EX-99 2 pucoapplication.txt EXHIBIT D-3 In the Matter of the Application of The Cincinnati Gas & Electric Company for Approval of its Electric Transition Plan, Approval of Tariff Changes and New Tariffs, Authority to Modify Current Accounting Procedures, and Approval to Transfer its Generating Assets to an Exempt Wholesale Generator Case No. 99-1658-EL-ETP; Case No. 99-1659-EL-ATA; Case No. 99-1660-EL-ATA; Case No. 99-1661-EL-AAM; Case No. 99-1662-EL-AAM; Case No. 99-1663-EL-UNC PUBLIC UTILITIES COMMISSION OF OHIO 2000 Ohio PUC LEXIS 814 August 31, 2000 CORE TERMS: customer, transition, transmission, generation, shopping, supplier, electric, retail, unbundled, residential, tariff, staff, switch, unbundling, stranded, affiliate, billing, energy, switching, plant, forecast, load, accounting, consumer, deferral, ratepayer, competitive, rider, entity, recovered PANEL: [*1] Alan R. Schriber, Chairman; Ronda Hartman Fergus; Craig A. Glazer; Judith A. Jones; Donald L. Mason COUNSEL: James B. Gainer, Paul A. Colbert, John J. Finnigan, Jr., and Michael J. Pahutski, Cincinnati, Ohio, and Baker & Hostetler, by Michael D. Dortch and Brian T. Johnson, Columbus, Ohio, on behalf of Cincinnati Gas & Electric Company. Betty D. Montgomery, Attorney General of the State of Ohio, Duane W. Luckey, Section Chief, by Thomas W. McNamee and Stephen Nourse, Assistant Attorneys General, Columbus, Ohio, on behalf of the staff of the Public Utilities Commission of Ohio. Boehm, Kurtz & Lowry, by Michael J. Kurtz, Cincinnati, Ohio, on behalf of The Kroger Company. Chester, Willcox & Saxby, by Jeffrey L. Small, Columbus, Ohio, on behalf Ohio Council of Retail Merchants, and by John W. Bentine, on behalf of the city of Cleveland and The American Municipal Power-Ohio, Inc. McNees, Wallace & Nurick, by Samuel C. Randazzo, Gretchen J. Hummel, and Kimberly J. Wile, Columbus, Ohio, on behalf of The Industrial Energy Users-Ohio. Boehm, Kurtz & Lowry, by David F. Boehm, Cincinnati, Ohio, on behalf of AK Steel Corporation. David C. Rinebolt, Findlay, Ohio, on behalf of Ohio Partners for Affordable [*2] Energy. Sutherland, Asbill & Brennan LLP, by Paul F. Forshay and Keith McCrea, Washington, DC, on behalf of Shell Energy Services Co., LLC. Bricker & Eckler LLP, by Sally W. Bloomfield, Elizabeth H. Watts, and Amy Straker-Bartemes, Columbus, Ohio, on behalf of The Ohio Manufacturers' Association, Strategic Energy LLC, Columbia Energy Services Corp., Columbia Energy Power Marketing Corp., Exelon Energy, and MidAtlantic Power Supply Association, and by Wanda M. Schiller on behalf of Strategic Energy LLC, and by David Dulick on behalf of Exelon Energy. Robert S. Tongren, Ohio Consumers' Counsel, by Evelyn R. Robinson-McGriff and Werner L. Margard, III, Assistant Consumers' Counsels, Columbus, Ohio, on behalf of the residential consumers of The Cincinnati Gas & Electric Company. Craig Goodman, Washington, D.C. and John & Hengerer, by Joelle Ogg, Washington, D.C., on behalf of the National Energy Marketers Association. Thompson, Hine and Flory, by Robert P. Mone and Scott A. Campbell, Columbus, Ohio, on behalf of the Ohio Rural Electric Cooperatives, Inc. and Buckeye Power, Inc. Vorys, Sater, Seymour & Pease, by M. Howard Petricoff, Columbus, Ohio, on behalf of Enron Energy Services, Inc.; [*3] New Energy Midwest, LLC; WPS Energy Services, Inc.; and Dynegy, Inc., and Janine L. Migden, Dublin, Ohio, on behalf of Enron Energy Services, Inc. Judith A. Phillips, Cincinnati, Ohio, on behalf of Stand Energy Corporation. Ellis Jacobs, Dayton Ohio, on behalf of the Supporting Council of Preventive Effort and Cincinnati/Hamilton County Community Action Agency. Bell, Royer & Sanders Co., LPA, by Langdon D. Bell, Columbus, Ohio, on behalf of the Greater Cleveland Growth Association. Snyder, Rakay & Spicer, by Gary A. Snyder, Dayton, Ohio, on behalf of Local Union 1347, International Brotherhood of Electrical Workers, AFL-CIO. Richard L. Sites, Columbus, Ohio, on behalf of The Association for Hospitals and Health Systems, dba Ohio Hospital Association. Bruce Weston, Columbus, Ohio, on behalf of People Working Cooperatively. William M. Ondrey Gruber, Shaker Heights, Ohio, and Vicki L. Deisner, Columbus, Ohio, on behalf of the Ohio Environmental Council. Jodi M. Elsass-Locker, Assistant Attorney General, Columbus, Ohio and Maureen Grady, Columbus, Ohio, on behalf of the Ohio Department of Development. OPINION: OPINION AND ORDER The Commission, coming now to consider the stipulations, testimony, [*4] and other evidence presented in these proceedings, hereby issues its opinion and order. I. HISTORY OF THE PROCEEDINGS On June 22, 1999, the Ohio General Assembly passed legislation requiring the restructuring of the electric utility industry and providing for retail competition with regard to the generation component of electric service (Amended Substitute Senate Bell No. 3 of the 123rd General Assembly). Governor Bob Taft signed this legislation (hereinafter SB3) on July 6, 1999, and most provisions of SB3 became effective on October 5, 1999. Section 4928.31, Revised Code, requires each electric utility to file with the Commission a transition plan for the company's provision of retail electric service in Ohio. The plan must include a rate unbundling plan, a corporate separation plan, a plan to address operational support systems and any other technical implementation issues related to competitive retail electric service, an employee assistance plan, and a consumer education plan. On December 28, 1999, Cincinnati Gas & Electric Company (CG&E or the Company) filed its transition plan, appendices, schedules, testimony, and supplemental information, pursuant to SB3. On January [*5] 7, 2000, CG&E held a technical conference with interested parties on its consumer education plan and employee assistance plan. n1 Between January 26, 2000, and February 14, 2000, various parties filed objections to CG&E's transition plan filings. By entry of February 1, 2000, an additional technical conference was held on February 24, 2000. By entry of March 2, 2000, a second prehearing conference was scheduled for May 11, 2000, and the hearing was scheduled for May 22, 2000. At the request of the parties, the hearing was continued to May 30, 2000. Supplemental testimony was filed by CG&E on May 1 and 3, 2000. CG&E filed a second supplemental testimony of its witnesses on May 17, 2000. AK Steel Corporation (AK Steel), Buckeye Power, Inc. (Buckeye), and Ohio Rural Electric Cooperatives (OREC) filed testimony on May 24, 2000. Pursuant to Section 4928.32(B), Revised Code, the Staff Report of Exceptions and Recommendations (Staff Report) was filed on March 28, 2000. - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n1 Also on January 21 and 25, 2000, CG&E held technical conferences on its operational support plan and rate unbundling plan. Between February 3 and 14, 2000, CG&E held technical conferences on the transition revenue, corporate separation, independent transmission, and shopping incentive portions of its transition plan. - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - [*6] Intervention was granted in this proceeding to the following parties: Kroger Company; The Ohio Council of Retail Merchants; Industrial Energy Users-Ohio; AK Steel; Ohio Partners for Affordable Energy; Shell Energy Services Company, LLC (Shell); The Ohio Manufacturers' Association; Ohio Consumers' Council; National Energy Marketers Association; OPEC; Buckeye Power, Inc.; New Energy Midwest, LLC; WPS Energy Services, Inc., Dynegy, Inc.; Enron Energy Services, Inc.; Stand Energy Corporation; PP&L Energy Plus Co.; Exelon Energy; Strategic Energy; Columbia Energy Services Corp.; Columbia Energy Power Marketing Corp.; Mid-Atlantic Power Supply Association; The Cincinnati/Hamilton County Community Action Agency; The Supporting Council of Preventive Effort; Local Union 1347, International Brotherhood of Electrical Workers, AFL-CIO; The Association for Hospitals and Health Systems, d.b.a. The Ohio Hospital Association; American Municipal Power-Ohio, Inc.; People Working Cooperatively; Ohio Environmental Council, Ohio Department of Development (ODOD); and Greater Cleveland Growth Association. n2 - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n2 PP&L EnergyPlus Co. was granted intervention in these proceedings but filed a notice of withdrawal on March 13, 2000. The motions to intervene on behalf of FirstEnergy, Ohio Edison, Cleveland Electric Illuminating Company, and Toledo Edison were denied on March 23, 2000. - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - [*7] On May 8, 2000, a stipulation and recommendation on CG&E's transition plan (CG&E Ex. 60) was filed on behalf of CG&E; the staff, Ohio Consumers' Council; Ohio Council of Retail Merchants; Industrial Energy Users-Ohio; Kroger Company; The Ohio Manufacturers' Association; National Energy Marketers Association; New Energy Midwest, LLC; WPS Energy Services, Inc.; Enron Energy Services, Inc.; Dynegy, Inc.; Cincinnati/Hamilton County Community Action Agency; Supporting Council of Preventive Effort; The Ohio Hospital Association; People Working Cooperatively; Exelon Energy; Strategic Energy; Columbia Energy Services Corp.; Columbia Energy Power Marketing Corp.; Mid-Atlantic Power Supply; city of Cleveland; and American Municipal Power-Ohio. Stand Energy Corp. and Local Union 1347, International Brotherhood of Electrical Workers, AFL-CIO, subsequently signed the stipulation. Also on May 8, 2000, a stipulation on CG&E's employee assistance plan was filed on behalf of CG&E; the staff; Industrial Energy Users-Ohio; The Ohio Council of Retail Merchants; AK Steel, Kroger Company; The Ohio Manufacturers' Association;, The Ohio Hospital Association; Columbia Energy Services Corp.;, Columbia Energy [*8] Power Marketing Corp.; Exelon Energy; Strategic Energy; Mid-Atlantic Power Supply Assoc.; Ohio Consumers' Council; New Energy Midwest, LLC; WPS Energy Services, Inc.; and Enron Energy Services, Inc. A third stipulation on CG&E's independent transmission plan was filed on May 8, 2000, on behalf of CG&E; staff; Ohio Consumers' Council; The Ohio Council of Retail Merchants; Industrial Energy Users-Ohio; Kroger Company; The Ohio Manufacturers' Association; New Energy Midwest, LLC; WPS Energy Services, Inc.; Enron Energy Services, Inc.; Dynegy, Inc.; and The Ohio Hospital Association. The evidentiary hearings were held on May 30, and June 1, 2, 5, 6, 8, and 14, 2000. CG&E filed its rebuttal testimony on June 12, 2000. A local public hearing was held on June 8, 2000, in Cincinnati, Ohio. Initial briefs were filed on July 5, 2000, by CG&E, staff, AK Steel, Buckeye and OREC collectively, Shell, People Working Cooperatively, Ohio Consumers' Council, and Industrial Energy Users-Ohio. Reply briefs were filed on July 19, 2000, by CG&E, Staff, Shell, AK Steel, and Buckeye and OREC. II. SUMMARY OF THE STIPULATIONS A. The Transition Plan Stipulation CG&E's transition plan stipulation provides, [*9] among other things, that: (1) CG&E agrees to eliminate the $563 million of generation transition charge (GTC) recovery proposed in its transition plan. (2) Approval of the stipulation shall be deemed to grant to CG&E accounting authority to create the necessary regulatory assets and defer costs and recover, through a regulatory transition charge (RTC), the following regulatory assets, including but not limited to existing regulatory asset balances on CG&E's books as of December 31, 2000, deferral of transition implementation costs, deferral of purchased power costs sufficient to maintain an adequate operating reserve margin as determined by CG&E, deferral of the litigation cost reimbursement, deferral of the Ohio Excise Tax overlap, and deferral or adjustment to the amortization schedule to reflect the effects of any shopping incentive. CG&E will not seek rate recovery of any costs deferred pursuant to such accounting authority that are not recovered through the RTC. During the market development period (MDP), for accounting purposes, there exists an implied residual RTC (unbundled generation charge less the shopping credit provided to customers). All regulatory assets created [*10] and recovered pursuant to this stipulation are in compliance with the requirements of Sections 4928.39 and 4928.40, Revised Code. (3) There will be no further netting or adjustment of any kind to CG&E's transition cost recovery, including but not limited to any adjustment of RTC rates, or shopping credits through 2010, related to the sale, lease, or transfer by CG&E, or any of its affiliate, of any generating asset. (4) CG&E will not end the MDP for residential customers prior to December 31, 2005. (5) CG&E may end the MDP for all customer classes, except for the residential class, when 20 percent of the load of such class switches the purchase of its generation supply to a certified supplier. This provision is effective only to the extent that CG&E does not possess as an affiliate a retail electric generation provider, selling commodity generation at retail. This paragraph also requires that CG&E measure switching by kilowatt-hour (kWh) for the residential class, and average demand for all other customers. At the end of the MDP for each non-residential rate schedule, the rate freeze on non-switching customers and the rate freeze for transmission, distribution, and ancillary [*11] service on switching customers will end. The shopping credit established at the time of exercising choice for switching customers will continue as a credit on the bills of such switching customers through December 31, 2005, and will not be affected by the end of the MDP; and the RTC will be collected from all non-residential customers pursuant to the stipulation through December 31, 2010. (6) CG&E will make the RTC charge load factor sensitive for rate classes billed on demand/energy rates. The RTC rate design will include a declining block structure where the first kWh per kW of billing demand will recover the RTC charge to the maximum extent possible. (7) The parties agree with and adopt CG&E's independent transmission plan stipulation and CG&E's employee assistance plan stipulation. (8) CG&E's exempt wholesale generator (EWG) is prohibited from selling power to an affiliate for resale at retail in CG&E's service territory, except through CG&E's requirements commodity service agreement (RCSA) and is prohibited from selling to an affiliate certified supplier on more favorable prices or terms than CG&E sells to a non-affiliate certified supplier. The information regarding the [*12] sales or transfers of power and ancillary services by the EWG to an affiliate shall be simultaneously posted with the execution of any agreement for the sale or transfer on a publicly available electronic bulletin board. These provisions do not apply during the MDP to wholesale sales of power and ancillary services from the EWG to CG&E for CG&E standard offer customers under the RCSA. Approval of the stipulations constitutes a finding of fact by the Commission of the items necessary for the Federal Energy Regulatory Commission (FERC) to approve CG&E's EWG and RCSA. Namely: that the transaction under the RCSA will benefit consumers; does not violate any state law; would not provide the EWG any unfair competitive advantage by virtue of its affiliation with CG&E; and is in the public interest. Also, with respect to the transfer of CG&E generation assets to an EWG, allowing such generation assets to be an eligible facility for EWG ownership: will benefit consumers; is in the public interest; and does not violate state law. (9) The following rates and terms, which reflect a five-percent reduction of CG&E's generation component, including RTC, shall be approved for the customers on residential [*13] rate schedules: the shopping credit on the bills of switching customers for the first 20 percent of the load per class for the calendar years 2001-2005 will be 5.0000 cents/kWh. The shopping credit on the bills of switching customers after 20 percent of the load per class switches for the calendar years 2001-2005 will be 3.9407 cents/kWh. For the calendars years 2006-08 all residential customers will pay an RTC rider of 0.6114 cents/kWh. Residential customers will pay no RTC after December 31, 2008. The kWh associated with Percentage of Income Payment Program (PIPP) customers will not be included in the determination of the first 20 percent of the switching customers' load per class. CG&E's EWG will not bid to supply the CG&E PIPP customers if such customers are aggregated and bid out as a group. (10) The shopping credit for secondary distribution small is established as 5.3601 cents/kWh through December 31, 2005, for the first 20 percent of load that switch, and 4.5438 cents/kWh through December 31, 2005, for the remaining 80 percent. The RTC for secondary distribution small is established as 0.9499 cents/kWh from the end of the MDP through December 31, 2010. The shopping credit [*14] for secondary distribution large is established as 4.8145 cents/kWh through December 31, 2005, for the first 20 percent that switch, and 4.2460 cents/kWh through December 31, 2005, for the remaining 80 percent. The RTC for secondary distribution large is established as 0.6719 cents/kWh from the end of the MDP through December 31, 2010. Secondary distribution small and secondary distribution large customers also have an identifiable shopping credit and RTC through December 31, 2010. (11) The shopping credit for primary distribution is established as 3.8877 cents/kWh through December 31, 2005, for the first 20 percent that switch, and 3.5145 cents/kWh through December 31, 2005, for the remaining 80 percent. The RTC for primary distribution is established as 0.4562 cents/kWh from the end of the MDP through December 31, 2010. The shopping credit for transmission is established as 3.27 cents/kWh through December 31, 2005, for the first 20 percent that switch, and 3.0322 cents/kWh through December 31, 2005, for the remaining 80 percent. The RTC for transmission is established as 0.3043 cents/kWh from the end of the MDP through December 31, 2010. The shopping credit for lighting is established [*15] as 3.0057 cents/kWh through December 31, 2005, for the first 20 percent that switch, and 2.8272 cents/kWh through December 31, 2005, for the remaining 80 percent. The RTC for lighting is established as 0.2290 cents/kWh from the end of the MDP through December 31, 2010. Customers with contracts approved pursuant to Section 4905.31, Revised Code, who would otherwise be on the primary distribution, transmission, or lighting rate schedules shall have a one-time right through December 31, 2001, to cancel any such contract without penalty, provided that the customer remains a distribution customer of CG&E. (12) CG&E will maintain certain of its existing contracts with providers of energy efficiency and weatherization contracts until December 31, 2005. (13) The Universal Service Fund (USF) Rider and the Energy Efficiency Revolving Loan Fund Rider will be determined by the ODOD and approved by the Commission. (14) CG&E agrees to accept any resolution of issues agreed to by all Operational Support Planning for Ohio Taskforce (OSPO) working group participants and to incorporate any such changes in its transition plan except with respect to the following: CG&E will establish new minimum [*16] stay rules for residential customers; CG&E will amend its open access transmission tariff to add a new schedule for retail energy imbalance service; CG&E commits to use its best efforts to take the actions necessary to purchase supplier accounts receivable and to provide consolidated bill ready billing and supplier consolidated billing; and CG&E agrees to revise the collateral computation that it will use for establishing a certified supplier's creditworthiness. In addition, large commercial and industrial customers who return to CG&E's standard service offer other than through certified supplier default must provide at least 90-days advance notice to CG&E if they are planning to return to CG&E's standard service offer between May 1 and October 31 of each calendar year. (15) CG&E will waive the switching fee for the first 20 percent of residential customers that switch the purchase of generation supply to a certified supplier during the MDP. (16) CG&E will establish a technical task force to resolve ongoing technical issues that may arise due to restructuring implementation. (17) CG&E will pay $1.5 million in litigation reimbursement to the active intervenor signatory parties. [*17] (18) The parties agree that the stipulation is conditioned upon adoption in its entirety by the Commission without material modification by the Commission and, if the Commission rejects or modifies all or any part of this stipulation or imposes additional conditions or requirements upon the parties, the parties shall have the right within 30 days of issuance of the Commission's order to either file an application for rehearing or terminate and withdraw from the stipulation. B. The Independent Transmission Plan (ITP) Stipulation On May 8, 2000, CG&E filed its ITP stipulation. CG&E's ITP stipulation provides that: (1) The sum of CG&E's transmission and distribution rates shall remain frozen during the MDP such that if CG&E's unbundled transmission rate increases, its unbundled distribution rate shall decrease by the inverse amount. CG&E will also perform and file a FERC seven-factor test by March 31, 2001. (2) Until the Midwest Independent System Operator (MISO) becomes operational, CG&E and its affiliates shall provide for transmission service for both affiliates and non-affiliates on the same terms and conditions, consistent with Open Access Same-Time Information System [*18] (OASIS) and FERC Standards of Conduct. CG&E will also provide distribution service only under the rates, terms and conditions stated in its distribution tariffs. (3) A transmission customer receiving retail commodity service will have the same priority for requesting and receiving network transmission service as an existing network customer under CG&E's open access transmission tariffs (OATT). (4) Retail customers or their certified suppliers who take 138 kV transmission service are entitled to receive either network or firm point-to-point transmission service or any other transmission service for which the customer is eligible. (5) CG&E agrees to participate in the collaborative process under FERC Order 2000, 89 FERC Section 61,285, to discuss integrating the facilities of the transmission-owning utilities in Ohio so as to achieve the objectives listed in Rule 4901:1-20-17(B)(3), O.A.C., and Section 4928.12, Revised Code. To the extent not resolved in the Commission proceeding: In the Matter of the Commission's Investigation Into the Adequacy and Availability of Electric Power for the Summer Months of 2000 from Ohio's Investor-Owned