Mr. Chairman and members, thank you for this opportunity to address you on the very important subject of restructuring the electric utility industry in the Commonwealth of Virginia. In particular, I have been asked to discuss the topics of stranded costs and the appropriate rate recovery of such costs. Attached to my written testimony as Exhibit 1 is a copy of draft legislative language that The Potomac Edison Company ("Potomac Edison") presents for your consideration on the topic of stranded costs. A brief summary of my education and work experience is contained in Exhibit 2.

Potomac Edison is part of the Allegheny Energy, Inc. utility holding company. Allegheny Energy’s operating utility subsidiaries serve about 1.4 million customers in parts of five states.

STRANDED COSTS
A good way to understand stranded costs is with a discussion of their origin. Essentially, stranded costs originate from the continuing generation-related fixed costs the electric utilities have incurred over the years in fulfilling their obligations to provide reliable service to their customers. Those costs are recoverable from customers under traditional regulated pricing. The State Corporation Commission has authorized Potomac Edison to recover these costs from Virginia customers for years because the Commission determined that the generation facilities that those costs support are used and useful in providing the required service to customers. In the Commission review of costs to be included in rates, Potomac Edison had the burden of proof that those costs were reasonable, proper and efficient. Costs that did not satisfy these requirements would not be included in rates. However, the competitive generation market price will not support full recovery of the fixed costs of these facilities. The question at hand today is how best to conclude the recovery of those prudent costs if the industry moves to generation competition. An explanation of why the competitive price would not support full recovery requires a review of how resource decisions were made in the electric industry.

It is generally recognized that the electric utility industry is the most capital intensive industry in the world. It is useful to look at why utilities have incurred a high level of fixed costs. In the process of planning generation resources to serve load, utilities have had to make two decisions: when to add resources and what type of resources to add. Most utilities have done a good job of forecasting load requirements and selecting when new resources are needed. The question of what type of new resource is most economic is illustrated in Figure 1.

Figure 1 shows how the fixed costs and variable costs compare for two alternative choices of new generation resources: base capacity (such as a coal-fired generation facility) and peaking capacity (such as a natural gas fired facility). The fixed costs include such investment-related items as depreciation, interest on borrowed funds, property taxes, stockholder return, income taxes and property insurance. These costs are the same regardless of how much energy (measured in kilowatt-hours or kWhs) the generating facility actually generates. The variable costs are primarily fuel-related costs. The level of variable costs incurred depends upon the amount of kWhs actually generated. The fixed and variable costs together produce total cost lines for the two alternative generation options. Those total costs intersect such that at high levels of use (more kWhs generated), the high fixed costs and low variable costs of the base generation facility yield a lower overall cost. This relationship has led utilities, with the oversight of regulators, to install base generation facilities over the years. Customers have benefited by getting access to the low variable costs.

As we ponder moving the electric generation industry into competition, utilities find themselves in a dangerous situation. Recent technological developments have made lower fixed cost natural gas fueled generation a viable option to fulfill generation needs. Economic theory holds that, in a competitive market, the market price over the long term will be set by the cost of additional resources. These new generation resources will prevent the market price from staying at a level that would allow utilities to recover the high capital investment made in base generating facilities over the years. In order to keep current electric rates low, regulators have forced electric utilities to slowly recover their investments in generating facilities over the expected lives of those facilities, typically 30 or 40 years. This is why economists often refer to utility investment as "patient capital." Potomac Edison has a net investment (original cost less accumulated depreciation) of $641 million in generating facilities, despite the fact that the average age of those facilities is 27 years. These are generation investments that the State Corporation Commission reviewed and approved as recoverable in rates. However, the introduction of competition together with the recent technology developments mentioned above will make it impossible for even low-cost utilities such as Potomac Edison to recover those investments without a stranded cost mechanism.

