REGULATORY MATTERS

Regulatory Matters Involving Potential Loss Contingencies

As a result of issues generated in the ordinary course of business, the Companies 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, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For matters for which the Companies cannot estimate a range of possible loss, 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, involves elements of judgment and significant uncertainties and may 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 the Companies' 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 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. 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. 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.

In March 2014, FERC issued an order excluding from Virginia Power's transmission rates for wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable for non-Virginia wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities because the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to benefit the citizens of Virginia. The order is retroactively effective as of March 2010 and will cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC determined that there was not sufficient evidence on the record to determine the magnitude of the underground increment and ordered a hearing to determine the appropriate amount of undergrounding cost to be allocated to each wholesale transmission customer in Virginia. While Virginia Power cannot predict the outcome of the hearing, 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 contains 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 2014, Virginia Power submitted its annual fuel factor filing to the Virginia Commission to recover an estimated $1.9 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2014. Virginia Power also offered to defer recovery of 50% of its total estimated $268 million jurisdictional deferred fuel balance to the 2015-2016 fuel year, thereby recovering $134 million of its jurisdictional deferred fuel balance for the rate year beginning July 1, 2014. In September 2014, the Virginia Commission approved Virginia Power’s increased fuel rate, which was already in effect on an interim basis since July 1, 2014. The new rate includes approval of Virginia Power's offer to defer recovery of 50% its jurisdictional deferred fuel balance and represents an annual fuel revenue increase of approximately $300 million.

Rate Adjustment Clauses

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


•	The Virginia Commission previously approved Rider T1. In July 2014, the Virginia Commission approved an approximately $538 million revenue requirement for the rate year beginning September 1, 2014, which represents an approximately $134 million increase over the previous year.


•	The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2014, Virginia Power proposed an approximately $244 million revenue requirement for the rate year beginning April 1, 2015. This case is pending.


•	The Virginia Commission previously approved Rider W in conjunction with Warren County. In February 2015, the Virginia Commission approved an approximately $135 million revenue requirement for the rate year beginning April 1, 2015.


•	The Virginia Commission previously approved Rider BW in connection with Brunswick County. In October 2014, Virginia Power proposed a total revenue requirement of approximately $111 million for the rate year beginning September 1, 2015. This case is pending.

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The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In August 2014, Virginia Power proposed a total revenue requirement of approximately $47 million for the rate year beginning May 1, 2015. Virginia Power further proposed three new energy efficiency programs for Virginia Commission approval with a requested five-year cost cap of approximately $106 million for those programs. This case is pending.


•	The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In June 2014, Virginia Power proposed an approximately $84 million revenue requirement for the rate year beginning April 1, 2015. This case is pending.


•	Virginia legislation which provides for the recovery of costs to move certain electric distribution lines underground became effective in July 2014. In October 2014, Virginia Power filed for approval of Rider U, which proposes a revenue requirement of approximately $28 million during the initial rate year beginning September 1, 2015. This case is pending.


•	The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2014, Virginia Power proposed an approximately $13 million revenue requirement for the rate year beginning April 1, 2015. This case is pending.

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In January 2015, Virginia Power applied for a CPCN to construct and operate a new 20 MW utility-scale solar facility near its existing Remington Power Station in Fauquier County, Virginia. Virginia Power also applied for approval of Rider US-1 to recover the costs of the facility. The total cost of the Remington Solar Facility is approximately $47 million (excluding financing costs). This case is pending.

Brunswick County

In August 2013, three motions for reconsideration were filed with the Virginia Commission, asking that it reconsider its August 2013 final order approving a CPCN for construction of Brunswick County. In November 2013, the Virginia Commission denied reconsideration. Three appeals were filed with the Supreme Court of Virginia, but two were withdrawn. In September 2014, the Supreme Court of Virginia issued an opinion affirming the Virginia Commission’s decision in the remaining appeal.

Electric Transmission Project

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 February 2014, the Virginia Commission granted reconsideration requested by Virginia Power and issued an Order Amending Certificate. Several appeals were filed with the Supreme Court of Virginia and oral arguments were heard in January 2015. The appeals are pending.