Electric Utility Companies, Case No. [*19] 00-617-EL-COI, CG&E will enter into a joint stipulation with all of the other transmission-owning utilities in Ohio to submit the subject of how to achieve the objectives listed in Rule 4901:1 -20-17(B)(3), O.A.C., and related issues to a separate joint Commission hearing dealing solely with that subject as part of their respective transition plan application proceedings; or if such other transmission-owning utilities will not so agree, to jointly request, together with all of the other intervenors in this case, that the Commission order the other transmission-owning utilities to participate in such a hearing. CG&E will also participate in a statewide collaborative process to resolve the transmission seams issues in Ohio to effectuate the policy objectives of Section 4928.12, Revised Code. C. The Employee Assistance Plan (EAP) Stipulation On May 8, 2000, CG&E filed its EAP stipulation. No parties oppose the EAP stipulation. The EAP stipulation provides that: (1) CG&E's EAP, as originally filed in this case, be found to comply with Section 4928.31, Revised Code, and Rule 4901:1-20-03, O.A.C., Appendix C. (2) The parties who intervened in CG&E's transition plan proceeding [*20] withdraw all of their preliminary objections relating to CG&E's EAP. Specifically, Coalition for Choice in Electricity (CCE) n3 withdraws preliminary objections Section D, including D-1 through D-3, and Industrial Energy Users-Ohio, Cincinnati/Hamilton County Community Action Agency and Supporting Council of Preventive Effort withdraw their adoption of CCE's preliminary objections Section D (3) To the extent that the parties have representatives serving on the electric employee assistance advisory board established under Section 4928.431, Revised Code, the parties agree that their representatives will recommend to the Commission that the Commission approve CG&E's EAP. (4) The parties agree that nothing herein resolves or waives any party's right to present evidence and arguments in these cases regarding CG&E's request to recover costs associated with employee assistance incurred under CG&E's EAP, in accordance with Section 4928.39, Revised Code. - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n3 CCE is composed of The Ohio Manufacturers' Association, The Industrial Energy Users-Ohio, The Ohio Council of Retail Merchants, Ohio Partners for Affordable Energy, Enron Energy Services, Inc., Supporting Council of Preventative Effort, Corporation of Ohio Appalachian Development, New Energy Midwest, LLC, Greater Cleveland Growth Assoc., Ashtabula County Community Action Agency, and WPS-Energy Services, Inc. - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - [*21] III. COMMISSION REVIEW OF THE STIPULATIONS, CG&E'S TRANSITION PLAN COMPLIANCE WITH SECTION 4928.34, REVISED CODE, AND ISSUES RAISED BY PARTIES OPPOSING THE STIPULATIONS. A. CG&E's Operations Support Plan (OSP) On November 30, 1999, the Commission issued an entry in Case No. 99-1141-EL-ORD, directing Ohio's investor-owned electric utilities and interested stakeholders to participate in a taskforce for the development of uniform business practices and electronic data interchange (EDI) standards. Pursuant to this directive, the Commission's staff created the OSPO taskforce. On May 15, 2000, numerous OSPO participants filed a pro forma certified supplier tariff (pro forma tariff) and a stipulation (OSPO stipulation) in each utility's transition plan case. The pro forma tariff contains a number of service regulations on which the parties were able to agree. These relate to: supplier registration and credit requirements, end-use customer enrollment process, end-use customer inquiries and requests for information, metering services and obligations, load profiling and scheduling, transmission scheduling agents, confidentiality of information, voluntary withdrawal by a [*22] competitive retail electric service (CRES) provider, liability, and alternative dispute resolution. In the OSPO stipulation, the parties specifically request the Commission to resolve issues in four general areas: (1) energy imbalance service, (2) minimum stay requirements for residential and small commercial customers returning to standard offer service, (3) consolidated billing and purchase of receivables, and (4) adoption of EDI standards. On May 18, 2000, the Commission issued an entry initiating a generic docket (Case No. 00-813-EL-EDI) to establish procedures for parties desiring to file comments and reply comments regarding the OSPO stipulation and pro forma tariff. On July 20, 2000, the Commission issued a finding and order approving the OSPO stipulation and resolving the four issues left unresolved. Under the transition plan stipulation in this case, CG&E agrees to incorporate into its transition plan, the OSPO stipulation and pro forma tariff with exception of certain terms that the stipulating parties have agreed will apply to CG&E. These terms include: (1) the establishment of new minimum stay rules for residential customers; (2) amendments to CG&E's open access [*23] transmission tariff to add a new schedule for retail energy imbalance service; (3) using CG&E's best efforts to take the actions necessary to purchase certified supplier accounts receivable and to provide consolidated bill ready billing and supplier consolidated billing; and (4) agreeing to revise the collateral computation that it will use for establishing a certified supplier's creditworthiness. Shell contends that allowing CG&E to exempt these four areas from compliance with the OSP stipulation will undermine the entire OSP process, preclude universal practices that the Commission tried to establish through the OSP task force, and will deter the development of effective competition. Under CG&E's minimum stay requirement, during the MDP, a residential customer who takes generation service from CG&E for any part of the period May 15 through September 15 (the stay out period) must remain a standard offer customer through May 14 of the following year before such customer may elect to switch to another supplier, provided that: (1) customers may switch suppliers at any time if they have not previously switched; (2) following the stay out period through the following May 14, returning [*24] customers may switch to another supplier at any time for the remainder of the MDP; and (3) during the first year of the MDP, residential customers returning to CG&E's standard offer service will not be subject to a minimum stay. Further, if a certified supplier defaults, an end-use customer has a one billing cycle time period in which to select another certified supplier. If the end-use customer fails to select another certified supplier by the end of one billing cycle, the end-use customer will remain on CG&E's standard service offcer and be subject to any applicable minimum stay requirement. Shell contends that CG&E's proposed minimum stay requirement violates SB3, as it contends SB3 contemplates no limitation on a residential customer's freedom of movement between service options even if those movements involve a return to standard offer service. Shell also claims that CG&E's minimum stay provision could remove large numbers of such consumers from the competitive market place for substantial periods of time and reduce competition. With respect to the issue of CG&E's minimum stay requirements, we defer to our ruling in our July 19, 2000 finding and order in In the Matter of the [*25] Establishment of Electronic Data Exchange Standards and Uniform Business Practices for the Electric Utility Industry, Case No. 00-813-EL-EDI (hereafter 00-813). In that order, we approved the use of minimum stay requirements conditioned upon the development of a market-based "come and go" rate alternative service. See page 13 of our finding and order in 00-813. We also prohibited the imposition of a mandatory stay when a customer defaults to the utility's standard offer service due to the default of the supplier of electricity. We also established a uniform penalty free return to standard offer service policy and a uniform period throughout Ohio in which companies can impose a summer/stay period of May 16th through September 15th. Accordingly, the Commission will approve the stipulation's treatment of minimum stay requirements conditioned upon certain modification so that CG&E's minimum stay requirements are in compliance with our order in 00-813 and any entry on rehearing therefrom. n4 - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n4 We note that on August 24, 2000, CG&E filed a request for exception in these proceedings regarding minimum stay requirements. Inasmuch as the issue raised in that request are the same issues raised in the company's application for rehearing in 00-813, the Commission will address the issues in the entry on rehearing. - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - [*26] Shell also objected to CG&E's retail energy imbalance service proposal, which it argues would create a narrow energy imbalance bandwidth for transmission scheduling agents. Shell contends that these bandwidths present an intolerable approach to energy imbalances for those transmission-scheduling agents trying to serve weather sensitive residential loads. Shell claims that the stipulation's energy imbalance service proposal would achieve an anticompetitive outcome the Commission should avoid, namely, imbalances as an increasing source of penalty costs for residential marketers and an increasing revenue source for CG&E. Under the transition plan stipulation, CG&E will amend its OATT to add a new schedule for retail energy imbalance service. In addition, CG&E will amend its OATT application procedures to allow a "description of purchased power designated as network resource including source control area location, transmission arrangements and delivery point(s) to the transmission provider's transmission system." CG&E will also amend its OATT to allow transmission customers to designate new resources on a day-ahead basis, provided that there exists available transfer capacity, that it [*27] is subject to the approval of the transmission provider, and that the transmission customer relinquishes network transmission rights to a designated resource once a new resource is designated. On this issue, only Shell is actively opposing the CG&E transition case stipulation while the other intervening marketers signed the CG&E transition case stipulation. Further, Shell offered no evidence at hearing to support its position. We believe that CG&E's proposal for energy imbalances is reasonable. As we noted in 00-318, although a single standard for operations is a goal which we would hope to eventually achieve in Ohio, we recognize that a great many differences currently exist between the electric utilities, who have traditionally operated in isolation with their own unique computer systems and processes, and that some differences will need to be accepted by suppliers if Customer Choice is to become a reality on January 1, 2001. We also considered the fact that each utility will only need to have an energy imbalance mechanism until its transmission assets become part of a functioning RTO, at which time, the RTO would become responsible for energy imbalance service. Since CG&E is anticipated [*28] to be in an RTO by 2001, we do not believe that uniformity with all the other utilities in the interim is crucial to the development of the Ohio choice market with the changes to CG&E's OATT set forth in the stipulation. Therefore, we do not find CG&E's energy imbalance service proposal to be anticompetitive. Shell also raised an issue related to CG&E's proposal for consolidated billing. Under the OSP, CG&E will use its best efforts in taking the actions necessary to implement purchasing of supplier accounts receivable by June 1, 2001, to implement consolidated bill ready billing by January 1, 2002, and to implement supplier consolidated billing by June 1, 2002. These provisions are based on CG&E's best efforts and do not require CG&E to take any action that would hinder or delay the implementation of the competitive framework necessary to facilitate customer choice in its service territory. Further, the implementation of these billing functions is not contingent upon the Commission making a determination under Section 4928.04, Revised Code, with respect to the unbundling of the billing function, but shall proceed independent of any supplier compensation or CG&E credit for such billing [*29] service. Shell contends that the transition plan stipulation makes no provision for a billing credit from CG&E in the event that a customer decides to take its billing services from a third party. Shell argues that it intends to perform consolidate billing for its customers and that permitting a year lag between implementation of utility and supplier consolidated billing would place Shell at a competitive disadvantage against those marketers that rely on CG&E's billing functions. Shell also complains that the consolidated billing proposals would preclude marketers from establishing a communication link in order to build supplier name recognition and consumer loyalty. As we determined in 00-813, we have adopted a target date for consolidate bill-ready billing by no later than June 1, 2002, and a target date for supplier consolidated billing by July 1, 2002. Having determined these dates are reasonable and the fact that CG&E's proposal agrees to dates earlier, we find the stipulated target dates by CG&E are reasonable. Shell contends that CG&E's OSP would impose additional collateral requirements on third-party suppliers beyond those adopted in the OSP pro forma tariff. Shell contends [*30] that the proposed collateral calculation relies too heavily on CG&E-generated usage estimates which, in the case of new market entrants, would amount to guess work. Shell argues that it is unclear how parties could verify either the shopping credit calculations or pricing data used by CG&E to establish these additional collateral obligations. Also, Shell claims that there is no support for why such additional collateral is needed. CG&E notes that its OSP provides for implementing a collateral calculation that will be applicable to certified suppliers who serve retail customers in CG&E's service territory and is intended to cover CG&E's risk as the default supplier. CG&E will calculate the amount of collateral to cover its risk as the default supplier by multiplying 45 days of CG&E's estimate of the summer usage of the certified supplier's customers by a price set at the highest monthly average megawatt hour price for CG&E off-system purchased power from the prior summer less the average shopping credit that CG&E will receive due to the defaulting certified supplier's customers returning to CG&E's standard service offer. On this issue, Shell offered no evidence to support its position. [*31] On review, we find CG&E's proposal quantifiable and not, as suggested by Shell, mere guess work. We also find that a collateral calculation applicable to certified suppliers who serve retail customers in CG&E's service territory will cover CG&E's risk as the default supplier. Finally, CG&E will be expected to be able to verify its charges to any affected certified supplier or retail customer upon request. Based on our findings above, we believe the company's operational support plan set forth in the stipulation, subject to modification to comply with 00-813, is reasonable and appropriately addresses operational support systems and technical implementation procedures. Accordingly, we find the transition plan meets the statutory requirements of Section 4928.34(A)(9), Revised Code. We also note that CG&E's transition plan filing included a proposed billing format. The Commission directs the staff to finalize a bill format which includes a "price to compare" (which is the price for an electric supplier to beat in order for the customer to save money) for residential and small commercial customers. As part of our approval of CG&E's transition plan, the company must meet staff's requirements [*32] regarding billing format. B. CG&E's Unbundling Plan Section 4928.31(A)(1), Revised Code, requires that the filed transition plans contain a rate unbundling plan that separates existing, bundled utility rates into their component parts consistent with the provisions of Section 4928.34(A), Revised Code, and applicable Commission rules. Discussed below are the various requirements regarding unbundling contained in Section 4928.34(A), Revised Code, CG&E's plans for unbundled rates, and AK Steel's objections. Provisions of Section 4928.34(A), Revised Code 1. Unbundled Transmission Component (Section 4928.34(A)(1), Revised Code) Under this section, the Commission must determine whether the unbundled components for the electric transmission component of retail electric service equal the tariff rates determined by the FERC in effect on the date of approval of the transition plan. The unbundled transmission component must include a sliding scale of charges to ensure that refunds determined or approved by the FERC are flowed through to retail electric customers. CG&E states that all stipulating parties have agreed that CG&E's rate unbundling plan satisfies the statutory requirements [*33] of Section 4928.34(A)(1), Revised Code (CG&E Ex. 60 at 3, 5, 6). As described by CG&E witness John P. Steffen, CG&E developed its unbundled transmission and ancillary services rates from CG&E's current FERC approved OATT (CG&E Ex. 12 at 8, 16-18). CG&E's proposed unbundled transmission rates are set out in Schedules UNB-1, UNB-7.1 and UNB-7.2 (CG&E Ex. 23). Consistent with Section 4928.34(A)(1), Revised Code, and Rule 4901:1-20-03, App. A, Part (C)(2), O.A.C., these unbundled components reflect the OATT rates approved by FERC, which rates are currently in effect and are not subject to refund (CG&E Ex. 12 at 7). Consistent with Rule 4901:1-20-03, App. A, Part (C)(2)(a), O.A.C., CG&E has unbundled and set out as separate components in its proposed tariffs, Schedules UNB-1, 7.1 and 7.2, the following ancillary services: (1) Scheduling, System Control and Dispatch, (2) Reactive Supply and Voltage Control, (3) Regulation and Frequency Control, (4) Spinning Reserve, and (5) Supplemental Reserve (CG&E Ex. 23). The rates for these services are based on the FERC rates currently in effect (CG&E Ex. 12 at 7). 2. Unbundled Distribution Component (Section 4928.34(A)(2), Revised Code) This [*34] section requires that the unbundled components for retail electric distribution service in the rate unbundling plan equal the difference between the costs attributable to the Company's transmission and distribution rates based on the Company's most recent rate proceeding, and the tariff rates for electric transmission service determined by the FERC under division (A)(1) of this section. CG&E states that, consistent with Section 4928.34(A)(2), Revised Code, and Rule 4901:1-20-30, App. A, Part (C)(3), O.A.C., the unbundled distribution rate component developed by CG&E is the difference between the sum of the transmission and distribution components of rates in effect on October 5, 1999, as further adjusted to reflect the effect of tax changes attributable to amendment of Section 5727.111, Revised Code, by SB3 and the unbundled transmission rate determined pursuant to Section 4928.34(A)(1), Revised Code (CG&E Ex. 12 at 7). CG&E functionalized costs to generation, distribution, transmission and other costs (CG&E Ex. 12 at 9-11). As with the unbundled transmission rate components, the resultant distribution rates are set out in Revised Schedules UNB-1, UNB-7.1 and UNB-7.2 n5 (CG&E Ex. 23). [*35] - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n5 In the case of customers on special contracts, the charges for distribution, transmission, ancillary services, kWh tax, the universal service fund, and the energy efficiency fund are those charges that would apply if the customer were served on an applicable rate schedule (CG&E Ex. 23, at UNB-7.1 at 17-19). - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - 3. Other Unbundled Components (Section 4928.34(A)(3), Revised Code) This section requires that all other unbundled components required by the Commission in the rate unbundling plan must equal the costs attributable to the particular service, as reflected in the Company's schedule of rates and charges. CG&E contends that, consistent with the provisions of Section 4928.34(A)(3), Revised Code, and Rule 4901:1-20-03, App. A, Part (C)(4), O.A.C., existing rates are unbundled to separate out certain components to be reflected in several riders for CG&E. The stipulations provide for a Universal Service Fund (USF) Rider and an Energy Efficiency Revolving Loan Fund (EERLF) Rider set out in Sections 4928.51 and 4928.61, [*36] Revised Code, for CG&E (CG&E Ex. 60 at 15). On July 13, 2000, ODOD filed an application with the Commission pursuant to Sections 4928.52 and 4928.62, Revised Code, regarding the establishment of USF and EERLF riders. ODOD has determined that the USF rider should be $0.0002442/kWh and that the EERLF rider should be $0.00010758/kWh. Attached to the application were supporting calculations to justify the riders. ODOD has allocated to CG&E $4,900,898 of the total $64.6 million annual target for USF funding and $2,159,262 of the total $15 million annual target for EERLF funding (ODOD application, attachments D and E). In its application, as amended on July 17, 2000, ODOD has requested that the USF rider take effect September 1, 2000, and the EERLF take effect January 1, 2001, both on a bills rendered basis. 4. Unbundled Generation Component (Section 4928.34(A)(4), Revised Code) Prerequisite (A)(4) requires that the unbundled components for retail electric generation service in the rate unbundling plan must equal the residual amount remaining after the determination of the transmission, distribution, and other unbundled components, and after any tax related adjustments as necessary [*37] to reflect the effects of the amendment of Section 5727.111, Revised Code. CG&E states that consistent with the provisions of Section 4928.34(A)(4), Revised Code, the component for retail electric service in CG&E's unbundled rates is the residual amount remaining after determination of the transmission, distribution, and other unbundled components, as further adjusted to reflect the effect of tax changes attributable to amendment of Section 5727.111, Revised Code, by SB3. CG&E states that, as required by Section 4928.40(C), Revised Code, CG&E has calculated a five percent reduction in the unbundled generation component for residential customers. CG&E and the parties to the stipulations have agreed to such an adjustment for residential customers (CG&E Ex. 50 at 11-12). CG&E states that, under the stipulations, it has agreed to forego its statutory right to seek reduction of this discount during the MDP because all shopping credits have been set and fixed during the MDP and are not subject to adjustment (CG&E Ex. 60 at 11-13). 