Duke Energy Ohio MBSSO Amendment
Case No. 06-986-EL-UNC

Duke Energy Ohio’s (formerly known as the Cincinnati Gas & Electric Company) (“DE-Ohio”) market-based standard service offer (“MBSSO”) was established in Case No. 03-93-EL-ATA. On August 2, 2006, DE-Ohio filed an application seeking authority to amend its MBSSO to be effective January 1, 2009.

Under DE-Ohio’s proposal, DE-Ohio would charge consumers a price to compare and a market price for the provider of last resort (“POLR”) service. The price to compare would consist of 85% of DE-Ohio’s unbundled generation rate plus the by-passable portion of a rate stabilization charge (“RSC”) equal to 24% in 2009 and 25% in 2010 of DE-Ohio’s unbundled generation rate less DE-Ohio’s Regulatory Transition Charge (“little g”) plus any PUCO approved increases to the Annually Adjusted Component (“AAC”) made prior to December 31, 2008 including recovery of environmental reagents approved for 2009, plus the fuel cost component. The AAC would no longer be billed separately but would be combined with the updated RSC that would be adjustable based upon incremental environmental costs, taxes and homeland security cost incurred January 1, 2009 and thereafter. The updated RSC would continue to be by passable by 25% of residential load and 50% of non-residential load.

The POLR charge would consist of updated Infrastructure Maintenance Fund (“IMF”) charge, plus the System Reliability Tracker (“SRT”) set at a reserve margin of 15% of DE-Ohio’s total load in its certified territory. The POLR would also consist of the non-by-passable portion of the RSC. The IMF would be phased in over the two year MBSSO wherein the IMF would be initially set at 9% of the little g in 2009 and updated to 10% of the little g in 2010.

DE-Ohio proposes to eliminate the SRT and would seek annual price adjustments based upon the cost of maintaining a 15% revenue margin as part of the IMF. DE-Ohio would also eliminate the ability of non-residential consumers to by-pass the SRT component of the IMF. The Transmission Cost Recovery (“RTC”) tracker under the MBSSO would continue in which the first call on the legacy generating assets of Cincinnati Gas & Electric would be committed to the MBSSO load in exchange for the IMF charge. All the other conditions of the RSP would be maintained including by-pass-ability, charging the market price to returning customers and the competitive bid process. DE-Ohio proposes to amend its Corporate Separation Plan so as not to be required to transfer its generating assets to an Exempt Wholesale Generator in order to continue to provide generating service from its generating assets.

DE-Ohio has offered to enter into a settlement as attached to application with willing parties. In exchange DE-Ohio will agree not file an application for rehearing or notice of appeal of a PUCO order that would resolve all the issues raised in this application. The offer of settlement is contingent upon PUCO approval without modification.

Distributed Generation Proceeding
Case No. 05-1500-EL-COI

Distributed generation (“DG”) refers generally to the use of on-site or localized generation, including conventional cogeneration facilities and also renewable sources of generation, such as wind, solar and biomass. DG is rapidly emerging as a significant part of the generation source mix in regional discussions about resource adequacy and load growth. In terms of cost, environmental impact, and system reliability, DG is an attractive option for both consumers and policymakers. A number of sub-issues surround the subject of DG. Issues regarding interconnection with the grid have been ongoing since before the enactment of PURPA [“Public Utilities Regulatory Policy Act” which created the Independent Power Producer (“IPP”), sometimes referred to as Qualifying Facilities (“QFs”) in 1978]. DG is increasing the demand for interconnection and pressure (and resistance) is being brought to bear for streamlined rules to govern the process. By reducing the up-front costs of interconnection improves the DG break-even point. But the issue de jour surrounding DG is net metering. Net metering refers to the ability of a DG operator to sell excess generation to the grid, either directly to the EDU or to some other market, such as the ISO’s real time market. Net metering part and parcel of the issue of demand response, whereby a DG operator could decide to consume its own power or turn that power over to the grid based on real-time price signals.

In May 2005, the Ohio Department of Development (“ODOD”) began a series of meetings with selected stakeholders to discuss barriers to the development of DG resources that extended through January 2006. While the ODOD has been conducting its workshops, the PUCO, in response to a letter from the Governor, opened Case No. 05-1500-EL-COI to examine the effect of the federal Energy Policy Act of 2005 on Ohio’s DG readiness and surrounding issues, most significantly, net metering.