Potomac Edison has an unusual stranded cost component as a member of a registered utility holding company, as defined by the federal Public Utility Holding Company Act of 1935. Potomac Edison has for decades relied upon the generating capacity of its sister electric utilities in Allegheny Energy. This reliance has enabled Potomac Edison to avoid the construction of additional generating facilities as its load grew. Instead, Potomac Edison’s generation planning process counted a portion of the facilities owned by Monongahela Power Company and West Penn Power Company as resources to fulfill Potomac Edison’s service obligations. Potomac Edison has paid those affiliated companies for relying upon their facilities through a tariff, the Power Supply Agreement, that is under the jurisdiction of the Federal Energy Regulatory Commission. The result has been lower rates for Potomac Edison than would have existed with Potomac Edison stand alone generating facilities. The Power Supply Agreement costs incurred by Potomac Edison are part of the rates paid by Potomac Edison’s retail customers in Virginia, Maryland and West Virginia. In fact, the fixed costs associated with the affiliated generating facilities relied upon by Potomac Edison are supported only by Potomac Edison, not by the ratepayers of Monogahela Power Company and West Penn Power Company. If Potomac Edison moves to generation competition, a portion of those fixed costs would be stranded.

CALCULATING STRANDED COSTS
Since stranded costs are costs incurred by utilities to fulfill their obligation to serve customers that cannot be recovered from the competitive generation market, it seems obvious that the level of the generation market price is an important determinant in calculating stranded costs. This is depicted below in Figure 2. As long as the total of fixed and variable generating costs remains constant, a higher market price would mean lower stranded costs. Conversely, a lower market price would mean greater stranded costs.

The greatest difficulty in dealing with stranded costs is trying to quantify the relationship shown in Figure 2. Many unknowns can influence the future market prices. Figure 3 below shows the three future market price scenarios Potomac Edison recently filed in Maryland’s investigation into stranded costs. The picture illustrates a common sense concept – the risks involved in projections are far greater when those projections stretch far into the future. For that reason, Potomac Edison’s suggested legislative language includes a practical limit of ten years upon projections.

While some forecasters would look at Figure 3 and take comfort that the increasing market price means lower stranded costs, that is not necessarily the case. The factors that influence the future market price also influence the costs of the utility generating facilities. For example, if the market price were being influenced by a high carbon tax, a coal-fired utility such as Potomac Edison would experience a significant increase in costs that could result in a greater amount of stranded costs. The calculation of stranded costs is not just equal to fixed costs less market price. It is fixed costs less the operating margin, where the operating margin is the market price less the operating or variable costs of the generation. Future cost projections, like future market price projections, are difficult to make with certainty. Therefore, Potomac Edison’s approach of limiting stranded cost calculations to ten years avoids a significant amount of the uncertainties involved with such projections.

The last aspect of stranded costs that I’d like to point out is that the costs which a utility must recover when moving to generation competition consist of the following components:

• Costs of generating assets currently recovered in rates, including costs currently incurred through tariffs under the jurisdiction of the Federal Energy Regulatory Commission;
• Existing generation-related regulatory assets; and
• Transition costs.

STRANDED COST RECOVERY
The fundamental point about stranded cost recovery is that customers within a utility’s service territory should not be able to avoid paying their share of those costs. That would be blatantly unfair to the utility and to other customers. Whether a customer continues to take generation from its current utility, chooses an alternative supplier, or installs new self-generation, that customer should pay the same for his stranded cost responsibility. His choice of generation source should not affect his stranded cost payment. In that way, the stranded cost responsibility will not bias his generation choice. This approach has all customers, even those who have not chosen an alternative generation supplier, contributing to stranded cost recovery through a competitive transition charge ("CTC"). This is appropriate if designed correctly. Under this approach, stranded costs are established assuming all customers have chosen an alternative supplier immediately at the start of the competition phase-in period. A CTC is calculated for each rate schedule that assumes every customer will pay it and thus contribute to the stranded cost recovery. Customers that have not actually chosen an alternative supplier will not pay any more than their bundled regulated rate. However, a part of their rate will be designated as a CTC which will be credited to recovery of the established stranded costs. This approach is similar to the operation of the existing fuel clause in Virginia and other states. The beauty of this approach is that it avoids having to predict how many customers will have chosen alternative suppliers at any given point in time. Customers who have selected alternative suppliers will pay those suppliers for generation, and pay the local utility a CTC to contribute to stranded costs recovery as well as pay for transmission and distribution services.

