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 Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California and Utah, under Dominion’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. 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, among other issues, that the incremental costs of undergrounding certain transmission line projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. A settlement of the other issues raised in the complaint was approved by FERC in May 2012.

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.

In June 2016, PJM, the PJM transmission owners and state commissions representing substantially all of the load in the PJM market submitted a settlement to FERC to resolve the outstanding issues regarding this matter. Under the terms of the settlement, Virginia Power would be required to pay in excess of $200 million to PJM over the next 10 years. Although the settlement agreement has not been accepted by FERC, and the settlement is opposed by a small group of parties to the proceeding, Virginia Power believes it is probable it will be required to make payment as an outcome of the settlement. Accordingly, as of March 31, 2017, Virginia Power has recorded a contingent liability of $208 million in other deferred credits and other liabilities, which is offset by a $200 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, 2016.

Virginia Regulation

Regulation Act Legislation

In March 2017, as required by Regulation Act legislation enacted in February 2015, Virginia Power filed an application for the Virginia Commission to determine the general ROE for Virginia Power’s non-transmission rate adjustment clauses. The application supported a 10.5% ROE for these rate adjustment clauses. This case is pending.

Solar Facility Project

In March 2017, Virginia Power received Virginia Commission approval for a CPCN to construct and operate the Oceana solar facility and related distribution interconnection facilities at a total estimated cost of approximately $40 million, excluding financing costs. The 18 MW facility is expected to begin operation in late 2017. 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. Virginia Power will retire renewable energy certificates on the Commonwealth's behalf in an amount equal to those generated by the facility. There is no rate adjustment clause associated with the facility, nor will any of its costs be recovered from jurisdictional customers.

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 2017, the Virginia Commission approved a $243 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017.


•	The Virginia Commission previously approved Rider W in conjunction with Warren County. In February 2017, the Virginia Commission approved a $121 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017.


•	The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In February 2017, the Virginia Commission approved a $72 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017.


•	The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In February 2017, the Virginia Commission approved a $27 million revenue requirement for the rate year beginning April 1, 2017.


•	The Virginia Commission previously approved Rider GV in conjunction with Greensville County. In February 2017, the Virginia Commission approved an $82 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017.

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The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2016, Virginia Power proposed a total revenue requirement of $45 million for the rate year beginning July 1, 2017. Virginia Power also proposed two new energy efficiency programs for Virginia Commission approval with a requested five-year cost cap of $178 million. Virginia Power further proposed to extend an existing energy efficiency program for an additional two years under current funding, and an existing peak shaving program for an additional five years with a new incremental $5 million cost cap. In April 2017, the Virginia Commission established a 9.4% ROE for Riders C1A and C2A effective July 1, 2017. This case is pending.

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The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In October 2016, Virginia Power proposed a $134 million revenue requirement for the rate year beginning September 1, 2017, which represents a $15 million increase over the previous year. In April 2017, the Virginia Commission established a 10.4% ROE for Rider BW effective September 1, 2017. This case is pending.

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The Virginia Commission previously approved Rider US-2 in conjunction with the Scott Solar, Whitehouse, and Woodland solar facilities. In October 2016, Virginia Power proposed a $10 million revenue requirement for the rate year beginning September 1, 2017, which represents a $6 million increase over the previous year. In April 2017, the Virginia Commission established a 9.4% ROE for Rider US-2 effective September 1, 2017. This case is pending.

Electric Transmission Projects

Virginia Power previously filed an application with the Virginia Commission for a CPCN to convert an existing transmission line to 230 kV in Prince William County, Virginia, and Loudoun County, Virginia, and to construct and operate a new approximately five mile overhead 230 kV double circuit transmission line between a tap point near the Gainesville substation and a new to-be-constructed Haymarket substation. In April 2017, the Virginia Commission granted a CPCN to construct and operate the project along an approved route subject to Virginia Power’s obtaining all necessary rights-of-way. Otherwise, Virginia Power can construct and operate the project along an approved alternative route. The total estimated cost of the project is approximately $55 million.

Virginia Power previously filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 28 miles of the existing 500 kV transmission line between the Carson switching station and a terminus located near the Rogers Road switching station under construction in Greensville County, Virginia, along with associated work at the Carson switching station. In March 2017, the Virginia Commission granted a CPCN to construct and operate the project. The total estimated cost of the project is approximately $55 million.

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. Virginia Power has not yet committed to building a new nuclear unit at North Anna nuclear power station.

Requests by BREDL for a contested NRC hearing on Virginia Power’s COL application have been dismissed, and in September 2016, the U.S. Court of Appeals for the D.C. Circuit dismissed with prejudice petitions for judicial review that BREDL and other organizations had filed challenging the NRC’s reliance on a rule generically assessing the environmental impacts of continued onsite storage of spent nuclear fuel in various licensing proceedings, including Virginia Power’s COL proceeding. This dismissal followed the Court’s June 2016 decision in New York v. NRC, upholding the NRC’s continued storage rule and August 2016 denial of requests for rehearing en banc. Therefore, the contested portion of the COL proceeding is closed. The NRC is required to conduct a hearing in all COL proceedings. This mandatory NRC hearing was held in March 2017 and was uncontested. A decision by the NRC whether to issue a COL is expected by the end of the second quarter of 2017.

In August 2016, Virginia Power received a 60-day notice of intent to sue from the Sierra Club alleging Endangered Species Act violations. The notice alleges that the U.S. Army Corps of Engineers failed to conduct adequate environmental and consultation reviews, related to a potential third nuclear unit located at North Anna, prior to issuing a CWA section 404 permit to Virginia Power in September 2011. No lawsuit has been filed and in November 2016, the Army Corps of Engineers suspended the section 404 permit while it gathered additional information. The section 404 permit was reinstated in April 2017.

Other Virginia Legislation

In February 2017, the Governor of Virginia signed legislation into law that allows utilities to file a rate adjustment clause to recover costs of pumped hydroelectricity generation and storage facilities that are located in the coalfield region of Virginia.

In March 2017, the Governor of Virginia signed legislation into law that allows utilities to file a rate adjustment clause to recover, beginning in 2020, reasonably appropriate costs for extending the COLs, or the operating lives, of nuclear power generation facilities.

Also in March 2017, the Governor of Virginia signed legislation into law stating that is in the public interest for utilities to replace existing overhead tap lines having nine or more total unplanned outage events-per-mile with new underground facilities, and that utilities can seek cost recovery for such new underground facilities through a rate adjustment clause.

Ohio Regulation

PIR Program

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In April 2017, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2016 costs. The filing reflects gross plant investment for 2016 of $188 million, cumulative gross plant investment of $1.2 billion and a revenue requirement of $157 million.

AMR Program

In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. In April 2017, the Ohio Commission approved East Ohio's application to adjust its AMR cost recovery rate for 2016 costs. The filing reflects a revenue requirement of approximately $6 million.

Ohio Legislation

In March 2017, the Governor of Ohio signed legislation into law that allows utilities to file an application to recover infrastructure development costs associated with economic development projects. The new cost recovery provision allows for projects totaling up to $22 million for East Ohio subject to Ohio Commission approval.