After several parties filed comments and reply comments, the PUCO held workshops on net metering and fuel diversity; distributed generation interconnection; sale of stand-by power; and smart metering and demand response. After the workshops the PUCO staff filed a report setting forth recommendations based upon comments and the technical conferences. The staff’s recommendations included:

• Develop an advanced energy portfolio for Ohio that would integrate advanced energy standards into Ohio’s retail electric market.

• Eliminate rules that place limits on net metering and streamline the interconnection rules that would allow for simplified applications and fee schedules.

• Require Ohio’s EDUs to file a comprehensive list of Advanced Metering Infrastructure (“AMI”) technologies and costs and identify types of customers and their related load shapes.

• Utilize the McKinsey model to evaluate the costs and benefits of AMI deployment strategies.

• Revise Ohio’s interconnection rules to include all interconnection services in the EDUs’ tariffs to ensure they are accessible for the interconnection service customer.

• Bill supplemental power and scheduled maintenance according to the tariff rate schedules.

• Establish the PUCO as a liaison to self-generators for interpreting tariff provision and facilitating interconnection processes.

• Analyze the EDUs’ transmission and distribution systems to identify locations where distributed generation could improve operations and provide additional generation benefits.

AEP Cost Recovery Application
PUCO Case Nos. 05-376-EL-UNC

On March 18, 2005, Columbus Southern Power Company and Ohio Power Company (collectively “AEP”) filed an application, PUCO Case No. 05-376-EL-UNC, for authority to recover costs associated with the construction and operation of a 600 MW integrated gasification combined cycle (“IGCC”) electric generation facility. Basically AEP requested authority to implement a three-phase mechanism to guarantee cost recovery associated with the construction and operation of a generation plant that it intends to treat as a regulated asset, although Ohio Revised Code Section 492817(E) appears to prevent the PUCO from enforcing AEP’s intentions.

On April 10, 2006, the PUCO issued an order finding that the IGCC generation plant is considered to be part of the wires distribution system, and allowable as a regulated asset because the utility will remain the provider of last resort (“POLR”). The PUCO reached this decision by tortious reasoning claiming that because it labeled the POLR service “ancillary” and therefore it was not competitive, it was a regulated service. In reaching this conclusion, the PUCO implied that an EDU could own and operate a generating station in order to provide POLR service. Therefore, the PUCO authorized AEP to recover $23.7 million in pre-construction costs associated with the IGCC generation plant (Phase I). The PUCO deferred ruling upon AEP’s request to recover costs associated with Phase II and Phase III, and instead directed AEP to address the level of cost recovery, rate design, how the plant would benefit customers, how Ohio coal would be used, what byproducts would be sold, how many federal tax incentives the plant would be eligible for and how AEP plans to present the project to outside investors.

Applications for rehearing were filed by several interveners, and on June 28, 2006, the PUCO denied the applications for rehearing. On June 26, 2008 Industrial Energy Users-Ohio (“IEU-Ohio”) filed a Writ of Prohibition with the Ohio Supreme Court requesting the court prohibit the PUCO order from becoming effective.

Notices of Appeal were filed by IEU-Ohio, the Office of the Ohio Consumers’ Counsel (“OCC”), Ohio Energy Group (“OEC”) and FirstEnergy Solutions Corp (“FE Solutions”). The basic argument in the Notices was that the PUCO illegally approved a $2.7 million rate increase for AEP in violation of Ohio ratemaking statutes. The parties also argued that the PUCO erred in finding that the IGCC generation plant is a regulated asset because the utility will remain the POLR, and that the POLR service is “ancillary” and therefore a regulated service.

Dominion East Ohio Standard Service Offer Proceeding
Case No. 05-474-GA-ATA

On April 8, 2005, East Ohio Gas Company dba Dominion East Ohio (“DEO”) filed an application for authority to implement, through a two-phased process, a new Standard Service Offer Gas Cost Rate (“SSO”) in which DEO would eliminate its gas cost recovery (“GCR”) rate, and obtain and price its natural gas supplies through a market-based rated methodology. DEO sought approval of Phase I (pilot) of the process, in which DEO would conduct an auction in which interested suppliers could compete for the ability to provide portions of DEO’s wholesale gas supply. DEO would continue to provide commodity service to its retail customers via the SSO, which would be partially based on the results of the auction.

On May 26, 2006, the PUCO approved Phase I, and directed DEO to hire a professional auction manager to conduct the auction, and to fund the hiring of a consultant to be hired by the PUCO staff to oversee the auction process and to assist staff in evaluating the auction results. EnergyGateway was hired as the auction manager, and CRA International was hired to provide consultant support for the PUCO staff.