Potomac Edison believes that the collection of stranded costs should generally reflect the same allocation of generation-related cost recovery among customers that exists in current rates. Beyond that, existing rate design principles are adequate to determine how much each customer should pay for stranded costs once the total amount to be recovered has been determined. The Virginia State Corporation Commission is familiar with evaluating the application of those principles by utilities and can approve final rate designs, providing that those designs allow for the full recovery of the stranded costs.

Exhibit 1

§___. COMPETITIVE AND INTANGIBLE TRANSITION CHARGES; SURCHARGES

(a) GENERAL RULE – EACH ELECTRIC UTILITY SHALL BE PERMITTED TO RECOVER ALL OF ITS PRUDENTLY INCURRED, REASONABLY VERIFIABLE AND REASONABLY NON-MITIGABLE TRANSITION OR STRANDED COSTS FOLLOWING THE COMMISSION’S DETERMINATION UNDER SUBSECTION (c) BELOW. TO EFFECT THAT RECOVERY, A COMPETITIVE TRANSITION CHARGE SHALL BE INCLUDED AS PART OF THE CHARGE PAID BY EVERY ELECTRIC PURCHASER LOCATED IN THE SERVICE TERRITORY OF THE ELECTRIC DISTRIBUTION COMPANY. THE COSTS TO BE RECOVERED SHALL BE ALLOCATED TO CUSTOMER CLASSES IN A MANNER THAT, AS NEARLY AS REASONABLY POSSIBLE, MATCHES THE COST OF PROVIDING SUCH SERVICE TO THOSE CLASSES OF CUSTOMERS, AVOIDING WHERE REASONABLY POSSIBLE ANY SIGNIFICANT INTER-CLASS OR INTRA-CLASS CROSS-SUBSIDY. SUCH CHARGES SHALL BE A NON-BYPASSABLE COST RECOVERY MECHANISM.

(b) PERIOD FOR COLLECTING COMPETITIVE TRANSITION CHARGE – THE COMPETITIVE TRANSITION CHARGE SHALL BE INCLUDED ON BILLS TO CUSTOMERS FOR A PERIOD NOT TO EXCEED 5 YEARS FROM THE INITIAL IMPLEMENTATION DATE, UNLESS AN ALTERNATIVE PAYMENT METHODOLOGY IS MUTUALLY AGREED UPON BY THE CUSTOMER AND THE UTILITY OR UNLESS THE COMMISSION, IN ITS DISCRETION AND FOR GOOD CAUSE SHOWN, ORDERS AN ALTERNATIVE PAYMENT PERIOD NOT EXCEEDING 7 YEARS IN ANY EVENT. THE COMMISSION MAY ESTABLISH RECOVERY PERIODS OF DIFFERENT LENGTHS FOR DIFFERENT CATEGORIES OF TRANSITION OR STRANDED COSTS. NOTWITHSTANDING THE FOREGOING, (1) REGULATORY ASSETS THAT ARE REFLECTED IN CURRENT RATES THROUGH AMORTIZATIONS APPROVED BY THE COMMISSION SHALL BE RECOVERED OVER A PERIOD NOT TO EXCEED THE REMAINING TIME OF SUCH AMORTIZATIONS; AND (2) TO THE EXTENT NOT INCLUDED IN THE SURCHARGE PROVIDED UNDER §___(e)(1), COSTS ASSOCIATED WITH EACH POWER PURCHASE CONTRACT, NET OF MARKET RESALE VALUE, IN EXISTENCE AND APPROVED BY OR SUBJECT TO AN ORDER OF THE COMMISSION AS OF THE EFFECTIVE DATE OF THE ACT SHALL BE RECOVERED OVER A PERIOD NOT TO EXCEED THE REMAINING LIFE OF SUCH POWER PURCHASE CONTRACT.

