Regulatory Matters	12 Months Ended
Dec. 31, 2011
Regulatory Matters [Abstract]
Regulatory Matters	REGULATORY MATTERS As a result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss does not represent the Companies' maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on Dominion's or Virginia Power's financial position, liquidity or results of operations. The following is a discussion of Dominion's and Virginia Power's material pending and recent regulatory matters. Electric Regulation in Virginia The enactment of the Regulation Act in 2007 significantly changed electric service regulation in Virginia by instituting a modified cost-of-service rate model. With respect to most classes of customers, the Regulation Act ended Virginia's planned transition to retail competition for its electric supply service. The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It provides for enhanced returns on capital expenditures on specific new generation projects, including but not limited to combined cycle gas generation, nuclear generation, clean coal/carbon capture compatible generation, and renewable generation projects. The Regulation Act also continues statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. If the Virginia Commission's future rate decisions, including actions relating to Virginia Power's rate adjustment clause filings, differ materially from Virginia Power's expectations, it may adversely affect its results of operations, financial condition and cash flows. 2009 Base Rate Review Pursuant to the Regulation Act, the Virginia Commission initiated a review of Virginia Power's base rates, terms and conditions in 2009, including a review of Virginia Power's earnings for test year 2008. In March 2010, the Virginia Commission issued the Virginia Settlement Approval Order, thus concluding the 2009 case and resolving open issues relating to Virginia Power's base rates, fuel factor and Riders R, S, T, C1 and C2. Virginia Power's fourth quarter 2009 results included a charge of $782 million ($477 million after-tax) as a result of the 2009 Base Rate Review. Dominion's 2009 results include an additional charge of $12 million ($8 million after-tax) recorded in other operations and maintenance expense, reflecting the write-off of previously deferred RTO costs since recovery was no longer probable based on the 2009 Base Rate Review. 2011 Biennial Review Pursuant to the Regulation Act and the Virginia Settlement Approval Order, in March 2011, Virginia Power submitted its base rate filing and accompanying schedules in support of the first biennial review of its base rates, terms and conditions, as well as of its earnings for the 2009 and 2010 test period. The biennial review included a determination of whether Virginia Power's earnings for the 2009 and 2010 combined test years were within 50 basis points of the authorized ROE of 11.9% established in the Virginia Settlement Approval Order, as well as authorization of an ROE which will be applicable to base rates and Riders R, S, C1 and C2 and which will be used to measure base rate earnings during the 2013 biennial review proceeding. As a result of the Virginia Settlement Approval Order and the Regulation Act, Virginia Power's base rates are not subject to change based on the 2011 biennial review. In November 2011, the Virginia Commission issued the Biennial Review Order. Base ROE The Virginia Commission determined that Virginia Power's new authorized ROE is 10.9%, inclusive of a performance incentive of 50 basis points for meeting certain RPS targets. Subject to the outcome of Virginia Power's petition for rehearing or reconsideration described below, this ROE will serve as the ROE against which Virginia Power's earned return will be compared for all or part of the test periods in the 2013 biennial review proceeding. The Virginia Commission ordered that the 50 basis point RPS performance incentive will not be included in the ROE applicable to any rate adjustment clauses. The Virginia Commission declined to award a performance incentive for generating plant performance, customer service or operating efficiency in connection with this biennial review but instead will initiate a rulemaking proceeding to develop performance incentive criteria to be applied in future biennial review proceedings. In December 2011, Virginia Power filed a petition with the Virginia Commission seeking rehearing or reconsideration of the Biennial Review Order, to confirm the effective date of the newly authorized 10.9% base ROE. In December 2011, Virginia Power also filed a Notice of Appeal with the Virginia Commission of the Biennial Review Order to the Supreme Court of Virginia. ROE Applicable to Riders C1, C2, R, and S Effective December 1, 2011, the ROE applicable to Riders C1 and C2 is 10.4%. An ROE of 11.3% applied through November 30, 2011. For Riders R and S, effective December 1, 2011, the ROE is 11.4%, inclusive of a statutory enhancement of 100 basis points. An ROE of 12.3%, inclusive of a statutory enhancement of 100 basis points, applied through November 30, 2011. Earned Return for 2009 and 2010 The Virginia Commission determined that Virginia Power earned an ROE of approximately 13.3% during the 2009 and 2010 combined test years, which exceeded the authorized ROE earnings band of 11.4% of 12.4% established in the Virginia Settlement Approval Order. Based on the determination that Virginia Power had excess earnings, the Virginia Commission ordered Virginia Power to refund 60% of earnings above the upper end of the authorized ROE earnings band, or approximately $78 million, to its customers, which is being provided in the form of credits to customers' bills amortized over a six-month period during 2012. A charge for the refund was recognized in operating revenues in the 2011 Consolidated Statement of Income. The actual aggregate refund amount is expected to total approximately $81 million, taking into account refunds to be paid to certain non-jurisdictional customers pursuant to their customer contracts. Base Rates and Existing Riders T, C1, and C2 As a result of the Virginia Commission's determination that credits will be applied to customers' bills, the Virginia Commission, as required by the Regulation Act, directed Virginia Power to combine its existing Riders T, C1, and C2 with Virginia Power's base costs, revenues and investments, and to file revised tariffs reflecting such combination pursuant to the Biennial Review Order. These Riders will thereafter be considered part of Virginia Power's base costs, revenues and investments for purposes of future biennial review proceedings. The Virginia Commission has initiated a proceeding to address further implementation of this directive. Virginia Power's base rates will otherwise remain unchanged through at least December 1, 2013. Earnings Test Adjustments The Virginia Commission ruled on numerous contested proposals to adjust Virginia Power's earnings for the 2009 and 2010 combined test periods. Among other adjustments, the Virginia Commission approved Virginia Power's ratemaking treatment of fuel inventories held by its wholly-owned subsidiaries. As a result of this finding, Virginia Power included in rate base approximately $177 million and $188 million in fuel inventory costs for 2009 and 2010, respectively. The Virginia Commission also adopted Virginia Power's treatment that includes, for regulatory earnings purposes, its AIP and LTIP expenses up to a 100% payout ratio. The Virginia Commission excluded from expense approximately $21 million in incentive plan costs that exceeded a payout ratio of 100%, allowing a net recovery of approximately $95 million of incentive compensation expense for the biennial review period. The Virginia Commission denied Virginia Power's ratemaking treatment that expensed the entire cost of its 2010 voluntary separation plan in 2010, ruling instead to amortize the cost through the end of 2011. This matches the costs of the plan with the period of realization of savings, which reduces 2010 operating costs (and in turn, increases 2011 operating costs) by approximately $103 million for purposes of the earnings test. Other than influencing the amount earned above the authorized ROE earnings band, the earnings test adjustments above did not have an impact to the Consolidated Financial Statements. In addition, the Virginia Commission required Virginia Power to