North Anna

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In April 2013, Virginia Power decided to replace the reactor design previously selected for a potential unit with ESBWR technology. 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. The COL is expected in 2016. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

In June 2012, the U.S. Court of Appeals for the D.C. Circuit vacated and remanded a 2010 NRC decision and related rulemaking that generically assessed the environmental impacts of spent fuel storage after expiration of a reactor’s license until a repository became available. In August 2012, the NRC partially granted a petition filed by BREDL and other petitioners in a number of ongoing licensing proceedings, including the North Anna COL proceedings, to withhold issuance of licenses until completion of action on the remand, and held proposed contentions accompanying the petition in abeyance. In August 2014, the NRC approved a new final rule codifying the NRC’s further generic assessment of environmental impacts of continued storage of spent fuel and lifted the suspension of final licensing decisions in pending cases and dismissed pending contentions on the subject, including the proposed contention filed by BREDL.

In September 2014, BREDL filed a new petition with the NRC again seeking suspension of final decision making in the COL proceeding, along with motions to reopen and file a new contention. The new filings assert that the NRC must make a safety finding on the feasibility and capacity of geologic disposal of spent fuel as a prerequisite to issuance of a license. The filings alleged that because these safety findings are no longer made as part of the NRC’s new continued storage rule, such findings must now be made in individual licensing proceedings. In January 2015, BREDL filed another petition in the COL proceeding asking the NRC to order supplementation of the final environmental impact statement for North Anna 3 to incorporate the NRC's generic assessment of the impacts of continued spent fuel storage, so that BREDL could then challenge that assessment. BREDL's September 2014 filings and January 2015 petition are substantially the same as filings made by various other intervenor groups in other licensing proceedings pending before the NRC. Resolution of these filings is not expected to affect the schedule for issuance of the COL.

North Anna and Offshore Wind Legislation

In April 2014, legislation was enacted in Virginia that permits Virginia Power to recover 70% of the costs previously deferred or capitalized related to the development of a third nuclear unit located at North Anna and offshore wind facilities through December 31, 2013 as part of the 2013 and 2014 base rates. Virginia Power had deferred or capitalized costs totaling approximately $577 million for these projects as of December 31, 2013, substantially all of which relate to North Anna. For the 70% portion of these previously deferred or capitalized costs allocable to customers in Virginia, Virginia Power recognized such amounts that are now recoverable in 2013 and 2014 base rates as charges against net income beginning in the second quarter of 2014 and for the remainder of the year. During 2014, Virginia Power recognized $374 million ($248 million after-tax) in charges against income representing the cumulative recovery of costs from January 2013 through December 2014, which are primarily included in other operations and maintenance expense in the Consolidated Statements of Income. The remaining deferred or capitalized costs, as well as costs incurred after December 31, 2013, continue to be eligible for inclusion in a future rate adjustment clause.

Regulation Act Legislation

In February 2015, the Virginia Governor signed legislation into law which will keep Virginia Power’s base rates unchanged until at least December 1, 2022. In addition, no biennial reviews will be conducted by the Virginia Commission for the five successive 12-month test periods beginning January 1, 2015, and ending December 31, 2019. Virginia Power is scheduled to file its next biennial review, covering 2013 and 2014, in March 2015. The legislation allows this review to proceed for the sole purpose of determining whether any refunds are due to customers based on earnings performance during the 2013 and 2014 test periods. In addition the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility's ROE for use in connection with the rate adjustment clauses and require utilities to file integrated resource plans annually rather than biennially. The legislation requires Virginia Power to write-off $85 million of prior-period deferred fuel costs during the first quarter of 2015. In addition, the legislation requires the Virginia Commission to implement a fuel rate reduction for Virginia Power as soon as practicable based on this non-recovery as well as any over-recovery for the 2014-2015 fuel year and projected fuel expense for the 2015-2016 fuel year. The legislation also deems the construction or purchase of one or more utility-scale solar facilities located in Virginia up to 500 MW in total is deemed to be in the public interest.