5. Cap on Unbundled Components (Section 4928.34(A)(6), Revised Code) This provision requires that the total of all unbundled components is capped and, during [*38] the MDP, will equal the total of rates in effect on the day before the effective date of SB3. The cap will be adjusted for changes in taxes, the USF rider, and the temporary rider under Section 4928.61, Revised Code. CG&E argues that consistent with Section 4928.34(A)(6), Revised Code, and Rule 4901:1-20-03, App. A, Parts (C)(5)(b) and (D), O.A.C., the total of all unbundled components of the CG&E's unbundled rates are capped, with limited statutory exceptions, during the MDP. CG&E contends that the total of all unbundled components of existing rates equals the rates and charges of the bundled components except for adjustments to reflect changes in taxation effected by SB3, the USF and EERLF riders (CG&E Ex. 12 at 11-12). Further, CG&E states that it initially unbundled existing rates to reflect components representing its transition charges, including separation of RTC and GTC (CG&E Ex. 12 at 31-40; and CG&E Ex. 23 at UNB-1, UNB-7.1). However, the stipulations have substantially modified the originally proposed unbundled rates for RTC and GTC (CG&E Ex. 60 at 11-14). The result of the stipulations is that CG&E is no longer requesting any GTC recovery or generation-related cost deferrals [*39] to the next rate case. Instead, CG&E is requesting an RTC that reflects new and existing regulatory assets approved by the Commission. 6. Compliance with Commission Rules (Section 4928.34(A)(7), Revised Code) This section requires the rate unbundling plan to comply with any rules adopted by the Commission under division (A) of Section 4928.06, Revised Code n6. The rules adopted by the Commission regarding unbundling of rates are set forth in Rule 4901:1-20-03, O.A.C., Appendix A. The portions of the Appendix that address the unbundling of separate rate components are covered in the discussion above of the various rate unbundling provisions included in the Company's plan, as amended by the stipulation. - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n6 Section 4928.06, Revised Code, directs the Commission to enact rules to effectuate commencement of competitive retail electric service. The Commission has enacted rules in compliance with this statute through its various generic rule proceedings. - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - CG&E's compliance with the provisions of Parts (A) through (D) of [*40] Appendix A is discussed in the immediately preceding sections, which address the unbundling of the separate rate components. Compliance with Parts (E), (F) and (G) are addressed by CG&E witnesses Steffen, Morris, Jett, and Pefley and are supported by the UNB schedules, the OSP stipulation in 00-813, and the transition plan stipulation. 7. Elimination of Gross Receipt Tax Effect (Section 4928.34(A)(15), Revised Code) This Section requires that all unbundled components be adjusted to reflect the elimination of the gross receipts tax imposed by Section 5727.30, Revised Code. CG&E states that the stipulations permit CG&E to defer and recover through the RTC the financial reporting impact of the Ohio excise tax overlap (CG&E Ex. 60 at 6; and CG&E Ex. 77 at 4). CG&E believes that this mechanism is envisioned by, and consistent with, the requirements of Section 4928.34(A)(6), Revised Code, which, in part, provide that the effect on customer rates resulting from such tax overlap "shall be addressed by the Commission through accounting procedures, refunds, or an annual surcharge or credit to customers, or through other appropriate means, to avoid placing the financial responsibility for [*41] the difference upon the electric utility or its shareholders." AK Steel's Objections to CG&E's Unbundling Plan AK Steel's primary objection to CG&E's unbundling plan is that CG&E's functional cost-of-service study that is used to unbundle retail rates assigns distribution costs to transmission service voltage customers (rate Schedule TS) who do not use the distribution system. AK Steel states that CG&E's unbundling analysis is based on the CG&E's cost-of-service study submitted by CG&E in its most recent electric rate case in 1992, Case No. 92-1464-EL-AIR (Tr. I at 8). This study is presented in Schedule UNB-4 of the Company's filing in this case. AK Steel states that, as a result of the unbundling analysis required by SB3 and the Commission's regulations, the original cost-of-service study had to be unbundled and functionalized into distribution, transmission, and generation cost functions. Some of the expenses and plant accounts in the original 1992 cost of service study were already reflected on a functionalized basis. For example, direct production plant, distribution plant, and transmission plant were separately identified in the cost-of-service study and allocated to customer [*42] classes on a functionalized basis. Other costs, however, such as administrative and general expenses (A&G) were not functionalized in the original study, since there was no need to do so in order to produce bundled rates. To fully functionalize all costs, in order to develop unbundled rates, AK Steel contends it was necessary for the Company to develop a functional analysis of the remaining expenses and plant accounts; principally, A&G expenses, general and intangible (G&I) plant, common plant, and property taxes. AK Steel argues that, although CG&E's functional cost analysis is based on the 1992 cost-of-service study (UNB Schedule 4), AK Steel witness Baron testified that CG&E has erred in the development of its unbundled distribution, transmission and generation costs because it has inappropriately functionalized A&G expenses, property taxes, G&I plant, and common plant. AK Steel believes that the errors associated with this misfunctionalization produce unjust and unreasonable rates, particularly for the transmission service class (AK Steel Ex. 13 at 41). For example, AK Steel contends that CG&E has produced unbundled tariffs for the transmission service voltage class that include [*43] a distribution charge when there are no distribution costs associated with serving this class (Tr. I at 71). CG&E's proposed unbundled tariff for Rate Schedule TS reflects a charge of $0.502 per kW for distribution service. According to AK Steel, the distribution rate for Rate Schedule TS should be $0 (AK Steel Ex. 13 at 9). AK Steel contends that in the 1992 cost-of-service study there were 34 customers taking service on Rate Schedule TS. Those customers were assigned $15,746 of net distribution plant costs, exclusively associated with meters. No such equipment (other than $15,746 of meters) is required to serve the 34 TS customers. In its unbundling analysis, CG&E assigned $473,979 to Rate Schedule TS for G&I plant associated with distribution (Tr. I at 72). The Company assigned $473,979 of G&I plant to support a distribution investment of $15,746 (Tr. I at 73). According to AK Steel, this amounts to a G&I support ratio of 30 times the underlying distribution net plant. AK Steel further argues that CG&E only assigned $361,244 of general and intangible plant to the Secondary Distribution Small customer class to support over $27 million in distribution net plant (Tr. I at [*44] 73). The G&I support ratio for this class is .013 or 1.3 percent. AK Steel asserts that similar implausible results are produced in the Company's analysis of A&G expenses that support distribution costs. In the development of its unbundled rates in this proceeding, the Company has assigned $485,569 of customer account expense to rate schedule TS to service 34 transmission service customers (Tr. I at 6-12). At the same time, the Company has assigned $370,077 to the Secondary Distribution Small class to support customer billing for 31,000 customers (Tr. I at 79). AK Steel argues further that, in CG&E's unbundling analysis, the Company has calculated that $2,231,007 of property taxes (out of this $6.2 million total) is associated with distribution property for Rate TS, even though it only has $15,746 of net distribution plant that is associated with meters. According to witness Baron, the underlying allocation of costs that is reflected in current bundled rates (from the 1992 cost of service study) is the appropriate source to functionalize costs for use in unbundling in this proceeding. AK Steel requests that CG&E's unbundling and functional cost analysis be rejected. AK Steel [*45] also argues that, should the Commission find that CG&E is entitled to receive regulatory transition costs, these charges must be allocated on a cost-of-service basis. Commission Conclusion CG&E and our staff argue that AK Steel's arguments against the Company's rate unbundling plan are without merit. After reviewing the arguments, the Commission agrees. As testified to by Company witness Steffen, CG&E began its rate unbundling with its current transmission and distribution revenue requirements which were computed based upon a functionalization review of the cost-of-service study in CG&E's last rate case, Case No. 92-1464-EL-AIR (CG&E Ex. 12 at 8-9). The revenue requirements were adjusted for the effects of SB3 tax changes. Following the formula set forth in SB3, CG&E subtracted the transmission component revenue requirement, determined by applying FERC tariff rates pursuant to Section 4928.34(A)(2), Revised Code, from the combined transmission and distribution revenue requirement, to arrive at the unbundled distribution component revenue requirement (CG&E Ex. 23 at UNB-6.1 at 11). Company witness Steffen, at hearing, stated that the unbundled costs are a direct result of following [*46] the statutory requirements of SB3 (Tr. I at 75). We find that the unbundling plan agreed to by the parties to the transition plan stipulation is reasonable and consistent with Section 4928.34, Revised Code. To adopt AK Steel's position would result in altering the cost allocations established in the 1992 rate proceeding and shift costs among the different rate classes in a manner not intended by the legislation. Adoption of AK Steel's recommendations could result in rates for certain classes that may exceed the statutory cap set forth in Section 4928.34(A)(6), Revised Code. The evidence of record shows that the unbundling plan proposed by the Company follows the intent of Section 4928.34, Revised Code. In unbundling the rates for each customer class, the Company had to follow the requirements of SB3, which not only dictated the unbundled transmission rate to be a FERC rate, but also necessitated the use of the CG&E 1992 cost-of-service study. Although certain allocations of costs may appear to be incongruous, we find that CG&E has followed the statutory scheme in unbundling its rates. Further, one of the purposes of this proceeding is to establish unbundled rates based on the already [*47] adopted cost-of-service study, not to alter that study or to determine whether a more appropriate allocation of costs should be used to unbundle rates. To do so would clearly be inconsistent with the mandate of Section 4928.34(A)(6), Revised Code, which requires the unbundling of the rates in effect on the day before the effective date of SB3. We also find that the transition charges for each class proposed in the stipulation reflect the cost allocations from the Company's last rate case and, accordingly, are based on the 1992 cost-of-service study. Therefore, we find such allocation of regulatory transition costs to be reasonable. With regard to the establishment of the USF and EERLF riders, we note the Commission by entry issued on August 17, 2000 approved a USF rider for CG&E of $0.0002442/kWh effective September 1, 2000, and a EERLF rider of $0.00010758/kWh effective January 1, 2001. After reviewing the testimony and exhibits submitted by CG&E that support the proposed unbundled rates, and having considered and rejected the objections and arguments raised by AK Steel, we find that the Company has satisfied the statutory requirements for the unbundling of rates set forth in divisions [*48] (A)(1) to (7), (15) of Section 4928.34, Revised Code. C. Transition Revenues Section 4928.34 (A)(12), Revised Code, requires that the transition revenues authorized under Sections 4928.31 to 4928.40, Revised Code, must be the allowable transition costs of the Company pursuant to Section 4928.39, Revised Code, and that the transition charges for customer classes and rate schedules are the charges under Section 4928.40, Revised Code. Section 4928.39, Revised Code, requires the Commission to determine the total allowable amount of the Company's transition costs to be received by the Company as transition revenues. Such transition costs must meet the following criteria: (1) The costs were prudently incurred. (2) The costs are legitimate, net, verifiable, and directly assignable or allocable to retail electric generation service provided to electric consumers in this state. (3) The costs are unrecoverable in a competitive market. (4) The utility would otherwise be entitled an opportunity to recover the costs. Section 4928.40(A), Revised Code, provides, among other things, that a company may create additional regulatory assets, with notice and an opportunity to be heard [*49] through an evidentiary hearing, as long as the company does not increase the level of regulatory transition charges above those contained in the company's existing rates. CG&E's request for transition cost recovery in its original transition plan filing totaled $1.518 billion, including carrying charges of $311 million, and deferral and recovery of $280 million of transition implementation costs, including carrying charges, until its next distribution rate case (CG&E Ex. 65 at Ex. WPLJP-8a). CG&E's request included $563 million of generation plant transition costs (CG&E Ex. 13 at 12). Furthermore, CG&E sought the right to modify its request for transition revenues for the costs of power purchased to provide reliable service. According to CG&E, the stipulations significantly modify and reduce CG&E's request for transition cost recovery to $884 million plus carrying costs and purchased power deferrals necessary to maintain an adequate operating reserve margin (CG&E Ex. 77 at 4-5, Ex. LJP-R-1, Ex. LJP-R-2). The transition plan stipulation provides CG&E with no GTC recovery and places the electricity market price risk entirely on CG&E. The stipulations do provide CG&E recovery of [*50] previously approved regulatory assets totaling $401 million and new regulatory assets totaling at least $483 million (CG&E Ex. 60 at 6-7; CG&E Ex. 50 at Ex. JPS-SUP-5; and CG&E Ex. 77 at Ex. LJP-R-2). CG&E states that the difference between CG&E's original request for $364 million of previously approved regulatory assets and the request, as modified by the stipulations, of $401 million is broken down as follows: $26,571 for grossed-up carrying charges recommended by staff in its Staff Report; an adjustment of $1,548,386 for regulatory liabilities for three percent and four percent investment tax credit related to generation; an adjustment to the Statement of Financial Accounts Standards (SFAS) 109 balance of $27,299,428 to properly reflect IRS normalization rules; an adjustment to restore the regulatory asset balance previously reduced by CG&E due to staff's recommendation F-9 on page 30 of the Staff Report for franchise and municipal taxes; and an update from estimated to December 31, 1999 year end balances (CG&E Ex. 50 at 43-44, and Ex. JPS-SUP-5). The new regulatory assets requested include the $115 million, before carrying costs, of transition implementation costs for which [*51] CG&E originally sought deferral, and deferral of the shopping incentive, Ohio excise tax overlap, and purchased power costs n7 (CG&E Ex. 12 at JPS-5; CG&E Ex. 60 at 6-7, and CG&E Ex. 77 at 3-5, LJP-R-1). - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n7 The $115 million of new regulatory assets includes $3 million for Transition Plan Case expense, $50,000 for the Commission Transition Cost Consultant, $4.6 million for the Commission mandated Consumer Education Program costs, $65 million for upgrades to CG&E's information and customer service systems, $15 million of otherwise unrecoverable costs associated with the MISO, and $28 million of costs to establish the EWG (CG&E Ex. 12 at Ex. JPS-5). - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - Set forth below are the issues and objections raised by AK Steel and Shell to the establishment of regulatory transition charges and the recovery of transition revenues as proposed by the parties to the transition plan stipulation. 1. Stranded Generation Benefits AK Steel argues that, while CG&E has withdrawn its claim for GTC and now claims only RTC costs, an [*52] analysis of the generation costs shows that CG&E has stranded generation benefits which must be "netted" against any RTC claimed by the CG&E. AK Steel argues that stranded benefits occur when unregulated market prices will be so high as to provide excessive returns on the investments made under regulation. According to the testimony of AK Steel witness Falkenberg, these stranded benefits amount to $957 million (AK Steel Ex. 15 at 64). Mr. Falkenberg testified that when only three mistakes in the CG&E study were corrected, the Company had stranded generation benefits (Id. at 49). Mr. Falkenberg also took issue with CG&E's market price model used to determine the value of generation assets. Mr. Falkenberg developed an independent market price and stranded cost forecast that was substantially different from that developed by CG&E witness Pifer. Mr. Falkenberg testified that only three variables are key in the determination of market price forecasts. They are: (1) fuel prices; (2) cost of new capacity; and (3) reserve margins (Id. at 10). Mr. Falkenberg testified that recent natural gas prices from futures contracts and current trading illustrates that gas prices used in CG&E [*53] forecast are simply too low. With regard to forecasting cost and performance of new merchant plants, Mr. Falkenberg pointed out that Dr. Pifer's study erred in its computation of the real fixed charge rate, the variable that determines the annual cost of ownership of new plants, and has a direct impact on market prices. Mr. Falkenberg contends that Dr. Pifer's forecast understates these costs by 16 percent (AK Steel Ex. 15 at 38). Mr. Falkenberg contends that this mistake alone overstates CG&E's stranded costs by $183 million in Dr. Pifer's study (Id. at 39). On the subject of reserve margins, Mr. Falkenberg presented a forecast premised on a 15 percent reserve margin, a level Mr. Falkenberg considers reasonable and the consensus of experts' opinions (AK Steel Ex. 15). This is in contrast to Dr. Pifer's Energy Only (no reserve margin) market concept. Mr. Falkenberg argues that Dr. Pifer's analysis suggests that reliability will be just fine as reserve margins drop to two percent in the years ahead. Beyond the market price model, AK Steel argues that CG&E ignores the plants that, even under its own calculations, have stranded benefits. According to Dr. Pifer's study, only the Zimmer [*54] and Woodsdale combustion turbine generators have stranded costs. Mr. Falkenberg calculated what he believes to be stranded generation benefits of $957 million as summarized on AK Steel Ex. 8. AK Steel argues that Section 4928.39, Revised Code, requires the transition cost must be "legitimate, net, verifiable, and directly assignable or allocable to retail electric generation service." AK Steel contends that any regulatory transition costs the Commission approves would have to be netted against stranded generation benefits. Another problem with the Company's forecast, according to AK Steel, is that CG&E witness Speyer uses a carbon tax on coal that he presumes will add more than a billion dollars in costs to the CG&E generators. Mr. Falkenberg testifies that this assumption is speculative and biased inasmuch as no one knows what the U.S. Senate will do about global warming, or if the utility industry will even be affected (AK Steel Ex. 15 at 7-8 and 41-48). As a result, AK Steel contends that the CG&E study overstates stranded costs by $350 million (AK Steel Ex. 15 at 48). AK Steel argues that, if these mistakes and other biases were corrected, the CG&E study would replicate [*55] the results of Mr. Falkenberg's study that shows the Company has $957 million in stranded benefits (AK Steel Ex. 8). Shell supports AK Steel's arguments regarding stranded generation benefits. Shell argues in its objection and on brief that the stipulation's approach to transition costs fails to demonstrate that the amount of stranded costs recovered (whatever it might be) is a "net" figure, i.e., the result of considering both losses and gains realized as a result of transitioning to a competitive market place. Shell disagrees with CG&E's position that, because SB3 does not make reference to transition benefits or negative transition costs, there is no legal requirement for such an offset. Further, Shell disagrees with CG&E's position that the word "net" in SB3 does not imply offsetting market valuations below book value on some plants with market valuations above book value on others. Shell argues that the testimony of Mr. Falkenberg illustrates that, far from having stranded generation costs, the market value of CG&E's generation portfolio substantially exceeds its book value, thereby providing the utility a market premium. Shell argues that the stipulation fails to satisfy [*56] one of the statute's fundamental criteria for transition cost approval, provides a potential windfall to CG&E in the form of generation premiums and inflated transition cost recoveries, and dramatically disadvantages ratepayers. Shell also argues that the stipulation, if approved, would deny ratepayers a share of the market premium associated with generation assets. According to Shell, these generation assets have a book value of approximately $1.59 billion (Shell Brief at 39). Shell contends that, if CG&E transferred these assets to an EWG, it would substantially harm ratepayers by denying them any share of the market premium associated with this portfolio of generation assets. Shell argues that in originally valuing its generation assets for GTC purposes, CG&E relied on unrealistically low projections of future wholesale power market prices which is the most significant factor in valuing generation assets. Shell states that, from a review of Company Ex. 33, Ex. HWP-2, 1 of 1, the firm power price assumed in 2001 by CG&E's analysis contrasts sharply with CG&E's own recent purchase power costs