recognize a gain, for purposes of the earnings test, of approximately $44 million on the settlement of certain interest rate hedging contracts in 2010, as opposed to amortizing the gains over the forecasted term of planned debt instruments that were not issued. Virginia Power determined that it was no longer probable that these derivative gains would be included in future base rates as the Virginia Commission would not allow the amortization of these amounts in future periods. As a result, Virginia Power removed approximately $50 million in December 2011 from regulatory liabilities and recognized the deferred derivative settlement gains in Interest and Other Charges in the Consolidated Statements of Income. Virginia Fuel Expenses In May 2011, Virginia Power submitted its annual fuel factor filing to the Virginia Commission, proposing an annual increase for the rate year beginning July 1, 2011. This revised factor included a projected $434 million balance of prior year under-recovered fuel expenses. To reduce the impact to customers, as an alternative, Virginia Power proposed to recover this projected prior year deferred fuel balance over a two-year period beginning July 1, 2011. In June 2011, the Virginia Commission approved the two-year recovery proposal, resulting in an increase of approximately $319 million in annual fuel revenue for the rate year beginning July 1, 2011. The rate increase is designed to recover $217 million of unrecovered fuel expenses from the prior fuel year as well as a $102 million increase in anticipated fuel expenses for the 2012 fuel year. Generation Riders R and S In connection with the Bear Garden and Virginia City Hybrid Energy Center projects, in March 2011, the Virginia Commission approved annual updates for Riders R and S with revenue requirements of $78 million and $199 million, respectively, for the April 1, 2011 to March 31, 2012 rate year, utilizing the 12.3% placeholder ROE (inclusive of a 100 basis point statutory enhancement) pending the Virginia Commission's ROE determination in the 2011 biennial review. Virginia Power's proposed revenue requirements for Riders R and S for Rider S for the April 1, 2012 to March 31, 2013 rate year were adjusted to approximately $76 million and $231 million, respectively, and are pending final Virginia Commission approval. Future annual updates for Riders R and S will provide revenue requirements reflecting any true-ups to revenue requirements approved for the previous calendar year, including the ROE determined in the Biennial Review Order. Construction of Bear Garden was completed and the facility commenced commercial operations in the second quarter of 2011. DSM Riders C1 and C2 In connection with Virginia Power's five DSM programs approved by the Virginia Commission, in March 2011, the Virginia Commission approved the annual updates for Riders C1 and C2 with revenue requirements of approximately $6 million and $12 million, respectively, for the April 1, 2011 to March 31, 2012 rate year, utilizing an 11.3% placeholder ROE pending the Virginia Commission's ROE determination in the 2011 biennial review. By order issued in June 2011, the Virginia Commission extended the rates through April 2012. In September 2011, Virginia Power filed with the Virginia Commission an application for approval of six new energy efficiency DSM programs, along with an annual update to Riders C1 and C2. Virginia Power's proposed revenue requirement for the May 1, 2012 through April 30, 2013 rate year is approximately $72 million, as amended in February 2012 to reflect, along with other adjustments, the determination of a 10.4% ROE applicable to Riders C1 and C2 in the the Biennial Review Order. As discussed above, previously implemented Riders C1 and C2 will be considered part of Virginia Power's base costs, revenues and investments for purposes of future biennial review proceedings, and the Virginia Commission has initiated a proceeding to address further implementation of this directive. Transmission Rider T In May 2011, Virginia Power filed its annual update to Rider T with the Virginia Commission. The proposed $481 million annual revenue requirement, effective September 1, 2011, represented an increase of approximately $144 million over the revenue requirement associated with the Rider T customer rates previously in effect. In July 2011, the Virginia Commission issued an order approving a revenue requirement of $466 million for the September 1, 2011 to August 31, 2012 rate year. As discussed above, previously implemented Rider T will be considered part of Virginia Power's base costs, revenues and investments for purposes of future biennial review proceedings, and the Virginia Commission has initiated a proceeding to address further implementation of this directive. Generation Rider W In May 2011, Virginia Power requested approval from the Virginia Commission to construct and operate Warren County, as well as approval of Rider W. In February 2012, the Virginia Commission approved Certificates of Public Convenience and Necessity for Warren County and related transmission facilities. The Virginia Commission also approved Virginia Power's proposed revised revenue requirement of $35 million for the April 1, 2012 to March 31, 2013 rate year, reflecting an ROE of 11.4%, inclusive of a statutory enhancement of 100 basis points for Rider W, consistent with the Biennial Review Order. In addition, the Virginia Commission approved an ROE enhancement of 100 basis points for Rider W for a period of 10 years following commercial operations. The facility is expected to start commercial operations in late 2014. Generation Rider B In June 2011, Virginia Power filed applications with the Virginia Commission seeking regulatory approval to convert three of its coal-fired power stations to biomass. The applications included a request for approval of Rider B. Virginia Power's proposed revenue requirement for Rider B is approximately $6 million for the April 1, 2012 to March 31, 2013 rate year, as adjusted to reflect the base ROE authorized in the Biennial Review Order, and inclusive of a renewable generating unit statutory enhancement of 200 basis points. To qualify for federal production tax credits associated with renewable energy generation, the power stations must commence operation as biomass generation facilities by December 31, 2013. Virginia Power has requested Virginia Commission approval of the biomass conversions on a schedule that will enable qualification for these tax credits. Solar Distributed Generation Demonstration Program In October 2011, Virginia Power filed with the Virginia Commission an application to conduct a solar distributed generation demonstration program, consisting of up to a combined 30 MW of Company-owned solar distributed generation facilities to be located at selected commercial, industrial and community locations throughout its Virginia service territory, as well as up to a combined 3 MW of customer-owned solar distributed generation facilities that will be subject to a tariff filed with the Virginia Commission in 2012. Virginia Power proposed to construct and operate the Company-owned facilities in two phases, with Phase I (up to 10 MW) from the date of approval through the end of 2013 and Phase II (up to 20 MW) from the beginning of 2014 to the end of 2015. Virginia Power did not seek a rate adjustment clause for Phase I facilities with this filing; Phase I costs will be recovered as part of base rates in a future biennial review. Virginia Power indicated that it may seek a rate adjustment clause at a future time for Phase II costs. Electric Transmission Projects Portions of the Mt. Storm-to-Doubs line and certain associated facilities are approaching the end of their expected service lives and require replacement with new facilities to maintain reliable service. Virginia Power owns, and has been designated by PJM to rebuild, 96 miles of the line in West Virginia and Virginia, and The Potomac Edison Company owns, and has been designated by PJM to rebuild, the remaining three miles of the line in Maryland. In September 2011, the Virginia Commission approved Virginia Power's application to rebuild its portion of the Mt. Storm-to-Doubs line. The approval of the West Virginia Commission was not required. Subject to applicable state and federal regulatory approvals, Virginia Power's portion of the rebuild