(c) DETERMINATION OF COMPETITIVE TRANSITION CHARGE – THE LEVEL OF TRANSITION OR STRANDED COSTS THAT AN ELECTRIC UTILITY SHALL RECOVER THROUGH THE COMPETITIVE TRANSITION CHARGE SHALL BE DETERMINED ON OR BEFORE SIX MONTHS PRECEDING THE INITIAL IMPLEMENTATION DATE. IN MAKING SUCH DETERMINATION, THE COMMISSION SHALL APPLY THE FOLLOWING PRINCIPLES:

(1) THE COMMISSION SHALL ALLOW FULL RECOVERY OF ALL GENERATION-RELATED REGULATORY ASSETS AND OTHER DEFERRED CHARGES TYPICALLY RECOVERABLE UNDER CURRENT REGULATORY PRACTICE TO THE EXTENT NOT INCLUDED IN THE SURCHARGES PROVIDED UNDER §___ (e).

(2) THE VALUE OF ALL GENERATION-RELATED ASSETS AND LIABILITIES AND ELECTRICITY SUPPLY COSTS MUST BE REASONABLY VERIFIABLE. TO THE EXTENT NOT INCLUDED IN THE SURCHARGE PROVIDED UNDER §____ (e)(1), TRANSITION OR STRANDED COSTS RELATIVE TO POWER PURCHASE CONTRACTS SHALL BE THE DIFFERENCE BETWEEN THE CONTRACT PRICE OF ELECTRIC ENERGY AND THE ACTUAL WHOLESALE MARKET PRICE OF ELECTRIC ENERGY OVER THE LIFE OF THE CONTRACT. TRANSITION OR STRANDED COSTS APPLICABLE TO EACH OTHER GENERATION-RELATED ASSET AND LIABILITY SHALL BE THE DIFFERENCE BETWEEN ITS FAIR VALUE UNDER TRADITIONAL RATE-MAKING PRINCIPLES IN THE STATE (ASSUMING THAT RATES, IN THE ABSENCE OF THE ACT, WOULD HAVE PERMITTED THE RECOVERY OF THE ELECTRIC UTILITY’S FULL REVENUE REQUIREMENTS WITH RESPECT TO SUCH ASSET, CONSISTENT WITH TRADITIONAL RATE-MAKING PRACTICES IN THE STATE) AND ITS FAIR VALUE IN A COMPETITIVE MARKET. THE METHOD FOR DETERMINING FAIR VALUE FOR SUCH OTHER GENERATION-RELATED ASSETS AND LIABILITIES SHALL BE AT THE OPTION OF THE ELECTRIC UTILITY IN ITS REASONABLE DISCRETION AND MAY INCLUDE BUT IS NOT LIMITED TO: (i) ESTIMATING FUTURE MARKET VALUES OF ELECTRICITY AND ANCILLARY SERVICES PROVIDED BY THE ASSETS OVER A PERIOD NO LONGER THAN 10 YEARS; (ii) IF THE ELECTRIC UTILITY HAS ELECTED TO SELL SUCH ASSETS OR A PORTION THEREOF TO A PARTY OR PARTIES, THE SALE PRICE THEREOF; OR (iii) IF THE ELECTRIC UTILITY HAS ELECTED TO AUCTION THE OUTPUT OF SUCH ASSETS OR A PORTION THEREOF, NOTWITHSTANDING THE AFFILIATION OF THE PURCHASER, THE SALE PRICE THEREOF.

(3) EACH ELECTRIC UTILITY SHALL BE PERMITTED, THROUGH THE COMPETITIVE TRANSITION CHARGE, TO EARN A RETURN ON ALL STRANDED COSTS DETERMINED PURSUANT TO THE FOREGOING, AT A RATE DETERMINED BY THE COMMISSION CONSISTENT WITH THE REGULATORY STRUCTURE IMMEDIATELY PRECEDING THE EFFECTIVE DATE OF THE ACT.