of $0.0297 in 1998 and $0.0334 in 1999. Shell believes that a wholesale market price [*57] substantially higher than that utilized by CG&E is needed to adequately value the utility's generation portfolio. Shell submits that by simply employing a wholesale market price projection more in keeping with CG&E's own actual recent experience in wholesale power markets would greatly reduce, if not eliminate completely, the supposedly uneconomic generation costs identified by CG&E's analysis. Shell also contends that CG&E's analysis contains several other dubious assumptions that, when corrected, produce even larger stranded benefits. For example, CG&E discounts the projected earnings streams for its generating plants using a 13.63 percent equity cost and a capital structure comprised of 49 percent equity and 51 percent debt. Another questionable assumption, according to Shell, concerns the retirement dates for the Beckjord, Conesville, Stuart, and Zimmer generating plants. CG&E owns each of these plants in partnership with American Electric Power's (AEP) subsidiary, Columbus Southern Power Company. CG&E has assumed much earlier retirement dates than those that were assumed by AEP's Transition Plan filing (Case Nos. 99-1729-EL-ETP and 99-1730-EL-ETP). CG&E disputes the finding of [*58] Mr. Falkenberg and disagrees with the arguments raised by AK Steel and Shell. CG&E contends that Mr. Falkenberg's future fuel price assumptions lack reliability. CG&E argues the single most significant variable in the forecast is future natural gas prices. CG&E states that low price gas forecasts tend to increase the calculated stranded costs, while high price gas forecasts tend to decrease stranded costs. CG&E states that Mr. Falkenberg relies upon the Energy Information Agency's (EIA) Annual Energy Outlook, 2000 (AEO 2000) forecast as his sole source of fuel price information. CG&E argues that there are several other more credible fuel forecasts. Each of the other forecasts project lower future fuel prices than AEO 2000. CG&E also contends that Mr. Falkenberg did nothing to compare AEO 2000 to the other various forecasts that are credible, or even to evaluate the historical accuracy of any of these forecasts (Tr. IV at 149, 156). Additionally, both AEO 2000 and AEO 1999 demonstrate that EIA's forecasts tend to be considerably higher than other fuel forecasts that Mr. Falkenberg himself concedes are credible (Id. at 150-154, CG&E Ex. 73 at 99). EIA's average forecast price at [*59] the wellhead demonstrated an average absolute percentage forecast error of 72.2% (Tr. IV at 160-164; and CG&E Ex. 67 at 81, 84, 90). CG&E argues that Mr. Falkenberg's market structure assumption is equally biased, and ignores the laws of economics altogether. As an economist, Dr. Pifer assumed that market forces, the laws of supply and demand, will ultimately determine the price at which electricity will be sold in the future, and that this price will reflect whatever reserve capacity market participants are willing to pay. Mr. Falkenberg, however, opines that these economic market forces should be ignored, and instead asserts that a 15 percent reserve margin must be factored into the market structure analysis. CG&E argues that the effect of Mr. Falkenberg's 15 percent reserve requirement assumption is that prices, and thus utility income, are assumed to be higher than the economic laws of supply and demand would otherwise dictate (Tr. IV at 178). CG&E asserts that Mr. Falkenberg did not evaluate the risk of future environmental regulation as it relates to the potential increased costs of NOx, SO2, PM 2.5, or Mercury regulations. Mr. Falkenberg evaluated only the risk of future tightened [*60] CO2 restriction resulting from implementation of the Kyoto protocols currently under consideration by the U.S. Senate to reduce greenhouse gases (Id. at 127-129, 168). CG&E contends that Mr. Falkenberg has assumed that no increased environmental regulation, of any sort, is likely, despite his failure to evaluate what these other environmental regulations might be. CG&E also notes that Mr. Falkenberg himself concedes that, by comparison to EIA, Mr. Speyer's use of a $10 per ton figure is conservative. CG&E argues that Mr. Falkenberg's testimony regarding the existence and amount of stranded costs, or stranded benefits, is simply not credible and should be ignored. With regard to the issue of netting of market premiums against transition costs raised by Shell and AK Steel, CG&E argues that SB3 provides it an opportunity to recover its revenue requirement through the transition charge from customers that choose to switch electric suppliers and that the netting recommendation contradicts the ratemaking statutes in effect and newly created SB3. Under the framework of these laws, unbundled rates plus transition charges must give CG&E the same opportunity to collect its revenue requirement [*61] as CG&E has under its current bundled rates. CG&E argues that, by basing its transition charge on the net market value of all of CG&E generation assets as proposed by AK Steel and Shell, the Commission would be denying CG&E an opportunity to collect its revenue requirement associated with the Commission approved book value of assets from CG&E's last rate case and with previously approved regulatory assets. CG&E also contends that, although it is not requesting to recover any GTC as part of the stipulation, that amount was fully netted (CG&E Ex. 22 at HWP-5 at 6; CG&E Ex. 13 at LJP-1; and CG&E Ex. 50 at JPS-SUP-6). After considering the arguments raised above, the Commission comes to the conclusion that CG&E has put forth sufficient evidence to support its argument that there are no stranded generation benefits that should offset the regulatory transition cost proposed by the stipulations. The Commission finds that Dr. Pifer's market forecast for electric power and future fuel price forecasts is reasonable. Dr. Pifer based his future fuel prices on a broader based analysis than that used by Mr. Falkenberg and, therefore, should have a greater degree of reliability. Further, the record [*62] shows that the EIA has had problems with accurately forecasting coal and natural gas prices used in its Annual Energy Outlook. We also believe Dr. Pifer's market structure assumptions are reasonable. Dr. Pifer assumed that market forces, the laws of supply and demand, will ultimately determine the price at which electricity will be sold in the future, and that this price will reflect whatever reserve capacity for which market participants are willing to pay. The use of a 15 percent reserve margin used by Mr. Falkenberg is unlikely to hold true in a competitive market. We further find that changes in environmental regulation that could occur may have an affect on market forecasts and should appropriately be considered as Mr. Speyer has done. From the evidence presented, Mr. Speyer's estimated costs of environmental compliance is conservative and not unreasonable. With regard to the issue of "netting" stranded generation benefits, believed to exist by AK Steel and Shell, with stranded regulatory costs, the Commission finds that the stipulation provides an equitable resolution of this matter. The Company has agreed to forego asserting a claim for stranded generation costs that they calculate [*63] on brief to be approximately be $470 million on a netted basis (CG&E Reply Brief at 22; CG&E Ex. 22 at HWP-5 at 6; CG&E Ex. 13 at LJP-1 at footnote 3; and CG&E Ex. 50 at JPs-SUP-6). Further, the parties to the stipulation have agreed, based on all the terms and conditions that are set forth in the stipulation, that there is no further netting or adjustments of any kind to CG&E's transition cost recovery that are necessary (CG&E Ex. 60 at 7). Additionally as discussed above, the Commission does not agree with Mr. Falkenberg's stranded benefit analysis and, therefore, cannot find that there are stranded benefits that exceed the amount of the GTC that CG&E has agreed to forego recovery of as part of the stipulation. Based upon the above finding, the Commission finds that there are no stranded generation benefits that should offset the regulatory transition cost proposed by the transition plan stipulation. 2. Existing Regulatory Assets AK Steel takes exceptions with a number of accounting treatments used by CG&E in calculating its existing regulatory assets to be recovered in its RTC. AK Steel argues that the Company mischaracterized the accumulated deferred income taxes (ADIT) as [*64] a component of the GTC rather than the RTC. According to AK Steel witness Kollen, the ADIT is a regulatory liability that should be subtracted from regulatory assets and provided to ratepayers through a reduced RTC rather than the GTC (AK Steel Ex. 14 at 21). Mr. Kollen also states that the FERC Uniform System of Accounts classifies ADIT as a "Deferred Credit," not as "Utility Plant" and, therefore, CG&E accounting is not consistent with the FERC accounting standards. AK Steel argues that the Commission should recognize the Company's ADIT associated with all its generating units as a regulatory liability and reduce the Company's regulatory asset transition cost claim to be recovered through the RTC, regardless of whether the Commission accepts or rejects the stipulation. AK Steel also argues that the SFAS 109 regulatory tax assets and liabilities must be stated on a net present value basis because there are no carrying costs associated with these future taxes under existing cost-based regulation (AK Steel Ex. 14 at 25). Further, AK Steel takes issue with the Company's proposal to include in the distribution component of unbundled rates a hypothetical SFAS 109 regulatory asset for [*65] municipal and franchise tax temporary differences the Company projects will exist in 2002. AK Steel argues that the Company has acknowledged that it will not record and is not required to record such a regulatory asset at December 31, 2000 (AK Steel Ex. 14 at 25-26). Thus, according to AK Steel, it would be absurd to allow the Company to create a hypothetical SFAS 109 regulatory asset at December 31, 2000, that will not exist at that date and then to recover this hypothetical cost from ratepayers in the distribution component of unbundled rates. AK Steel also disagrees with the Company's excess deferred income tax (EDIT) and the related SFAS 109 tax benefits. The Company has removed the entirety of the EDIT tax benefits from the ADIT component of its net book value computations; thereby increasing its generation transition costs claims. AK Steel argues that the EDIT amounts represent taxes prepaid by ratepayers at tax rates higher than they are currently. Historically, these EDIT prepaid taxes benefits were amortized back to ratepayers over the remaining lives of the underlying assets. The Company removed EDIT benefits of $11.378 million (AK Steel Ex. 14 at 28). In addition, AK Steel [*66] argues that the removal of the EDIT regulatory liability from the ADIT utilized by the Company in its SFAS 109 regulatory asset computations improperly increased the Company's SFAS 109 regulatory asset transition cost claim by $19.186 million on a nominal dollar basis, or $8.068 million on a net present value basis (AK Steel Ex. 14 at 28). AK Steel contends that the EDIT and the related SFAS 109 tax benefits belong to ratepayers pursuant to existing cost-based regulation (AK Steel Ex. 14 at 29 and Tr. VI at 33-34). According to AK Steel, the Commission should reject the Company's attempt to unilaterally appropriate these regulatory liabilities in order to increase its claimed regulatory asset transition costs. Similar to the EDIT, AK Steel argues that the Company failed to reduce its regulatory or generation transition cost claims by the net present value of its investment tax credit (ITC) amounts. AK Steel argues that the ITC and the related SFAS 109 tax benefits belong to ratepayers pursuant to existing cost-based regulation (AK Steel Ex. 14 at 35 and Tr. VI at 33-34). AK Steel requests the Commission reject the Company's attempt to unilaterally appropriate these regulatory liabilities [*67] in order to increase its claimed regulatory asset transition costs. AK Steel also argues that there will be no normalization violation if the Commission provides the ADIT, EDIT, ITC, and related SFAS 109 regulatory liability tax benefits to ratepayers through the RTC. Mr. Kollen stated that the normalization requirements of the Internal Revenue Code of 1986, as further described in the IRS regulations and as further interpreted for specific taxpayers in the IRS Private Letter Rulings, provide that there is no normalization violation if such ADIT benefits are provided to ratepayers no more rapidly than the time period over which the underlying costs are recovered through regulated rates. All transition costs allowed by the Commission in this proceeding will be recovered in ten years or less which is more than the recovery of generation transition costs of five years or less under a GTC. Lastly, AK Steel requests that, if the Company sells its generating assets, then the related SFAS 109 amounts will be reversed (eliminated) from the balance sheet, with no gain or loss recognized. Thus, the unamortized SFAS 109 regulatory asset transition cost balance as of the date of the sale should [*68] be removed from the RTC. The Commission should establish this treatment in its order in this proceeding in order to assure that ratepayers are not penalized in the event of a sale of the generating assets (AK Steel Ex. 14 at 18-19). CG&E witness Mr. Hriszko disagrees with Mr. Kollen's characterization of the ADIT. Mr. Hriszko testified that the IRS views ADIT as an interest-free loan from the federal government (CG&E Ex. 76 at 3). Similarly, Mr. Kollen's treatment of EDIT balances in the Company's SFAS 109 computation cannot be justified according to CG&E. Congress established specific rules concerning how the benefits of EDIT were to be shared between ratepayers and shareholders. CG&E argues that these rules would be violated by the treatment that Mr. Kollen proposes (Id. at 8). Mr. Hriszko states in his rebuttal testimony, that the adjustments that Mr. Kollen proposes violate the tax normalization rules. The IRS has ruled that, where the cost of property is no longer included in the calculation of cost of service for ratemaking purposes, the inclusion of tax benefits from such property is a violation of the tax normalization rules (CG&E Ex. 71 at 31). CG&E believes it is clear [*69] that the Ohio General Assembly has directed this Commission to resolve deregulation issues now so that deregulation of the generation market occur within Ohio no later than January 1, 2001. Thus, according to CG&E, the Ohio General Assembly clearly contemplated that the current IRS position regarding tax treatments of these items would control, and that CG&E would necessarily set its regulatory asset balances recognizing the existing position of the IRS. CG&E disagrees with Mr. Kollen's treatment of SFAS 109 regulatory asset for municipal and franchise tax temporary differences. CG&E argues that Section 4928.34 (A)(6), Revised Code, expressly allows the Company to recover costs associated with statutory tax changes and that it is following the recommendation for collection of such assets set forth in the Staff Report. The Commission finds that $401.4 million for jurisdictional regulatory assets quantified by CG&E witness Steffen is reasonable and based upon the Staff Report adjustments to the Company's original transition plan filing (CG&E Ex. 50 at JPS-SUP-5 at 1). We find that the tax-related adjustments to these regulatory assets proposed by AK Steel witness Kollen would not be [*70] in keeping with the tax normalization rules established by the IRS. As Mr. Hriszko testified, Mr. Kollen's proposal would decouple tax attributes from the assets that generated the tax attributes, namely generation plants. By offsetting these tax attributes against regulatory assets, a pattern would be established that would return these tax attributes to the ratepayer over a period of time that is different than the period of time over which the tax attributes would normally reverse (CG&E Ex. 76 at 2). Accordingly, we will not adopt the adjustments to the RTC proposed by Mr. Kollen above. The Commission has already approved $401 million of CG&E's regulatory assets and, therefore, found that amount prudent. The testimony of CG&E witnesses Steffen and Pefley support findings that such transition costs were prudently incurred; legitimate, net, verifiable, and directly assignable or allocable to retail electric generation service; are unrecoverable in a competitive market, and that the utility would otherwise be entitled an opportunity to recover the costs. 3. CG&E's Request to Defer and Recover Certain Costs as Regulatory Assets The parties to the transition plan stipulation have [*71] requested accounting authority to create the necessary regulatory assets, defer the costs of those assets, and recover them through an RTC. Such costs are associated with purchased power, litigation of this proceeding, establishing an EWG, and shopping incentives, among others. AK Steel contends that many of the items in the stipulation that CG&E seeks to have accounting authority to defer and recover as regulatory assets do not meet the criteria established for transition costs under Section 4928.39, Revised Code, as discussed above. Set forth below are the objections raised by AK Steel and Shell, the responses to those objections, and the Commission's findings. Objections of AK Steel and Shell One of the costs which CG&E is asking to be deferred as a transition cost is purchased power costs sufficient to maintain an adequate operating reserve margin as determined by CG&E. AK Steel argues that CG&E does not show anywhere in its transition plan filing or stipulation the amount of money claimed, forecasted, or desired for purchased power. AK Steel also argues that, since the 1999 fuel and purchased power costs, including the summer 1999 price spikes, are already being recovered [*72] in the EFC, a separate deferral of purchased power costs clearly would be a double and improper recovery. AK Steel witness Baron testified that there is no basis to determine that these costs are prudently incurred. Neither are these purchased power costs directly assignable or allocable to retail electric generation service provided to electric consumers who shop. Under the stipulation, deferred purchased power expenses will be charged to all ratepayers through the RTC, both those who shop and those who remain CG&E customers. AK Steel witness Baron believes that, under traditional standard ratemaking methodologies, shopping customers who do not impose any purchased power expenses on CG&E should not be assigned these costs, contrary to the stipulation. AK Steel next takes issue with CG&E's proposals to pay $1.5 million in litigation reimbursement to be shared, and agreed upon, by, and among, active intervenor signatory parties to the stipulation. The intervenors are given voting rights to be used to disburse the money with agreement of 75 percent of the active parties constituting a binding vote as to reimbursement. AK Steel argues that this proposal is inappropriate and illegal [*73] and does not comply with Section 4928.39, Revised Code. AK Steel further asserts that the costs are not prudently incurred, because the Company is not obligated or required in any case to pay the legal fees of its opponents but only its own legal fees. AK Steel knows of no past precedent to allow a public utility to pass on to its ratepayers the legal costs of intervenors. AK Steel's third issue concerns the deferral and recovery of $28 million associated with CG&E's plan to sell off all its generating units to an affiliated EWG. The costs are for start up and debt financing and refinancing (Tr. I at 52). AK Steel witness Kollen testified that these costs are discretionary and are not required by SB3. Thus, the costs cannot be considered just and reasonable transition costs as a threshold matter. Further, Mr. Kollen contends that the costs to establish an EWG are not directly assignable or allocable to retail electric generation service inasmuch as it is not a retail service (AK Steel Ex. 13 at 36). AK Steel further argues that CG&E may not incur most of these costs if CG&E is able to release the generation assets from its existing first mortgage obligations without having to redeem [*74] the first mortgage bonds. AK Steel claims that this would save the Company $22.5 million dollars of the $28 million dollars requested for EWG transaction costs (Tr. III at 40). AK Steel's final issue in this area concerns the overstatement of deferred shopping incentive transition costs and its affect on the determination of whether the Company will over recover transition cost over the next ten years. AK Steel disputes CG&E's quantification of the level of transition revenues and transition costs that would be recovered as result of the stipulation. CG&E submitted the testimony of witness Pefley to show the level of transition costs that the Company will actually recover as a result of the stipulation (CG&E Ex. 77, LJP-R-2). Based on this analysis, the Company claims that it will under-recover approximately $153 million through the year 2010 under the Stipulation (Tr. VI at 2). Among the costs included in the Company's analysis are the amounts for regulatory assets claimed by CG&E in its original filing and supplemental filings ($401.4 million), as well as $115.6 million of implementation costs, $34.5 million of Ohio excise tax overlap, and shopping incentives of $333 million. [*75] AK Steel witness Baron developed an analysis that estimates the level of RTC revenue recovery on a present-value basis. Mr. Baron calculated that the Company will recover RTC revenues of $651,257,591 on a present-value basis if the stipulation is approved and implemented by the Commission (AK Steel Ex. 13 at 67). This $651 million revenue amount far exceeds the regulatory assets that the Company has claimed in its filing ($401 million) or the regulatory assets that AK Steel witness Kollen has developed for CG&E ($12 million) (AK Steel Ex. 13 at 67). AK Steel argues that, of all the costs included in the Company's analysis that it relies on to support the stipulation, the $333 million of shopping incentives is the most unreasonable. AK Steel defines a shopping credit as the additional amount of payment necessary to induce a customer to leave the incumbent utility (CG&E) and use an alternative supplier. AK Steel argues that the Company uses this exaggerated shopping incentive quantification to argue that the stipulation produces transition revenues that are lower than its claimed transition costs. AK Steel argues that CG&E has calculated shopping incentives for the first 20 percent [*76] of