project is expected to be completed by June 2015. In October 2008, the Virginia Commission authorized construction of the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line. The Meadow Brook-to-Loudoun line was placed in service in April 2011 and the Carson-to-Suffolk line was placed in service in May 2011. In June 2010, the Virginia Commission authorized the construction of the Hayes-to-Yorktown line along the proposed eight-mile route utilizing existing easements and property previously acquired for the transmission line right-of-way. In accordance with the Virginia Commission's approval, approximately 4.2 miles of the Hayes-to-Yorktown line will be constructed overhead and approximately 3.8 miles will be installed underground in order to cross under the York River. The Hayes-to-Yorktown line is expected to be completed by June 2012. In January 2012, the Virginia Commission authorized the replacement at higher voltage of approximately 43 miles of existing transmission lines between the Dooms and Bremo substations. Subject to the receipt of other applicable state and federal regulatory approvals, Dooms-to-Bremo is expected to be completed by May 2014. In December 2011, Virginia Power submitted an application to the Virginia Commission for approval of the Waxpool-Brambleton-BECO line. This project is is required to provide requested service to a new datacenter campus in Loudoun County, Virginia. Virginia Power expects PJM to authorize Waxpool-Brambleton-BECO as part of the 2012 RTEP within the first half of 2012. Subject to the receipt of applicable state and federal regulatory approvals, Waxpool-Brambleton-BECO is expected to be completed by November 2013. North Anna Power Station Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna, which Virginia Power owns along with ODEC. In May 2010, Virginia Power announced its decision to replace the reactor design previously selected for the potential third nuclear unit with the US-APWR technology. In June 2010, Virginia Power and ODEC amended the COL application to reflect the selection of the US-APWR technology. In January 2011, Virginia Power and the DOE terminated their cooperative agreement to share equally the cost of developing a COL. The agreement references the technology previously selected by Virginia Power. DOE funding related to COL development activities is not available under the agreement for activities related to the US-APWR technology. In February 2011, ODEC informed Virginia Power of its intent to no longer participate in the development of a potential new unit at North Anna. In December 2011, Virginia Power acquired ODEC's interest in the project, thereby terminating ODEC's involvement in the development of a potential third unit at North Anna. Virginia Power has not yet committed to building a new nuclear unit at North Anna. If Virginia Power decides to build the new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power continues to pursue the COL from the NRC. Based on the current NRC schedule, the COL could be issued as early as late 2014. The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the ASLB of the NRC permitted BREDL to intervene in the proceeding. All of BREDL's previous contentions in this proceeding have been dismissed. In September 2011, BREDL submitted a new proposed contention seeking to litigate issues related to the August 2011 Mineral, Virginia earthquake. In October 2011, the ASLB granted a motion filed by Virginia Power, with the consent of BREDL and the NRC staff to hold any ruling on this proposed contention in abeyance until Virginia Power completes an assessment of this earthquake. No other persons have sought to intervene in the proceeding. If a new contention is not admitted, the mandatory NRC hearing will be uncontested with respect to other issues. On April 14, 2011, twenty-one organizations and individuals that had previously intervened opposing various reactor licensing proceedings filed a petition requesting that the NRC suspend all decisions regarding reactor licensing and design certification pending completion of an NRC task force review of the events at Fukushima, Japan, among other requested relief. The North Anna 3 COL proceeding is one of the pending proceedings identified in this petition, and BREDL served the petition in the North Anna 3 COL proceeding on April 18, 2011. In September 2011, the NRC denied the petitioners' requests to suspend licensing and design certification proceedings. The only relief granted was the petitioners' request that the NRC perform a safety analysis of the regulatory implications of the Fukushima event to the extent it is doing so. Virginia Power continues to pursue various environmental permits that would be needed to support future construction and operation of a third nuclear unit at North Anna. North Carolina Regulation In February 2010, in preparation for the end of a five-year moratorium on Virginia Power's North Carolina base rates, Virginia Power filed an application with the North Carolina Commission to increase its base rates and adjust its fuel rates. In December 2010, the North Carolina Commission issued the North Carolina Settlement Approval Order approving a settlement agreement among all parties to the base rate and fuel case except one, which did not oppose the settlement. The North Carolina Settlement Approval Order authorized an increase in base revenues of approximately $8 million. In addition, the North Carolina Settlement Approval Order allowed the recovery through fuel rates of 85% of the net energy costs of power purchases from both PJM and other wholesale suppliers and from the non-utility generators subject to economic dispatch that do not provide actual cost data. The North Carolina Settlement Approval Order authorized an ROE of 10.7% and a capital structure composed of 49% long-term debt and 51% common equity. The new base and fuel rates became effective on January 1, 2011. In December 2011, the North Carolina Commission issued an order approving a settlement agreement among Virginia Power, the Public Staff of the North Carolina Commission and other interested parties in Virginia Power's fuel case for its North Carolina service territory. The settlement agreement provides for a $36 million increase in Virginia Power's fuel revenues for one year, effective January 1, 2012, including approximately $13 million in under recovery of fuel expenses for the previous fuel period. Virginia Power intends to file an application with the North Carolina Commission by March 30, 2012, to increase base rates. Ohio Regulation PIR Program In March 2011, East Ohio filed a request with the Ohio Commission to accelerate the PIR program by nearly doubling its PIR spending to more than $200 million annually. East Ohio identified 1,450 miles of pipeline that need to be replaced, in addition to the pipeline originally identified in the PIR project scope. East Ohio plans to accelerate the pace of the program by investing more resources in its infrastructure in the near term, in an effort to promote ongoing public safety and reduce operating costs over the longer term. In August 2011, the Ohio Commission approved the stipulation by East Ohio, the Staff of the Ohio Commission and other interested parties in East Ohio's accelerated PIR proceeding. The stipulation provides for an increase in annual PIR capital investment from the current level of approximately $120 million stepping up to approximately $160 million by 2013. In addition, the stipulation provides for cost recovery over a five-year period commencing upon the approval of the Ohio Commission. In accordance with the stipulation, East Ohio requested the dismissal of its appeal at the Ohio Supreme Court regarding its opposition to the Ohio Commission's order concerning East Ohio's first year PIR cost recovery charge. In August 2011, East Ohio submitted its annual application to adjust the cost recovery charge under the previously approved PIR program. A supplement to the application was filed in September 2011. The proposed recovery charge includes actual costs and a return related to investments made through June 30, 2011. A settlement agreement approved by the Ohio Commission in October 2011 supports the revenue requirement of $37 million reflected in the application. PIPP Plus Program Under the Ohio PIPP Plus program, eligible customers can receive energy assistance