EX-99 3 caleb200300252.txt Exhibit D-3 COMMONWEALTH OF KENTUCKY BEFORE THE PUBLIC SERVICE COMMISSION In the Matter of: THE APPLICATION OF THE UNION LIGHT, HEAT AND ) POWER COMPANY FOR A CERTIFICATE OF PUBLIC ) CONVENIENCE TO ACQUIRE CERTAIN GENERATION ) RESOURCES AND RELATED PROPERTY; FOR ) APPROVAL OF CERTAIN PURCHASE POWER ) CASE NO AGREEMENTS; FOR APPROVAL OF CERTAIN ) 2003-00252 ACCOUNTING TREATMENT; AND FOR APPROVAL OF ) DEVIATION FROM REQUIREMENTS OF KRS 278.2207 ) AND 278.2213(6) ) I N D E X INTRODUCTION............................................................1 SUMMARY OF DECISION.....................................................2 BACKGROUND .............................................................3 ULH&P'S PROPOSAL........................................................4 THE AG'S POSITION.......................................................7 Need For an RFP.....................................................7 Transaction Costs..................................................12 ADITC and Deferred Income Taxes....................................14 Profits From Off-System Sales......................................18 FAC Treatment of Energy Transfers Under the PSOA...................20 OTHER ISSUES...........................................................21 New Agreements and Contracts.......................................21 Request for Deviation Regarding Affiliate Transactions.............25 Other Accounting and Rate-Making Treatment Proposals...............27 Requirement to File a Stand-Alone IRP..............................28 ULH&P'S Next General Rate Case.....................................28 Acceptance of Decision.............................................29 FINDINGS AND ORDERS....................................................30 APPENDIX A APPENDIX B COMMONWEALTH OF KENTUCKY BEFORE THE PUBLIC SERVICE COMMISSION In the Matter of: THE APPLICATION OF THE UNION LIGHT, HEAT AND ) POWER COMPANY FOR A CERTIFICATE OF PUBLIC ) CONVENIENCE TO ACQUIRE CERTAIN GENERATION ) RESOURCES AND RELATED PROPERTY; FOR ) CASE NO. APPROVAL OF CERTAIN PURCHASE POWER ) 2003-00252 AGREEMENTS; FOR APPROVAL OF CERTAIN ) ACCOUNTING TREATMENT; AND FOR APPROVAL OF ) DEVIATION FROM REQUIREMENTS OF KRS 278.2207 ) AND 278.2213(6) ) INTERIM ORDER On July 21, 2003, The Union Light, Heat and Power Company ("ULH&P") applied for a certificate of public convenience to acquire 1,105 megawatts ("MW") of generating capacity from its parent company, The Cincinnati Gas and Electric Company ("CG&E"), and approval of: (1) certain purchase power agreements with CG&E; (2) certain accounting and rate-making treatments related to the proposed acquisition, and (3) a request to deviate from certain statutory requirements related to affiliate transactions. The Attorney General of the Commonwealth of Kentucky, by and through his Office of Rate Intervention ("AG"), is the only intervenor in this proceeding. ULH&P responded to two rounds of interrogatories by the AG and Commission Staff. The AG filed testimony of his expert witnesses on September 26, 2003 and responded to one round of interrogatories by ULH&P and Commission Staff. Informal conferences were held at the Commission's offices on October 15, 21, and 24, 2003. On October 29, ULH&P filed an amendment to its application that changed several of the accounting and rate-making treatments proposed in its original application. A public hearing was held on October 29 and 30, 2003. ULH&P and the AG filed responses to hearing data requests on November 7, 2003. Post-hearing briefs were received on November 19, 2003, and the case now stands submitted for decision. SUMMARY OF DECISION Having considered and thoroughly analyzed the evidence, we find that the proposed transfer is in the best interests of ULH&P and its ratepayers and should be approved, with some clarification and modification, subject to the Commission's review and approval of all transaction documents in their final form.1 While this Commission cannot, in this transfer proceeding, render a decision on certain requests that will be binding on a future Commission in a ULH&P general rate case, we find that the related accounting and rate-making treatments proposed by ULH&P appear, at this time, to be reasonable.2 We also find that ULH&P's requests to deviate from the Commission's statutory requirements regarding affiliate transactions and from our requirement that it analyze bids for purchased power in conjunction with its next Integrated Resource Plan ("IRP") filing are reasonable and should be granted. BACKGROUND In Case No. 2001-00058, the Commission approved a wholesale power contract under which ULH&P purchases power from CG&E as a full requirements customer.3 That contract, scheduled to run through 2006, provides for ULH&P to purchase power from CG&E at a fixed price containing a market price component.4 In its approval Order in that proceeding, the Commission expressed its interest in ULH&P acquiring generation in order to insulate itself from the impacts of market prices for wholesale power on a going-forward basis. The Commission also required ULH&P to file a stand-alone IRP no later than June 30, 2004 as a means of evaluating its future resource supply needs.5 In its December 21, 2001 Order in Administrative Case No. 387, the Commission reiterated its concern regarding ULH&P's potential exposure to market prices in the future and also expressed concern that ULH&P had no announced plans for meeting its customers' power needs after the termination date of the current wholesale power contract.6 ULH&P states that this application is its response to the concerns expressed by the Commission in those prior proceedings. Its proposal includes the acquisition of CG&E's 69 percent share of East Bend No. 2,7 a 648 MW base load, coal-fired generating unit located in Rabbit Hash, Kentucky; Miami Fort No. 6, a 168 MW intermediate load, coal-fired generating unit located in North Bend, Ohio; and the 490 MW Woodsdale Generating Station, consisting of six peak load, gas or propane-fired generating units located in Trenton, Ohio.8 Along with its application, ULH&P filed an independent due diligence assessment of the subject facilities, which was performed by Burns & McDonnell Engineering Company ("B&McD").9 ULH&P'S PROPOSAL Under the amended application, the specific generating units will be transferred from CG&E to ULH&P at what is commonly referred to as net book value which, from a utility regulatory perspective, is defined as original cost less accumulated depreciation, with the original cost and the accumulated depreciation being carried forward to the accounting records of the acquiring entity. Because FERC and the SEC must rule upon the proposed transaction before it can be consummated, ULH&P and CG&E anticipate that the proposed transaction will not be completed until mid 2004. Although ULH&P will acquire ownership of these units, Cinergy's generation fleet, including these units, will continue to be operated and dispatched on a system-wide, centralized basis. ULH&P requests approval of a back-up power sale agreement ("PSA") under which CG&E will provide power to ULH&P when ULH&P's generation is not available to meet its system demand. It also requests approval of a purchase, sale and operation agreement ("PSOA") which will govern the terms of energy transfers between ULH&P and CG&E that occur for economic rather than reliability reasons. In addition to these agreements, ULH&P requests approval of assignment from CG&E of existing contracts governing the natural gas supply, propane fuel supply and propane storage at the Woodsdale site. The parties to these contracts are Cinergy Marketing and Trading, LP ("CMT"), Ohio River Valley Propane LLC ("ORVP"), affiliates within Cinergy, and TE Products Pipeline Company ("TEPPCO"), a non-affiliate company.10 In conjunction with the proposed acquisition of these generating units, ULH&P proposes specific accounting and rate-making treatments for certain revenues and costs, treatments it claims are necessary to make the transaction acceptable to CG&E and to maintain benefits that CG&E and Cinergy presently realize under the units' deregulated status. These accounting and rate-making treatments, as set forth in the amendment to ULH&P's application, are: (1) Fixing, for