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, California and Utah 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, Old Dominion Electric Cooperative and North Carolina Electric Membership Corporation filed a complaint with FERC against Virginia Power claiming that $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 held 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.

Virginia Power expects that a settlement agreement will be executed regarding this matter. Under the terms of the settlement,

Virginia Power would be required to pay $200 million to PJM over the next 10 years. Although no FERC order has been issued and the expected settlement agreement has not been filed and accepted by FERC, Virginia Power believes it is probable it will be required to make payment as an outcome of the hearing and settlement proceedings. Accordingly, as of March 31, 2016, Virginia Power has recorded a contingent liability of $200 million in other deferred credits and other liabilities, which is offset by a $192 million regulatory asset for the amount that will be recovered 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, 2015.

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. The legislation states that Virginia Power’s 2015 biennial review, filed in March 2015, would proceed for the sole purpose of reviewing and determining whether any refunds are due to customers based on earnings performance for generation and distribution services 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 rate adjustment clauses and requires utilities to file integrated resource plans annually rather than biennially. In November 2015, the Virginia Commission ordered testimony, briefs and a separate bifurcated hearing in Virginia Power's then-pending Rider B, R, S, and W cases on whether the Virginia Commission can adjust the ROE applicable to these rate adjustment clauses prior to 2017. In February 2016, the Virginia Commission issued final orders in these cases, stating that it could adjust the ROE and setting a base ROE of 9.6% for the projects, which results in a 10.6% ROE for Riders R, S and W and a 11.6% ROE for Rider B, effective April 1, 2016. In April 2016, the Virginia Commission issued a final order setting a 9.6% ROE for Riders C1A and C2A, effective May 1, 2016.

2015 Biennial Review

Pursuant to the Regulation Act, in March 2015, Virginia Power filed its base rate case and schedules for the Virginia Commission’s 2015 biennial review of Virginia Power’s rates, terms and conditions. Per legislation enacted in February 2015, this biennial review was limited to reviewing Virginia Power’s earnings on rates for generation and distribution services for the combined 2013 and 2014 test period, and determining whether credits are due to customers in the event Virginia Power’s earnings exceeded the earnings band determined in the 2013 Biennial Review Order. In November 2015, the Virginia Commission issued the 2015 Biennial Review Order. In December 2015, a group of large industrial customers filed notices of appeal with the Supreme Court of Virginia from both the 2015 Biennial Review Order and the Virginia Commission’s order denying their petition for rehearing or reconsideration. In April 2016, the Supreme Court of Virginia granted these appeals as a matter of right. In April 2016, the Attorney General filed an unopposed motion to suspend appellate briefing pending the outcome of a separate case at the Virginia Commission raising the same issues. These appeals are pending.

Virginia Fuel Expenses

In May 2016, Virginia Power submitted its annual fuel factor to the Virginia Commission to recover an estimated $1.4 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2016. Virginia Power's proposed fuel rate represents a fuel revenue decrease of $286 million when applied to projected kilowatt-hour sales for the period July 1, 2016 to June 30, 2017. This case is pending.

Solar Facility Project

In January 2015, Virginia Power applied for a CPCN to construct and operate a 20 MW utility-scale solar facility near its existing Remington power station in Fauquier County, Virginia. The total estimated cost of the Remington solar facility was approximately $47 million, excluding financing costs. Virginia Power also applied for approval of Rider US-1 to recover the projected costs of the facility. In October 2015, the Virginia Commission denied approval of the CPCN and Rider US-1 based on the evidence in the record but stated that an application could be re-filed to address the concerns cited by the Virginia Commission. In May 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate the Remington solar facility and related distribution interconnection facilities. The facility is the subject of a public-private partnership whereby the Commonwealth of Virginia, a non-jurisdictional customer, will compensate Virginia Power for the facility's net electrical energy output, and Microsoft will purchase all environmental attributes (including renewable energy certificates) generated by the facility. There is not a rate adjustment clause associated with this CPCN filing, nor will any costs of the project be recovered from jurisdictional customers. This case is pending.

Rate Adjustment Clauses

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


•	The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In February 2016, the Virginia Commission approved a $251 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2016. It also established a 10.6% ROE for Rider S effective April 1, 2016.


•	The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In February 2016, the Virginia Commission approved a $74 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2016. It also established a 10.6% ROE for Rider R effective April 1, 2016.


•	The Virginia Commission previously approved Rider W in conjunction with Warren County. In February 2016, the Virginia Commission approved a $118 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2016. It also established a 10.6% ROE for Rider W effective April 1, 2016.


•	The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In February 2016, the Virginia Commission approved a $30 million revenue requirement for the rate year beginning April 1, 2016. It also established an 11.6% ROE for Rider B effective April 1, 2016.