customers in each customer class based on a comparison of the shopping credits paid to such customers and the Company's estimated market price, as developed by CG&E's witness Pifer. AK Steel argues that when the shopping incentive quantification used by CG&E is corrected to reflect the actual shopping incentives provided to the first 20 percent of each customer class, the Company's analysis falls apart. Mr. Baron developed the shopping incentives using the difference between the RTC that all customers will pay and the RTC net of shopping incentives that is offered to the first 20 percent of each rate class. AK Steel argues that using this interpretation of the shopping incentive produces a shopping incentive cost to CG&E of $135.8 million, instead of the Company's $333 million amount. When this value is substituted into Ms. Pefley's analysis of transition costs, it shows that CG&E will actually overrecover $425.7 million by the end of the ten-year transition period (AK Steel Ex. 20). Shell supports AK Steel's position the shopping incentive-related transition costs are overstated. Due to unrealistically low average energy prices used in the Company's calculations, Shell argues [*77] that shopping incentive-related transition costs are inflated. Shell also takes the position that the new regulatory assets have yet to be incurred and, therefore, were not prudently incurred as required by SB3. Shell also believes that SB3 leads to the inescapable conclusion that the regulatory asset portion of the RTC charge must reflect only CG&E's previously approved regulatory assets, and that newly approved regulatory assets must be recovered within the parameters of that RTC charge. Because the stipulation would premise its RTC charge on both existing and new regulatory assets, Shell believes it violates SB3. Shell also argues that the stipulation's request for new regulatory assets fails to satisfy SB3 in several additional respects. The proposed new regulatory assets for purchased power costs, payment of other parties' litigation costs, and the effects of any shopping incentive simply do not fall within the parameters of "regulatory assets" as defined by SB3. If anything, many of these costs, such as EWG set-up costs ($28 million) MISO costs ($15 million) and System & Business Processes ($65 million) contained in the transition implementation costs, and future purchased [*78] power costs represent the type of "going forward" costs related to the future conduct of CG&E's business that regulatory agencies consistently have refused to include in stranded cost calculations. CG&E and Staff Responses CG&E argues that it will incur costs associated with purchasing power to maintain an adequate reserve margin as it meets the needs of its customers who take service under CG&E's standard offer service. These costs are directly assignable to retail electric generating service. Because the mechanism to recover these costs, the RTC, is fixed by the stipulation, CG&E will have the incentive to prudently manage these costs. Additionally, these costs will be recorded on the Company's books and will be verifiable by the Commission. CG&E further argues that, since these costs will be incurred to provide regulated generation service under fixed rates, there is clearly no possible recovery through the market. With regard to litigation costs, CG&E's argues that the limited payment of these expenses is prudent inasmuch as the Company would have spent far more on its own if the case was fully litigated. CG&E believes that, given the number of parties and witnesses, the $[*79] 1.5 million is not an unreasonable sum of money nor improper to provide as part of a settlement offer. CG&E notes that the Commission will have access to the company's books and records to verify that CG&E has incurred these expenses. CG&E also disagrees with AK Steel's EWG arguments. The Company argues that these costs are appropriately recovered under Section 4928.39, Revised Code. CG&E views these cost as the most pragmatic and economical way to comply with the Corporate Separation Plan required by Section 4928.17, Revised Code. CG&E states that it will take all measures to minimize costs of the transfer and the amount proposed to be recover represents the expected costs to accomplish this task (CG&E Ex. 39 at Ex. LJP-SUP-1, 3 and 5). CG&E states that it will record and defer the actual costs incurred, and make its books and records available the Commission for review. CG&E asserts that Mr. Baron has mischaracterized the shopping incentive and the associated cost. Mr. Baron calculates the cost to be the difference between the shopping credit that CG&E proposes to the first 20 percent of customers who switch and the shopping credit offered to the remaining 80 percent of customers [*80] (Tr. VI at 72). This computation reflects the cost that CG&E will incur to induce 20 percent of its customers to switch. CG&E disagrees with this analysis. CG&E believes that customers will be induced to switch only if they can obtain real savings or value. The measure of this value, or inducement, will be the difference between the amount the customer is credited by CG&E for not taking generation from CG&E, and the amount the customer must pay to an alternative supplier for retail generation. According to Ms. Pefley, the inducement, or incentive to shop, is simply the difference between CG&E's shopping credit and the market price (CG&E Ex. 77 at Ex. No. LJP-R-2 at 4-5). The staff supports the arguments made by CG&E regarding the deferral and recovery of regulatory transition costs. Because CG&E has agreed to a fixed RTC rider rate, it bears a risk of never recovering a certain portion of the deferrals based upon future, unknown, and presently unknowable market conditions. Mr. Baron's concern, of allowing CG&E to "defer purchase power costs sufficient to maintain an adequate operating reserve margin," is more an academic difference than a real issue according to staff. The stipulation [*81] does not provide any separate rate recovery of the accounting deferrals but merely provides accounting flexibility to the Company. It does not reduce the Company's risk of recovery, nor guarantee it a fixed and excessive stream of revenue. The staff notes that CG&E has waived the right to seek any rate recovery of any costs deferred pursuant to such accounting authority that are not recovered through the RTC (CG&E Ex. 60 at 6). Staff further points out that, in Section 4928.40(b)(2), Revised Code, satisfactory shopping incentive results are referred to as one cause for the Commission to consider ending the MDP. Staff contends that the transition charges shall be structured to provide shopping incentives to customers sufficient to encourage the development of effective competition in the supply of retail electric generation service (Section 4928.40, Revised Code). Staff believes that CG&E's deferral and recovery of reasonable shopping incentives provides the room for competing marketers to enter and create a viable and competitive market. The staff also believes that the establishment of a EWG is a reasonable method both of ensuring corporate separation and of compensating CG&E for [*82] their compliance with Section 4928.17(A), Revised Code. Commission Conclusion The Commission finds that the costs of the new regulatory assets discussed above meet the requirements of Section 4928.39, Revised Code, and can be deferred for recovery through the RTC. We believe the record demonstrates that the costs subject to recovery are prudently incurred, are directly assignable to retail electric generation service provided to electric customers in this state, not recoverable in a competitive market, and would otherwise have been recoverable. Inasmuch as purchased power costs will be incurred to provide regulated generation service under fixed rates, it is reasonable to recover future costs of purchased power through the RTC. Further, we believe the Company would have spent far more on litigation if it had to fully litigate the case. The payment of other parties' legal costs under terms of this stipulation, although unique, is not unreasonable taking into account the full parameters of this case. With respect to the recovery of EWG transition costs, the Commission finds that these costs are attributable to electric restructuring and the provision of retail electric generation [*83] service. We believe Mr. Kollen takes a too restrictive position regarding this requirement. We further find that the Company has adequately supported its projected costs of transferring its generation assets through the testimony of witness Pefley (CG&E Ex. 39). Regarding the issue of the cost of shopping credits, SB3 permits the Commission to authorize shopping incentives in order to induce at least 20 percent of customers in each customer class to shop (Section 4928.40(A), Revised Code). The Company has projected the cost to be $333 million as opposed to $135.8 million calculated by Mr. Baron. The stipulation provides CG&E the accounting authority to create the necessary regulatory assets and defer and recover deferrals or adjustments to the amortization schedules to reflect the effect of any shopping incentives (CG&E Ex. 60 at 6). The Company argues the measure of this value, or inducement, will be the difference between the amount the customer is credited by CG&E for not taking generation from CG&E, and the amount the customer must pay to an alternative supplier for retail generation. According to Ms. Pefley, the inducement, or incentive to shop, is simply the difference between [*84] CG&E's shopping credit and the market price. The Commission finds this approach to arrive at the amount of deferred costs is reasonable and in keeping with the stipulation. The stipulation addresses the effects of any shopping incentives, not just those related to the first 20 percent of customers that switch. We further note, as pointed out by our staff, that the stipulation does not provide any separate rate recovery of the accounting deferrals but merely provides accounting flexibility to the Company. It does not reduce CG&E's risk of recovery, nor guarantee it a fixed and excessive stream of revenue. Accordingly, we are not persuaded by the arguments raised by AK Steel and Shell on this issue. The Commission would also like to note that, inasmuch as the transition plan stipulation is a compromise involving a balancing of competing positions and does not necessarily reflect the views which one or more of the parties to the stipulation would have taken if these issues had been fully litigated, our approval of these new regulatory assets does not necessary reflect what the Commission's position would have been had not the issue been part of an all encompassing stipulation. Accordingly, [*85] our decision to accept the creation and accounting treatment of the new regulatory assets creates no precedent for any other transition plan proceeding. We further note that, although the stipulation provides for the opportunity to recover the cost of various newly created regulatory assets, CG&E's analysis shows that at the end of 2010 the unrecovered balance of generation-related regulatory assets is projected to be approximately $153 million (CG&E Ex. 77 at LJP-R-2 at 1). The recovery mechanism for these costs provides protection to consumers and supports the reasonableness of approving the creation of these new regulatory assets. 4. Transition Costs Compliance with Statutory Requirements Shell argues that the stipulation's treatment of regulatory transition costs violates SB3 in a variety of fundamental respects. Shell states that the Commission must determine the total allowable amount of the transition costs of the utility to be received as transition revenues and that these costs must meet the standards of Section 4928.39 (A) through (D), Revised Code. Shell contends that the stipulation's treatment of transition costs violates each of the foregoing statutory provisions. [*86] Shell contends that nowhere does the stipulation purport to identify the maximum level of transition costs authorized for recovery by CG&E. In fact, the stipulation makes plain that its proposed transition revenue recovery is "not limited to" the regulatory assets it identifies. AK Steel argues that CG&E has failed to provide (a) the amount of its transition revenues; (b) the amount of its transition costs; and (c) proof that its transition revenues equal its transition costs. AK Steel asserts that, under the stipulation, there is no mechanism to track the RTC revenue recovery and to compare the RTC revenues to the revenue requirement of the allowed regulatory asset transition costs. Thus, AK Steel claims that the RTC recovery will be excessive because it will not terminate once the Company has recovered the allowed costs, but rather will extend for the maximum ten-year RTC recovery period, eight years for residential customers. AK Steel argues that such a result is inconsistent with the statutory requirements. Pursuant to Section 4928.34(12), Revised Code, AK Steel contends that the Company may not recover more than its allowed transition costs. Shell also takes exception to Ms. [*87] Pefley's rebuttal testimony which suggests that, even if purchase power costs are excluded, a $153 million shortfall still exists between CG&E's RTC revenues under the stipulation and its likely transition costs. Shell argues that Ms. Pefley's numbers are unreliable, as they rest on inappropriate assumptions concerning kWh sales levels, market prices, switching rates, and carrying charges. All of these inappropriate assumptions serve either to decrease CG&E's RTC revenues or to increase its RTC costs, thereby producing the revenue "gap" about which Ms. Pefley complains. Shell contends that, when these erroneous premises are corrected, the results strongly suggest that, in fact, CG&E would take in far more in RTC revenues under the stipulation than it would incur in RTC costs. Shell contends that Ms. Pefley's transition cost figures are still further inflated by the high carrying charge she imputes. CG&E's calculations assume an RTC carrying charge equal to the utility's full authorized pre-tax rate of return of 14.23 percent (Company Ex. 77 Ex. LJP-R-2 at 1 of 5). In light of the non-bypassable, guaranteed nature of RTC collections, Shell states that CG&E does not face the same level [*88] of business risk with respect to their collection as applies to other aspects of its regulated business. Additionally, Shell claims that other jurisdictions that have considered this matter have had no difficulty concluding that such transition costs merit a carrying charge closer to the utility's cost of debt than its overall rate of return. CG&E argues that the rebuttal testimony of Ms. Pefley demonstrates that the Company's recovery of transition costs through the RTC will fall $153 million short of the transition costs that CG&E has shown exist (CG&E Ex. 77 at LJP-R-2 at 1). Further, CG&E points out that the stipulation imposes the risk of a shortfall upon CG&E rather than the consumers. Further, CG&E states that it has used a carrying charge of 14.23 percent because that is the authorized rate of return from its last rate case. As discussed previously in this order, the Commission finds that existing and new regulatory assets for which the stipulation requests recovery through the RTC are reasonable and do not violate the various provisions of SB3. Although not all of the regulatory transition costs are calculable to the penny at this point in time, Company witness Pefley has [*89] provided a reasonable accounting of what the amounts of transition cost are or are projected to become. The stipulation does provide CG&E recovery of previously approved regulatory assets totaling $401 million and new regulatory assets estimated to total at least $483 million (CG&E Ex. 60 at 6-7; CG&E Ex. 50 at Ex. JPS-SUP-5; and CG&E Ex. 77 at Ex. LJP-R-2). It is clear from SB3 that the Commission is authorized to permit the creation of, or amortization of, additional regulatory assets. Therefore, we do not buy into the argument the transition regulatory assets must already be in existence to be prudently incurred (Section 4928.40(A), Revised Code). Further, Ms Pefley filed rebuttal testimony to support the reasonableness of the amount of transition costs to be recovered through the RTC. Based on a present value of RTC revenue of $517 million, calculated using Mr. Baron's methodology and a pre-tax authorization rate of return, and comparing it to $552 million of transition costs allowed to be recovered based on the stipulation, not including shopping credit costs, purchased power costs, and appropriate carrying charges, CG&E demonstrates that it is not likely that it will over [*90] recover all of its regulatory transition costs through the RTC rider (CG&E Ex. 77 at 4 and 5). We also note that the Company is only entitled to an opportunity to collect its transition charges and that there is no precise arithmetic guarantee under Section 4928.34(A)(12), Revised Code. Many factors will come into play in the future that will determine whether the Company will under- or overrecover all of its approved transition costs. Consequently, we do not believe that the stipulation is unreasonable or in violation of Section 4928.34(A)(12), Revised Code, because the stipulation does not guarantee that the Company will recover no more than the projected transition costs. With the considerable number of parties that have agreed to the stipulation, the Commission can conclude that the recovery of transition costs established by the stipulation is reasonable and will not lead to any significant overrecovery of transition costs. D. Transition Plan Stipulation's Compliance with Sections 4905.33, 4905.35, 4928.37 and 4928.40, Revised Code As discussed in our summary of the stipulations, the shopping credits for each customer class set forth in the stipulation are higher for the [*91] first 20 percent of the load of that customer class that switch to an electric energy marketer. Further, the RTC for residential customers ends at December 31, 2008, as opposed to December 31, 2010, for other customers. The stipulation also provides for a MDP for residential customers of five years while the MDP for other classes could end sooner than five years. AK Steel contends that these provisions of the stipulation are unreasonable and in violation of Sections 4905.33 and 4905.35, Revised Code. Section 4905.35, Revised Code, provides in relevant part as follows: (A) No public utility shall make or give any undue or unreasonable preference or advantage to any person, firm, corporation ... or subject any person, firm, corporation ... to any undue or unreasonable prejudice. Section 4905.33, Revised Code, provides in relevant part: No public utility shall directly or indirectly, or by any special rate, rebate, drawback, or other device or method, charge, demand, collect, or receive from any person, firm, or corporation a greater or lesser compensation for any services rendered, or to be rendered, except as provided in Chapters 4901., 4903., 4905., 4907., 4909., 4921., 4923., [*92] and 4925. of the Revised Code, than it charges, demands, collects, or receives from any other person, firm, or corporation for doing a like and contemporaneous service under substantially the same circumstances and conditions. Objections of AK Steel and Shell AK Steel states that the shopping credit, although nowhere found in SB3, represents the number, on average, of the cost of power, below which it pays a customer on the Standard Service Offer (SSO) to begin shopping. AK Steel argues that the stipulation's offer of enhanced shopping credits to some customers at the expense of similar customers in similar circumstances is discriminatory. Further, AK Steel contends that the effect is far worse as to non-residential customers, because CG&E may cancel the MDP and, thus, the availability of the SSO as soon as there exists 20 percent shopping by load in a rate class. AK Steel believes that it is to CG&E's distinct economic advantage to cancel the MDP as soon as a class achieves 20 percent load switching even though the remaining 80 percent lose the safe harbor of the SSO. AK Steel contends that significant preference or advantage based upon a place in a queue is unreasonable and [*93] unjust and that no rational justification can be found to charge different rates to the same class of customers based on the ability to get into a line first. AK Steel also argues that CG&E has bestowed upon the residential class benefits that it has not deemed to confer on the non-residential customers. While nonresidential customers may be expelled from the SSO whenever the first 20 percent of the customer load of the class switch, the residential customers have the security of the SSO until December 31, 2005. AK Steel believes this is a considerable advantage since it secures them against the vagaries of the market place for five years regardless of whether 20 percent load switching as occurred or not. Further, AK Steel argues that the reduced RTC recovery period for residential customers is discriminatory since it means an underpayment by the residential customers of their share of the RTC. AK Steel also argues that these provisions concerning shopping credits also violate Sections 4928.37 and 4928.40, Revised Code, because they permit certain customers to by-pass the non-bypassable RTC and create a RTC of less than zero for the first 20 percent of residential customers. Shell [*94] also takes issue with the provision of the stipulation that would permit the Company to end the MDP for non-residential customers prior to December 31, 2005. Specifically, Section 5 of the stipulation would grant CG&E the authority to end the MDP, at its sole option, if (1) 20 percent load switching by class has occurred, (2) CG&E provides notice to the Commission, and (3) CG&E does not have a certified supplier affiliate in its service territory. Shell argues that, because CG&E has indicated it has no intention of establishing a retail marketing affiliate and the notice provision is purely ministerial, CG&E's exercise of this requested discretion would turn on the level of non-residential customer switching. Shell states that, under SB3, a utility's application to end the MDP must demonstrate either that there is 20 percent switching rate by the customer class, or there exists effective competition in the utility's service territory (Section 4928.40(B)(2), Revised Code). Shell contends that the Commission cannot authorize an early termination to the MDP unless it finds either of the requisite threshold circumstances to exist, something it obviously cannot do now, prior to the commencement [*95] of the MDP. Shell argues that the stipulation's request for "up front" authorization to end the MDP seeks to