based on their ability to pay their bill. The difference between the customer's total bill and the PIPP plan payment amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. The PIPP Plus program sets the customer's monthly payments at 6% of household income and provides for forgiveness credits to the customer's balance when required payments are received in full by the due date. Such credits may result in the elimination of the customer's arrearage balance over 24 months. In March 2011, the Ohio Commission approved East Ohio's annual update of the PIPP Rider, which reflected the elimination of accumulated arrearages and projected deferred program costs of approximately $112 million for the 12-month period from April 2011 to March 2012. UEX Rider East Ohio files an annual UEX Rider with the Ohio Commission, pursuant to which it seeks recovery of the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar-for-dollar recovery of East Ohio's actual write-offs of uncollectable amounts. In 2011, East Ohio deferred approximately $62 million of bad debt expense for recovery through the UEX Rider. House Bill 95 Ohio enacted utility reform legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future. In December 2011, East Ohio filed an application requesting authority to implement a capital expenditure program under the new law. If the application is approved, East Ohio would be able to defer as a regulatory asset carrying costs, depreciation and property tax associated with approximately $95 million in capital expenditures for assets placed in service but not yet reflected in rates. Federal Regulation FERC - Electric Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominion's merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion's market-based sales tariffs authorized by FERC. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power's service territory. Any such sales would be voluntary. Rates In April 2008, FERC granted an application for Virginia Power's electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure. In July 2008, Virginia Power filed an application with FERC requesting a revision to its revenue requirement to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 1.5% for four of the projects (including the Meadow Brook-to-Loudoun and Carson-to-Suffolk lines, which were completed in 2011) and an incentive of 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008. The total cost for all eleven projects is estimated at $877 million, and all projects are currently expected to be completed by 2012. Numerous parties sought rehearing of the FERC order in August 2008, and rehearing is pending. Although Virginia Power cannot predict the outcome of the rehearing, it is not expected to have a material effect on results of operations. In March 2010, ODEC and NCEMC filed a complaint with FERC against Virginia Power claiming that approximately $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power's transmission formula rate. ODEC and NCEMC requested that FERC establish procedures to determine the amount of costs for each applicable project that should be excluded from Virginia Power's rates. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. In February 2012, Virginia Power submitted to FERC a settlement agreement to resolve all issues set for hearing. All transmission customer parties to the proceeding joined the settlement. The Virginia Commission, North Carolina Commission and Public Staff of the North Carolina Commission, while not parties to the settlement, have agreed to not oppose the settlement. If accepted by FERC, the settlement provides for payment by Virginia Power to the transmission customer parties of $250,000 per year for ten years and resolves all matters other than the incremental cost of certain underground transmission facilities, which will be set for briefing. While Virginia Power cannot predict the outcome of the briefing, it is not expected to have a material effect on results of operations. PJM For recovery of costs of investments of new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a regional rate design where all customers pay a uniform rate based on the costs of such investment. For recovery of costs of investment in new PJM-planned transmission facilities that operate below 500 kV, FERC affirmed its earlier decision to allocate costs on a beneficiary pays approach. A notice of appeal of this decision was filed in February 2008 at the U.S. Court of Appeals for the Seventh Circuit. In August 2009, the court denied the petition for review concerning the rate design for existing facilities, but granted the petition concerning the rate design for new facilities that operate at or above 500 kV, and remanded the issue of existing facilities back to FERC for further proceedings. Although Dominion and Virginia Power cannot predict the outcome of the FERC proceedings on remand, the impact of any PJM rate design changes on the Companies' results of operations is not expected to be material. In May 2008, the RPM Buyers filed a complaint with FERC claiming that PJM's Reliability Pricing Model's transitional auctions have produced unjust and unreasonable capacity prices. The RPM Buyers requested that a refund effective date of June 1, 2008 be established and that FERC provide appropriate relief from unjust and unreasonable capacity charges within 15 months. In September 2008, FERC dismissed the complaint. The RPM Buyers requested rehearing of the FERC order in October 2008 and rehearing was denied in June 2009. A notice of appeal was filed in August 2009 by the Maryland Public Service Commission and the New Jersey Board of Public Utilities at the U.S. Court of Appeals for the Fourth Circuit. In November 2009, the Court transferred the appeal to the Court of Appeals for the District of Columbia Circuit. In February 2011, the Court of Appeals denied the petition for review, concluding that FERC had adequately explained why the rates were just and reasonable. In November 2011, PJM issued a formal notification that it would recalculate certain ancillary service revenues that had previously been paid during 2009, 2010 and 2011. Also in November 2011, PJM requested FERC permission to suspend its rebilling and repayment obligations associated with the recalculation of such revenues and petitioned FERC to establish a proceeding to determine the appropriate recalculations for the revenues during this period. In December 2011, FERC permitted the suspension of rebilling and repayment by PJM, subject to the outcome of FERC's proceedings to determine the appropriate revenue recalculation. Virginia Power has accrued a liability of $36 million as of December 31, 2011 for estimated future billing adjustments from PJM related to the ancillary service revenues. FERC - Gas FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion's interstate natural gas company subsidiaries, including DTI, Cove Point and the Dominion South Pipeline Company, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities. In December 2007, DTI and the IOGA entered into a settlement agreement on DTI's gathering and processing rates, which DTI and IOGA agreed in May 2010 to extend through December 31, 2014. DTI, at its option, may elect to extend the agreement for an additional year through December 31, 2015. The settlement extension maintains the gas retainage fee structure that DTI has had since 2001. The rates are 10.5% for gathering and 0.5% for processing. Under the settlement, DTI continues to retain all revenues from its liquids sales, thus maintaining cash flow from the liquids business. In October 2011, DTI requested and received FERC approval of the negotiated rates associated with the agreement extension. In May 2011, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective July 1, 2011. Cove Point proposed an annual cost of service of approximately $150 million. In June 2011, FERC accepted a July 1, 2011 effective date for all proposed rates but two of which were suspended to be effective December 1, 2011. In December 2011, Cove Point, FERC trial staff and the other active parties in the rate case reached a settlement in principle on all issues set for hearing by FERC, as well as on all outstanding proposed tariff changes filed in May 2011. The parties expect to file the stipulation and agreement resolving all outstanding issues in the rate case in March 2012.