rate-making purposes, the value of the facilities being transferred at original cost less accumulated depreciation; (2) Deferring until ULH&P's next rate case a maximum of $2.45 million in transaction costs incurred by ULH&P and CG&E related to the transfer of the specific units, with such costs amortized over 5 years without carrying charges; (3) Including in ULH&P's future base rates the capacity charges set out in the back-up PSA; (4) Including in ULH&P's future Fuel Adjustment Clause ("FAC") the costs of energy charges assessed under the back-up PSA and the costs of energy transfers from CG&E assessed under the PSOA; (5) Authorizing ULH&P to record accumulated deferred investment tax credits ("ADITC") and accumulated deferred income taxes ("deferred income taxes") transferred from CG&E "below the line" and to exclude the ADITC and deferred income taxes from retail rate-making in its next general rate case; and (6) In its next general rate case, permitting ratepayers to retain the first $1 million in profits from off-system sales and 50 percent of profits above $1 million, with ULH&P retaining the other 50 percent of any off-system sales profits in excess of $1 million.11 ULH&P also requests approval to modify the IRP that it is required to file by June 30, 2004 to eliminate the requirement that the IRP include an evaluation of purchased power alternatives. In its amendment to its application, ULH&P commits to submit to the Commission for review and approval all final transaction documents prior to closing. ULH&P requests approval to deviate from the affiliate transaction requirements of KRS 278.2207 through 278.2213 in order to effect the acquisition of the specific units and establish the proposed agreements with CG&E, CMT and OVRP. ULH&P also proposes to continue the rate freeze ordered in Case No. 2001-00058. It will honor its commitment to continue its rate freeze through 2006, and its commitment will apply to base rates, FAC charges, and environmental surcharges. THE AG'S POSITION The AG takes issue with certain aspects of ULH&P's proposal. Those are as follows: (1) The fact that ULH&P did not issue a Request for Proposals ("RFP") seeking offers of generating assets, purchase power agreements, or combinations thereof, to meet its future needs; (2) The request to fix the value of the facilities being Transferred for future rate-making purposes; (3) The proposed deferral and recovery of transaction costs; (4) The proposal to record ADITC and deferred income taxes "below the line" and exclude them for retail rate-making in ULH&P's next general rate case; (5) ULH&P's proposed sharing of off-system sales profits; and (6) The FAC Treatment of energy transfers made under the proposed PSOA. The aspects of the proposal which the AG contests, or with which the AG disagrees, are discussed individually in the following paragraphs. Need for an RFP The AG commends ULH&P and CG&E for working to provide a means by which ULH&P's rates can remain stable and ratepayers can be sheltered from the impact of market price fluctuations. However, he argues that without an RFP, ULH&P and the Commission cannot be assured that the offer from CG&E represents the least cost alternative for meeting ULH&P's future power supply needs. Among other things, the AG cites KRS 278.2207(2), arguing that ULH&P has not demonstrated that the pricing for the transfer and related agreements is at CG&E's or its other affiliates' fully distributed costs, but in no event greater than market. The AG also contends that ULH&P has not demonstrated that the requested pricing is reasonable. The AG cites the recent experiences of East Kentucky Power Cooperative, Inc. ("East Kentucky") and Louisville Gas and Electric Company and Kentucky Utilities Company ("LG&E/KU") in support of his argument. He refers to East Kentucky's recent application for approval to construct two combustion turbines ("CTs") based on the low bid it received in response to an RFP for peaking power. He also cites LG&E/KU's use of an RFP to demonstrate that purchasing CTs from a non-regulated affiliate was the least cost alternative for meeting their need for additional peaking capacity. The AG argues that an RFP is especially warranted when the transaction involves affiliates. He states that the acquisition price of the Woodsdale units exceeds the prices of the CTs acquired recently by East Kentucky and LG&E/KU; therefore, he concludes the price ULH&P is paying exceeds market. ULH&P states that it did not issue an RFP for several reasons. First, it cites the recent and ongoing financial problems that have resulted in significant downgrades in the credit ratings of numerous electric industry participants, both regulated and non-regulated. Such downgrades have greatly increased credit risk concerns within the industry. Second, ULH&P indicates that the electricity market today focuses primarily on short-term contractual arrangements and that such a focus likely means that it would need to be back in the market for power within three to five years if it entered into a purchase power agreement at this time. Third, while acknowledging that a market exists for peaking generation such as CTs, ULH&P notes that there is not a comparable market for base load capacity.12 It also notes that there are no recent transactions similar to the proposed transaction, wherein a distribution utility attempted to acquire generation to supply its entire system or where facilities originally regulated, which were later deregulated, would go back under regulation.13 Although an active market for base load capacity similar to the market for peaking capacity does not exist, ULH&P engaged ICF Consulting ("ICF")14 to prepare an analysis of the market value of the generating capacity that is the subject of the proposed transaction.15 ICF's analysis includes a base case scenario that shows the market value of the assets being transferred to be more than twice their book value. It also includes 11 sensitivities to reflect changes in assumptions such as demand levels, fuel prices, environmental regulations, and/or combinations of changes in various assumptions. Under each of the 11 sensitivities, the market value of the generating assets exceeds their book value.16 ULH&P points to the advantages of acquiring existing facilities with documented service histories and avoiding the risks inherent with siting and permitting new facilities. It also cites the advantages of acquiring generation facilities that are already integrated into the Cinergy transmission system and that will continue to be dispatched on a centralized basis along with the rest of the generation in the Cinergy system. Finally, ULH&P states that the offer from CG&E may not remain available after it goes through the 6- to 9-month RFP process described by the AG. This is due to the potential for other parties to make purchase offers for some or all of the capacity or for wholesale power prices to increase to the point where CG&E decides that selling the output of the units in the market is in its best business interests. The AG's arguments regarding the affiliate nature of the transaction and whether ULH&P has met its burden under KRS 278.2207(2) are not compelling. It is clear that the cost of the generating units to be transferred reflects CG&E's fully distributed costs. The record evidence is also very clear that the cost of the units is no greater than market. While the AG claims that the absence of an RFP leaves the Commission no alternative but to speculate as to the market price of alternatives to the proposed transaction, he ignores other measures of "market" prices. ICF's market analysis of the facilities being transferred, which the AG neither refuted or contested, is one such measure. The AG's reliance on the recent CT proposals by East Kentucky and LG&E/KU does not consider any differences between those units and the Woodsdale units that could affect their relative costs. Some of those differences include: (1) Woodsdale's cost includes the cost of the land at that location; (2) Woodsdale's cost includes the cost of the pipelines that will be acquired with the generating units; and (3) the design of the Woodsdale units allows them to operate on either natural gas or propane. Furthermore, the AG has not demonstrated, in