Phase I of the auction took place on August 29, 2006 via the Internet. Twelve bidders participated in the auction, which was jointly monitored by DEO, PUCO staff and the Office of the Consumers’ Counsel. The rate was a Retail Price Adjustment, which is a fixed dollar amount for the entire 23-month term, which would be in the form of an adder to the monthly NYMEX settlement price.

Also on August 29, 2006, the PUCO staff filed a post-auction report detailing the results of the auction. The report described the auction process and set forth the conclusion by the consultants that the auction was fair and devoid of any indications of collusion or other anomalies. Staff also concluded that a range of $2.196 to $2.504 per Mcf above the monthly NYMEX settlement price for natural gas futures was a reasonable benchmark by which to evaluate the auction, and concluded that the Retail Price Adjustment should be $1.44 per Mcf. Staff recommended that the PUCO approve the auction results and allow DEO to proceed with Phase I of the plan.

By entry dated August 30, 2006, the PUCO agreed with the conclusions of the Staff Report. The PUCO authorized DEO to replace its current GCR rate with the SSO and to enter into the necessary agreements with the winning bidders to implement the SSO process. The PUCO set the monthly SSO price at the sum of the NYMEX settlement price plus the Retail Price Adjustment of $1.44 per Mcf. Furthermore, the PUCO set Phase I for the period October 2006 through September 1, 2008 at which time the PUCO reserved the right to terminate Phase I and return DEO to the GCR pricing methodology if circumstances warrant. Separate analyses after the auction by the PUCO and OCC calculated that DEO’s cost have averaged between $2.35 and $2.50. On April 8, 2005, East Ohio Gas Company dba Dominion East Ohio (“DEO”) filed an application for authority to implement, through a two-phased process, a new Standard Service Offer Gas Cost Rate (“SSO”) in which DEO would eliminate its gas cost recovery (“GCR”) rate, and obtain and price its natural gas supplies through a market-based rated methodology. DEO sought approval of Phase I (pilot) of the process, in which DEO would conduct an auction in which interested suppliers could compete for the ability to provide portions of DEO’s wholesale gas supply. DEO would continue to provide commodity service to its retail customers via the SSO, which would be partially based on the results of the auction.

On May 26, 2006, the PUCO approved Phase I, and directed DEO to hire a professional auction manager to conduct the auction, and to fund the hiring of a consultant to be hired by the PUCO staff to oversee the auction process and to assist staff in evaluating the auction results. EnergyGateway was hired as the auction manager, and CRA International was hired to provide consultant support for the PUCO staff.

Phase I of the auction took place on August 29, 2006 via the Internet. Twelve bidders participated in the auction, which was jointly monitored by DEO, PUCO staff and the Office of the Consumers’ Counsel. The rate was a Retail Price Adjustment, which is a fixed dollar amount for the entire 23-month term, which would be in the form of an adder to the monthly NYMEX settlement price.

Also on August 29, 2006, the PUCO staff filed a post-auction report detailing the results of the auction. The report described the auction process and set forth the conclusion by the consultants that the auction was fair and devoid of any indications of collusion or other anomalies. Staff also concluded that a range of $2.196 to $2.504 per Mcf above the monthly NYMEX settlement price for natural gas futures was a reasonable benchmark by which to evaluate the auction, and concluded that the Retail Price Adjustment should be $1.44 per Mcf. Staff recommended that the PUCO approve the auction results and allow DEO to proceed with Phase I of the plan.

By entry dated August 30, 2006, the PUCO agreed with the conclusions of the Staff Report. The PUCO authorized DEO to replace its current GCR rate with the SSO and to enter into the necessary agreements with the winning bidders to implement the SSO process. The PUCO set the monthly SSO price at the sum of the NYMEX settlement price plus the Retail Price Adjustment of $1.44 per Mcf. Furthermore, the PUCO set Phase I for the period October 2006 through September 1, 2008 at which time the PUCO reserved the right to terminate Phase I and return DEO to the GCR pricing methodology if circumstances warrant. Separate analyses after the auction by the PUCO and OCC calculated that DEO’s cost have averaged between $2.35 and $2.50.

Remand of FirstEnergy’s Rate Stabilization Plan
PUCO Case No. 03-2144-EL-ATA

FirstEnergy Service Company, on behalf of Ohio Edison Company (“OE”), The Cleveland Electric Illuminating Company (“CEI”), and The Toledo Edison Company (“TE”) (collectively, “FirstEnergy”) filed an application on October 21, 2003 for authority to continue and to modify certain regulatory accounting practices and procedures, and to establish regulatory transition charges following the market development period (“MDP”). FirstEnergy proposed to either (a) establish a competitive bidding process to determine standard offer generation service rates commencing as of January 1, 2006 under which the price for generation services would be determined by then current market prices, or (b) implement a rate stabilization plan at the current tariffed levels (with some adjustments), to be effective through December 31, 2008, which FirstEnergy contends that it would provide stable long-term competitive pricing of energy services for their customers, assure electricity and enhance economic development within the companies’ service areas.

