customers will migrate to companies that don't have heavy tax burdens to recover in the price for their service. Tax authorities need to begin considering what changes are required to assure there is an equitable redistribution of the tax burden and what will enhance the chances for effective competition.
    Retail competition will affect taxpayers and tax authorities in several ways. Revenue based taxes will decrease due to lower prices and revenues lost when customers depart their host utility. Property taxes may decrease due to reductions in market value of generation assets, any write-offs associated with stranded costs, or premature plant abandonments. State income taxes will decrease due to profit declines, reflecting price reductions and sales lost to tax exempt or out-of-state producers.
    There are a number of responses available to State and local taxing authorities. One solution is to impose a tax on all energy consumption in the State, regardless of where produced or the entity source. Another is to change the manner in which utilities are taxed comparable to other businesses. Additional options include the imposition of a revenue tax on power marketers to level the playing field between in-state and out-of-state suppliers, or repealing tax exemptions enjoyed by only certain market participants.
    In addressing this issue, the Subcommittee was aware that any resolution was beyond the scope of the Commission's authority. The intent was to explore the issue and obtain information that could be disseminated for purposes of raising the level of awareness of potentially affected parties. Subsequent to the creation of this Subcommittee a special investigative committee has been created by the State Legislature to analyze the effect of retail competition on State and local taxes. Our concerns are now being addressed. Accordingly, no recommendations in connection with this matter are being made.

The subcommittee identified several key Finance issues that warrant consideration in connection with Electric Industry Restructuring:

Several financial issues raised by Staff received little discussion, including whether there was any evidence that investors had previously been compensated for stranded costs, what should be the applicable discount rate (i.e. authorized rate of return) to use for any financial studies prepared in connection with stranded cost quantification or recovery, and if the existence of asset specific financing (i.e. pollution control bonds) should be considered in stranded cost calculations.
The major concerns identified by the Affected Utilities in this area include the implications of forced asset sales and the ability to maintain the tax exempt status of debt securities. With respect to the former, to the extent the Affected Utilities are required to sell or otherwise divest their current stranded assets, it will necessitate their securing from the respective bond trustees releases of the assets from the liens of the mortgage indentures. This may be difficult and costly.
Utilities issuing mortgage bonds pledge their investments in utility assets as the underlying collateral. Typically, mortgage indentures include plant-to-bond ratios in excess of one. That means, for every $1 in bonds issued, something in excess of $1 dollar in plant assets is required as security. For some utilities, the ratio is as high as 1.6 or 1.7 to one. Utilities must have additional, unbonded assets available anytime they plan to issue new bonds or dispose of existing bonded assets. To issue new bonds, additional bonded property must be placed under the lien of the mortgage. To obtain a release of assets in connection with their sale, a utility generally must substitute other bondable property as replacement collateral or, in the alternative, place the net proceeds with the bond trustee. These may be used either to retire outstanding debt or be held in escrow until sufficient replacement property is available for bonding. Forcing utilities to sell or auction off assets may not automatically provide cash to reduce stranded costs, and it may significantly reduce their ability to issue new debt. This must be considered in deciding upon an appropriate method for recovering stranded costs.
Another significant Finance issue addressed by the Subcommittee is the effect that retail competition may have on those companies with tax exempt debt. TEP and SRP raised concerns about the potential to lose their bonds' tax exempt status if restructuring is not conducted properly. TEP has significant "two-county" bonds outstanding. The interest on such bonds is tax exempt to the recipients as long as the facilities acquired with the proceeds therefrom are used solely for the "local furnishing of electric energy or gas." That has been defined as service limited to two contiguous counties or one city and a contiguous county. To serve beyond such limits may disqualify the interest payment of such bonds from their exempt status. In consideration of its concerns about possibly losing tax exemptions, TEP suggests the Commission might consider including in the Rules a provision similar to that applicable to cooperatives that would authorize utilities to request Commission approval to modify the phase-in schedule described in R14-2-1604 (A-D) as may be necessary in these circumstances. SRP raised similar concerns about its debt and the effects of mandatory exit fees and forced asset sales on its continuing tax exempt status.
AEPCO stated concerns about its debt that is subject to mortgage arrangements with the Rural Utilities Services. To the extent that the introduction of retail competition adversely affects the applicable coverage rations (i.e. Times-Interest-Earned and Debt Service Coverage) significantly, the Company may experience increases in the interest rates on its variable interest debt or face mandatory bond redemptions.
Based on the foregoing and its independent analysis of the financial issues, Staff believes that many of the concerns cannot be fully addressed until additional clarity and specificity is incorporated into the Rules. This includes, in particular, some resolution as to whether asset divestiture is going to be mandated, and the manner by which, as well as the period during which, stranded cost recovery shall occur. Accordingly, Staff recommends further study of these issues with appropriate revisions to the Rules at a later date when more information is known.
Appendix A




Steven Ahern (1) (3)

Arizona Dept. of Commerce

A. B. Baarsdon (1)

Nordic Power

Ronald Ballard (1) (2)

City of Tucson

Michael Block (1) (2) (3)

Goldwater Institute

Jana Brandt (1)

RUCO and Salt River Project

Sean Breen (2)

Citizens Utilities

Tom Broderick (1) (2) (3)

PG&E Energy Services

Richard Brown


Maureen Bureson

MLB Consulting

David Caplow

Economic Energy Alternatives

Kim Clark (1) (2) (3)

Arizona Corporation Commission Staff

Ellen Corkhill

American Association of Retired Persons

George Courteny (3)

Arizona Dept. of Revenue

Michael Curtis

Arizona Municipal Power Users Assn.