arguing as to whether prices are "no greater than market," that the Commission is required to review the components of the proposed transaction separately. Therefore, while the per cost kilowatt ("kw") of capacity of the Woodsdale units may exceed the cost of the East Kentucky and LG&E/KU CTs, the cost of the total package of generating facilities that ULH&P proposes to acquire is substantially below market value as reflected in ICF's market analysis. The Commission recognizes the AG's concerns and acknowledges that utilities under its jurisdiction typically conduct an RFP as part of the process of selecting new supply resources. We believe that such a process has benefited Kentucky's utilities and its ratepayers and that it will continue to benefit them in the future. However, in this instance, given the uniqueness of the proposed transaction, we are not persuaded that undertaking an RFP process would benefit ULH&P or its ratepayers. Attempting to acquire an entire generation fleet through a single transaction is unprecedented in the electric utility industry. Given the level of uncertainty that exists in the electric industry today, there are several arguments in favor of relying on factors other than the market or the financial strength of the firms that make up that market. Furthermore, based on ICF's market analysis, the facilities included in the transaction are being offered at an attractive price. As noted in the record, the average depreciated cost of the generating units included in the offer to ULH&P is $332 per kw of capacity.17 This compares to typical installed costs in today's electric industry of roughly $350 to $400 per kw for CTs and $1,000, or more, per kw for base load coal-fired capacity.18 As evident both in Case No. 2001-00058 and Administrative Case No. 387, the Commission is on record as favoring ULH&P owning generation to serve the needs of its customers and to reduce its reliance on wholesale power purchases. Under the unique circumstances of this case, and given that the evidence demonstrates that a market for baseload capacity comparable to the market for peaking capacity does not exist, we find ULH&P's analysis of supply-side resource options to be reasonable. While CG&E's generation offer may not reflect the mix of facilities that ULH&P would seek under ideal circumstances, this "imperfection" does not persuade the Commission that the proposed transaction should be put on hold while ULH&P undertakes the process of issuing an RFP and evaluating the responses it receives thereto.19 Considering all relevant factors, we find that requiring ULH&P to conduct an RFP process is not necessary to determine the reasonableness of the proposed transfer of generating facilities. Based on a thorough review and analysis of the evidence of record, the Commission finds that it has other means of determining whether the proposed transfer is reasonable. We also find that ULH&P's acquisition of the facilities being offered by CG&E is in its best interests and the interests of its ratepayers. Having determined that an RFP is not necessary in this instance, we must still make a determination of whether the various conditions proposed by ULH&P are reasonable before ruling on whether to approve the transfer as proposed. Transaction Costs In its amended application, ULH&P requests that it be permitted to defer no more than $2.45 million of transaction costs incurred in conjunction with the proposed acquisition. ULH&P also proposes that the deferred costs be amortized over 5 years without carrying charges, beginning on the effective date of the Commission's Order in its next general rate case.20 ULH&P has estimated that the total transaction costs would be $4.9 million, and would include transaction costs associated with filing preparation, financing, and taxes.21 The AG recommends that the transaction costs be deferred and recovered, but does not recommend that amortization begin with the next rate case. The AG suggests that, during the period between the transfer of the units and the next rate case, any profits generated by the units in excess of a reasonable rate of return be applied against the recovery of the deferred transaction costs. The AG believes this approach would reduce or possibly eliminate the deferred balance by the time of the next rate case.22 The Commission finds that ULH&P's proposal is reasonable and should be approved. Limiting the deferral provides for a sharing of the transaction costs between ULH&P's shareholders and ratepayers. The 5-year amortization period also represents a reasonable balance between the interests of these two groups. The exclusion of carrying charges on the deferred balance is consistent with the Commission's previous decisions concerning situations in which the unamortized balance of a deferred cost is excluded from the rate base calculations during a general rate case. ADITC and Deferred Income Taxes As a result of Ohio's retail unbundling effective January 1, 2001, ADITC and deferred income tax balances associated with the generating units proposed to be transferred to ULH&P were reclassified as "below the line" and have been amortized "below the line" over the remaining lives of the plants. ULH&P proposes that ADITC and deferred income tax balances associated with the generating units be transferred from CG&E's books to ULH&P's books concurrent with the transfer of the units. ULH&P proposes that the transferred ADITC and deferred income tax balances remain "below the line" items on its books, amortized over the remaining lives of the units, and excluded from retail rate-making in ULH&P's future general rate proceedings. Any deferred income taxes generated after ULH&P owns the units would be "above the line" and included for rate-making purposes.23 ULH&P acknowledges that the amortization expense associated with the "below the line" ADITC and deferred income tax balances would be recorded "below the line" as well.24 As of March 31, 2003, the ADITC balance was $7,404,258,25 and the deferred income tax balance was $83,388,148.26 ULH&P argues that the proposed treatment for the ADITC and deferred income tax balances is reasonable. It states that the units included in the proposal were not subject to retail rate-making in Kentucky during the period when they were owned by CG&E, and concludes that ULH&P's ratepayers should not receive the benefit of the rate base reduction generally made by the Commission for ADITC and deferred income taxes.27 ULH&P notes that the treatment proposed in this case is identical to that proposed and accepted in a recent plant transfer involving Cinergy affiliates in Indiana.28 ULH&P also contends that the proposed treatment is consistent with Internal Revenue Service ("IRS") tax normalization requirements, and cites several IRS rulings in support of this conclusion.29 The AG opposes ULH&P's proposed treatment of the ADITC and deferred income tax balances. The AG argues that ULH&P's proposal will result in an overstated rate base, a distorted capital structure that will produce an overstated cost of equity, and an overstated income tax expense on a going-forward basis. The AG contends that the proposed treatment is at odds with conventional rate-making and that it does not recognize that the ADITC and deferred income tax balances represent customer-supplied capital that was provided while the plants were under regulation. The AG estimates that the revenue requirement impact of ULH&P's proposed treatment would be approximately $341.9 million over the next 25 years.30 The AG recommends that the ADITC balance be either subtracted from ULH&P's rate base or treated as zero-cost capital, with the ADITC balance amortized over the remaining lives of the plant "above the line" in order to recognize the source of the ADITC. The AG further recommends that the deferred income tax balance be accounted for "above the line" in accordance with the FERC Uniform System of Accounts ("FERC USoA"). ULH&P's proposed acquisition of generating facilities from CG&E represents an unprecedented transaction to be considered by the Commission. Not only must the Commission consider that the proposed transaction is between affiliated companies, it must also recognize that the generating assets being sold to the regulated entity have been