REGULATORY MATTERS

Regulatory Matters Involving Potential Loss Contingencies

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, 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. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any 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.

FERC - Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. 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. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in the wholesale market. 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 incentives were included in the PJM Tariff, and billing for the incentives was made accordingly. In 2012, PJM canceled one of the eleven projects with an estimated cost of $7 million. The total cost for the other ten projects included in Virginia Power's formula rate for 2014 is $857 million and the remaining projects were completed by 2012. Numerous parties sought rehearing of the FERC order in August 2008. In May 2012, FERC issued an order denying the rehearing requests. In July 2012, the North Carolina Commission filed an appeal of the FERC orders with the U.S. Court of Appeals for the Fourth Circuit. In January 2014, the court rejected the appeal and affirmed FERC's decision granting the incentives.

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. The settlement was accepted by FERC in May 2012 and provides for payment by Virginia Power to the transmission customer parties collectively of $250,000 per year for ten years and resolves all matters other than allocation of the incremental cost of certain underground transmission facilities, which has been briefed pursuant to FERC's May 2012 order and awaits FERC action. While Virginia Power cannot predict the outcome of the briefing, it is not expected to have a material effect on results of operations.

Other Regulatory Matters

Electric Regulation in Virginia

The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia's planned transition to retail competition for electric supply service to most classes of customers.

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, and also constitutes statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly proposed generation projects.

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.

2013 Biennial Review

Pursuant to the Regulation Act, in March 2013, Virginia Power submitted its base rate filings and accompanying schedules in support of the Virginia Commission's 2013 biennial review of Virgina Power's rates, terms and conditions, as well as of Virginia Power's earnings for 2011 and 2012 test periods. The Virginia Power earnings test analysis reviewed by the Virginia Commission reflected an ROE of 10.30% on its generation and distribution services earnings for the combined test periods.

In November 2013, the Virginia Commission issued its 2013 Biennial Review Order. After deciding eleven contested earnings test adjustments, the Virginia Commission ruled that Virginia Power earned on average an ROE of approximately 10.25% on its generation and distribution services for the combined 2011 and 2012 test periods. Because this ROE was more than 50 basis points below Virginia Power’s authorized ROE of 10.9%, the Virginia Commission authorized the deferred recovery, for earnings test purposes, of $23 million in costs related to asset impairments with early retirement decisions, severe weather events, and natural disasters to be amortized over the 2013 calendar year. The Virginia Commission did not order a base rate increase because Virginia Power had previously waived its right to any such increase, and because it determined that Virginia Power had a revenue sufficiency of approximately $280 million when projecting the annual revenues generated by base rates to the revenues required to cover costs of service and earn a fair return. As part of its revenue sufficiency determination, the Virginia Commission also made findings on eleven rate case adjustments, in addition to changes to the cost of capital and capital structure, which resulted in changes to Virginia Power’s rate year revenues and expenses, and Virginia Power’s rate base for generation and distribution, for the rate year beginning January 1, 2014. Virginia Power incurred a $55 million ($37 million after-tax) charge in connection with the 2013 Biennial Review Order.

In its 2013 Biennial Review Order, the Virginia Commission also set the ROE that will be used in Virginia Power’s 2015 biennial review earnings test analysis for earnings on generation and distribution services for the combined 2013 and 2014 test periods, and that will be applied to Riders R, S, W, B, BW, C1A, and C2A. Pursuant to the Regulation Act, Virginia Power’s authorized ROE can be no lower than the average of the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., subject to certain limitations as described in the Regulation Act. Following this statutory peer group analysis, the Virginia Commission determined that the peer group floor ROE for Virginia Power was 9.89%. It further held, declining to increase or decrease Virginia Power’s combined rate of return based on performance, that Virginia Power’s ROE for earnings test purposes in its 2015 biennial review and for rate adjustment clause purposes is 10.0%, consistent with its determination that Virginia Power’s market cost of equity is 10.0%.