(4) THE COMPETITIVE TRANSITION CHARGE DETERMINED FOR ANY PERIOD FOR EACH ELECTRIC UTILITY SHALL BE BASED UPON THE ESTIMATED TOTAL KWH SALES OF ELECTRICITY BY ALL ELECTRIC SUPPLIERS TO CUSTOMERS IN SUCH ELECTRIC UTILITY’S SERVICE TERRITORY FOR SUCH PERIOD.

(5) EXCEPT FOR THOSE COSTS REFERRED TO IN PARAGRAPH (1) ABOVE, THE ELECTRIC UTILITY SHALL USE ITS REASONABLE EFFORTS TO MITIGATE GENERATION-RELATED TRANSITION OR STRANDED COSTS. AN ELECTRIC UTILITY MAY, BUT IN NO EVENT SHALL DIRECTLY OR INDIRECTLY BE REQUIRED OR ENCOURAGED TO, ENTER INTO AN ARRANGEMENT TO BUY DOWN, BUY OUT AND TERMINATE OR OTHERWISE RESTRUCTURE ANY POWER PURCHASE AGREEMENT, INCLUDING ANY CONTRACT WITH A UTILITY OR NONUTILITY GENERATOR. PRUDENTLY INCURRED COSTS ASSOCIATED WITH SUCH A BUY DOWN, BUY OUT, TERMINATION OR RESTRUCTURING SHALL ALSO BE ALLOWED TO BE RECOVERED. IN DETERMINING WHETHER THE ELECTRIC UTILITY HAS SATISFIED ITS MITIGATION OBLIGATION, THE COMMISSION SHALL GIVE SPECIFIC CREDIT FOR EFFORTS UNDERTAKEN PRIOR TO THE EFFECTIVE DATE OF THE ACT TO REDUCE OR MODERATE ITS RETAIL RATE LEVELS COMPARED TO AVERAGE REGIONAL AND NATIONAL RATE LEVELS.

(1) THE REVIEW OF THE COMPETITIVE TRANSITION CHARGE SHALL RECONCILE THE ANNUAL REVENUES RECEIVED FROM SUCH CHARGE WITH THE ANNUAL AMORTIZATION OF TRANSITION OR STRANDED COSTS APPROVED BY THE COMMISSION UNDER THIS §____ TO TAKE ACCOUNT OF ACTUAL KWH SALES IN THE PRIOR YEAR VERSUS PREVIOUSLY ESTIMATED KWH SALES; THE COMMISSION SHALL ADJUST THE COMPETITIVE TRANSITION CHARGE BASED UPON SUCH UNDERRECOVERY OR OVERRECOVERY IN RESPECT OF THE AUTHORIZED AMORTIZATION AMOUNT. TRANSITION OR STRANDED COSTS DETERMINED PURSUANT TO SUBSECTION (c)(2)(ii) OR (iii) OF THIS §________ (SALE OF AN ASSET) SHALL BE FINAL AND NOT SUBJECT TO REVIEW OR ADJUSTMENT FOLLOWING THE SALE OF SUCH ASSET, EXCEPT FOR OUTPUT SALES WHOSE PURCHASE PRICE IS NOT YET DETERMINED AT THE TIME OF THE INITIAL STRANDED COST DETERMINATION ;

(2) THERE SHALL BE NO ADJUSTMENT OR REVIEW OF THE COMPETITIVE TRANSITION CHARGE IN ORDER TO ADJUST INDIRECTLY FOR ADJUSTMENTS PROHIBITED BY PARAGRAPH (1) ABOVE.