deregulated. Consequently, the Commission must carefully consider the accounting and rate-making treatments authorized in conjunction with the proposed transaction, including the tax normalization impacts. After reviewing the arguments and evidence, the Commission finds that the treatment of ADITC and deferred income taxes proposed by ULH&P is reasonable and should be approved. The generating units proposed to be transferred to ULH&P have been deregulated since January 1, 2001. When CG&E's regulated generating fleet became deregulated, the ADITC and deferred income tax balances were moved "below the line" for rate-making purposes. The possibility that some units of the deregulated generating fleet may be returning to regulation does not, in and of itself, support an assumption that the associated ADITC and deferred income tax balances will automatically move "above the line" for rate-making purposes. No evidence has been presented in this case that supports such an assumption. ULH&P has provided the results of its research concerning the treatment of the ADITC and deferred income tax balances from a tax perspective. That research indicates that, upon the sale of public utility assets between two public utilities, ADITC cannot be added to the regulated books of the purchasing utility and that it cannot be flowed-through to the customers of either the buyer or seller. ULH&P's research also indicates that, as the result of an asset sale and purchase transaction, any reduction of the purchaser's cost of service for pre-transfer ADITC or deferred income tax balances would result in a tax normalization violation. In addition, ULH&P's proposal concerning the transfer of the deferred income taxes is consistent with the FERC USoA. In three separate account descriptions, the FERC USoA provides, "When plant is disposed of by transfer to a wholly owned subsidiary the related balance in this account shall also be transferred."31 However, the Commission notes that the FERC USoA addresses only the accounting treatment, and does not state for rate-making purposes whether the deferred income taxes are to be recorded "above the line" or "below the line." Concerning the AG's estimated revenue requirement impact of ULH&P's proposed treatment for ADITC and deferred income taxes, the Commission finds the estimate to be of little persuasive value. The AG has not consistently stated the amount of the estimated impact.32 The Commission has examined the calculation of the $341.9 million estimate and notes that the calculation assumes the rate of return on rate base and federal and state income tax rates to be constant over the approximate 25-year time frame covered by the estimate. The calculations include the determination of an annual return resulting from the AG's contention that there will be an excessive equity ratio. This annual return is also assumed to be constant, and is multiplied by 24.75 years to reflect its impact on the AG's revenue requirement. We note that ULH&P expressed similar concerns about the calculations in its brief.33 The Commission does not believe that these assumptions produce a reasonable estimate of the revenue requirement impact of ULH&P's proposed rate-making treatment for ADITC and deferred income taxes. The Commission must consider all impacts of the proposal submitted rather than focus solely on the revenue requirement impact, as it appears the AG has done. Given the potential tax normalization issues, the lack of documentation supporting the AG's arguments, and the unrealistic assumptions contained in the AG's estimate of the revenue requirements impact, the Commission cannot consider the AG's position to be a reasonable alternative. Profits from Off-System Sales The AG argues that ratepayers should receive 90 percent of the profits from off-system sales and that ULH&P should be allowed to retain 10 percent as an incentive to make such sales. The AG states that ratepayers receive 100 percent of the profits from off-system sales under standard rate-making treatment, but recognizes that ULH&P should be given an incentive, albeit a small one, to make these sales. The AG also argues against ULH&P's proposed treatment of off-system sales profits on the basis that the proposal is not limited to sales made exclusively from the facilities being transferred. He claims the proposal would also apply to off-system sales derived from other assets that ULH&P could acquire while its proposed treatment of off-system sales profits was in place, which would produce an absurd result. ULH&P acknowledges that the proposal to share off-system sales profits between customers and shareholders departs from typical rate-making treatment. However, it points out that, since Ohio's electric restructuring went into effect, CG&E has retained 100 percent of the profits from off-system sales from the units. ULH&P argues that this aspect of the proposal is critical to making the transaction acceptable to CG&E from an economic perspective. The Commission finds ULH&P's proposal that ratepayers retain the first $1 million in profits from off-system sales and 50 percent of profits above $1 million to be acceptable. While it represents a departure from standard rate-making treatment, it represents an improvement for ratepayers compared to the current purchased power contract. As the contract is not cost-based, its pricing is not based on ratepayer retention of any off-system sales profits; hence, under ULH&P's proposal, ratepayers will be receiving a benefit from off-system sales that they had not received previously. In addition, ULH&P forecasts annual off-system sales profits of $4.5 million in the early years after the transfer, with the amount declining to $1.6 million by 2012. Given the uncertainty attendant to forecasting off-system sales, the guarantee of retaining up to the first $1 million in profits from such sales is a significant benefit to ratepayers. We recognize that this treatment does not comport with conventional rate-making; however, as stated elsewhere in this Order, this is not a conventional proceeding before this Commission. While ULH&P has referred to the sharing of off-system sales profits that has been approved for American Electric Power ("AEP") in the past, this is largely an issue of first impression.34 It is also, contrary to the AG's brief, an issue applicable only to sales from the facilities that are the subject of the proposed transfer.35 For these reasons, and considering all provisions in the transaction as a whole, we find that the treatment of off-system sales profits proposed in the amendment to ULH&P's application is reasonable. We further find no reason, at this time, that such treatment should not be approved in ULH&P's next general rate proceeding. FAC Treatment of Energy Transfers Under the PSOA The AG does not disagree with ULH&P's proposal to include the cost of energy transfers from CG&E to ULH&P for recovery through its future FAC. However, he argues that such treatment is appropriate only if credits that occur when ULH&P makes transfers to CG&E are also passed through the FAC. The amendment to ULH&P's application revised its original proposal, under which it would have retained 100 percent of the profits from off-system sales, such that ratepayers will receive the bulk of the profits from such sales. The proposal in ULH&P's original application would have precluded the AG's proposed treatment of the costs of energy transfers from ULH&P to CG&E. However, recognizing the change to both ULH&P's proposed treatment of off-system sales and its proposed treatment of energy transfers, as set out later in this Order in the section "Other Accounting and Rate-making Treatment Proposals," we conclude that passing through the FAC the credits that occur when ULH&P makes energy transfers to CG&E is entirely consistent with the FAC treatment prescribed in 807 KAR 5:056 and should, therefore, be approved, as proposed by the AG. OTHER ISSUES New Agreements and Contracts ULH&P seeks approval of a form of asset transfer agreement for each of the three generating facilities included in the proposed transfer. A draft of the asset transfer agreement for East Bend was filed with the application.36 Based on the amendment to ULH&P's application, the final agreements are expected to mirror the