strip the Commission of this flexibility and hand over to CG&E the authority to determine whether circumstances warrant early termination. In Shell's view, the stipulation's proposal concerning early termination of the MDP is unlawful, represents ill-conceived policy, and should be rejected. Responses of CG&E and Staff CG&E disagrees with the arguments made by AK Steel and Shell. The Company asserts that all customers have an equal opportunity to shop and that CG&E exercises no influence over which customers will be among the first 20 percent of load to switch. CG&E also points out that Section 4905.33, Revised Code, recognizes circumstances where preferences may be given pursuant to statutory authority, and Section 4905.35, Revised Code, only prohibits undue or unreasonable preferences. CG&E cites Section 4928.40(A), Revised Code, which permits the Commission to authorize shopping incentives to induce 20 percent switching, to support its argument that the shopping incentives provided are reasonable and permissible by law. With respect to the difference in the MDP and RTC [*96] recovery periods among the various classes of customers, CG&E argues that residential customers are not similarly situated to commercial and industrial customers in a competitive context. Further, CG&E points out that any underrecovery of RTC due to the treatment of residential customers within the stipulation is absorbed by CG&E and that CG&E has shown it will underrecover transition costs of approximately $153 million (CG&E Ex. 77 at 2). CG&E also disagrees that the RTC is being by-passed or is established at below zero. CG&E states that it has shown through the testimony of witness Pefley that all customers pay an undiscounted RTC which is offset by a shopping incentive (CG&E Ex. 65 at Ex. LJP-Sup-8; and CG&E Ex. 77 at LJP-R-2 at 3). CG&E argues that SB3 requires the Commission to consider offsetting the RTC with shopping incentives. The staff takes the position that shopping incentives are legitimate regulatory tools designed to promote competition. Staff believes that the structure of the shopping credits, MDPs, and the RTC recovery periods are consistent with the regulatory intent of SB3. Commission Conclusion The Commission finds that the structure of the shopping credits, [*97] MDPs, and the RTC recovery periods do not violate Sections 4905.33 and 4905.35, Revised Code. Clearly, Sections 4928.37(B) and 4928.40(A), Revised Code, provide the Commission with the authority to approve the shopping incentives set forth in the stipulation. Although customers who take the early initiative to shop for an alternative supplier of generation will benefit from their actions, this does not amount to undue preference nor create a case of discrimination. All customers will have an equal opportunity to take advantage of the shopping incentives. The Commission cannot conceive of a mechanism that provides customers with more of an incentive to shop than those created by the stipulation. The Commission also finds that Section 4928.40(A), Revised Code, authorizes the Commission to set the recovery of the costs associated with regulatory assets up to December 31, 2010. The Commission does not find it discriminatory to have two different periods for the recovery of the RTC, one for residential customers and one for non-residential customers, inasmuch as the rates, incentives, and shopping credits vary between the various customer classes. We also believe that, inasmuch as SB3 [*98] permits the Commission to authorize the end of a MDP prior to December 1, 2005 if there is a 20 percent switching rate by a particular class of customer, the approval of such through this order as part of the stipulation is not unreasonable nor contradictory to Section 4928.40(B), Revised Code. Further, we do not believe that the development of a shopping incentive should be viewed as creating an RTC of less than zero or that it permits the RTC to be by-passed. We view the two as separate provisions of the SB3. E. Shopping Credits Section 4928.40, Revised Code, provides for the establishment of shopping incentives to induce customers to switch to a certified supplier to obtain their generation supply. The goal of the incentive is to achieve at least a 20 percent switching rate by December 31, 2003. CG&E states that the stipulation creates such shopping incentives by granting shopping credits greater than the projected market price of power. Per the stipulation, such credits are equal to or greater than CG&E's unbundled generation component to the first 20 percent of customers that switch to a certified supplier to obtain their generation supply (CG&E Ex. 60 at 11-14). Shell argues [*99] that the stipulation's shopping credits would not spur the level of switching sought by SB3 and the Commission's rules, particularly among residential ratepayers. Shell's position is that, once a marketer adds on to the wholesale price of power such costs as line loss, advertising, other customer acquisition costs, collection costs, reserves for bad debt, accounts payable, customer call centers, office overheads, and the marketer profit, there will be no margin left to provide the customer a savings off of the $0.05 shopping credit provided the first 20 percent of residential customers who shop. Thus, according to Shell, during the MDPs crucial initial stages, when CG&E's service territory first opens to competition, the stipulation's proposed $0.05 shopping credit would force residential marketers to either offer no significant consumer savings or to do so at a loss. Shell also contends that assuming, for argument's sake, that the initial $0.05 credit did induce a 20 percent residential switch rate by the midpoint of the MDP, the prospect for further customer switching would vanish under the subsequent $0.0394 shopping credit provided the remaining 80 percent of residential customers. [*100] Shell argues that, in short, the fact that the stipulation's proposed shopping credits exceed CG&E's unbundled generation charge has no bearing on whether they merit approval by this Commission. Instead, Shell maintains that the Commission must assess whether those credits would produce the effective competition and competitive choice sought by SB3. Shell claims that CG&E's attempt to mask the deficiency of the stipulation's shopping credits through a simplistic comparison to those offered by Duquesne Light Company misses the mark. Unlike CG&E, Duquesne Light Company did more to promote competition than merely provide shopping credits. Shell believes that CG&E should actually provide a certain amount of generation capacity at a predetermined price to those retail suppliers competing to serve its market. In conclusion, Shell argues that the stipulation's residential shopping credits are wholly inadequate for accomplishing the level of switching and effective competition sought by SB3 and the Commission should reject them. Alternatively, Shell claims that, if the Commission finds that providing generation capacity is not well suited for the CG&E system, the Commission, at a minimum, [*101] should increase substantially the stipulation's residential shopping credits. In this regard, Shell recommends increasing the credit to $0.055 per kWh for the entire MDP. This enhanced initial shopping credit, according to Shell, would have a much greater chance of engendering immediate, vigorous third-party participation in the CG&E residential market than the stipulation's inadequate $0.05 credit. Shell also takes issue with Section 3 of transition plan stipulation that provides: There will be no further netting or adjustments of any kind to CG&E's Transition Cost recovery, including but not limited to any adjustment of RTC rates, or shopping credits through 2010, related to the sale, lease or transfer by CG&E, or any of its affiliates, of any generating assets. Shell argues that this provision represents a blatant attempt to tie the Commission's hands regarding future actions it might take to protect and encourage the emerging competitive market place in light of unanticipated market conditions. Shell believes that this provision of the stipulation is in conflict with Section 4928.40(B)(1), Revised Code, which permits the Commission to conduct a periodic review no more [*102] often than annually and, as it determines necessary, adjust the transition charges of the electric utility as initially established or subsequently adjusted. Moreover, Shell argues that the Commission is specifically permitted to adjust the regulatory asset component of a utility's regulatory transition charge on a prospective basis after December 31, 2004, or earlier in conjunction with approval of an early termination date for the MDP (Section 4928.39 (D), Revised Code). Shell argues that the acceptance of Section 3 of the stipulation would negate the Commission's broad authority to safeguard retail competition during the MDP and should be rejected. CG&E's argues that its plan for shopping incentives filed with its transition plan describes numerous studies conducted by CG&E in developing a switching forecast (CG&E Ex. 8 at 2-15; and CG&E Ex. 16 at 6-27). These studies include residential customer satisfaction studies, commercial and industrial satisfaction studies, an image tracking study, and a market forecast study (CG&E Ex. 16 at 6). CG&E contends that an analysis of these studies reveals that, with certified suppliers offering as little as two percent value over CG&E's standard [*103] service offer, 22.7 percent of residential load, 52.1 percent of commercial load, 89.5 percent of industrial load, and 69 percent of governmental load are projected to switch to certified suppliers by the end of 2003 (CG&E Ex. 16 at 25, 27). CG&E asserts that these projections far exceed the switching targets specified in Section 4928.40(A), Revised Code. However, CG&E contends that with the stipulated shopping credits, the customers who switch will receive far greater than two percent added value, based on projected retail market prices, and the first 20 percent of the customers who switch will receive even greater incentives. CG&E also points out that Shell's use of CG&E's wholesale power purchases in 1998 does not reflect properly the wholesale price of power in the future. CG&E asserts that much of this power was purchased during peak periods when prices were high. CG&E argues that it is more appropriate to look forward to projected retail market prices (CG&E Ex. 77 at LJP-R-2 at 4). The Commission finds that the stipulation provides appropriate shopping incentives to achieve a 20 percent load switching contemplated by Section 4928.40(A), Revised Code. We believe CG&E's forward [*104] looking wholesale prices of power used to estimate future retail power markets are more appropriate than CG&E purchased power costs from past years. Further, the record lacks sufficient evidence to support Shell's recommendation of a shopping credit of $0.055 per kWh. The stipulation's $0.05 shopping credit for the first 20 percent of residential customer load that switches exceeds the unbundled rate for generation and, therefore, should help ensure that residential customers have an incentive to shop. The first 20 percent load switched from the remaining customer classes will also have an adequate incentive to shop inasmuch as shopping credits will equal 100 percent of the unbundled generation rate. We believe that these significant shopping incentives will effectively foster early competition by providing significant motivation to customers to switch retail generation suppliers. With regard to Section 3 of the stipulation, the Commission does not believe that this provision is in conflict with Section 4928.40(B)(1), Revised Code. This section of the Revised Code permits the Commission to conduct a periodic review no more often than annually and, as it determines necessary, adjust [*105] the transition charges of the electric utility as initially established or subsequently adjusted. It does not require such reviews or adjustments. We believe that the stipulation establishes reasonable transition charges, shopping credits, and incentives for customers to shop. We do not believe that Section 3 negates the Commission's broad authority to safeguard retail competition during the MDP. Various sections of SB3 give the Commission the continued oversight to monitor the progress of competitive retail electric services, to take action where necessary, and to promote the policies of the state of Ohio set forth in Section 4928.02, Revised Code. F. CG&E's Corporate Separation Plan (CSP) CG&E proposed a CSP that it contends meets all the requirements set forth in Sections 4928.17 and 4928.06, Revised Code, and the Commission's rules on utilities' code of conduct. No parties opposed CG&E's CSP. Under its plan, effective January 1, 2001, CG&E will not offer non-tariffed products and services and it will transfer any such products and services to a fully separated affiliate (CG&E Ex. 57 at 2). Additionally, CG&E's CSP provides for the transfer of its generating assets to an EWG [*106] and, according to the plan, CG&E will complete the transfer by no later than December 31, 2004 (CG&E Ex. 57 at 3). CG&E's CSP also describes the mechanisms that CG&E will utilize to ensure that CG&E institutes proper accounting procedures for affiliate transactions (CG&E Ex. 57 at 4-5). CG&E's CSP includes provisions related to structural safeguards, separate accounting, financial arrangements, complaint procedures, education and training, the policy statement, internal compliance monitoring, and a detailed listing of CG&E's electric services. As described in the testimony of Paul G. Smith, CG&E will implement a cost allocation manual, pursuant to Rules 4901:1-20-16(G)(1)(a) and (b) and 4901:1-20-16(J), O.A.C. (CG&E Ex. 14 at 5). CG&E will also only share employees, facilities, and services in accordance with its SEC-approved service agreements, pursuant to Rule 4901:1-20-16(G)(1)(c), O.A.C. (CG&E Ex. 37 at 3). Under its proposal, CG&E will keep its books, records, and accounts separate from those of its affiliates pursuant to Rule 4901:1-20-16(G)(2), O.A.C. (CG&E Ex. 14 at 6). CG&E will also follow the Commission's rules on financial arrangements to preserve the financial independence [*107] of CG&E from its affiliates pursuant to Rule 4901:1-20-16(G)(3), O.A.C. (CG&E Ex. 14 at 7). CG&E's filing includes an affiliate code of conduct that complies with the Commission's rules. According to the Company's proposal, CG&E is prohibited from releasing any proprietary customer information to an affiliate without the prior authorization of the customer (CG&E Ex. 37 at Ex. PGS-1 at 2). Furthermore, CG&E's affiliate code of conduct requires CG&E to make customer lists available on a nondiscriminatory basis to all nonaffiliated and affiliated certified retail electric competitors transacting business in its service territory (Id. at 1). CG&E's affiliate code of conduct stipulates that the Company shall treat as confidential all information obtained from any certified supplier of retail electric service and that the Company shall not tie the provision of regulated services to the taking of any goods and/or services from CG&E's affiliates. CG&E maintains that its code of conduct ensures that anticompetitive subsidies will not flow from a noncompetitive retail electric service to a competitive retail electric service or to a product or service other than retail electric service, [*108] and vice versa (Id. at 6). CG&E notes that Section 4928.17(C), Revised Code, provides that "for good cause, the Commission may issue an order approving a corporate separation plan that does not comply with Section 4928.17(A)(1), Revised Code, but complies with such functional separation requirements as the Commission authorizes to apply for an interim period. Further, CG&E states that the Commission's corporate separation rules require the utility to show good cause for selecting an interim functional separation plan. CG&E believes that it has met this burden through its corporate separation financing plan. CG&E notes that its corporate separation financing plan provides for a program to complete the transfer of its generating assets to an EWG by December 31, 2004, and it describes the expected costs CG&E would incur if it is forced to transfer its generating assets to the EWG by December 31, 2000. It is CG&E's intention to achieve the transfer of assets to the EWG at the lowest cost practicable by seeking to minimize the transaction costs, including tax obligations; minimize the expenditures related to the recapitalization of CG&E; and optimize the capital structure of CG&E. [*109] CG&E's ability to minimize its transaction costs will turn on three key issues: (1) what steps CG&E must take to adjust its capital structure as a result of the corporate separation plan; (2) whether it can release the generation from the mortgage without having to redeem the first mortgage bonds; and (3) whether it can eliminate or minimize the tax obligations which may arise from the transfer (Id. at 3). CG&E is undertaking the process of seeking to release the generation assets from its existing first mortgage lien obligations (Id. at 3). CG&E expects this process to take at least six to nine months (Id. at 3). While CG&E hopes that it can achieve this release, there can be no assurance that CG&E will be fully successful. In the event CG&E is unsuccessful, it may have to pursue other means to release the properties, as described in CG&E's Corporate Separation Financing Plan. CG&E has presented a corporate separation plan for Commission approval pursuant to Section 4928.17(C), Revised Code. CG&E has indicated that, if it is forced to transfer its generating assets to the EWG by December 31, 2000, it will incur significant costs. Since the corporate separation plan does [*110] not provide for complete separation by December 31, 2000, in order for this Commission to approve an interim plan the company must show "good cause" pursuant to Section 4928.17(C), Revised Code. This section provides that an interim plan must be consistent with such functional separation requirements as is authorized for the interim period, and that the plan must provide for ongoing compliance with the policy set out in Section 4928.02, Revised Code. Section 4928.17(A)(2), Revised Code, also requires that all plans satisfy the public interest in preventing unfair competitive advantage and abuse of market power. The plan must also be sufficient to ensure that no undue preference or advantage is extended to or received by the competitive retail affiliate from the utility affiliate (Section 4928(A)(3), Revised Code). The Commission's rules also address interim plans and require that such plans set out a detailed timeline of progression to full structural separation, and that they be subject to periodic Commission review (Rule 4901:1-20-16(G)(1)(d), O.A.C.). We find that CG&E's proposed interim plan achieves the structural separation contemplated by Section 4928.17(A)(1), Revised Code, [*111] and the corresponding Commission rules. The Company has shown that it will incur significant costs if it is forced to transfer its generating assets to the EWG by December 31, 2000. We find that good cause exists to allow the separation as proposed by the company to occur by December 31, 2004, in that specific steps are set forth to insure the release of the subject properties in that time frame. The plan provides for competitive retail electric service through a fully separated affiliate of the utility and includes separate accounting requirements and code of conduct necessary to effectuate the policy specified in Section 4928.02, Revised Code. The plan also satisfies the public interest in preventing unfair competitive advantage and preventing the abuse of market power. The plan also is sufficient to ensure that the Company will not extend any undue reference or advantage to any affiliate, division, or part of its own business engaged in the business of supplying the competitive retail electric service or nonelectric produce or service. CG&E has provided a reasonable timeline for its transition to full structural separation. Therefore, the Company has met its burden of showing "good [*112] cause" for this Commission to approve the interim functional separation plan. We will closely monitor the implementation of the plan and take appropriate steps where we find competitive inequality, unfair competitive advantage, or abuse of market power. We believe that through the periodic Commission review of the interim separation plan, through auditing of the company's books and records, including the cost allocation manual, and the complaint process, this Commission can ensure that the corporate separation plan is implemented in accordance with the policy enunciated in SB3. G. CG&E's Employee Assistance Plan (EAP) CG&E's EAP was presented through the testimony of Richard L. Bond, CG&E's general manager of Compensation, Benefits and Human Resources Information System. Mr. Bond described CG&E's EAP including the programs for severance, retraining, retirement, retention, outplacement and other assistance that the company commits to provide to its employees whose employment is affected by electric industry restructuring (CG&E Ex. 17, 3). Mr. Bond contended that CG&E's EAP provides for all of the types of benefits described in Section 4928.31(A)(4), Revised Code, and that the EAP [*113] will be communicated to CG&E's eligible employees verbally and in writing (Id. at 3). He noted that CG&E has had experience with voluntary workforce reduction and voluntary severance plans and that a very substantial number of those employees who were eligible to participate in the plans took advantage of the plans' benefits (Id. at 5). Mr. Bond also testified that CG&E has no current plans to downsize its workforce during the MDP as a result of restructuring (Id. at 6). CG&E has requested no transition costs related to the EAP (CG&E Ex. 12 at Ex. JPS-5 at 1). No parties opposed CG&E's EAP or the EAP stipulation. Pursuant to Section 4928.34(A)(10), Revised Code, the Commission finds that the Company's EAP sufficiently provides severance, retraining, early retirement, retention, outplacement, and other assistance for the Company's employees whose employment is affected by electric industry restructuring. As noted above, CG&E's EAP will be subject to negotiations with CG&E's unions and, in accordance with the EAP rules, we will continue to provide the Company flexibility in implementing the EAP. H. CG&E's Education Plan Section 4928.31(A)(5), Revised Code, requires each [*114] utility's transition plan to include a consumer education plan consistent with Section 4928.42, Revised Code. Section 4928.42, Revised Code, provides that, prior to the starting date of competitive retail electric service, the