(1) POWER PURCHASE CONTRACTS –

(A) EACH ELECTRIC UTILITY SHALL BE PERMITTED TO FULLY RECOVER ALL ABOVE-MARKET COSTS ASSOCIATED WITH POWER PURCHASE CONTRACTS WITH UTILITY AND NON-UTILITY GENERATORS WHICH ARE IN EFFECT ON THE EFFECTIVE DATE OF THIS ACT. TO THE EXTENT NOT OTHERWISE RECOVERED IN RATES, SUCH COSTS MAY, AT THE ELECTRIC UTILITY’S OPTION, BE RECOVERED PURSUANT TO A SURCHARGE OR OTHER NON-BYPASSABLE COST RECOVERY MECHANISM. THE ABOVE-MARKET COSTS ASSOCIATED WITH EACH POWER PURCHASE CONTRACT SHALL BE RECOVERED OVER A PERIOD NOT TO EXCEED THE REMAINING LIFE OF SUCH POWER PURCHASE CONTRACT. ABOVE MARKET COSTS OF POWER PURCHASE CONTRACTS SHALL BE THE DIFFERENCE BETWEEN THE CONTRACT PRICE OF ELECTRIC ENERGY AND THE ACTUAL WHOLESALE MARKET PRICE OF ELECTRIC ENERGY OVER THE LIFE OF THE CONTRACT.

(B) AN ELECTRIC UTILITY MAY, BUT IN NO EVENT SHALL DIRECTLY OR INDIRECTLY BE REQUIRED OR ENCOURAGED TO, ENTER INTO AN ARRANGEMENT TO BUY DOWN, BUY OUT AND TERMINATE OR OTHERWISE RESTRUCTURE ANY POWER PURCHASE CONTRACT. EACH ELECTRIC UTILITY SHALL BE PERMITTED TO FULLY RECOVER, AS A PART OF ANY SURCHARGE OR OTHER NON-BYPASSABLE COST RECOVER MECHANISM UNDER THIS SUBSECTION (e)(1), ALL PRUDENTLY INCURRED COSTS ASSOCIATED WITH SUCH A BUY DOWN, BUY OUT, TERMINATION OR RESTRUCTURING.

(2) ENERGY CONSERVATION - EACH ELECTRIC UTILITY SHALL BE PERMITTED TO FULLY RECOVER ALL DEMAND SIDE MANAGEMENT AND OTHER ENERGY CONSERVATION COSTS THAT HAVE BEEN OR WILL BE INCURRED PURSUANT TO PROGRAMS OR OTHER PLANS ESTABLISHED BY LAW OR REGULATION OR ORDERED BY THE COMMISSION. SUCH COSTS SHALL BE FUNDED IN EACH ELECTRIC DISTRIBUTION TERRITORY BY A SURCHARGE OR OTHER NON-BYPASSABLE COST RECOVERY MECHANISM THAT FULLY RECOVERS FROM CUSTOMERS IN SUCH TERRITORY THE COSTS OF SUCH PLANS AND PROGRAMS IN SUCH TERRITORY.

(3) UNIVERSAL SERVICE PROGRAM COSTS - EACH ELECTRIC UTILITY SHALL BE PERMITTED TO FULLY RECOVER ALL COSTS OF UNIVERSAL SERVICE PROGRAMS (AND ANY OTHER PUBLIC PURPOSE PROGRAMS), WHICH COSTS HAVE BEEN OR WILL BE INCURRED PURSUANT TO LAW OR REGULATION OR ORDERED BY THE COMMISSION. SUCH COSTS SHALL BE FUNDED IN EACH ELECTRIC DISTRIBUTION TERRITORY BY A SURCHARGE OR OTHER NON-BYPASSABLE COST RECOVERY MECHANISM THAT FULLY RECOVERS FROM CUSTOMERS IN SUCH TERRITORY THE COSTS OF SUCH PROGRAMS IN SUCH TERRITORY.

DEFINITIONS:

INITIAL IMPLEMENTATION DATE – MEANS _______________, 200__, OR AS EXTENDED PURSUANT TO §__________ OF THIS ACT.