Virginia Fuel Expenses

In May 2013, Virginia Power submitted its annual fuel factor filing to the Virginia Commission, proposing an increase of approximately $162 million in fuel revenue for the rate year beginning July 1, 2013. In June 2013, the Virginia Commission issued an order approving the rate.

In November 2013, the Virginia Commission approved Virginia Power’s voluntary request to reduce Virginia Power’s currently-approved fuel factor rate from 2.942 ¢/kWh to 2.572 ¢/kWh effective for usage on and after December 1, 2013, due to an expected over-recovery of fuel costs. This request is expected to reduce Virginia Power’s anticipated fuel recoveries through June 30, 2014 by more than $140 million. At December 31, 2013, Virginia Power's Consolidated Balance Sheets reflected $24 million of other current liabilities and $85 million of noncurrent regulatory liabilities related to the over-recovered fuel costs.

Rate Adjustment Clauses

Below is a discussion of significant riders associated with various Virginia Power projects:


•	In 2012, the Virginia Commission approved the conversion of the Altavista, Hopewell, and Southampton power stations to biomass, and in conjunction approved Rider B. Virginia Power proposed an approximately $16 million revenue requirement for the rate year beginning April 1, 2014. This case is pending.


•	In 2013, the Virginia Commission approved Virginia Power's request to construct and operate Brunswick County, and in conjunction approved the associated transmission facilities and Rider BW. Virginia Power proposed an approximately $101 million revenue requirement for the rate year beginning September 1, 2014. This case is pending.


•	The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. Virginia Power proposed an approximately $248 million revenue requirement for the rate year beginning April 1, 2014. This case is pending.


•	The Virginia Commission previously approved Rider W in conjunction with Warren County. Virginia Power proposed an approximately $101 million total revenue requirement for the rate year beginning April 1, 2014. This case is pending.


•	The Virginia Commission approved Riders C1A and C2A in connection with various DSM programs. The requested revenue requirements are approximately $1 million for Rider C1A and approximately $35 million for Rider C2A. This case is pending.


•	In May 2013, Virginia Power filed for an adjustment to its current Rider T1 with the Virginia Commission for the rate year beginning September 1, 2013, which reflects a total revenue requirement of approximately $404 million. In July 2013, the Virginia Commission issued an order approving the rate.

Bremo Power Station

In September 2013, the Virginia Commission issued its final order approving an amended and reissued CPCN that would allow Virginia Power to convert Bremo Units 3 and 4 from using coal to natural gas as their fuel source. The proposed conversion will preserve 227 MW (net) of existing capacity and is expected to cost approximately $53 million, excluding financing costs.

North Anna

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. In April 2013, Virginia Power decided to replace the reactor design previously selected for a potential unit with ESBWR technology.

If Virginia Power decides to build a 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 filed the first of its two-part amendment to the COL application with the NRC in July 2013 to reflect the ESBWR technology, and filed the second part of the amendment in December 2013. A COL is expected in 2015. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

In May 2013, BREDL filed a motion with the NRC ASLB to reopen the COL adjudicatory proceeding relating to North Anna based on new information, citing the change in reactor technology. The motion did not propose any new contentions but asked that either (i) the proceeding be restarted from the beginning by submittal of a new application and renoticing in the Federal Register, or (ii) the proceeding be reopened pending submittal of new contentions, which BREDL would be given an extended amount of time to file.

In July 2013, the ASLB issued an order holding BREDL’s motion in abeyance. The ASLB noted that because BREDL proposed no contentions, it could not determine whether any portion of the motion falls within the ASLB’s jurisdiction, which is currently limited to ruling on a September 2011 petition filed by BREDL to reopen the COL proceeding related to seismic issues. In January 2014, Virginia Power informed the ASLB and parties that the Company’s assessment of seismic issues was complete. Under a previous ruling of the ASLB, BREDL will have a period of 60 days from the time Virginia Power informs the NRC and parties that its seismic assessment is complete to submit a motion to reopen the proceeding on this topic.