On June 9, 2004, the PUCO approved a modified version of FirstEnergy’s proposed rate stabilization plan, and further found that the price under the plan should be periodically compared with the prices submitted in a competitive bid process. On rehearing, the PUCO further modified the rate stabilization plan.

OCC and the Northwest Ohio Aggregation Coalition, which included the cities of Maumee, Northwood, Oregon, Perrysburg, Sylvania, the village of Holland and the Board of County Commissioners of Lucas County (“NOAC”) filed appeals to the Ohio Supreme Court. OCC and NOAC argued that the court should reverse the PUCO’s approval of the rate stabilization plan, the rate stabilization charge, shopping credits, allowance of interest on shopping credits and FirstEnergy’s financial-separation plan.

In a 5-2 decision, the Ohio Supreme Court reversed the PUCO’s approval of the rate stabilization plan finding that the PUCO failed to follow a statutory requirement for utilities to provide customers with both a market-based standard service offer and an option to buy service at a price to be determined through a competitive bidding process. However, the court upheld the PUCO’s approval of the rate stabilization charge, shopping credits, interest on shopping credits, and First Energy’s financial-separation plan.

On July 20, 2006 OCC and NOAC filed a Remand Proposal wherein OCC and NOAC seek implementation of Voluntary Competitive Bidding Option (“VCBO”) proposal for FirstEnergy’s residential customers, which customers have the option to enroll. Under the VCBO customers would have the option to procure electricity from an alternative generation provider, the current shopping credit would be eliminated thereby making the entire tariffed generation rate plus the shopping credit adder plus the rate stabilization charge avoidable, and the existing standard service offer would be maintained for customers who choose to remain with FirstEnergy. FirstEnergy also filed a proposal in which FirstEnergy recommended that it should conduct a competitive solicitation whereby competitive suppliers may submit market prices and customers will have an opportunity to participate by selecting to receive generation service at rates derived from those market prices.

By entry dated July 26, 2006, the Commission directed FirstEnergy to submit a plan that would provide an option for customer participation in the electric market through competitive bids or other reasonable means. The plan must be submitted within 45 days of the entry.

Remand of American Electric Power’s Rate Stabilization Plan
Case No. 04-169-EL-UNC

On February 9, 2004, Columbus Southern Power Company (“CSP”) and Ohio Power Company (collectively “AEP”) filed an application for approval of a post-Market Development Rate Stabilization Plan (“RSP”) (Case No. 04-169-EL-UNC). AEP proposed to substitute its plan for a post-market development period market-based standard service offer and to eliminate a competitive bidding process from 2006 through 2008. On January 26, 2006, the PUCO issued an order approving a RSP, which resulted in a 3% generation rate increase for CSP worth $77 million annually by 2008, and a 7% increase for Ohio Power worth $194 million annually.

Applications for rehearing were filed by several interveners including OCC, and on March 23, 2005, the PUCO denied the applications for rehearing. On April 29, 2005, OCC filed a Notice of Appeal, in which OCC argued, among other things, that the PUCO order violated Ohio Revised Code Section 4928.14(A) and (B). Section 4928.14(A) requires that a market-based standard service offer be available to customers at the end of the Market Development Period, and Section 4928.14(B) requires that an option to purchase competitive retail electric service at a price determined through a competitive bidding process be made available to customers at the end of the Market Development Period.

Consistent with its decision in the appeal of the FirstEnergy RSP proceeding, on July 5, 2006, the Ohio Supreme Court vacated and remanded the PUCO Order for further consideration.

By entry issued August 9, 2006, the PUCO directed AEP to file a plan that would provide an option for customers to purchase electric service at a price determined through a competitive bid process, or through another means that would be readily available and accessible to customers. In the meantime, the PUCO found that AEP’s RSP should remain in effect.

AEP Distribution Service Reliability
PUCO Case No. 06-222-EL-SLF

In December of 2003, Columbus Southern Power and Ohio Power (collectively “AEP”) entered into a stipulation with Staff, which addressed concerns of Staff regarding AEP’s provision of electric distribution service to certain rural areas. AEP agreed to make improvements to its 25% worst performing circuits in order to reduce the average outage time by 40%, and to maintain three other circuit quartiles at levels that would not worsen from their 2002 levels.

