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, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Tennessee, Georgia and California 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.

PJM Transmission Rates

In April 2007, FERC issued an order regarding its transmission rate design for the allocation of costs among PJM transmission customers, including Virginia Power, for transmission service provided by PJM. For new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a PJM regional rate design where customers pay according to each customer's share of the region's load. For recovery of costs of existing facilities, FERC approved the existing methodology whereby a customer pays the cost of facilities located in the same zone as the customer. A number of parties appealed the order to the U.S. Court of Appeals for the Seventh Circuit.

In August 2009, the court issued its decision affirming the FERC order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above for further consideration by FERC. On remand, FERC reaffirmed its earlier decision to allocate the costs of new facilities 500 kV and above according to the customer’s share of the region’s load. A number of parties filed appeals of the order to the U.S. Court of Appeals for the Seventh Circuit. In June 2014, the court again remanded the cost allocation issue to FERC. In December 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the cost allocation issue. The hearing only concerns the costs of new facilities approved by PJM prior to February 1, 2013. Transmission facilities approved after February 1, 2013 are allocated on a hybrid cost allocation method approved by FERC and not subject to any court review. Settlement discussions are ongoing. Virginia Power anticipates that the majority of the impacts of any rate design changes resulting from the settlement discussions will be recoverable through retail rates in Virginia.

Other Regulatory Matters

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 13 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 2014 and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2015.

Virginia Regulation

Rate Adjustment Clauses

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

•

The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2015, Virginia Power proposed an approximately $668 million total revenue requirement for the rate year beginning September 1, 2015, which represents an approximately $130 million increase over the previous year. Virginia Power also presented a mitigation proposal to defer approximately $96 million of this revenue requirement to the rate year beginning September 1, 2016, which would reduce by 50% the one-year rate impact on residential customers. In August 2015, the Virginia Commission rejected the mitigation proposal and approved full recovery of the proposed revenue requirement.


•	The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2015, Virginia Power proposed an approximately $250 million revenue requirement for the rate year beginning April 1, 2016, which represents an approximately $5 million increase over the previous year. This case is pending.


•	The Virginia Commission previously approved Rider W in conjunction with Warren County. In June 2015, Virginia Power proposed an approximately $118 million revenue requirement for the rate year beginning April 1, 2016, which represents an approximately $17 million decrease versus the previous year. This case is pending.


•	The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In June 2015, Virginia Power proposed an approximately $74 million revenue requirement for the rate year beginning April 1, 2016, which represents an approximately $10 million decrease versus the previous year. This case is pending.


•	The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2015, Virginia Power proposed an approximately $30 million revenue requirement for the rate year beginning April 1, 2016, which represents an approximately $21 million increase over the previous year. This case is pending.

•

Virginia legislation which provides for the recovery of costs to move certain electric distribution facilities underground became effective in July 2014. In October 2014, Virginia Power filed for approval of Rider U, which proposed a revenue requirement of approximately $28 million during the initial rate year beginning September 1, 2015. In May 2015, Virginia Power revised the revenue requirement to $24 million. In July 2015, the Virginia Commission denied approval of Rider U based on the evidence in the record, but found that an alternative plan addressing certain concerns they had, such as the lack of a cost benefit analysis, could reasonably satisfy the regulatory requirements for approval. Virginia Power is reviewing the order and assessing its options, which could include filing such an alternative plan by year end.

Electric Transmission Project

In April 2015, the Supreme Court of Virginia issued its opinion in the consolidated appeals of the Virginia Commission’s order granting a CPCN for the Skiffes Creek transmission line and related facilities. The Supreme Court of Virginia unanimously affirmed all but one of the alleged grounds for appeal. The court approved the proposed project including the proposed route for a 500 kV overhead transmission line from Surry Power Station to the Skiffes Creek Switching Station site. The court reversed and remanded the Virginia Commission’s determination in one set of appeals that the Skiffes Creek Switching Station was a transmission line for purposes of statutory exemption from local zoning ordinances. In May 2015, the Supreme Court of Virginia denied separate petitions filed by Virginia Power and the Virginia Commission to rehear its ruling regarding the Skiffes Creek Switching Station. Pending receipt of remaining required permits and approvals, Virginia Power expects to construct the project.

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. The COL is expected as early as 2016. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

In September 2014, BREDL filed a 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. BREDL asserted that the NRC must make a safety finding on the feasibility and capacity of geologic disposal of spent fuel prior to the issuance of a license. BREDL also 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 asking the NRC to supplement the final environmental impact statement for North Anna 3 to incorporate the NRC’s generic assessment of the impacts of continued spent fuel storage, which would allow BREDL to then challenge that assessment.

The NRC denied the September 2014 petition and motions filed by BREDL in February 2015 and the January 2015 petition filed by BREDL in April 2015. In April 2015, BREDL filed a new motion and petition seeking to object to the NRC’s reliance on the continued storage rule in licensing proceedings. The BREDL filings are substantially the same as those filed in other COL proceedings in which final environmental impact statements were issued prior to promulgation of the continued storage rule, like North Anna 3. In June 2015, the NRC denied the April 2015 motion and petition.

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. In the second quarter of 2014, Virginia Power recognized a $287 million ($191 million after-tax) charge against income representing the cumulative recovery of costs from January 2013 through June 2014 and recognized additional charges of approximately $87 million ($57 million after-tax) ratably during the remainder of 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.

North Carolina Regulation

In December 2012, the North Carolina Commission decided Virginia Power’s general rate case filed earlier that year, authorizing a 10.2% ROE. Following an appeal to the Supreme Court of North Carolina by multiple parties and a remand, the North Carolina Commission issued an opinion in July 2015 reaffirming its 10.2% ROE determination.

Ohio Regulation

PIPP Rider

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 amount is deferred and collected under the PIPP Rider in accordance with the rules of the Ohio Commission. In July 2015, 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 revised rider rate reflects the refund for the twelve-month period from July 2015 through June 2016 of an over-recovery of accumulated arrearages of approximately $57 million as of March 31, 2015, net of projected deferred program costs of approximately $35 million from April 2015 through June 2016.

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 2015, the Ohio Commission approved East Ohio's application to decrease its UEX Rider, which reflects a refund of over-recovered accumulated bad debt expense of approximately $14 million as of March 31, 2015, and recovery of prospective net bad debt expense projected to total approximately $20 million for the twelve-month period from April 2015 to March 2016.