Legislation has been proposed that would limit the portion of costs incurred by an investor-owned electric utility between July 1, 2007 and December 31, 2013, in developing a nuclear power facility or an offshore wind project that are recoverable from Virginia jurisdictional and non-jurisdictional customers through a future rate adjustment clause to a maximum of 30% of such amount. Virginia Power has deferred or capitalized costs totaling $570 million as of December 31, 2013 related to the development of a third nuclear unit site located at North Anna. If this proposed legislation is enacted, 70% of the costs previously deferred or capitalized would be recovered from Virginia jurisdictional and non-jurisdictional ratepayers as part of the 2013 and 2014 base rates. Upon enactment, Virginia Power would recognize 70% of the costs previously deferred or capitalized against net income in 2014. The remaining deferred or capitalized costs, as well as costs incurred after December 31, 2013, would continue to be eligible for inclusion in a future rate adjustment clause.

Electric Transmission Projects

In January 2013, a notice of appeal was filed with the Supreme Court of Virginia by a private party regarding the Virginia Commission's December 2012 order granting a CPCN and authorizing construction of the Waxpool-Brambleton-BECO line. In October 2013, the Supreme Court of Virginia issued an opinion affirming the Virginia Commission’s decision.

In October 2013, Virginia Power applied for a CPCN to rebuild within existing rights-of-way its existing 500 kV Loudoun-Pleasant View transmission line in Loudoun County. As stated in the application, the project is needed to address NERC Reliability Standards violations projected to occur in 2016 and to replace aging transmission facilities. This case is pending.

In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry Switching Station in Surry County to a new Skiffes Creek Switching Station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek Switching Station to Virginia Power’s existing Whealton Substation in the City of Hampton. In December 2013, Virginia Power filed a motion for reconsideration to the Virginia Commission and a notice to appeal the Virginia Commission's order to the Supreme Court of Virginia. The Virginia Commission granted reconsideration and ordered a hearing, which was held in January 2014. The matter is pending at the Virginia Commission. The projected in-service date for this transmission project has been delayed until December 2015 at the earliest.

Ohio Regulation

PIR Program

In 2008, East Ohio began PIR, aimed at replacing approximately 20% of its pipeline system, or approximately 4,100 miles, over a 25-year period. In February 2013, East Ohio filed an application with the Ohio Commission to adjust the cost recovery charge for costs associated with PIR investments for the calendar year 2012 and cumulatively. The application includes total gross plant investment for 2012 of $148 million, cumulative gross plant investment of $511 million, and a revenue requirement of $67 million. The Ohio Commission issued an order approving the rates in April 2013. In May 2013, the approved PIR cost recovery rates became effective.

In November 2013, East Ohio filed a notice to adjust the PIR cost recovery for 2013 costs. The filing reflects projected gross plant investment for 2013 of $170 million, cumulative gross plant investment of $681 million and an estimated revenue requirement of approximately $90 million. This case is pending.

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 payment plan amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. In July 2013, the Ohio Commission approved East Ohio's annual update of the PIPP Rider, which reflects the refund over the next year of an over-recovery of accumulated arrearages of approximately $91 million as of March 31, 2013, net of projected deferred program costs of approximately $54 million for the period from April 2013 through June 2014.

FERC Regulation

DTI Fuel Settlement

In mid-2013, DTI received concerns about its fuel retainage percentages and apparent over-recovery of fuel costs during certain time periods reflected in its annual fuel reports. In December 2013, DTI submitted for FERC approval a stipulation and agreement addressing, among other things, reductions in its fuel retainage percentages.

In February 2014, FERC approved the stipulation and agreement. DTI will implement the reduced fuel retainage percentages effective March 1, 2014. DTI will also provide refunds with interest to each settling customer reflecting the value of the actual quantities of fuel retained from that party between January 1, 2014 and the March 1, 2014 implementation date. This agreement is expected to reduce DTI’s revenues by approximately $35 million in 2014.