draft agreement, except for the deletion of provisions governing a "Regulatory Non-Satisfaction Event" and the "Purchase Option" both of which addressed circumstances that could lead to ULH&P transferring the facilities back to CG&E in the future. In conjunction with the proposed transfer, ULH&P and CG&E will enter into the back-up PSA and PSOA described earlier in this Order.37 The back-up PSA provides a firm supply of power for ULH&P's native load customers to replace capacity from either East Bend or Miami Fort when outages or deratings of those units occur.38 Pricing terms under the back-up PSA call for energy to be priced at the average variable cost per MWh during the prior calendar month at the plant for which back-up power is required. The capacity charges ULH&P will pay under the back-up PSA are based on a value of power calculated using forward market prices quoted from Megawatt Daily and the North American Power 10x Report.39 There are separate capacity charges for East Bend and Miami Fort which, on a combined basis, equal $421,595 per month. The overall price for back-up power included in the PSA is less than the price embedded in ULH&P's existing wholesale purchase power contract with CG&E. ULH&P and CG&E will also enter into the PSOA, which will allow the units being transferred to be jointly dispatched along with other Cinergy generating units. Energy transferred between ULH&P and CG&E under the PSOA will be priced at the market price for the hour in which the energy transfer takes place but will be capped at the receiving entity's incremental cost of available generation. The PSOA also establishes the terms under which off-system purchases and sales will be made and how the costs and revenues associated with such transactions will be treated by ULH&P and CG&E. For its operation of the Woodsdale station, CG&E presently has a contract with CMT to obtain its natural gas supply and contracts with ORVP to obtain propane and to store propane in a cavern partially owned by ORVP. CG&E also has a contract with TEPPCO to store propane in TEPPCO's pipeline system.40 CG&E owns the pipelines used to transport propane to Woodsdale from both the ORVP cavern and the TEPPCO pipeline. ULH&P will acquire CG&E's pipelines as part of the proposed transaction. Other than stating his concerns about the price of the facilities and the affiliate aspects of the proposed transaction, the AG did not oppose the form or content of the amended draft asset transfer agreement or ULH&P's proposal to enter into the back-up PSA and PSOA with CG&E. Likewise, the AG did not oppose CG&E's assignment of the "Woodsdale contracts" or its coal supply contracts to ULH&P. The Commission finds that the subject agreements and contracts are required in conjunction with the proposed transfer and, based on information in this record, appear to be reasonable and should therefore be approved, subject to our review and approval of the final documents.41 Several of the transaction documents have been and will be drafted to accomplish the proposed transaction. ULH&P commits to submit to the Commission for review and approval the final documents prior to closing. ULH&P refers to 12 transaction documents that will be executed as part of the proposed transaction.42 The Commission recognizes that the timing of the closing of the proposed transaction will be of significant concern to ULH&P and CG&E. However, the Commission must have adequate time to review the numerous documents related thereto. Therefore, the Commission finds that a process should be established to address the review and approval of the transaction documents in their final form. ULH&P should submit all the transaction documents in their final form to the Commission no later than 30 days prior to the expected closing date of the transaction. The submitted documents should include all attachments, exhibits, appendices, and schedules that are referenced as part of the particular transaction document. For those documents it has already included in this record, ULH&P should include a detailed explanation for any changes made to the document from the version already existing in the record. For those documents not already included in this record, ULH&P should include a narrative describing the purpose of the document and explaining how the terms and conditions contained in the document are consistent with this Order. ULH&P should file an original and 5 copies of this information with the Commission and a copy with the AG.43 Upon ULH&P's filing of these documents and explanations, the Commission will complete its review as expeditiously as possible. Request for Deviation Regarding Affiliate Transactions In 2000, the Kentucky General Assembly enacted guidelines on cost allocations and affiliate transactions, as well as a code of conduct for utilities with nonregulated activities or affiliates. These standards and guidelines are codified in Chapter 278 of the Kentucky Revised Statutes, specifically as KRS 278.2201 through KRS 278.2219. Provided within these statutes is the opportunity for regulated utilities to request from the Commission a waiver or deviation from the requirements thereof. ULH&P requests permission to deviate from the requirements of KRS 278.2207(1)(b) and requests a waiver from the requirements of KRS 278.2213(6) for its plant acquisition transaction and certain affiliate agreements.44 These statutes require, respectively, that the services and products provided to the utility by an affiliate be priced at the affiliate's fully distributed cost but in no event greater than market, and that all dealings between a utility and a nonregulated affiliate be conducted at arm's length. The Commission may grant a deviation from KRS 278.2207(1)(b) if it determines that the deviation is in the public interest. It shall grant a waiver or deviation from KRS 278.2207(1)(b) and/or KRS 278.2213 if it finds that compliance with the provisions thereof are impracticable or unreasonable. The AG argues that ULH&P has failed to demonstrate to the Commission that a waiver or deviation from the provisions of KRS 278.2207 and KRS 278.2213 is appropriate and asserts that ULH&P's request should be denied. The Commission does not agree. In reviewing ULH&P's arguments justifying the lack of an RFP for the acquisition of the generating facilities and ICF's market analysis of those facilities, the Commission was able to determine that the generating units being transferred from CG&E are priced at CG&E's fully distributed cost and that the cost is below market. Therefore, the Commission finds that no deviation from KRS 278.2207(1)(b) is required for the acquisition of the generating units. The Commission is also satisfied from the evidence presented by ULH&P that the pricing of the products and services provided in the Gas Supply and Management Agreement, Commodity Storage Agreement, and the Propane Supply and Management Agreement is reasonable and that ULH&P's request to deviate from the pricing requirements of KRS 278.2207(1)(b) with regard to these agreements should be granted. As stated previously, KRS 278.2213(6) requires that all dealings between a utility and its nonregulated affiliate be conducted at arm's length. Thus, a deviation from KRS 278.2213(6) is required for all of the agreements proposed by ULH&P in this proceeding, including the agreements for the generating units that the Commission has determined do not require a deviation from KRS 278.2207(1)(b). Having reviewed ULH&P's reasons for not issuing an RFP and our previous findings herein that an RFP was not necessary to determine the reasonableness of the transfer of generating units, that the transfer is reasonable and in the public interest, and that the agreements associated with the transfer are in the public interest, the Commission finds that ULH&P has met its burden under KRS 278.2219. Consequently, ULH&P's request to deviate from KRS 278.2213(6) should be granted. The Commission finds, however, that the deviations approved herein should apply only to this transaction and the agreements discussed herein. Future transactions or successor agreements will require separate deviation or waiver requests if and when they are proposed by ULH&P. Other Accounting and Rate-Making Treatment Proposals In addition to its