REGULATORY MATTERS

As a result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss does not represent the Companies' maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on Dominion's or Virginia Power's financial position, liquidity or results of operations. The following is a discussion of Dominion's and Virginia Power's material pending and recent regulatory matters.

Electric Regulation in Virginia

The enactment of the Regulation Act in 2007 significantly changed electric service regulation in Virginia by instituting a modified cost-of-service rate model. With respect to most classes of customers, the Regulation Act ended Virginia's planned transition to retail competition for its electric supply service.

The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It provides for enhanced returns on capital expenditures on specific new generation projects, including but not limited to combined cycle gas generation, nuclear generation, clean coal/carbon capture compatible generation, and renewable generation projects. The Regulation Act also continues statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.

If the Virginia Commission's future rate decisions, including actions relating to Virginia Power's rate adjustment clause filings, differ materially from Virginia Power's expectations, it may adversely affect its results of operations, financial condition and cash flows.

2009 Base Rate Review

Pursuant to the Regulation Act, the Virginia Commission initiated a review of Virginia Power's base rates, terms and conditions in 2009, including a review of Virginia Power's earnings for test year 2008. In March 2010, the Virginia Commission issued the Virginia Settlement Approval Order, thus concluding the 2009 case and resolving open issues relating to Virginia Power's base rates, fuel factor and Riders R, S, T, C1 and C2. Virginia Power's fourth quarter 2009 results included a charge of $782 million ($477 million after-tax) as a result of the 2009 Base Rate Review. Dominion's 2009 results include an additional charge of $12 million ($8 million after-tax) recorded in other operations and maintenance expense, reflecting the write-off of previously deferred RTO costs since recovery was no longer probable based on the 2009 Base Rate Review.

2011 Biennial Review

Pursuant to the Regulation Act and the Virginia Settlement Approval Order, in March 2011, Virginia Power submitted its base rate filing and accompanying schedules in support of the first biennial review of its base rates, terms and conditions, as well as of its earnings for the 2009 and 2010 test period. The biennial review included a determination of whether Virginia Power's earnings for the 2009 and 2010 combined test years were within 50 basis points of the authorized ROE of 11.9% established in the Virginia Settlement Approval Order, as well as authorization of an ROE which will be applicable to base rates and Riders R, S, C1 and C2 and which will be used to measure base rate earnings during the 2013 biennial review proceeding. As a result of the Virginia Settlement Approval Order and the Regulation Act, Virginia Power's base rates are not subject to change based on the 2011 biennial review. In November 2011, the Virginia Commission issued the Biennial Review Order.

Base ROE

The Virginia Commission determined that Virginia Power's new authorized ROE is 10.9%, inclusive of a performance incentive of 50 basis points for meeting certain RPS targets. Subject to the outcome of Virginia Power's petition for rehearing or reconsideration described below, this ROE will serve as the ROE against which Virginia Power's earned return will be compared for all or part of the test periods in the 2013 biennial review proceeding. The Virginia Commission ordered that the 50 basis point RPS performance incentive will not be included in the ROE applicable to any rate adjustment clauses. The Virginia Commission declined to award a performance incentive for generating plant performance, customer service or operating efficiency in connection with this biennial review but instead will initiate a rulemaking proceeding to develop performance incentive criteria to be applied in future biennial review proceedings.

In December 2011, Virginia Power filed a petition with the Virginia Commission seeking rehearing or reconsideration of the Biennial Review Order, to confirm the effective date of the newly authorized 10.9% base ROE. In December 2011, Virginia Power also filed a Notice of Appeal with the Virginia Commission of the Biennial Review Order to the Supreme Court of Virginia.

ROE Applicable to Riders C1, C2, R, and S

Effective December 1, 2011, the ROE applicable to Riders C1 and C2 is 10.4%. An ROE of 11.3% applied through November 30, 2011.

For Riders R and S, effective December 1, 2011, the ROE is 11.4%, inclusive of a statutory enhancement of 100 basis points. An ROE of 12.3%, inclusive of a statutory enhancement of 100 basis points, applied through November 30, 2011.

Earned Return for 2009 and 2010

The Virginia Commission determined that Virginia Power earned an ROE of approximately 13.3% during the 2009 and 2010 combined test years, which exceeded the authorized ROE earnings band of 11.4% of 12.4% established in the Virginia Settlement Approval Order. Based on the determination that Virginia Power had excess earnings, the Virginia Commission ordered Virginia Power to refund 60% of earnings above the upper end of the authorized ROE earnings band, or approximately $78 million, to its customers, which is being provided in the form of credits to customers' bills amortized over a six-month period during 2012. A charge for the refund was recognized in operating revenues in the 2011 Consolidated Statement of Income. The actual aggregate refund amount is expected to total approximately $81 million, taking into account refunds to be paid to certain non-jurisdictional customers pursuant to their customer contracts.

Base Rates and Existing Riders T, C1, and C2

As a result of the Virginia Commission's determination that credits will be applied to customers' bills, the Virginia Commission, as required by the Regulation Act, directed Virginia Power to combine its existing Riders T, C1, and C2 with Virginia Power's base costs, revenues and investments, and to file revised tariffs reflecting such combination pursuant to the Biennial Review Order. These Riders will thereafter be considered part of Virginia Power's base costs, revenues and investments for purposes of future biennial review proceedings. The Virginia Commission has initiated a proceeding to address further implementation of this directive. Virginia Power's base rates will otherwise remain unchanged through at least December 1, 2013.

Earnings Test Adjustments

The Virginia Commission ruled on numerous contested proposals to adjust Virginia Power's earnings for the 2009 and 2010 combined test periods. Among other adjustments, the Virginia Commission approved Virginia Power's ratemaking treatment of fuel inventories held by its wholly-owned subsidiaries. As a result of this finding, Virginia Power included in rate base approximately $177 million and $188 million in fuel inventory costs for 2009 and 2010, respectively. The Virginia Commission also adopted Virginia Power's treatment that includes, for regulatory earnings purposes, its AIP and LTIP expenses up to a 100% payout ratio. The Virginia Commission excluded from expense approximately $21 million in incentive plan costs that exceeded a payout ratio of 100%, allowing a net recovery of approximately $95 million of incentive compensation expense for the biennial review period. The Virginia Commission denied Virginia Power's ratemaking treatment that expensed the entire cost of its 2010 voluntary separation plan in 2010, ruling instead to amortize the cost through the end of 2011. This matches the costs of the plan with the period of realization of savings, which reduces 2010 operating costs (and in turn, increases 2011 operating costs) by approximately $103 million for purposes of the earnings test. Other than influencing the amount earned above the authorized ROE earnings band, the earnings test adjustments above did not have an impact to the Consolidated Financial Statements.