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In July 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate Greensville County and related transmission interconnection facilities. Virginia Power also applied for approval of Rider GV to recover the costs of Greensville County. In March 2016, the Virginia Commission granted the requested CPCN and approved a $40 million revenue requirement for the rate year beginning April 1, 2016. It also established a 9.6% ROE for Rider GV effective April 1, 2016.

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The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for demand-side management programs. In April 2016, the Virginia Commission approved a $46 million revenue requirement, subject to true-up, for the rate year beginning May 1, 2016. The Virginia Commission approved one new energy efficiency program at a reduced cost cap, denied a second energy efficiency program, and approved the extension of an existing peak shaving program recovered in base rates at no additional incremental cost.


•	The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2016, Virginia Power proposed a $639 million total revenue requirement for the rate year beginning September 1, 2016, which represents a $29 million decrease over the previous year. This case is pending.

North Anna

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna nuclear power station. 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 in 2017. Virginia Power has not yet committed to building a new nuclear unit at North Anna nuclear power station.

The motions and petitions filed by BREDL prior to April 2015 have been dismissed, and under a previous ruling of the NRC, the contested portion of the COL proceeding remains terminated. The NRC is required to conduct a hearing in all COL proceedings, and if a new contention is not admitted, the mandatory NRC hearing will be uncontested.

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 August 2015, BREDL filed a petition in the U.S. Court of Appeals for the D.C. Circuit seeking review of the NRC’s June 2015 decision. Along with the petition for judicial review, BREDL also filed a motion to hold this judicial review in abeyance pending the outcome of the ongoing judicial review of the NRC’s rule pertaining to the continued onsite storage of spent nuclear fuel in litigation pending before the same court. Similar petitions were filed seeking judicial review of the NRC’s decision as it applies to other COL and license renewal proceedings. In March 2016, the court granted Virginia Power's motion to intervene in the proceeding. This case is pending.

North Carolina Regulation

North Carolina Base Rate Case

In March 2016, Virginia Power filed its base rate case and schedules with the North Carolina Commission. Virginia Power proposed a non-fuel, base rate increase of $51 million effective November 1, 2016 on a temporary basis subject to refund, with any permanent rates ordered by the North Carolina Commission effective January 1, 2017. This base rate increase was proposed to recover the significant investments in generation, transmission, and distribution infrastructure for the benefit of North Carolina customers. Virginia Power also proposed an accelerated implementation of a new lower fuel rate, to be filed in August 2016, as part of the temporary rate effective November 1, 2016 subject to refund, along with a new Rider EDIT to return certain excess accumulated deferred income taxes to its North Carolina customers over a two-year period. Virginia Power presented an earned return of 5.06%, based upon a fully-adjusted test period, compared to its authorized 10.2% return, and proposed a 10.5% ROE going forward within the 10.25% to 10.75% range of its current cost of equity. This case is pending.

Ohio Regulation

PIR Program

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In February 2016, East Ohio filed an application to adjust the PIR cost recovery for 2015 costs. The filing reflects gross plant investment for 2015 of $171 million, cumulative gross plant investment of $1 billion and a revenue requirement of $131 million. This application was approved by the Ohio Commission in April 2016.

AMR Program

In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. In February 2016, East Ohio filed an application to adjust the AMR cost recovery for costs incurred during the calendar year 2015. The filing reflects a revenue requirement of approximately $7 million. This application was approved by the Ohio Commission in April 2016.

FERC - Gas

In 2013, DTI executed binding precedent agreements with several local distribution company customers for the New Market project. The project is expected to cost approximately $159 million and provide 112,000 Dths per day of firm transportation service from Leidy, Pennsylvania to interconnects with Iroquois and Niagara Mohawk Power Corporation's distribution system in the Albany, New York market. In April 2016, DTI received FERC authorization to construct, operate and maintain the project facilities, which are expected to be placed into service in the fourth quarter of 2016.

In 2014, DCG executed three binding precedent agreements for the approximately $120 million Transco to Charleston project, which will provide 80,000 Dths per day of firm transportation service from an existing interconnect with Transcontinental Gas Pipe Line Company, LLC in Spartanburg County, South Carolina to customers in Dillon, Marlboro, Sumter, Charleston, Lexington and Richland counties, South Carolina. In March 2016, DCG filed an application to request FERC authorization to construct and operate the project facilities, which are expected to be placed into service in the fourth quarter of 2017.

In April 2016, FERC issued an order authorizing DTI to abandon by sale its gathering and processing facilities to Dominion Gathering and Processing, Inc., a newly-formed wholly-owned subsidiary of Dominion Gas. These gathering and processing facilities, with a carrying value of approximately $430 million, are expected to be transferred in the second half of 2016.