proposals regarding the value of the facilities being transferred, deferral and recovery of transaction costs, treatment of ADITC and deferred income taxes, and sharing the profits from off-system sales, ULH&P also requested approval of the following provisions related to the back-up PSA and the PSOA, to be effective with its next general rate case: (1) Inclusion in its future base rates of all monthly capacity charges specified in the back-up PSA; and a commitment to consult with the Commission and the AG prior to filing a successor agreement at FERC; (2) Inclusion in its future FAC of all energy charges assessed under the back-up PSA in accordance with 807 KAR 5:056 and Commission precedent; (3) Inclusion in its future FAC of the costs of energy transfers from CG&E under the PSOA in accordance with 807 KAR 5:056 and Commission precedent; and (4) Inclusion in its future FAC of the cost of the fuel consumed in the facilities in accordance with 807 KAR 5:056 and Commission precedent. The Commission finds that this request is generally reasonable and should be approved. However, ULH&P did not specify what is meant by "Commission precedent" regarding its requested FAC treatment. Given that application and review of an electric utility's FAC is addressed in its entirety in 807 KAR 5:056, the Commission will limit its decision herein to approving treatment in accordance with that administrative regulation. Requirement to File a Stand-Alone IRP In Case No. 2001-00058, the Commission required ULH&P to file a stand-alone IRP by June 30, 2004. Our Order stated that the IRP should include analyses of bids to purchase power from non-affiliated suppliers as well as construction of generation to lock in prices for the long term. In the amendment to its application, ULH&P requests that it be permitted to deviate from the requirement to analyze bids for purchased power. ULH&P states that, should the Commission approve the proposed transfer, such a requirement, which would impose significant costs on ULH&P, would no longer be necessary. Given that ULH&P's load forecast and supply-side analysis show that it will not need additional resources until the 2011-2012 time frame, and that this need is expected to be met with summer season purchases, the Commission finds that the requested deviation is reasonable and should be granted. ULH&P's Next General Rate Case Based on the current freeze on ULH&P's retail electric rates, effective through December 31, 2006, many of the accounting or rate-making provisions included in the amendment to its application refer to its next general rate proceeding or contain the phrasing "on or after January 1, 2007." These same references and phrasing were in ULH&P's original application and in numerous of its responses to data requests. The Commission takes notice of the fact that ULH&P has not filed to increase its retail electric rates since 1991. By the end of the current rate freeze, its customers will have gone 15 years without a base rate increase. The Commission commends ULH&P for its efficiency and its stewardship of ratepayers' monies, which have contributed to its not requiring a general rate increase for this length of time. In some of its testimony and exhibits, ULH&P projected the future rate impact of acquiring the facilities that are the subject of the proposed transfer. Its projections show a possible future rate increase going into effect January 1, 2007, concurrent with the end of its current rate freeze. The Commission believes that a general rate proceeding will be necessary for ULH&P within that time frame. Given the numerous changes that have occurred in the electric industry since 1991, we believe that shareholders and ratepayers will both be better served in the long run by ULH&P filing a general rate application to effect a change in rates on January 1, 2007. Such an effective date, of course, would be at the conclusion of the suspension period provided by the statutes and regulations governing changes in rates. Therefore, we find that ULH&P should file a general rate application in 2006 to adjust its retail electric rates, so that, based on the suspension period applicable to ULH&P's choice of test period, the effective date of any eventual rate adjustment ordered by the Commission will be January 1, 2007. Acceptance of Decision The decision enunciated herein approves ULH&P's proposal, subject to certain conditions and modifications. Since the proposal was a response to concerns previously expressed by the Commission regarding ULH&P's long-term power supply needs, if any modifications are found to be unacceptable by ULH&P or its affiliates, the Commission wishes to be informed of that finding as soon as is practicable. Therefore, ULH&P should notify the Commission in writing, no later than 30 days from the date of this Order, whether or not it and its affiliates accept this decision, including all modifications. FINDINGS AND ORDERS Based on the evidence of record and being otherwise sufficiently advised, the Commission finds that: 1. ULH&P's amendment to its application, which establishes the terms and conditions under which it will acquire CG&E's interests in East Bend Unit No. 2, Miami Fort Unit No. 6, Woodsdale Unit Nos. 1 through 6, and the related property, appurtenances, contracts and agreements, should be approved, subject to Commission review and approval of final drafts of the transaction documents. 2. The termination of ULH&P's current PSA with CG&E, effective on the closing date of the transfer of facilities, is reasonable and should be approved. 3. ULH&P should be granted a waiver, in accordance with KRS 278.2219, from the requirements of KRS 278.2213(6) that its acquisition of the facilities, subject to this transfer, from its affiliate, CG&E, be at arm's length; and ULH&P should be granted a deviation, pursuant to KRS 278.2207, of certain affiliate agreements related to the operation of the facilities being transferred. 4. ULH&P's draft transfer agreements for the three facilities being acquired, with the provisions governing a "Regulatory Non-Satisfaction Event" and the "Purchase Option" deleted, should be approved, subject to Commission review and approval of the agreements in their final form. 5. ULH&P's back-up PSA and its PSOA, which will govern its power transactions with CG&E on a going forward basis subsequent to the consummation of the proposed transfer of facilities, should be approved, subject to Commission review and approval of the agreements in their final form. 6. The assignment to ULH&P by CG&E of CG&E's interests in the contracts for the supply, delivery, and storage of coal, oil, natural gas and propane used as fuel for electricity generation at East Bend Unit No. 2, Miami Fort Unit No. 6, and Woodsdale Unit Nos. 1 through 6 should be approved, subject to Commission review and approval of the contracts in their final form. 7. The facilities being acquired by ULH&P should be recorded by ULH&P at their original cost less accumulated depreciation. At this time, the Commission knows of no reason why such value should not be used in the future for rate-making purposes. 8. ULH&P should defer no more than $2.45 million of the transaction costs incurred in relation to its acquisition of the subject generating facilities, with the costs to be deferred and amortized over 5 years, without carrying charges, beginning with the effective date of the Commission's Order in ULH&P's next general rate proceeding. At this time, the Commission knows of no reason why the resulting amortization expense should not be recovered through rates beginning with the effective date of the Commission's Order in ULH&P's next general rate proceeding. 9. ULH&P's proposal to record the ADITC and deferred income tax balances associated with the generating facilities being transferred "below the line" is reasonable and should be approved. At this time, the Commission knows of no reason why such treatment should not be reasonable for future rate-making purposes. 