Commission shall prescribe and adopt a general plan by which each electric utility shall provide during its MDP consumer education on electric restructuring. Utilities are required to spend up to $16 million in the first year on consumer education within their certified service territories and an additional $17 million in decreasing amounts over the remaining years of the MDP. As part of its transition plan, CG&E filed an education plan, which was later amended. CG&E's amended education plan targets residential customers; small and mid-sized commercial customers; elected officials, community leaders, civic organizations, trade associations, and consumer groups; and large commercial and industrial customers. The amended plan also describes the methods, timelines, and spending that will be used for CG&E's education campaign. Further, CG&E's amended education plan included deferral of its expenditures on consumer education in CG&E's requested transition costs [*115] recovery. No parties opposed CG&E's amended education plan. On November 30, 1999, the Commission issued rules for the electric transition plan proceedings, and adopted a general plan for electric utilities' consumer education in Case No. 99-1141-EL-ORD, In the Matter of the Commission's Promulgation of Rules for Electric Transition Plans and of a Consumer Education Plan, Pursuant to Chapter 4928, Revised Code. After the companies filed their transition plans, various intervenors filed preliminary objections. Separate staff reports were filed in each of the transition plan proceedings. In each staff report, the staff stated that the consumer education plans are consistent with the requirements issued by the Commission on November 30, 1999. n8 After reviewing all of the education plans filed in all of the transition cases and after considering the objections and comments submitted, we found in our July 20, 2000 finding and order in 99-1658-EL-ETP et al., CG&E's amended education plan to be in compliance with Section 4928.42, Revised Code, and we approved CG&E's education plan subject to three contingencies. First, we noted that, with regard to provisions for the funding of local [*116] community-based organizations (CBO), although we did not require funding of the CBOs, we did encourage CG&E to provide CBO funding. We also required CG&E to include an unaffiliated energy marketer representative on their advisory groups. Second, we required that the plans for CG&E include further details on how the territory-specific campaigns will be managed and operated, how materials and information will be disseminated, and how funds will be allocated to activities, as well as other matters. Further, we conditioned our approval on the Commission staff's continuing supervision of the general and territory-specific plans as further details are developed for each of the consumer education programs. With the conditions to CG&E's education plan set forth in our July 20, 2000 order, we find that CG&E's transition plan complies with Section 4928.31(A)(5), Revised Code. - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n8 The staff's only recommendation was the inclusion of an energy marketer representative in the advisory group. CG&E was the only company to file an amended education plan that added an energy marketer representative to the advisory group. - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - [*117] I. Independent Transmission Plan (ITP) Pursuant to Section 4928.12(A), Revised Code, no entity shall own or control transmission facilities (as defined by federal law) in Ohio as of the date of competitive retail electric service unless the entity is a member of, and transfers control of those facilities to, one or more qualifying transmission entities. Section 4928.12(B), Revised Code, sets forth nine requirements for a qualifying transmission entity must meet including: (1) the transmission entity is approved by FERC; (2) the transmission entity separates control of transmission facilities from control of generation facilities; (3) the transmission entity implements, to the extent reasonably possible, policies and procedures designed to minimize pancaked transmission rates within Ohio; (4) the transmission entity improves service reliability within Ohio; (5) the transmission entity provides for an open and competitive electric generation marketplace, eliminates barriers to market entry and precludes control of bottlenecked transmission facilities; (6) the transmission entity is of sufficient scope or otherwise increases economical supply options; (7) the transmission entity's [*118] governance structure is independent from transmission users; (8) the transmission entity satisfies customers' electricity requirements; and (9) the transmission entity maintains real-time reliability of the transmission system, ensures comparable and non-discriminatory transmission access and necessary services, minimizes congestion and addresses transmission constraints. CG&E states that the requirements of Section 4928.12(B), Revised Code, are substantially similar to the requirements established by the FERC for Independent System Operators (ISOs) in Order No.888 n9 and for Regional Transmission Organizations (RTOs) in Order No. 2000. n10 CG&E asserts that an RTO approved under FERC's Order No. 2000 requirements will of necessity also satisfy the requirements of Section 4928.12(B), Revised Code. - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n9 FERC Stats. & Regs., P 31,036 (1996) n10 FERC Stats. & Regs. P 31,089 (2000). - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - CG&E witness John C. Procario (CG&E Exs. 20 and 54) sponsored and explained CG&E's ITP, which is Part G of CG&E's transition plan. Mr. [*119] Procario explained how CG&E believes the MISO and CG&E's participation in the MISO satisfies each of the requirements of Section 4928.12(B), Revised Code, as well as the more specific criteria set forth in Rule 4901:1-20-17, O.A.C. Mr. Procario indicated that CG&E will belong to the MISO and that the MISO is a transmission entity approved by FERC. He noted that FERC initially gave conditional approval to the MISO on September 16, 1998 (CG&E Ex. 20 at 9). The MISO transmission owners subsequently made a compliance filing and FERC issued an order approving the compliance filing on April 16, 1999, conditioned on a minor change that the MISO Transmission Owners made on May 17, 1999 (CG&E Ex. 20 at 9-10). He indicated that the MISO still must make additional compliance filings within 60 days of becoming operational regarding filing and operating procedures and the MISO must also make a compliance filing arising from FERC's recent Order 2000 (CG&E Ex. 20 at 9; 89 FERC Section 61,285; Buckeye Ex. 2 at 22). Mr. Procario indicated that the MISO will separate control of transmission facilities from control of generation facilities because the MISO will have functional control over transmission [*120] facilities (CG&E Ex. 20 at 14-15). Mr. Procario testified that the MISO also eliminates pancaked transmission rates within the MISO, by providing for non-pancaked zonal rates during a six-year transition period (CG&E Ex. 20 at 20). At the end of the six-year transition period, the progression to a single rate or combined rates will depend on how quickly states encompassed by the MISO adopt customer choice and the development of independent transmission companies (Id. at 22). Under the ITP stipulation, CG&E committed to participate in the collaborative process under FERC Order 2000 to discuss integrating the facilities of the transmission-owning utilities in Ohio. CG&E will also seek to enter into a joint stipulation with all of the other transmission-owning utilities in Ohio to submit the subject of how to achieve the objectives listed in Rule 4901:1-20-17(B)(3), O.A.C., and related issues to a separate joint Commission hearing dealing solely with that subject as part of their respective transition plan application proceedings. CG&E will also seek to jointly request, together with the intervenors in this case, that the Commission order the other transmission-owning utilities to [*121] participate in such a hearing. CG&E will also participate in a statewide collaborative process to resolve the transmission seams issues in Ohio. Mr. Procario noted that the MISO improves service reliability within Ohio because the MISO will act as the security coordinator for the transmission facilities under its functional control (CG&E Ex. 20 at 24). In addition, the MISO will promote open competition because the MISO's transmission usage and availability will be publicly posted on OASIS in real time and the MISO's transmission rates will be calculated in a uniform manner and will also be publicly available (Id. at 29). Mr. Procario indicated that the MISO is of adequate size and scope to increase economical supply options. He noted that the MISO's scope and configuration is significant because the MISO would serve a 16-state area and span three reliability councils: MAIN, ECAR, and MAPP (CG&E Ex. 20 at 7). Mr. Procario also testified that the MISO has several structural features that provide for independent governance. The MISO's governing structure consists of an independent board of directors and an advisory committee. Any eligible transmission customer may join the MISO. [*122] The members elect the board of directors (CG&E Ex. 20 at 36, 37). The MISO provides for satisfaction of customer requirements because it provides non-discriminatory open access to the transmission system for all eligible transmission customers (CG&E Ex. 20 at 44). Finally, Mr. Procario noted that the MISO will provide for real-time reliability because it will have primary responsibility for short-term reliability of the grid's operation (CG&E Ex. 20 at 48). We note that the transition plan stipulation and the ITP stipulation are designed to address the fact that, even if the MISO is fully approved by FERC by January 1, 2001, it will not be operational until some time later that year. The MISO is currently scheduled to become operational during 2001 (CG&E Ex. 20 at 10). CG&E respectfully requests that the Commission approve a deferral of CG&E's compliance with the ITP requirements until December 31, 2001, as the Commission is expressly authorized to do under Sections 4928.34(A)(13) and 4928.35(G), Revised Code. Objections to CG&E's ITP Buckeye, a non-profit electric generation and transmission cooperative, and OPEC, a statewide association that represents the interests of Buckeye [*123] and its members, argue that CG&E's transition plan fails to meet the requirements of Section 4928.12(B), Revised Code, because it fails to satisfy the requirement to minimize pancaked transmission rates in Ohio n11. Buckeye and OREC contend that rate pancaking is a major obstacle to the development of workably competitive markets for electric generation service. According to Buckeye and OREC, CG&E has three options under SB3 to minimize transmission rate pancaking by January 1, 2001. In this case, Buckeye and OREC argue that CG&E has failed to make an adequate proposal in its transition plan under any of these three criteria to minimize pancaking and, therefore, its transition plan should be rejected (Id. at 6). - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n11 Rate pancaking occurs when each owner of a transmission system is allowed to add the transmission price to the cost of delivering energy. - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - Buckeye and OREC contend that, under the first option, utilities can all be part of one transmission entity. Buckeye notes that CG&E is a member of the MISO, while [*124] three of the other four investor-owned utilities in Ohio, American Electric Power Company ("AEP"), FirstEnergy Corporation ("FirstEnergy"), and Dayton Power and Light Company ("DP&L"), plan to be members of the Alliance RTO. Buckeye and OREC agree that a merger of these two entities would maximize the reliability benefits and enhance competition. However, they claim that CG&E participated in discussions about merging the Midwest ISO and the Alliance RTO, but those discussions have been unsuccessful. Thus, Buckeye and OREC contend that, so long as CG&E remains in the MISO, and AEP, FirstEnergy, and DP&L are in the Alliance RTO, there will be a transmission "seam" in Ohio, and the requirement to minimize transmission rate pancaking will not be met. Under the second option, CG&E can enter into reciprocity agreements with other Ohio utilities to minimize pancaking of rates. Mr. Solomon explained in his direct testimony how such reciprocity agreements are established. Buckeye and OREC state, however, that CG&E acknowledged that it has never provided a reciprocity proposal for the other Ohio utilities to consider. Mr. Solomon argued that the failure of the MISO and the Alliance RTO to reach [*125] agreement on merging into a single RTO could result in the creation of at least two RTOs that would operate within Ohio (Id. at 7). The third option allows utilities to propose another means to minimize rate pancaking. According to Buckeye and OREC, CG&E claims it is satisfying the third criteria because, under the stipulation, it is agreeing to participate in the collaborative process under FERC to resolve the transmission seams issues, and to participate in hearings at the Commission if other transmission owning utilities will not agree to work together (Id. at 18). Buckeye and OREC argue that, under this option, the utility must provide documentation to enable the Commission to determine whether it has met its burden (Id. at 19). They argue that CG&E has failed to provide documentation that would demonstrate that the MISO will minimize pancaked transmission rates. Further, Mr. Solomon contends that CG&E's ITP is only a promise to continue talking about pancaking and, therefore, CG&E's transition plan should be rejected. Commission Conclusion Pursuant to Section 4928.34(A)(13), Revised Code, as an alternative to approving an ITP that complies with Section 4928.12, [*126] Revised Code, the Commission may, for good cause shown, authorize a company "to defer compliance until an order is issued under division (G) of Section 4928.35 of the Revised Code." Upon review, we find that we will defer approval of CG&E's ITP. Our action is based, in part, because the Commission cannot determine, at this time, whether the Midwest ISO, in its present state, is compliant with the requirements of Section 4928.12, Revised Code. At this time, the MISO is not operational and is not projected to be operational until late 2001. Furthermore, CG&E's ITP does not, at this time, minimize pancaked transmission rates and there are no provisions in the stipulation that act to minimize pancaked transmission rates during the interim time period until the Midwest ISO is operational. We note that, under the stipulation in FirstEnergy Corp. (99-1212-EL-ETP et. al.,) the FirstEnergy Corp. operating companies agreed to reimburse any supplier serving retail customers within the operating companies' respective service areas for the cost of any associated transmission charges imposed by the Pennsylvania-New Jersey-Maryland Interconnect and/or by the Midwest ISO. No such provisions exist [*127] under the CG&E stipulation. Accordingly, for these reasons, the Commission will defer the approval of CG&E's ITP until such time as the activities set forth in paragraph 5 of the ITP stipulation have been explored to adequately address compliance with Section 4928.12, Revised Code, and Rule 4901:10-20-17(B)(3), O.A.C., regarding minimizing pancaked transmission rates. We will authorize CG&E to defer compliance with these provisions until an order is issued pursuant to Section 4928.34(A)(13), Revised Code. J. Exempt Wholesale Generator (EWG) Under section 8 of the transition plan stipulation, CG&E's EWG will be prohibited from selling power to an affiliate for resale at retail in CG&E's service territory, except through CG&E's RCSA, and it will be prohibited from selling to an affiliate certified supplier on more favorable prices or terms than CG&E sells to a non-affiliate certified supplier. The information regarding the sales or transfers of power and ancillary services by the EWG to an affiliate shall be simultaneously posted with the execution of any agreement for the sale or transfer on a publicly available electronic bulletin board. Shell objects to CG&E's treatment of the [*128] wholesale power price it would pay to the EWG. Shell claims that, by shielding the price paid to the EWG for the wholesale power resold as standard offer service, stipulation Section 8 would deprive the market place of pricing transparency regarding the EWG's dealings with an affiliate that likely would be its single largest customer during the MDP. Shell also contends that it would make it more difficult for competitors to discern anticompetitive price discrimination in favor of standard offer service. Shell argues that, even if a supplier did not purchase power from the EWG, the pricing information at issue would represent a significant part of the prevailing wholesale market, and would assist suppliers in assessing prices available from alternative wholesale power sources. According to Shell, withholding the EWG's standard offer-related pricing thus would distort the wholesale market pricing signals received by third-party suppliers, thereby producing uneconomic wholesale deals that, in turn, would make it more difficult for marketers to offer significantly lower prices to consumers. Shell contends that access to the wholesale prices paid the EWG by CG&E also would permit third [*129] parties and the Commission to monitor the excess generation revenues collected by CG&E under its frozen rate for standard offer generation service. CG&E claims that Shell's first contention is wrong. It maintains that, under CG&E's RCSA, the price to be paid by CG&E to the EWG is set at the unbundled generation rate charged to CG&E's customers who have not switched and that these unbundled rates are delineated in CG&E's filed tariffs. Thus, the price charged by the EWG to CG&E is information available in public documents and simply not shielded. CG&E also finds Shell's arguments regarding suppliers purchasing power from the EWG as not credible. CG&E maintains that its RCSA sets the price to be paid by CG&E at the unbundled generation rate charged to CG&E's customers who have not switched and that these generation rates are set forth in its filed tariffs. CG&E also contends that it is required to report monthly data related to noncompetitive electric generation services to the Commission on a quarterly basis. It contends that this information is all that is needed to monitor CG&E's generation revenues. CG&E also argues that to allow suppliers to purchase power from the EWG at unbundled [*130] generation standard service offer rates would provide nothing more that a subsidy to CRES providers and should be rejected. Upon review of the issues raised by Shell, we find that stipulation Section 8 to be reasonable. We agree with CG&E that, according to the stipulation, the price to be paid by CG&E to the EWG under CG&E's RCSA will be set at the unbundled generation rate charged to CG&E's customers who have not switched. This information will be available in CG&E's filed tariffs and will not be shielded. We also agree with CG&E on Shell's second argument regarding access to sufficient information in order to monitor CG&E's generation-related revenue. We believe that the rate information set forth in CG&E's tariffs in conjunction with CG&E's reporting data on sales, billed revenues, and other monthly data will provide sufficient information in order to monitor CG&E's generation revenues. Finally, with regard to the issue of allowing suppliers, such as Shell, to purchase power from the EWG at unbundled generation standard service offer rates, the Commission finds that the stipulation provides adequate measures to promote competition and, therefore, does not believe it is necessary [*131] to mandate at what price suppliers can purchase power from the EWG. IV. CRITERIA FOR EVALUATING STIPULATIONS Rule 4901-1-30, Ohio Administrative Code, authorizes parties to Commission proceedings to enter into stipulations. Although not binding on the Commission, the terms of such agreements are accorded substantial weight. See, Consumers Counsel v. Pub. Util. Comm. (1992), 64 Ohio St.3d 123, at 125, citing Akron v. Pub. Util. Comm. (1978), 55 Ohio St.2d 155. This concept is particularly valid where the stipulation is supported or unopposed by the vast majority of parties in the proceeding in which it is offered. The standard of review for considering the reasonableness of a stipulation has been discussed in a number of prior Commission proceedings. See, e.g., Ohio-American Water Co., Case No. 99-1038-WW-AIR (June 29, 2000); Cincinnati Gas & Electric Co., Case No. 91-410-EL-AIR (April 14, 1994); Western Reserve Telephone Co., Case No. 93-230-TP-ALT (March 30, 1004); Ohio Edison Co., Case No. 91-698-EL-FOR et al. (December 30, 1993); Cleveland Electric Illum. Co., Case No. 88-170-EL-AIR (January 30, 1989); Restatement of Accounts and Records (Zimmer [*132] Plant), Case No. 84-1187-EL-UNC (November 26, 1985). The ultimate issue for our consideration is whether the agreements, which embody considerable time and effort by the signatory parties, are reasonable and should be adopted. In considering the reasonableness of a stipulation, the Commission has used the following criteria: (1) Is the settlement a product of serious bargaining among capable, knowledgeable parties? (2) Does the settlement, as a package, benefit ratepayers and the public interest? (3) Does the settlement package violate any important regulatory principle or practice? The Ohio Supreme Court has endorsed the Commission's analysis using these criteria to resolve issues in a manner economical to ratepayers and public utilities. Indus. Energy Consumers of Ohio Power Co. v. Pub. Util. Comm. (1994), 68 Ohio St.3d 547 (citing Consumers' Counsel, supra, at 126). The court stated in that case that the Commission may place substantial weight on the terms of a stipulation, even though the stipulation does not bind the Commission (Id.). Based on our three-prong standard of review, we find that the first criterion, that the process involved serious bargaining [*133] by knowledgeable, capable parties, is met. Multiple bargaining sessions, open to all parties, took place before commencement of the hearings. The parties to these negotiations have been involved in many cases before the Commission, including a number of prior cases involving rate issues. Further, there have been few settlements in major cases before this Commission in which the overwhelming majority of intervenors either supported or do not oppose the resolution of issues presented