In addition, the Virginia Commission required Virginia Power to recognize a gain, for purposes of the earnings test, of approximately $44 million on the settlement of certain interest rate hedging contracts in 2010, as opposed to amortizing the gains over the forecasted term of planned debt instruments that were not issued. Virginia Power determined that it was no longer probable that these derivative gains would be included in future base rates as the Virginia Commission would not allow the amortization of these amounts in future periods. As a result, Virginia Power removed approximately $50 million in December 2011 from regulatory liabilities and recognized the deferred derivative settlement gains in Interest and Other Charges in the Consolidated Statements of Income.

Virginia Fuel Expenses

In May 2011, Virginia Power submitted its annual fuel factor filing to the Virginia Commission, proposing an annual increase for the rate year beginning July 1, 2011. This revised factor included a projected $434 million balance of prior year under-recovered fuel expenses. To reduce the impact to customers, as an alternative, Virginia Power proposed to recover this projected prior year deferred fuel balance over a two-year period beginning July 1, 2011. In June 2011, the Virginia Commission approved the two-year recovery proposal, resulting in an increase of approximately $319 million in annual fuel revenue for the rate year beginning July 1, 2011. The rate increase is designed to recover $217 million of unrecovered fuel expenses from the prior fuel year as well as a $102 million increase in anticipated fuel expenses for the 2012 fuel year.

Generation Riders R and S

In connection with the Bear Garden and Virginia City Hybrid Energy Center projects, in March 2011, the Virginia Commission approved annual updates for Riders R and S with revenue requirements of $78 million and $199 million, respectively, for the April 1, 2011 to March 31, 2012 rate year, utilizing the 12.3% placeholder ROE (inclusive of a 100 basis point statutory enhancement) pending the Virginia Commission's ROE determination in the 2011 biennial review. Virginia Power's proposed revenue requirements for Riders R and S for Rider S for the April 1, 2012 to March 31, 2013 rate year were adjusted to approximately $76 million and $231 million, respectively, and are pending final Virginia Commission approval. Future annual updates for Riders R and S will provide revenue requirements reflecting any true-ups to revenue requirements approved for the previous calendar year, including the ROE determined in the Biennial Review Order. Construction of Bear Garden was completed and the facility commenced commercial operations in the second quarter of 2011.

DSM Riders C1 and C2

In connection with Virginia Power's five DSM programs approved by the Virginia Commission, in March 2011, the Virginia Commission approved the annual updates for Riders C1 and C2 with revenue requirements of approximately $6 million and $12 million, respectively, for the April 1, 2011 to March 31, 2012 rate year, utilizing an 11.3% placeholder ROE pending the Virginia Commission's ROE determination in the 2011 biennial review. By order issued in June 2011, the Virginia Commission extended the rates through April 2012.

In September 2011, Virginia Power filed with the Virginia Commission an application for approval of six new energy efficiency DSM programs, along with an annual update to Riders C1 and C2. Virginia Power's proposed revenue requirement for the May 1, 2012 through April 30, 2013 rate year is approximately $72 million, as amended in February 2012 to reflect, along with other adjustments, the determination of a 10.4% ROE applicable to Riders C1 and C2 in the the Biennial Review Order. As discussed above, previously implemented Riders C1 and C2 will be considered part of Virginia Power's base costs, revenues and investments for purposes of future biennial review proceedings, and the Virginia Commission has initiated a proceeding to address further implementation of this directive.

Transmission Rider T

In May 2011, Virginia Power filed its annual update to Rider T with the Virginia Commission. The proposed $481 million annual revenue requirement, effective September 1, 2011, represented an increase of approximately $144 million over the revenue requirement associated with the Rider T customer rates previously in effect. In July 2011, the Virginia Commission issued an order approving a revenue requirement of $466 million for the September 1, 2011 to August 31, 2012 rate year. As discussed above, previously implemented Rider T will be considered part of Virginia Power's base costs, revenues and investments for purposes of future biennial review proceedings, and the Virginia Commission has initiated a proceeding to address further implementation of this directive.

Generation Rider W

In May 2011, Virginia Power requested approval from the Virginia Commission to construct and operate Warren County, as well as approval of Rider W. In February 2012, the Virginia Commission approved Certificates of Public Convenience and Necessity for Warren County and related transmission facilities. The Virginia Commission also approved Virginia Power's proposed revised revenue requirement of $35 million for the April 1, 2012 to March 31, 2013 rate year, reflecting an ROE of 11.4%, inclusive of a statutory enhancement of 100 basis points for Rider W, consistent with the Biennial Review Order. In addition, the Virginia Commission approved an ROE enhancement of 100 basis points for Rider W for a period of 10 years following commercial operations. The facility is expected to start commercial operations in late 2014.

Generation Rider B

In June 2011, Virginia Power filed applications with the Virginia Commission seeking regulatory approval to convert three of its coal-fired power stations to biomass. The applications included a request for approval of Rider B. Virginia Power's proposed revenue requirement for Rider B is approximately $6 million for the April 1, 2012 to March 31, 2013 rate year, as adjusted to reflect the base ROE authorized in the Biennial Review Order, and inclusive of a renewable generating unit statutory enhancement of 200 basis points. To qualify for federal production tax credits associated with renewable energy generation, the power stations must commence operation as biomass generation facilities by December 31, 2013. Virginia Power has requested Virginia Commission approval of the biomass conversions on a schedule that will enable qualification for these tax credits.

Solar Distributed Generation Demonstration Program

In October 2011, Virginia Power filed with the Virginia Commission an application to conduct a solar distributed generation demonstration program, consisting of up to a combined 30 MW of Company-owned solar distributed generation facilities to be located at selected commercial, industrial and community locations throughout its Virginia service territory, as well as up to a combined 3 MW of customer-owned solar distributed generation facilities that will be subject to a tariff filed with the Virginia Commission in 2012. Virginia Power proposed to construct and operate the Company-owned facilities in two phases, with Phase I (up to 10 MW) from the date of approval through the end of 2013 and Phase II (up to 20 MW) from the beginning of 2014 to the end of 2015. Virginia Power did not seek a rate adjustment clause for Phase I facilities with this filing; Phase I costs will be recovered as part of base rates in a future biennial review. Virginia Power indicated that it may seek a rate adjustment clause at a future time for Phase II costs.