On January 31, 2006, AEP filed its final report pursuant to the stipulation. While the performance goals for the 25% lowest performance circuits were exceed, AEP stated that the baseline system average interruption duration index was not maintained for the remaining three circuit quartiles. AEP also filed an application requesting the PUCO to implement a process whereby AEP would present enhanced service reliability programs for PUCO approval, and if approved AEP would be authorized to recover those costs through an increase in distribution rates.

On February 6, 2006, the PUCO directed Staff to review and file a report on AEP’s performance during the course of the stipulation, recommend what consequences should be taken for it failure to fulfill the terms of the stipulation, and determine what areas of distribution service quality require improvement in order for AEP to provide reliable distribution service. Staff filed its report finding that for the years 2001 through 2005 that the system-wide reliability performance of both Columbus Southern Power and Ohio Power “has been getting worse on all measures, even after their efforts during the past two years.” Staff recommended that the PUCO order AEP to submit a comprehensive plan to improve its service reliability.

On May 3, 2006, the PUCO directed AEP to begin developing a plan to enhance its service reliability, and to file a response to Staff’s recommended consequences for its failure to maintain system-wide performance for the second, third and fourth quartiles. AEP filed its response on May 23, 2006, arguing that the PUCO should not impose any consequences for its failure not to meet all the terms of the stipulation. AEP offered to commit $5 million to further improving its system reliability, and agreed not to request recovery from its customers any of the $5 million.

By entry issued July 26, 2006, the PUCO found that the $5 million proposed by AEP was not adequate to address its failure to meet the terms of the stipulation. Therefore, the PUCO fined AEP $10 million, and found that AEP would not be permitted to recover the fine from ratepayers. AEP must submit by October 6, 2006 a plan that outlines future plans to ensure reliability and service quality, project costs to implement the service reliability programs and provide supporting documentation and testimony. After the plan and testimony have been filed, the PUCO will issue an entry scheduling the filing of intervener testimony, local public hearings and an evidentiary hearing.

Office of the Consumers’ Counsel’s Mixed Energy Resource Portfolio

Janine Migden-Ostrander and her staff have developed an energy plan designed to provide affordable and stable rates for residential customers, price certainty for business customers and the ability of utilities and power suppliers to recover their reasonable costs for new power plant construction and manage their risk. Because re-regulation, a flash-cut to competition or continuation of the RSPs are not acceptable electric energy policies for the future, the OCC proposes a plan entitled “Integrated Portfolio Management” (IPM). IPM is designed to:

1. Allow for the development of a portfolio of supply options that permits hedging of options to manage risk.

2. Encourage the construction of new generation while placing caps on the cost to ensure that those companies building plants do so as efficiently as possible.

3. Provide the opportunity to diversify the options to serve customers’ load, which include clean coal technology, renewable energy and energy efficiency.

4. Reduce price volatility and providing a zone of price certainty that will help energy intensive businesses make decisions regarding locating or continuing to do business in Ohio.

The IPM would consist of a percentage of short-term and long-term power purchases.

A percentage of an electric distribution utility (EDU)’s load would be bid on the short-term market for staggered three-year contracts such that one third of the short term contracts would expire every year. These short-term supplies could be competitively bid through a Request for Proposal (RFP) process or a descending clock auction.

EDUs would file long-term forecast reports of their forecasted energy demand for the next 20 years along with an IPM plan to meet that demand. For the long-term portion, there would be a tranche (or slice of the system) for renewable energy and another for reductions in demand via energy efficiency, both options containing no fuel risk and little environmental risk. The IPM plan could specify base load and peaking power for varying lengths of time.

In order to encourage new construction, the IPM could include a request for the construction of a power plant to serve load into the future. For example, if a long-term forecast report in 2009 demonstrated that 600 MW would be needed in 2015, then there would be a competitive bid to supply that demand. The winning bidder would have a six-year window to obtain financing and build the plant.

The IPM would serve as the standard service offer (SSO) as required under current law. Every year, the price would be readjusted to account for the cost of new or expiring long-term contracts serving load and the new short-term power purchases, as well as adjusting for the number of customers being served under the standard service offer. The price could either go up or down or remain the same, however, it would be expected that the price adjustments would not be dramatic.

In order to effectuate this policy, minimal refinements to current statutes would be required. These requirements include reinstituting forecasting and planning proceedings. It would also include establishing parameters for renewable energy and energy efficiency. Only a few statutes would have to be amended.