Note 12. 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 Energy’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, South Carolina and Utah, under Dominion Energy’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.

In October 2017, FERC issued an order determining the calculation of the incremental costs of undergrounding the transmission projects and affirming that the costs are to be recovered from the wholesale transmission customers with loads located in Virginia. FERC directed Virginia Power to rebill all wholesale transmission customers retroactively to March 2010 within 30 days of when the proceeding becomes final and no longer subject to rehearing. Parties have until November 2017 to seek rehearing. Virginia Power is evaluating the order, which 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 September 30, 2017, Virginia Power has recorded a contingent liability of $223 million in other deferred credits and other liabilities, which is offset by a $215 million regulatory asset for the amount that will be recovered through retail rates in Virginia.

FERC – Gas

DETI

In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations that have the potential to result in adjustments which could be material to Dominion Energy and Dominion Energy Gas’ results of operations. DETI submitted its initial response to the audit staff in September 2017. In connection with one preliminary recommendation that management did not challenge, DETI recognized in the second quarter of 2017, a charge of $15 million ($9 million after-tax) recorded within other operations and maintenance expense in Dominion Energy’s and Dominion Energy Gas’ Consolidated Statements of Income to write-off the balance of a regulatory asset, originally established in 2008, that is no longer considered probable of recovery. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the other preliminary recommendations and no amounts have been recognized.

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 and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017.

Virginia Regulation

Regulation Act Legislation

The Supreme Court of Virginia previously granted appeals to certain industrial customers of Appalachian Power Company that challenged the constitutionality of legislation enacted in 2015 keeping Appalachian Power Company’s base rates unchanged until at least 2020. This legislation also keeps Virginia Power’s base rates unchanged until at least 2022. In September 2017, the Supreme Court of Virginia affirmed that the legislation is constitutional.

Rate Adjustment Clauses

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

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Virginia Power previously filed an application with the Virginia Commission to recover through Rider U costs for the first and second phases of a program to underground outage-prone overhead distribution lines. In September 2017, the Virginia Commission approved a total $22 million annual revenue requirement effective October 1, 2017, using a 9.4% ROE, and a total capital investment of $40 million for second phase conversions.

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The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2017, Virginia Power requested approval to extend one existing energy efficiency program for five years with a new $25 million cost cap, and proposed a total $31 million revenue requirement for the rate year beginning July 1, 2018, which represents a $3 million increase over the previous year. This case is pending.

•	The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In October 2017, Virginia Power proposed a $132 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. 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 2017, Virginia Power proposed a $15 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. This case is pending.

Electric Transmission Projects

Virginia Power previously filed an application with the Virginia Commission for a CPCN to rebuild and rearrange its Idylwood substation in Fairfax County, Virginia. In September 2017, the Virginia Commission granted a CPCN for the project. The total estimated cost of the project is approximately $110 million.

Virginia Power previously filed an application with the Virginia Commission for a CPCN to construct and operate in multiple Virginia counties an approximately 38-mile overhead 230 kV transmission line between the Remington and Gordonsville substations, along with associated facilities. In August 2017, the Virginia Commission granted a CPCN for the project. The total estimated cost of the project is approximately $105 million.

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. As of July 2017, Virginia Power has received all major required permits and approvals and is proceeding with construction of the project. In connection with the receipt of the permit from the U.S. Army Corps of Engineers in July 2017, Virginia Power was required to make payments totaling approximately $90 million to fund improvements to historical and cultural resources near the project. Accordingly, in July 2017, Virginia Power recorded an increase to property, plant and equipment and a corresponding liability for these payment obligations. Through September 30, 2017, Virginia Power had made $70 million of such payments, with the remaining $20 million paid in October 2017. Also in July 2017, the National Parks Conservation Association filed a lawsuit in U.S. District Court for the D.C. Circuit seeking to set aside the permit granted by the U.S. Army Corps of Engineers for the project and requested a preliminary injunction against the permit. In August 2017, the National Trust for Historic Preservation and Preservation Virginia filed a similar lawsuit in U.S. District Court for the D.C. Circuit. In October 2017, the preliminary injunction requests were denied. These lawsuits are pending.

North Carolina Regulation

In August 2017, Virginia Power submitted its annual filing to the North Carolina Utilities Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $15 million increase to the fuel component of its electric rates for the rate year beginning January 1, 2018. This case is pending.

Ohio Regulation

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 September 2017, the Ohio Commission approved East Ohio’s application requesting approval of its UEX Rider to reflect a refund of over-recovered accumulated bad debt expense of approximately $12 million as of March 31, 2017, and recovery of prospective net bad debt expense projected to total approximately $22 million for the twelve-month period from April 2017 to March 2018.

Utah and Wyoming Regulation

In October 2017, Questar Gas submitted filings with both the Public Service Commission of Utah and the Wyoming Public Service Commission for an approximately $25 million gas cost increase reflecting forecasted increases in commodity and transportation costs. The Public Service Commission of Utah and the Wyoming Public Service Commission both approved the filings in October 2017 with rates effective November 2017.

West Virginia Regulation

In October 2017, the Public Service Commission of West Virginia approved Hope’s application for new PREP customer rates, for the year beginning November 1, 2017, that provide for projected revenue of $4 million related to capital investments of $21 million, $27 million and $31 million for 2016, 2017 and 2018, respectively.

FERC – Gas

DETI

In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header Project, a project to provide approximately 1,500,000 Dths per day of firm transportation service to various customers. This project is expected to be placed into service in late 2019 and cost approximately $550 million to $600 million to construct, excluding financing costs. In October 2017, DETI received FERC authorization to construct and operate the project facilities.

In September 2017, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $39 million. Also in September 2017, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $6 million. In October 2017, FERC approved these adjustments.

Cove Point

In November 2016, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with 23 proposed rates to be effective January 1, 2017. Cove Point proposed an annual cost-of-service of approximately $140 million. In December 2016, FERC accepted a January 1, 2017 effective date for all proposed rates but five which were suspended to be effective June 1, 2017. In August 2017, Cove Point filed a proposed stipulation and settlement agreement with FERC, which was supported or not opposed by the active parties. Under the terms of the settlement agreement, Cove Point’s rates effective October 2017 would result in decreases to annual revenues and depreciation expense of approximately $18 million and $3 million, respectively, compared to the rates in effect through December 2016. In September 2017, the Presiding Administrative Law Judge certified the uncontested settlement to FERC. Cove Point is awaiting final FERC approval of the settlement. This case is pending.