North Carolina Regulation

In December 2012, the North Carolina Commission approved a $36 million increase in Virginia Power’s annual non-fuel base revenues based on an authorized ROE of 10.2%, and a $14 million decrease in annual base fuel revenues for a combined total base revenue increase of $22 million. These rate changes became effective on January 1, 2013 and were appealed to the North Carolina Supreme Court by multiple parties. In June 2014, the Supreme Court of North Carolina issued an opinion reversing the portion of the North Carolina Commission’s December 2012 order from Virginia Power’s 2012 base rate case approving a 10.2% ROE for Virginia Power, and remanding the case to the North Carolina Commission for additional findings of fact in light of a 2013 opinion issued after the North Carolina Commission’s order. This case is pending.

In December 2014, the North Carolina Commission issued an order approving an approximately $17 million increase to the fuel component of Virginia Power’s electric rates for the rate year beginning January 1, 2015. This increase includes the approval of Virginia Power’s mitigation proposal to defer recovering 50% of its estimated $17 million jurisdictional deferred fuel balance to the 2016 fuel year, without interest.

Ohio Regulation

PIR Program

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In February 2014, East Ohio filed an application requesting approval to adjust the PIR cost recovery rates for 2013 costs. The filing reflects gross plant investment for 2013 of $164 million, cumulative gross plant investment of $674 million and an estimated revenue requirement of $89 million. This application was approved by the Ohio Commission in April 2014.

In February 2015, East Ohio filed an application to adjust the PIR cost recovery for 2014 costs. The filing reflects gross plant investment for 2014 of $155 million, cumulative gross plant investment of $829 million and a revenue requirement of$108 million. This case is pending.

AMR Program

In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. In May 2014, AMR cost recovery rates became effective as approved by the Ohio Commission in April 2014. The approval includes a revenue requirement of $8 million, which represents an approximately $3 million increase over the previous year.

In January 2013, East Ohio filed with the Ohio Supreme Court an appeal of a rate reduction ordered by the Ohio Commission in October 2012 and a motion seeking a stay of the AMR cost recovery rate imposed. The Ohio Supreme Court granted the stay in March 2013 and East Ohio put the higher AMR cost recovery rate filed by East Ohio into effect. In July 2014, the Ohio Supreme Court ruled in East Ohio’s favor by agreeing that the rate reduction imposed by the Ohio Commission was unreasonable.

In February 2015, East Ohio filed its application with the Ohio Commission to adjust its AMR cost recovery charge to recover costs for calendar year 2014 associated with AMR deployment, which was completed in 2012. The filing reflects a projected revenue requirement of approximately $8 million. This case is pending.

The AMR program approved by the Ohio Commission is now complete. Although no further capital investment will be added, East Ohio is approved to recover depreciation, property taxes, carrying charges and a return until East Ohio has another rate case.

PIPP Plus Program

Under the Ohio PIPP Plus Program, eligible customers can make reduced payments 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 2014, East Ohio’s annual update of the PIPP Rider was automatically approved by the Ohio Commission after a 45-day waiting period from the date of the filing. The increased rider rate reflects the refund over the next year of an over-recovery of accumulated arrearages of approximately $82 million as of March 31, 2014, net of projected deferred program costs of approximately $96 million for the period from April 2014 through June 2015.

UEX Rider

East Ohio has approval for a UEX Rider through which it recovers 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 uncollectible amounts. In July 2014, the Ohio Commission approved a decrease to East Ohio’s UEX Rider, which reflects the elimination of the over-recovered balance of accumulated bad debt expense of approximately $8 million as of March 31, 2014, and recovery of prospective bad debt expense projected to total approximately $25 million for the twelve-month period from April 2014 to March 2015.

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 July 2014, the Ohio Commission approved East Ohio’s application requesting authority to implement a capital expenditure program for 2014 capital expenditures totaling $110 million.

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 and a rate moratorium through 2016. In February 2014, FERC approved the stipulation and agreement. The revised fuel retainage percentages became effective January 1, 2014. DTI began assessing the reduced fuel retainage percentages on March 1, 2014, and as a result provided refunds totaling nearly $10 million. The refunds reflect, with interest, the value of the difference between the actual quantities of fuel retained for the months of January and February and the quantities that would have been retained using the reduced percentages.