10. Based on its approval of the back-up PSA, the monthly capacity charges set out therein are reasonable. The Commission knows of no reason, at this time, why such charges should not be recovered through rates beginning with the effective date of the our final Order in ULH&P's next general rate proceeding. ULH&P should consult with the Commission and the AG prior to filing any successor agreement with FERC. 11. ULH&P's recovery of energy charges assessed under the Back-Up PSA, from the date that its next FAC goes into effect, on or after January 1, 2007, should be in accordance with 807 KAR 5:056. 12. Treatment of the costs of energy transfers between ULH&P and CG&E under the PSOA, from the date that its next FAC goes into effect, on or after January 1, 2007, should be in accordance with 807 KAR 5:056. 13. ULH&P's proposal to share off-system sales profits with its customers, beginning with the effective date of the Commission's Order in its next general rate proceeding so that customers receive up to $1 million from off-system sales profits annually and 50 percent of such profits above $1 million annually, if any, while ULH&P retains 50 percent of the profits from off-system sales above $1 million annually, if any, is reasonable. The costs attributable to off-system sales should include the incremental costs listed in the PSOA, Paragraph 1.10. ULH&P should implement the necessary processes to allocate appropriately said incremental costs to its off-system sales. The Commission knows of no reason, at this time, why such treatment of off-system sales profits should not be approved in ULH&P's next general rate proceeding. 14. ULH&P should be granted a waiver from the Commission's requirement, imposed in Case No. 2001-00058, that it analyze purchase power alternatives in its stand-alone IRP, which is to be filed by June 30, 2004. 15. ULH&P should file its next general rate application to adjust retail electric rates so that, based on the suspension period applicable to ULH&P's choice of test period, the effective date of any eventual rate adjustment ordered by the Commission will be January 1, 2007. 16. ULH&P should notify the Commission in writing, not later than 30 days from the date of this Order, if this decision, including all conditions and modifications, is acceptable to it and its affiliates. 17. ULH&P should submit the final draft versions of the various transaction documents and accompanying narrative explanations for final Commission review and approval in the manner described herein. 18. Within 10 days of their receipt, ULH&P should file one copy of each of the approval documents issued by the FERC and the SEC. IT IS THEREFORE ORDERED that: 1. The proposed acquisition of generating facilities by ULH&P, as described in its amended application of October 29, 2003, is approved, subject to the conditions and modifications described in this Order. 2. Findings 2 through 15 shall be implemented as if the same were individually so ordered. 3. ULH&P shall notify the Commission in writing, not later than 30 days from the date of this Order, if this decision, including all conditions and modifications, is acceptable to it and its affiliates. 4. ULH&P shall submit the final draft versions of the various transaction documents and accompanying narrative explanations for final Commission review and approval in the manner described herein. 5. Within 10 days of their receipt, ULH&P shall file with the Commission one copy of each of the approval documents issued by the FERC and the SEC. Done at Frankfort, Kentucky, this 5th day of December, 2003. By the Commission ATTEST: APPENDIX A APPENDIX TO AN ORDER OF THE KENTUCKY PUBLIC SERVICE COMMISSION IN CASE NO. 2003-00252 DATED December 5, 2003 DESCRIPTION OF FACILITIES PROPOSED TO BE TRANSFERRED East Bend No. 2 A 648 MW (nameplate rating ) coal-fired base load plant in Boone County, Kentucky. Commissioned in 1981, it is jointly owned by CG&E and Dayton Power and Light, with CG&E owning a 69% interest. The unit's net rating is 600 MW, after allowing for power used to operate the plant machinery. The net rating of CG&E's 69% share is 414 MW. East Bend is designed to burn low- to high-sulfur eastern bituminous coal. Its recent achieved heat rates have ranged between 10,400 and 10,900 Btu/kWh. It is equipped with a lime-based flue gas desulfurization system (scrubber) along with a selective catalytic reduction (SCR) control system, which is designed to reduce NOx emissions by 85%. East Bend No. 2 has a 1.2 lbs./MMBTU SO2 emission limit. The unit's output is directly connected to Cinergy's 345 kV transmission system. Burns & McDonnell (B&McD) completed its due diligence review of East Bend in June 2003. Its personnel had visited the East Bend Generating Station on May 23, 2003. Its report concludes that the plant is fully capable of providing long-term, reliable service as a base load power facility if it continues to be properly operated and maintained in accordance with good utility practice. B&McD estimates that the unit's remaining useful operating life is at least 38 years. Miami Fort No. 6 A 168 MW (nameplate rating) coal-fired base or intermediate load plant in Hamilton County, Ohio. Commissioned in 1960, it is one of four coal-fired units at the Miami Fort Generating Station. CG&E owns 100% of the unit, which has a net rating of 163 MW. Miami Fort 6 is designed to burn low- to medium- sulfur eastern bituminous coal. Its recent heat rates have ranged between 9,900 and 10,200 Btu/kWh. It is equipped with a high efficiency electrostatic precipitator and with a temporary selective non-catalytic reduction (SNCR) system for NOx reductions. Miami Fort 6 has a 5.0 lbs./MMBTU SO2 emission limit. The SNCR has not performed as well as expected and will be replaced with second generation low NOx burners in the future. It is directly connected to Cinergy's 138 kV transmission system. B&McD visited the Miami Fort Generating Station on May 26, 2003. It shares a 600-foot tall exhaust stack and continuous emissions monitoring system with its sister unit, Miami Fort No. 5 as well as crushed coal conveyors. Miami Fort 6 also shares coal handling and fuel oil storage facilities with the three other units at the site. B&McD's report concludes that the plant is fully capable of providing long-term, reliable service as a base load/intermediate power facility if it continues to be properly operated and maintained in accordance with good utility practice. B&McD estimates that the unit's remaining useful operating life is at least 17 years. Woodsdale A 490 MW (nameplate rating) six-unit combustion turbine station located in Butler County, Ohio. Its net summer capacity, including inlet cooling, is 500 MW. It is owned 100% by CG&E. The Woodsdale Generating Station was originally planned for twelve units, but only six units were constructed. It has dual fuel capability (natural gas and propane) and black start capability. Five units were commissioned in 1992 with the sixth unit commissioned in 1993. Woodsdale is connected to two interstate natural gas transmission pipelines, Texas Eastern Transmission Company and Texas Gas Transmission Company. Its contracts with Ohio River Valley Propane LLC, an affiliate, provide for its propane supply and its propane storage. NOx emissions are controlled by water injection. Woodsdale's output is directly connected to Cinergy's 345 kV transmission system. B&McD visited the Woodsdale Station on May 28, 2003. Its report noted that Units 5 and 6 had undergone major overhauls in 2001 and that Units 1-4 will have major overhauls in 2004-2005. B&McD's report concludes that the plant is fully capable of providing long-term, reliable service as a peaking power facility if it continues to be properly operated and maintained in accordance with good utility practice. B&McD indicated that the units' remaining useful operating lives will be dependent on the number of times the units are started and that, based on the number of starts that have occurred since the units were commissioned, they should be able to operate for several more years. APPENDIX B APPENDIX TO AN ORDER OF THE KENTUCKY PUBLIC SERVICE COMMISSION IN CASE NO. 2003-00252 DATED December 5, 2003 TRANSACTION DOCUMENTS Documents Filed with the Commission as of July 21, 2003: Asset Transfer Agreement for Unit 2 of the East Bend Generating Station (See Turner Direct Testimony, Attachment JLT-1) Back-up Power Sale Agreement (See McCarthy Direct Testimony, Attachment RCM-1) Purchase, Sales and Operation Agreement (See McCarthy Direct Testimony, Attachment RCM-2) Documents Referenced But