Electric Transmission Projects

Portions of the Mt. Storm-to-Doubs line and certain associated facilities are approaching the end of their expected service lives and require replacement with new facilities to maintain reliable service. Virginia Power owns, and has been designated by PJM to rebuild, 96 miles of the line in West Virginia and Virginia, and The Potomac Edison Company owns, and has been designated by PJM to rebuild, the remaining three miles of the line in Maryland. In September 2011, the Virginia Commission approved Virginia Power's application to rebuild its portion of the Mt. Storm-to-Doubs line. The approval of the West Virginia Commission was not required. Subject to applicable state and federal regulatory approvals, Virginia Power's portion of the rebuild project is expected to be completed by June 2015.

In October 2008, the Virginia Commission authorized construction of the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line. The Meadow Brook-to-Loudoun line was placed in service in April 2011 and the Carson-to-Suffolk line was placed in service in May 2011.

In June 2010, the Virginia Commission authorized the construction of the Hayes-to-Yorktown line along the proposed eight-mile route utilizing existing easements and property previously acquired for the transmission line right-of-way. In accordance with the Virginia Commission's approval, approximately 4.2 miles of the Hayes-to-Yorktown line will be constructed overhead and approximately 3.8 miles will be installed underground in order to cross under the York River. The Hayes-to-Yorktown line is expected to be completed by June 2012.

In January 2012, the Virginia Commission authorized the replacement at higher voltage of approximately 43 miles of existing transmission lines between the Dooms and Bremo substations. Subject to the receipt of other applicable state and federal regulatory approvals, Dooms-to-Bremo is expected to be completed by May 2014.

In December 2011, Virginia Power submitted an application to the Virginia Commission for approval of the Waxpool-Brambleton-BECO line. This project is is required to provide requested service to a new datacenter campus in Loudoun County, Virginia. Virginia Power expects PJM to authorize Waxpool-Brambleton-BECO as part of the 2012 RTEP within the first half of 2012. Subject to the receipt of applicable state and federal regulatory approvals, Waxpool-Brambleton-BECO is expected to be completed by November 2013.

North Anna Power Station

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna, which Virginia Power owns along with ODEC. In May 2010, Virginia Power announced its decision to replace the reactor design previously selected for the potential third nuclear unit with the US-APWR technology. In June 2010, Virginia Power and ODEC amended the COL application to reflect the selection of the US-APWR technology. In January 2011, Virginia Power and the DOE terminated their cooperative agreement to share equally the cost of developing a COL. The agreement references the technology previously selected by Virginia Power. DOE funding related to COL development activities is not available under the agreement for activities related to the US-APWR technology. In February 2011, ODEC informed Virginia Power of its intent to no longer participate in the development of a potential new unit at North Anna. In December 2011, Virginia Power acquired ODEC's interest in the project, thereby terminating ODEC's involvement in the development of a potential third unit at North Anna.

Virginia Power has not yet committed to building a new nuclear unit at North Anna. If Virginia Power decides to build the new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power continues to pursue the COL from the NRC. Based on the current NRC schedule, the COL could be issued as early as late 2014.

The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the ASLB of the NRC permitted BREDL to intervene in the proceeding. All of BREDL's previous contentions in this proceeding have been dismissed. In September 2011, BREDL submitted a new proposed contention seeking to litigate issues related to the August 2011 Mineral, Virginia earthquake. In October 2011, the ASLB granted a motion filed by Virginia Power, with the consent of BREDL and the NRC staff to hold any ruling on this proposed contention in abeyance until Virginia Power completes an assessment of this earthquake. No other persons have sought to intervene in the proceeding. If a new contention is not admitted, the mandatory NRC hearing will be uncontested with respect to other issues.

On April 14, 2011, twenty-one organizations and individuals that had previously intervened opposing various reactor licensing proceedings filed a petition requesting that the NRC suspend all decisions regarding reactor licensing and design certification pending completion of an NRC task force review of the events at Fukushima, Japan, among other requested relief. The North Anna 3 COL proceeding is one of the pending proceedings identified in this petition, and BREDL served the petition in the North Anna 3 COL proceeding on April 18, 2011. In September 2011, the NRC denied the petitioners' requests to suspend licensing and design certification proceedings. The only relief granted was the petitioners' request that the NRC perform a safety analysis of the regulatory implications of the Fukushima event to the extent it is doing so.

Virginia Power continues to pursue various environmental permits that would be needed to support future construction and operation of a third nuclear unit at North Anna.

North Carolina Regulation

In February 2010, in preparation for the end of a five-year moratorium on Virginia Power's North Carolina base rates, Virginia Power filed an application with the North Carolina Commission to increase its base rates and adjust its fuel rates. In December 2010, the North Carolina Commission issued the North Carolina Settlement Approval Order approving a settlement agreement among all parties to the base rate and fuel case except one, which did not oppose the settlement. The North Carolina Settlement Approval Order authorized an increase in base revenues of approximately $8 million. In addition, the North Carolina Settlement Approval Order allowed the recovery through fuel rates of 85% of the net energy costs of power purchases from both PJM and other wholesale suppliers and from the non-utility generators subject to economic dispatch that do not provide actual cost data. The North Carolina Settlement Approval Order authorized an ROE of 10.7% and a capital structure composed of 49% long-term debt and 51% common equity. The new base and fuel rates became effective on January 1, 2011.

In December 2011, the North Carolina Commission issued an order approving a settlement agreement among Virginia Power, the Public Staff of the North Carolina Commission and other interested parties in Virginia Power's fuel case for its North Carolina service territory. The settlement agreement provides for a $36 million increase in Virginia Power's fuel revenues for one year, effective January 1, 2012, including approximately $13 million in under recovery of fuel expenses for the previous fuel period.

Virginia Power intends to file an application with the North Carolina Commission by March 30, 2012, to increase base rates.

Ohio Regulation

PIR Program

In March 2011, East Ohio filed a request with the Ohio Commission to accelerate the PIR program by nearly doubling its PIR spending to more than $200 million annually. East Ohio identified 1,450 miles of pipeline that need to be replaced, in addition to the pipeline originally identified in the PIR project scope. East Ohio plans to accelerate the pace of the program by investing more resources in its infrastructure in the near term, in an effort to promote ongoing public safety and reduce operating costs over the longer term. In August 2011, the Ohio Commission approved the stipulation by East Ohio, the Staff of the Ohio Commission and other interested parties in East Ohio's accelerated PIR proceeding. The stipulation provides for an increase in annual PIR capital investment from the current level of approximately $120 million stepping up to approximately $160 million by 2013. In addition, the stipulation provides for cost recovery over a five-year period commencing upon the approval of the Ohio Commission. In accordance with the stipulation, East Ohio requested the dismissal of its appeal at the Ohio Supreme Court regarding its opposition to the Ohio Commission's order concerning East Ohio's first year PIR cost recovery charge.