by the stipulations. The stipulations also meet the second criterion. The stipulated resolution of these cases is for many reasons advantageous and promotes the public interest. The stipulations establish a framework for transition to and development of a competitive electricity marketplace in an orderly fashion. The stipulations also remove significant uncertainty and continuing controversy which could delay the primary goal of these proceedings to create a functioning and effective retail market for the sale of electricity to CG&E customers and an orderly transition from the traditional regulatory environment to one of supplier and service choices. Further, the stipulations assure an aggressive transition [*134] to a functioning retail generation market and provides other significant economic benefits for consumers, some of which would otherwise have been subject to legal challenge by CG&E. These benefits take the form of extended rate freezes, rate reductions, flexibility for larger contract customers not otherwise available, low income energy efficiency grants and, as a result of shorter, defined transition periods for CG&E, significant risks with respect to its ability to recover transition costs. Additionally, through the availability of shopping credits and incentives, the stipulations enable marketers to compete and sell retail electricity. Some of these benefits include: (1) Offers a five percent reduction of CG&E's generation component, including RTC, for residential rate schedules (2) Creates shopping credits that facilitate the development of the retail marketplace. (3) Waives the switching fee for the first 20 percent of residential customers that switch to a certified supplier during the MDP. (4) Maintains for five years the MDP, including a rate cap, to the residential customers, irrespective of the number that switch. (5) Continues support for energy efficiency and [*135] weatherization services to low-income persons by maintaining certain existing contracts valued at approximately $4 million for five years. (6) Prohibits the Company's EWG from offering power or ancillary services incident to the delivery of power at prices and terms more favorable than those available to the nonaffiliated electric suppliers. (7) Offers to customers with contracts approved pursuant to Section 4905.31, Revised Code, who would otherwise be on the primary distribution, transmission, or lighting rate schedules, a one-time right, through December 31, 2001, to cancel any such contract without penalty, provided that the customer remains a distribution customer of CG&E. (8) CG&E offers to make best efforts to implement consolidated bill-ready billing by January 1, 2002, and to implement supplier consolidated billing by June 1, 2002. (9) CG&E commits to work with other regions, RTO/ISO groups and transmission level customers to develop and implement specific proposals to address reciprocity and interface/seams issues. (10) CG&E commits to accept any resolution of issues agreed to by all OSPO working-group participants and to incorporate any such changes in its transition [*136] plan. (11) CG&E offers to amend its OATT to add a new schedule for retail energy imbalance service, and will amend its OATT to allow transmission customers to designate new resources on a day-ahead basis, provided that there exists available transfer capacity that is subject to the approval of the transmission provider, and that the transmission customer relinquishes network transmission rights to a designated resource once a new resource is designated. (12) CG&E offers to establish a technical task force to address and attempt to resolve technical and operational issues that may arise upon implementation of customer choice. Adoption of the stipulations also reduces significantly the number of possible appeals, and provides additional lead time to put in place the mechanisms necessary to get the customer choice program up and running. Additional evidence that the public interest is served by the stipulations is found in the support offered by representatives of residential, commercial, and industrial customers, including OCC and the Commission's staff. As indicated above, the agreement provides that certain rates will be decreased and the prior rate plan freezes extended. Finally, [*137] the stipulations meet the third criterion because they do not violate any important regulatory principle or practice. Indeed, the agreements balance the interests of a broad range of parties that represent a diverse spectrum of views. As indicated in the description of stipulations provided above, the stipulations provide substantial benefits to all customer classes and shareholders. Further, the policies of the state embodied in SB3 will be implemented more quickly and efficiently than would otherwise be possible. V. PENDING MOTIONS A. Interlocutory Appeal of Examiner's Ruling On May 15, 2000, AK Steel filed a motion to compel discovery against CG&E to name and produce for deposition and other discovery all persons who have knowledge of any agreements, promises, payments, or inducements offered to any of the signatories to the transition plan stipulation filed in this case. Further, AK Steel requested that each such person be required to produce all letters, notes, agreements, tapes, and contracts discussing, proposing, promising, or agreeing to some inducement to a signatory. AK Steel argued that, according to the language in the stipulation, the stipulation and CG&E's [*138] filing in this case represent all of the facts and data upon which the signatories relied when agreeing to the stipulation. AK Steel contended that it has reason to believe that some or all of these assertions are untrue and it seeks to confirm or disprove its suspicion. AK Steel claimed that, if it were shown that some or all of the signatory parties to the stipulation were offered or promised special consideration in addition to the terms of the stipulation, it would impeach or contradict the fundamental assertions of the stipulation. AK Steel cited to Rule 4901-1-16(B), O.A.C., that provides that any party to a Commission proceeding may obtain discovery of any matter, not privileged, which is relevant to the subject matter of the proceeding. AK Steel argued that an intervenor inquiring into the reasonableness of a stipulation should not be prevented from discovering the motives and considerations provided to those who signed and supported the stipulation. Also on May 15, 2000, CG&E filed a memorandum in opposition to AK Steel's motion to compel discovery. CG&E contended that AK Steel's motion is in direct conflict with the policy of the Commission to encourage settlement and is [*139] irrelevant to the proceeding. CG&E argued that the stipulation is a recommendation that is not legally binding upon the Commission. CG&E contended that the Commission must conclude independently that, based on the evidence, the stipulation offers a just and reasonable resolution of the issues. CG&E claimed that the motives of the parties who signed the stipulation are irrelevant to the determination of the Commission's approval of the stipulation. CG&E also contended that the only result of an inquiry into any alleged side agreements among the parties could only be to approve or disapprove such alleged agreements, which is not relevant to the stipulation. CG&E also contended that public policy favors the compromise and settlement of disputes and the Commission recognizes the need to encourage settlement among parties. The examiners assigned to this case issued an entry on May 19, 2000 ruling that AK Steel's motion should be denied. The examiners found that AK Steel failed to state what relevance the information it might discover through its motion to compel could have on the Commission's determination in this case. The examiners stated that the stipulations in these cases address [*140] the rates and services proposed in CG&E's transition plan and that the Commission's charge will be to determine if the stipulations and CG&E's transition plan are just and reasonable. The examiners also stated that motives of the parties in agreeing or not agreeing to sign the stipulation should not and will not affect the Commission's determination of the reasonableness of the stipulations and CG&E's transition plan. Consequently, the examiners believed that the discovery request of AK Steel was not relevant to the subject matter of the proceeding. The examiners further noted that evidence of the motives of parties in signing a stipulation is generally not admissible in a hearing. On May 24, 2000, AK Steel filed an application for review and interlocutory appeal of the hearing examiners' May 19, 2000 discovery ruling. AK Steel argues that it was improper for the examiners to deny its motion to compel. AK Steel argues that the evidence adduced from the discovery would be relevant to whether the stipulations are discriminatory on their face and not in the public interest if it can be shown that CG&E has agreed to give special considerations to parties that signed on to the stipulations. [*141] AK Steel reiterates many of the same argument raised in its original motion to compel. On May 25, 2000, CG&E filed a memorandum in opposition to AK Steel's application for review. Inasmuch as AK Steel's application for review has not been addressed prior to the issuance of this opinion and order, the Commission will address it at this time. The Commission affirms the ruling of the examiners for the reasons set forth in the examiner's May 19, 2000 entry. The Commission agrees that the information AK Steel seeks to discover will not lead to relevant information. The Commission will determine if the stipulation and CG&E's transition plan are just and reasonable. The transition plan and stipulation can not be modified by any private agreements not before the Commission. The motives of the parties in agreeing or not agreeing to sign the stipulation will not affect the Commission's determination of the reasonableness of the stipulation and CG&E's transition plan. Further, as noted by the examiners, the Commission's longstanding policy has been to encourage settlements in cases that come before it. The Commission believes that its policy would not be advanced if one party in a case could [*142] require another party to disclose information on the motives toward settlement or force another party to produce all letters, notes, agreements, tapes, and contracts related to that settlement motivation. By granting AK Steel's motion, we would be forcing such disclosures. Further, the Commission has the authority to verify CG&E's compliance with SB3, Title 49 of the Revised Code, and the Commission's rules, including the corporate separation requirements of the Commission's order and CG&E's corporate separation plan and applicable code of conduct. In addition, the Commission has authority to audit any transactions made by CG&E and its affiliates. This authority allows the Commission to prevent any improper subsidy or discriminatory treatment of customers. Accordingly, AK Steel's request that the Commission overturn the examiners' decision is denied. B. Filing of Compliance Tariffs On June 27, 2000, the CCE filed a motion for a "compliance tariff filing, service, review, and comment procedures. n12" The motion states that, because of the broad-sweeping changes that will be subject to the provisions of the tariffs ultimately approved in these proceedings, it is necessary to allow [*143] interested parties adequate time to review and comment on the proposed tariffs prior to final approval. CCE requests that the Commission order each of the applicants in the transition plan cases to serve tariffs and associated work papers simultaneous with their filing with the Commission. CCE asks that a two-week period be provided after the date of receipt of the tariffs and work papers in order for intervenors to review the documents and submit comments to the Commission for its consideration prior to approval of the tariffs. - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n12 This motion was jointly filed in all of the pending electric transition plan dockets. - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - CCE's motion shall be granted, subject to modification. We believe that, instead of receiving formal filings with respect to CG&E's compliance tariffs, a more informal process will be beneficial to all interested parties. Accordingly, the Company and other interested parties should observe the following timelines for distributing and reviewing CG&E's proposed tariffs pursuant to this order: (1) within [*144] 14 days following the issuance of this order, CG&E should distribute (via electronic mail, fax, or overnight delivery) to all intervenors and the Commission's staff a working draft of its proposed compliance tariffs as well as associated work papers, and UNB schedules that reflect the rates embodied in the compliance tariffs; (2) within 14 days thereafter, interested parties should circulate (via electronic mail, fax, or overnight delivery) comments to the Company and the staff regarding the Company's working draft n13; and (3) within 14 days thereafter, CG&E shall formally file its proposed tariffs in the form of an application for approval of compliance tariffs. - - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - - - n13 Neither the working draft nor the informal comments are to be filed formally in the docket in this proceeding. - - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - - - - VI. FINDINGS OF FACT AND CONCLUSIONS OF LAW: (1) On December 28, 1999, CG&E filed its transition plan, appendices, schedules, testimony, and supplemental information. (2) Preliminary objections were filed between January 26, 2000, [*145] and February 14, 2000. (3) On March 27, 2000, the Staff Report was filed. CG&E filed supplemental testimony on May 1, 3, and 17, 2000, and rebuttal testimony on June 12, 2000. (4) Intervention was granted to a number of parties. On May 8, 2000, a stipulation and recommendation on CG&E's transition plan was filed by CG&E; the staff; Ohio Consumers' Council; Ohio Council of Retail Merchants; Industrial Energy Users-Ohio; Kroger Company; The Ohio Manufacturers' Association; National Energy Marketers Association; New Energy Midwest, LLC; WPS Energy; Enron Energy Services, Inc.; Dynegy, Inc.; Cincinnati/Hamilton County Community Action Agency; Supporting Council of Preventive Effort; The Ohio Hospital Association; ODOD; People Working Cooperatively; Exelon Energy; Strategic Energy; Columbia Energy Services Corp.; Columbia Energy Power Marketing Corp.; Mid-Atlantic Power Supply; city of Cleveland; and American Municipal Power-Ohio. Stand Energy Corp. and Local Union 1347, International Brotherhood of Electrical Workers, AFL-CIO subsequently signed the stipulation. 5) Also on May 8, 2000, a stipulation on CG&E's employee assistance plan was filed on behalf of CG&E; the staff; Industrial [*146] Energy Users-Ohio; The Ohio Council of Retail Merchants; AK Steel Corporation; Kroger Company; The Ohio Manufacturers' Association; The Ohio Hospital Association; Columbia Energy Services Corp.; Columbia Energy Power Marketing; Exelon Energy; Strategic Energy; Mid-Atlantic Power Supply Assoc.; Ohio Consumers' Council; New Energy Midwest, LLC; WPS Energy Services, Inc.; and Enron Energy Services, Inc. A third stipulation on CG&E's independent transmission plan was filed on May 8, 2000, on behalf of CG&E; the staff; Ohio Consumers' Council; The Ohio Council of Retail Merchants; Industrial Energy Users-Ohio; Kroger Company; The Ohio Manufacturers' Association; New Energy Midwest, LLC; WPS Energy Services, Inc.; Enron Energy Services, Inc.; Dynegy, Inc.; and The Ohio Hospital Association. (6) Prehearing conferences were held on April 5, and May 11, 2000. The evidentiary hearings were held on May 30, June 1, 2, 5, 6, 8, and 14, 2000. (7) A local public hearing was held in Cincinnati, Ohio on June 8, 2000. (8) Pursuant to Section 4928.39, Revised Code, the total allowable transition costs for CG&E, as agreed to in the transition plan stipulation, are reasonable and include the recovery [*147] of $401.4 million of existing regulatory assets and projected $483 million of new regulatory assets, plus certain carrying costs and purchased power costs. (9) The stipulation provides appropriate shopping incentives to achieve a 20 percent load switching contemplated by Section 4928.40(A), Revised Code. (10) CG&E's transition plan, as modified by the stipulations, satisfies the requirements of SB3, and is approved for the reasons and to the extent set forth herein. It is, therefore, ORDERED, That CG&E's transition plan and stipulations filed on April 17, 2000, and May 8, 2000, are approved, to the extent set forth in this opinion and order and subject to final approval of CG&E's compliance tariffs. It is, further, ORDERED, That the tariff amendments and accounting authority requested by CG&E are approved in accordance with the discussion set forth in this opinion and order. It is, further, ORDERED, That CG&E and other interested intervenors follow the timelines for informal review and comments with respect to the company's compliance tariffs, and that CG&E file an application for approval of its compliance tariffs in accordance with the directives set forth in this opinion [*148] and order. It is, further, ORDERED, That a copy of this opinion and order be served upon all parties of record. THE PUBLIC UTILITIES COMMISSION OF OHIO SUMMARY OF THE COMMISSION'S OPINION AND ORDER OF AUGUST 31, 2000 IN THE CINCINNATI GAS & ELECTRIC COMPANY ELECTRIC TRANSITION PLAN CASE CASE NO. 99-1658-EL-ETP ET AL. On June 22, 1999, the Ohio General Assembly passed legislation requiring the restructuring of the electric utility industry and providing for retail competition with regard to the generation component of electric service (Amended Substitute Senate Bill No. 3 of the 123rd General Assembly). Governor Bob Taft signed this legislation (SB3) on July 6, 1999 and most provisions of SB3 became effective on October 5, 1999. Section 4928.31, Revised Code, required each electric utility to file with the Commission a transition plan for the company's provision of retail electric service in the state of Ohio. On December 28, 1999, Cincinnati Gas & Electric Company filed its transition plan, as well as applications for tariff approval and accounting authority. On May 8, 2000, a stipulation and recommendation on CG&E's transition plan (CG&E Ex. 60) was filed on behalf of CG&E, the staff, [*149] Ohio Consumers' Council, Ohio Council of Retail Merchants, Industrial Energy Users-Ohio, Kroger Company, The Ohio Manufacturers' Association, National Energy Marketers Association, New Energy Midwest, LLC, WPS Energy Services, Inc., Enron Energy Services, Inc., Dynegy, Inc, Cincinnati/Hamilton County Community Action Agency, Supporting Council of Preventive Effort, The Ohio Hospital Association, People Working Cooperatively, Exelon Energy, Strategic Energy, Columbia Energy Services Corp., Columbia Energy Power Marketing Corp., Mid-Atlantic Power Supply, city of Cleveland, and American Municipal Power-Ohio. Stand Energy Corp., and Local Union 1347 International Brotherhood of Electrical Workers, AFL-CIO subsequently signed the stipulation. Also on May 8, 2000, a stipulation on CG&E's employee assistance plan was filed on behalf of CG&E, the staff, Industrial Energy Users-Ohio, The Ohio Council of Retail Merchants, AK Steel, Kroger Company, The Ohio Manufacturers' Association, The Ohio Hospital Association, Columbia Energy Services Corp., Columbia Energy Power Marketing Corp., Exelon Energy, Strategic Energy, Mid-Atlantic Power Supply Assoc., Ohio Consumers' Council, New Energy Midwest, [*150] LLC, WPS Energy Services, Inc., and Enron Energy Services, Inc. A third stipulation on CG&E's independent transmission plan was filed on May 8, 2000, on behalf of CG&E, staff, Ohio Consumers' Council, The Ohio Council of Retail Merchants, Industrial Energy Users-Ohio, Kroger Company, The Ohio Manufacturers' Association, New Energy Midwest LLC, WPS Energy Services, Inc., Enron Energy Services, Inc., Dynegy, Inc., and The Ohio Hospital Association. The evidentiary hearings were held on May 30, and June 1, 2, 5, 6, 8, and 14, 2000. A local public hearing was held on June 8, 2000, in Cincinnati, Ohio. In the opinion and order, the Commission is approving the agreements submitted by the various parties listed above with certain modification regarding the operational support plan. The Commission found that the terms of the agreements, considered in their totality, advance the public interest and provide substantial benefits to all customer classes. The stipulations provide for extended rate freezes, rate reductions, flexibility for larger contract customers not otherwise available, low income energy efficiency grants and, as a result of shorter, defined transition periods for CG&E, significant [*151] risks with respect to its ability to recover transition costs. The stipulations, among other things: provide a five-percent reduction of CG&E's generation component for residential rate schedules; waive the switching fee for the first 20 percent of residential customers that switch to a certified supplier during the market development period; create shopping credits that facilitate the development of the retail marketplace; maintain for five years the market development period, including a rate cap, to the residential customers, irrespective of the number that switch; continue support for energy efficiency and weatherization services to low-income persons by maintaining certain existing contracts valued at approximately $4 million for five years; commit CG&E to work with other regions, RTO/ISO groups and transmission level customers to develop and implement specific proposals to address reciprocity and interface/seams issues; and offer to customers with contracts approved pursuant to Section 4905.31, Revised Code, who would otherwise be on the primary distribution, transmission, or lighting rate schedules, a one-time right, through December 31, 2001, to cancel any such contract without [*152] penalty, provided that the customer remains a distribution customer of CG&E. The Commission also determined that CG&E's transition plan filing, as amended by the settlement agreements, is in compliance with the statutory requirements contained in SB3. By approving the stipulations, the Commission also authorizes certain accounting treatments for CG&E to create the necessary regulatory assets, defer costs, and recover those costs through a regulatory transition charge. This summary was prepared to provide a brief statement of the Commission's action in this case. It is not part of the Commission's decision and does not supersede the full text of the Commission's opinion and order.