Not Flied with the Commission: Schedules referenced in Section 7.09 of the Asset Transfer Agreement for Unit 2 of the East Bend Generating Station Asset Transfer Agreement for Miami Fort 6 Asset Transfer Agreement for Woodsdale Assignment Document for the Gas Supply and Management Agreement (See Roebel Direct Testimony, Attachment JJR-1 for copy of the current Gas Supply and Management Agreement) Assignment of the Commodity Storage Agreement (See Roebel Direct Testimony, Attachment JJR-2 for copy of the current Commodity Storage Agreement) Assignment of the Storage and Service Agreement (See Roebel Direct Testimony, Attachment JJR-3 for copy of the current Storage and Service Agreement) Assignment of the Propane Supply and Management Agreement (See Roebel Direct Testimony, Attachment JJR-4 for copy of the current Propane Supply and Management Agreement) Amendment/Assignment of current Coal Contracts Ownership transfer and lease back of shared stack at Miami Fort 5 and 6 Use of shared coal handling and fuel oil storage facilities associated with Miami Fort 6 1 Based on the evidence in this record, it appears that the proposed transaction is in the best interests of ULH&P's customers. The Commission urges that the federal agencies that must approve this transfer, the Federal Energy Regulatory Commission ("FERC") and the Securities and Exchange Commission ("SEC"), will give consideration to our findings in this proceeding when rendering their decisions. 2 We recognize, however, that a change in law or compelling evidence to the contrary may require Commission consideration in ULH&P's next general rate case. 3 Case No. 2001-00058, The Application of The Union Light, Heat and Power Company for Certain Findings Under 15 U.S.C. ss. 79Z, final Order dated May 11, 2001, at 17. 4 ULH&P and CG&E are both part of the Cinergy Corp. ("Cinergy") system. CG&E's rates to ULH&P include a market component due to its generating facilities being deregulated under Ohio's electric industry restructuring and FERC's mandate that wholesale rates be market-based rather than cost-based. 5 In Case No. 2001-00058 ULH&P also agreed to freeze retail rate components that recover wholesale generation and transmission costs through December 31, 2006. 6 Administrative Case No. 387, A Review of the Adequacy of Kentucky's Generation Capacity and Transmission System, final Order dated December 21, 2001, at 39-40. 7 The Dayton Power and Light Company owns the remaining 31 percent. 8 Under Ohio's electric industry restructuring plan, all the units proposed to be transferred were deregulated effective January 1, 2001. See Transcript of Evidence ("T.E."), Vol. I, October 29, 2003, at 221-222. 9 Information on the facilities subject to the proposed transfer and B&McD's due diligence study of the facilities are included in Appendix A to this Order. 10 ULH&P also requests approval of assignment from CG&E of the existing coal supply contracts for East Bend and Miami Fort No. 6. 11 Off-system sales profits will be calculated by subtracting the incremental costs of such sales, as listed in paragraph 1.10 of the proposed PSOA, from the revenues generated through off-system sales. 12 T.E., Vol. I, October 29, 2003, at 181-182. 13 Id. at 182. 14 ICF Consulting is an international consulting firm whose clients include the United States Environmental Protection Agency, Royal Bank of Canada, JP Morgan Securities, Inc., Moody's Investors Service, other government entities and investment firms, along with utilities and regulatory commissions. 15 Rose Direct Testimony, Attachments JLR-26 and JLR-26a. 16 Id. 17 Id. at 183. 18 Response to the Commission Staff's Hearing Data Request of October 29, 2003, Item 1. 19 The Commission notes that it has no statutory authority to require that CG&E sell any generation to ULH&P or to require CG&E to hold open its current offer until ULH&P has completed an RFP process. 20 Amendment to Application at 2-3. 21 Steffen Direct Testimony, Attachment JPS-7. ULH&P explained that as a result of becoming "more comfortable" with certain aspects of Kentucky statutes and regulations, it decided to amend the application. The proposal to defer roughly half of the estimated transaction costs was one of the areas in which ULH&P felt comfortable in shifting the "balance more in customers' favor." See T.E., Volume I, October 29, 2003, at 16. 22 King Direct Testimony at 10-11. The AG's testimony on this issue related to the original application and request to defer all the transaction costs and amortize those costs over 3 years. The AG did not address the treatment of the transaction costs as included in the amended application in testimony or in his brief. 23 Application at 9-10 and Steffen Direct Testimony at 12-13. 24 T.E., Volume I, October 29, 2003, at 216-217. 25 Response to the Commission Staff's First Data Request dated August 21, 2003, Item 51(a). 26 Id., Item 52(a). 27 Id., Items 51(d)(1) and 52(c)(1). 28 T.E., Volume I, October 29, 2003, at 222. 29 Response to the Commission Staff's Hearing Data Request of October 29, 2003, Item 4. ULH&P cites a 1987 IRS General Counsel Memorandum and references several IRS Private Letter Rulings issued between 1987 and 1996. 30 AG's Response to Hearing Data Request filed November 7, 2003. 31See FERC USoA, Account No. 281, Accumulated Deferred Income Taxes - Accelerated Amortization Property; Account No. 282, Accumulated Deferred Income Taxes - Other Property; and Account No. 283, Accumulated Deferred Income Taxes - Other. 32 The AG did not include an estimate of the revenue requirement impact in his prefiled testimony. At the public hearing, the AG's witness stated the estimated impact was approximately $200.0 million. See T.E., Volume II, October 30, 2003 at 43-44. In the AG's response to the hearing data request, the estimated revenue requirement was determined to be $341.9 million. However, the AG's brief states that the impact on ULH&P's revenue requirement is $317.7 million. See AG's Post Hearing Brief at 10. 33 ULH&P Brief at 43-44. 34 AEP's sharing of profits from off-system sales has no revenue requirement impact, as does ULH&P's proposal. It involves a monthly comparison of such profits to the level (100%) of profits included in the revenue requirements determination in its prior general rate case. 35 ULH&P's application and testimony refer to off-system sales from the facilities being transferred and its amended application refers only to its next general rate case. To extend its proposal to include facilities that it might acquire in the future, ULH&P would have to file for and receive Commission approval. 36 Turner Direct Testimony, Attachment JLT-1. 37 Although the Commission can "approve" the back-up PSA and the PSOA as requested by ULH&P, because they both relate to wholesale transactions between ULH&P and CG&E, those agreements are subject to FERC's jurisdiction. Therefore, any approval thereof by the Commission would constitute an official endorsement of the agreements but would not constitute the final approval necessary. 38 Woodsdale is not covered by the back-up PSA because it is peaking capacity, which will not operate for most hours of the year and will not be relied upon to meet ULH&P's base load requirements. 39 McCarthy Direct Testimony, as adopted by M. Stephen Harkness, at 4. 40 CG&E also has non-affiliate contracts for the coal supply for East Bend and Miami Fort 6, which are to be assigned to ULH&P. 41 It should be noted, due to their impact on ULH&P's base rates and/or future FAC charges, that both the back-up PSA and the PSOA are subject to periodic audit or review by the Commission. 42 The transaction documents identified in the record are listed in Appendix B of this Order. 43 This docket will remain open to receive the final documents. The AG, as is his right as an intervenor, will have an opportunity to offer his opinion on those documents. 44 The affiliate agreements for which ULH&P requests deviation and waiver are the contract with CM&T that provides for CG&E to obtain natural gas for Woodsdale (Gas Supply and Management Agreement), the contract with ORVP for propane storage in the Todhunter propane cavern (Commodity Storage Agreement), and the contract CG&E has with ORVP to obtain propane for Woodsdale (Propane Supply and Management Agreement).