In August 2011, East Ohio submitted its annual application to adjust the cost recovery charge under the previously approved PIR program. A supplement to the application was filed in September 2011. The proposed recovery charge includes actual costs and a return related to investments made through June 30, 2011. A settlement agreement approved by the Ohio Commission in October 2011 supports the revenue requirement of $37 million reflected in the application.

PIPP Plus Program

Under the Ohio PIPP Plus program, eligible customers can receive energy assistance based on their ability to pay their bill. The difference between the customer's total bill and the PIPP plan payment amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. The PIPP Plus program sets the customer's monthly payments at 6% of household income and provides for forgiveness credits to the customer's balance when required payments are received in full by the due date. Such credits may result in the elimination of the customer's arrearage balance over 24 months.

In March 2011, the Ohio Commission approved East Ohio's annual update of the PIPP Rider, which reflected the elimination of accumulated arrearages and projected deferred program costs of approximately $112 million for the 12-month period from April 2011 to March 2012.

UEX Rider

East Ohio files an annual UEX Rider with the Ohio Commission, pursuant to which it seeks recovery of the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar-for-dollar recovery of East Ohio's actual write-offs of uncollectable amounts. In 2011, East Ohio deferred approximately $62 million of bad debt expense for recovery through the UEX Rider.

House Bill 95

Ohio enacted utility reform legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future. In December 2011, East Ohio filed an application requesting authority to implement a capital expenditure program under the new law. If the application is approved, East Ohio would be able to defer as a regulatory asset carrying costs, depreciation and property tax associated with approximately $95 million in capital expenditures for assets placed in service but not yet reflected in rates.

Federal Regulation

FERC - Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominion's merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion's market-based sales tariffs authorized by FERC. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power's service territory. Any such sales would be voluntary.

Rates

In April 2008, FERC granted an application for Virginia Power's electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.

In July 2008, Virginia Power filed an application with FERC requesting a revision to its revenue requirement to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 1.5% for four of the projects (including the Meadow Brook-to-Loudoun and Carson-to-Suffolk lines, which were completed in 2011) and an incentive of 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008. The total cost for all eleven projects is estimated at $877 million, and all projects are currently expected to be completed by 2012. Numerous parties sought rehearing of the FERC order in August 2008, and rehearing is pending. Although Virginia Power cannot predict the outcome of the rehearing, it is not expected to have a material effect on results of operations.

In March 2010, ODEC and NCEMC filed a complaint with FERC against Virginia Power claiming that approximately $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power's transmission formula rate. ODEC and NCEMC requested that FERC establish procedures to determine the amount of costs for each applicable project that should be excluded from Virginia Power's rates. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. In February 2012, Virginia Power submitted to FERC a settlement agreement to resolve all issues set for hearing. All transmission customer parties to the proceeding joined the settlement. The Virginia Commission, North Carolina Commission and Public Staff of the North Carolina Commission, while not parties to the settlement, have agreed to not oppose the settlement. If accepted by FERC, the settlement provides for payment by Virginia Power to the transmission customer parties of $250,000 per year for ten years and resolves all matters other than the incremental cost of certain underground transmission facilities, which will be set for briefing. While Virginia Power cannot predict the outcome of the briefing, it is not expected to have a material effect on results of operations.

PJM

For recovery of costs of investments of new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a regional rate design where all customers pay a uniform rate based on the costs of such investment. For recovery of costs of investment in new PJM-planned transmission facilities that operate below 500 kV, FERC affirmed its earlier decision to allocate costs on a beneficiary pays approach. A notice of appeal of this decision was filed in February 2008 at the U.S. Court of Appeals for the Seventh Circuit. In August 2009, the court denied the petition for review concerning the rate design for existing facilities, but granted the petition concerning the rate design for new facilities that operate at or above 500 kV, and remanded the issue of existing facilities back to FERC for further proceedings. Although Dominion and Virginia Power cannot predict the outcome of the FERC proceedings on remand, the impact of any PJM rate design changes on the Companies' results of operations is not expected to be material.

In May 2008, the RPM Buyers filed a complaint with FERC claiming that PJM's Reliability Pricing Model's transitional auctions have produced unjust and unreasonable capacity prices. The RPM Buyers requested that a refund effective date of June 1, 2008 be established and that FERC provide appropriate relief from unjust and unreasonable capacity charges within 15 months. In September 2008, FERC dismissed the complaint. The RPM Buyers requested rehearing of the FERC order in October 2008 and rehearing was denied in June 2009. A notice of appeal was filed in August 2009 by the Maryland Public Service Commission and the New Jersey Board of Public Utilities at the U.S. Court of Appeals for the Fourth Circuit. In November 2009, the Court transferred the appeal to the Court of Appeals for the District of Columbia Circuit. In February 2011, the Court of Appeals denied the petition for review, concluding that FERC had adequately explained why the rates were just and reasonable.

In November 2011, PJM issued a formal notification that it would recalculate certain ancillary service revenues that had previously been paid during 2009, 2010 and 2011. Also in November 2011, PJM requested FERC permission to suspend its rebilling and repayment obligations associated with the recalculation of such revenues and petitioned FERC to establish a proceeding to determine the appropriate recalculations for the revenues during this period. In December 2011, FERC permitted the suspension of rebilling and repayment by PJM, subject to the outcome of FERC's proceedings to determine the appropriate revenue recalculation. Virginia Power has accrued a liability of $36 million as of December 31, 2011 for estimated future billing adjustments from PJM related to the ancillary service revenues.

FERC - Gas

FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion's interstate natural gas company subsidiaries, including DTI, Cove Point and the Dominion South Pipeline Company, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

In December 2007, DTI and the IOGA entered into a settlement agreement on DTI's gathering and processing rates, which DTI and IOGA agreed in May 2010 to extend through December 31, 2014. DTI, at its option, may elect to extend the agreement for an additional year through December 31, 2015. The settlement extension maintains the gas retainage fee structure that DTI has had since 2001. The rates are 10.5% for gathering and 0.5% for processing. Under the settlement, DTI continues to retain all revenues from its liquids sales, thus maintaining cash flow from the liquids business. In October 2011, DTI requested and received FERC approval of the negotiated rates associated with the agreement extension.

In May 2011, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective July 1, 2011. Cove Point proposed an annual cost of service of approximately $150 million. In June 2011, FERC accepted a July 1, 2011 effective date for all proposed rates but two of which were suspended to be effective December 1, 2011. In December 2011, Cove Point, FERC trial staff and the other active parties in the rate case reached a settlement in principle on all issues set for hearing by FERC, as well as on all outstanding proposed tariff changes filed in May 2011. The parties expect to file the stipulation and agreement resolving all outstanding issues in the rate case in March 2012.