NON-BYPASSABLE COST RECOVERY MECHANISM – MEANS A SURCHARGE, EXIT FEE OR OTHER CHARGE OR FEE CREATED TO ENSURE RECOVERY OF CERTAIN ELECTRIC COMPANY COSTS AND TO BE INCLUDED AS PART OF THE TOTAL CHARGES PAID BY EVERY ELECTRIC PURCHASER LOCATED IN THE SERVICE TERRITORY OF THE ELECTRIC COMPANY; SUCH SURCHARGE, EXIT FEE OR OTHER CHARGE OR FEE SHALL BE DESIGNED SO THAT A CUSTOMER MAY NOT REDUCE, AVOID OR BYPASS SUCH CHARGE OR FEE BY OBTAINING SERVICES FROM ALTERNATIVE SUPPLIERS OR BY PROVIDING ITS OWN SERVICES. FOR EXAMPLE, AND WITHOUT LIMITATION, IF A CUSTOMER INSTALLS OR OPERATES ON-SITE GENERATION WHICH REDUCES, BELOW PRIOR PURCHASES, THE CUSTOMER’S PURCHASES OF ELECTRICITY THROUGH THE ELECTRIC DISTRIBUTION COMPANY’S NETWORK AFTER THE EFFECTIVE DATE OF THE ACT, THE CUSTOMER’S FULLY ALLOCATED SHARE, BASED ON PRIOR PURCHASES, OF THE COSTS TO BE RECOVERED SHALL BE RECOVERED THROUGH THE NON-BYPASSABLE COST RECOVERY MECHANISM.

POWER PURCHASE CONTRACT – MEANS ANY CONTRACT FOR THE PURCHASE OF POWER WITH UTILITY OR NONUTILITY GENERATORS WHICH, AS OF THE EFFECTIVE DATE OF THE ACT, HAS BEEN APPROVED BY THE COMMISSION, IS THE SUBJECT OF A COMMISSION ORDER, OR HAS BEEN REFLECTED IN RATES.

REGULATORY ASSETS – MEANS ANY DEFERRED COSTS OR CHARGES BOOKED AS ASSETS FOR REGULATORY PURPOSES, INCLUDING, BUT NOT LIMITED TO, COSTS ASSOCIATED WITH: (1) UNAMORTIZED SECURITIES ISSUANCE AND REACQUISITION; (2) ENVIRONMENTAL REMEDIATION; (3) RATE CASES; (4) VOLUNTARY RETIREMENTS/SEVERANCE PROGRAMS; (5) DEFERRED FEDERAL INCOME TAXES; (6) POST-RETIREMENT BENEFITS; (7) ENERGY CONSERVATION AND/OR DEMAND SIDE MANAGEMENT PROGRAMS; (8) PUBLIC PURPOSE PROGRAMS; (9) POWER PURCHASE CONTRACTS AND (10) PURCHASES FROM AFFILIATED ENTITIES CURRENTLY RECOVERED IN RATES THROUGH FERC TARIFFS.

TRANSITION OR STRANDED COSTS –MEANS AN ELECTRIC UTILITY’S COSTS, LIABILITIES AND INVESTMENTS (INCLUDING COSTS OF CAPITAL), DETERMINED AS PART OF ITS RESTRUCTURING PLAN, TO THE EXTENT SUCH COSTS, LIABILITIES AND INVESTMENTS TRADITIONALLY HAVE BEEN OR WOULD BE RECOVERABLE UNDER THE EXISTING REGULATORY STRUCTURE (WITH RETAIL RATES FOR THE PROVISION OF ELECTRIC SERVICE) BUT WHICH MAY NOT BE RECOVERABLE IN THE RESTRUCTURED ELECTRICITY SUPPLY MARKET, ALL AS PROVIDED IN §___ OF THIS ARTICLE. THIS TERM INCLUDES, BUT IS NOT LIMITED TO:

(a) GENERATION-RELATED REGULATORY ASSETS AND OTHER DEFERRED CHARGES TYPICALLY RECOVERABLE UNDER CURRENT REGULATORY PRACTICE;

(b) AT THE OPTION OF THE ELECTRIC UTILITY, ABOVE-MARKET COSTS OF POWER PURCHASE CONTRACTS AND COSTS RELATED TO CANCELLATION, BUY OUT, BUY DOWN OR RENEGOTIATION OF POWER PURCHASE CONTRACTS; AND

(c) THE FOLLOWING ADDITIONAL COSTS IN EXCESS OF MARKET VALUE:

(1) NET PLANT INVESTMENTS AND COSTS ATTRIBUTABLE TO THE ELECTRIC UTILITY’S EXISTING GENERATION PLANTS AND FACILITIES, WHETHER OR NOT SUCH PLANTS AND FACILITIES ARE OPERATING, INCLUDING, WITHOUT LIMITATION (I) REASONABLY NECESSARY OPERATING, MAINTENANCE AND CAPITAL EXPENDITURES (INCLUDING INSURANCE, PROPERTY AND OTHER TAXES) RELATED THERETO, AND (II) FUEL CONVERSION COSTS;

(2) RETIREMENT, DECOMMISSIONING AND ENVIRONMENTAL COSTS ATTRIBUTABLE TO THE UTILITY’S EXISTING GENERATING PLANTS OTHER THAN THE COSTS REFERRED TO IN (A) ABOVE;

(3) COSTS OF MITIGATION REFERRED TO IN §___(c)(5) OF THIS ARTICLE;

(4) OTHER TRANSITION COSTS OF THE UTILITY, INCLUDING WITHOUT LIMITATION (i) INCURRED AND PROJECTED COSTS OF EMPLOYEE SEVERANCE, RETRAINING, EARLY RETIREMENT, OUTPLACEMENT AND RELATED EXPENSES FOR EMPLOYEES WHO ARE AFFECTED BY CHANGES THAT OCCUR AS A RESULT OF THE RESTRUCTURING OF THE ELECTRIC INDUSTRY, (ii) THE COSTS OF REFINANCING AND RETIRING DEBT OR EQUITY CAPITAL OF AN ELECTRIC UTILITY OR AN AFFILIATE THEREOF, (iii) THE COSTS OF REENGINEERING AND MODIFICATION OF BUSINESS PROCESSES, AND THE ACQUISITION OF EQUIPMENT, COMPUTER SOFTWARE OR OTHER ASSETS, INCURRED BY THE ELECTRIC UTILITY TO ACCOMMODATE THE RESTRUCTURING OF THE ELECTRIC INDUSTRY OCCASIONED BY THE ACT, (iv) FEDERAL AND STATE TAX LIABILITIES RESULTING FROM THE TRANSITION AND (v) CONSUMER EDUCATION COSTS RELATED TO RESTRUCTURING;

(5) ANY COSTS ATTRIBUTABLE TO ELECTRIC PLANT NO LONGER USED AND USEFUL BECAUSE OF THE TRANSITION TO RETAIL COMPETITION; AND

(6) PURCHASES FROM AFFILIATED ENTITIES CURRENTLY RECOVERED IN RATES THROUGH FERC TARIFFS.

Exhibit 2

Mr. Binder is employed by the Allegheny Power Service Corporation ("APSC") as Executive Director, Regulation and Rates. In that position, Mr. Binder directs the activities of the Regulation and Rates Department of APSC, a wholly owned service company of Allegheny Energy, Inc. ("AE"). Those activities include economic studies, load research, cost allocation studies, rate design and preparing testimony in support of regulatory proceedings. The department performs these functions for all three operating companies of AE, West Penn Power Company, Monongahela Power Company, and The Potomac Edison Company.
Mr. Binder is a 1974 graduate of the Pennsylvania State University with a degree of Bachelor of Science of Electrical Engineering. He has an MBA from the University of Pittsburgh granted in 1978. He has also taken several courses given by utility, management and engineering organizations on various topics and has been a registered professional engineer in the Commonwealth of Pennsylvania since 1982.
Upon his graduation from Penn State in 1974, Mr. Binder went to work for APSC as Area Transmission Planning Engineer. In 1976, he became a Division Planning Engineer for West Penn. He returned to APSC in 1979 as Rates Engineer in the area of load research. In the years that followed, he held various positions in the Rate Department including Manager, Rate Analysis and Manager, Rate Studies. In 1989 Mr. Binder became Manager of Generation Planning Projects for APSC. He became Assistant Director of Rates for APSC in 1993, and Director of Rates in 1996. In May of 1996 he became General Manager of Industrial Marketing for AE’s Operations Business Unit. In May of 1997 Mr. Binder took his current position of Executive Director of Regulation and Rates.