Carl Dabelstein (1) (2) (3)

Arizona Corporation Commission Staff

Sandra Dunphy (1)

BHP Copper

Elizabeth Firkins (1)

IBEW Local #1116

Rick Gilliam (1) (3)

Land & Water Fund

Suzanne Gilstrap

Arizona Multihousing Assn.

Larry Graber

Swiss Energy Association

Janet Guerrero

Enron Corporation

Scott Gutting

Arizona Association of Industries, Intel Corporation, and Allied Signal

Stephanie Hamilton

Cinergy Corporation

Kevin Higgins (1) (2) (3)

Energy Strategies, Inc., Cyprus Climax Metals Co., and BHP Copper

Susan Husij

Dept. of Revenue

Layel Inguarson

Enerco Energy, Inc.

Ken Jacobs (1)

Southwest Gas Corporation

Jimmy Jayne

Office of Senator Kyle

Gary Jurkin

Arizona Electric Power Cooperatives

Deborah Kimberly (2)

Salt River Project

Joe King (1) (2) (3)

Tucson Electric Power

Choi Lee (1) (2)

Phelps Dodge

Enrique Lopezlira (3)

Attorney General's Office

Cliff Mattie

Tempe City Attorney's Office

Stephen McArthur

Mohave Electric Cooperative

Mike McElrath (2)

Cyprus Climax Metals Company

Bill Meek (1) (2) (3)

Arizona Utility Investors Association

David Mills (2)

Allied Signal

Dan Neidlinger (1) (2) (3)

Fort Huachuca

Doug Nelson (1) (2) (3)

Electric Competition Coalition

Paul O'Dair

Navopache/Mohave Electric Cooperatives

Darrel Pichoff (2)

City of Mesa Electric Utility, Irrigation & Electric Districts Assn., and Arizona Municipal Power Users Assn.

Jerry Porter

Office of the Governor

Betty Pruitt

Arizona Community Action Assn.

Michael Raci

Munger & Munger

Dwayne Richard

Arizona Food Marketing Alliance

Donald Robinson (1) (2) (3)

Arizona Public Service Company

Mike Rowley (1) (2)

Calpine Corporation and Enserco

Monsinor Edward Ryle (3)

Arizona Catholic Conference

Jeff Schlegel (1) (2)

Arizona Community Action Assn. and Arizona Catholic Conference

Deborah Scott

Residential Utility Consumer Office

Marty Sedler (1) (2)

Intel Corporation

Barbara Sherman

Arizona Consumers Council

Louis Stahl

Streich Lang

Albert Sterman (2)

Arizona Consumes Council

Josie Stukes (1) (2) (3)

Arizona Electric Power Cooperatives

Hon. John Wettaw

Arizona State Senator

Tim White (2) (3)

Office of State Treasurer

Jeff Woner (1) (2)

K. R. Saline & Associates

Hon. Barry Wong

Arizona State Representative

 1. Participant in Calculation Methodology Subcommittee
2. Participant in Recovery Mechanism Subcommittee
3. Participant in Accounting, Tax and Finance Subcommittee
Note: The above summary was prepared from the mailing lists used in connection with the Stranded Cost Working Group Mailings. It does not necessarily reflect actual attendance at Group and subcommittee meetings.
Appendix B 

Working Group:

March 4, 1997;

April 4, 1997;

July 25, 1997




Calculation Methodologies

Recovery Mechanism

Accounting, Tax & Finance

March 13, 1997

March 10, 1997

March 12, 1997

April 1, 1997

April 1, 1997

April 8, 1997

May 2, 1997

May 2, 1997

May 1, 1997

June 26, 1997

June 26, 1997

June 26, 1997

Appendix C





Incumbent and New Energy Suppliers:



Investor-Owned Utility

Arizona Public Service

Don Robinson

Investor-Owned Utility

Tucson Electric Power

Joe King

Investor-Owned Utility

Citizens Utilities

Sean Breen

Municipal Utility

Salt River Project

Deborah Kimberly

Municipal Utility

City of Mesa, Arizona Municipal Power Users

Darrel Pichoff

Generation & Transmission


Josie Stukes

Transmission & Distribution

Navapache & Mohave Electric Co-ops

Paul O'Dair


Electric Competition Coalition

Doug Nelson


Calpine Corp. & Enserco

Mike Rowley


Nordic Power

Andy Baardson






Greg Patterson


Arizona Community Action

Jeff Schlegel


Arizona Assn. of Industries

Scott Gutting


Energy Strategies, BHP Copper, Cyprus Climax

Kevin Higgins


Arizona Food Marketing

Dwayne Richard

Public Interest & Other:



Public Interest

Goldwater Institute

Michael Block

Public Interest

Department of Commerce

Stephen Ahern

Public Interest

Land & Water Fund

Rick Gillam


IBEW Local #1116

Elizabeth Firkins


Arizona Utility Investors

Bill Meek

Note: For purposes of establishing whether consensus with respect to a particular issue exists among the participants, a two-thirds super majority, based on votes cast, was agreed upon as the accepted threshold.
Appendix D

Arizona Community Action Association
Arizona Consumers Council and Arizona Citizen's Association
Arizona Electric Power Cooperative
Arizona Public Service Company
City of Tucson
Electric Competition Coalition
Energy Strategies (ASARCO, BHP Copper, et al)
Goldwater Institute
Land & Water Fund of the Rockies
Nordic Electric Arizona
PG&E Energy Services
Residential Utility Consumers Office
Tucson Electric Power Company