Note 13. 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, 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. In November 2017, Virginia Power, North Carolina Electric Membership Corporation and the wholesale transmission customers filed petitions for rehearing. While Virginia Power cannot predict the outcome of the matter, 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 approximately $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, 2018, Virginia Power has recorded a contingent liability of $239 million in other deferred credits and other liabilities, which is offset by a $229 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. In November 2017, the FERC audit staff issued its audit report, which could have the potential to result in adjustments which could be material to Dominion Energy’s and Dominion Energy Gas’ results of operations. In December 2017, DETI provided its response to the audit report. DETI requested FERC review of contested findings and submitted its plan for compliance with the uncontested portions of the report. In connection with one uncontested issue, DETI recognized 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 during 2017 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 findings and no amounts have been recognized.

2017 Tax Reform Act

Subsequent to the enactment of the 2017 Tax Reform Act, the Companies’ state regulators issued orders requesting that public utilities evaluate the total tax impact on the entity’s cost of service and accrue a regulatory liability attributable to the benefits of the reduction in the corporate income tax rate. Certain of the orders requested that the public utilities submit a response to the state regulatory commissions detailing the total tax impact on the utility’s cost of service.

Virginia Power submitted a response to the North Carolina Utilities Commission detailing the impact of the 2017 Tax Reform Act on base non-fuel cost of service and Virginia Power’s excess deferred income taxes clarifying that the amounts have been deferred to a regulatory liability. The Virginia Commission directed Virginia Power to submit a compliance filing in May 2018 detailing the implementation plan for rate reductions attributable to reductions in the corporate income tax obligations pursuant to the 2017 Tax Reform Act. Questar Gas submitted a response to the Utah Commission and Wyoming Public Service Commission detailing the impact of the 2017 Tax Reform Act on base rates and the infrastructure rider, and proposing that the benefits be passed back to customers. East Ohio submitted responses to the Ohio Commission’s request for comments on those components of utility rates that will need to be reconciled with the 2017 Tax Reform Act, and on the process and mechanics by which the Ohio Commission should do so. The Public Service Commission of West Virginia directed Hope to utilize regulatory accounting to track the effects of the 2017 Tax Reform Act beginning January 2018 and to submit pre-filed testimony in May 2018 detailing such effects. These filings are pending. Dominion Energy plans to respond to the remaining state regulatory commissions in accordance with the due dates on the issued orders. The Companies began to reserve the impacts of the cost-of-service reduction as a regulatory liability beginning in 2018 until the rates are reset.

The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate and are currently assessing these actions and decisions, which could have a material impact on the Companies’ results of operations, financial condition and/or cash flows.

In March 2018, FERC announced actions to address the income tax allowance component of regulated entities’ cost-of-service rates as a result of the 2017 Tax Reform Act. FERC issued a notice of proposed rulemaking introducing a process for determining whether jurisdictional natural gas pipelines may be collecting unjust and unreasonable rates as a result of the reduction in the corporate income tax rate. The proposed rule would require all interstate natural gas pipelines to make a one-time informational filing with FERC to provide financial information to allow FERC and other interested parties to analyze the impacts of the changes in tax law. The actions also included the reversal of FERC’s policy allowing master limited partnerships to recover an income tax allowance in cost-of-service rates and requiring other pass-through entities to justify the inclusion of an income tax allowance. FERC also issued a notice of inquiry seeking comments on whether it should take any additional actions to address changes in federal corporate income taxes, the elimination of an income tax allowance for master limited partnerships, excess or deficient accumulated deferred income taxes and bonus depreciation, among other items. Given these developments and associated uncertainty, Dominion Energy and Dominion Energy Gas are currently unable to predict the outcome of these matters; however, any change in rates permitted to be charged to customers could have a material impact on results of operations, financial condition and/or cash flows. Virginia Power’s regulated electric transmission formula rate mechanism includes provisions allowing changes in income tax rates to be incorporated in rates charged to customers.

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, 2017.

Virginia Regulation

Grid Transformation and Security Act of 2018

In March 2018, the Governor of Virginia signed into law legislation to reinstate base rate reviews on a triennial basis other than the first review, which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020. This review for Virginia Power will occur one year earlier than under the Regulation Act legislation enacted in February 2015.

In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized return on equity that might have been refunded to customers may be reduced by approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include in a customer credit reinvestment offset. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a customer credit reinvestment offset. Any costs that are the subject of a customer credit reinvestment offset may not be recovered in base rates for the service life of the projects and may not be included in base rates in future triennial review proceedings.

The legislation also includes provisions requiring Virginia Power to provide current customers one-time rate credits totaling $200 million and to reduce base rates to reflect reductions in income tax expense resulting from the 2017 Tax Reform Act. As a result, Virginia Power incurred a $215 million ($160 million after-tax) charge in connection with this legislation, including the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology. In addition, Virginia Power will reduce base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act, which is subject to adjustment in April 2019.

Rate Adjustment Clauses

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

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The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In February 2018, the Virginia Commission approved a $47 million revenue requirement based on updated revenue requirement projections and using an established 11.2% ROE for the rate year beginning April 1, 2018, subject to true-up. Public notice required by the Virginia Commission in connection with the proceeding reflected the originally proposed $42 million revenue requirement; therefore, in approving the updated $47 million revenue requirement, the Virginia Commission ordered that recovery from customers be limited to $42 million during the rate year beginning April 1, 2018, with any unrecovered amounts subject to true-up in future annual update proceedings.

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The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by Virginia legislation. In March 2018, Virginia Power requested approval of its third phase of conversions totaling $179 million and a balance of $65 million in second phase conversions not previously approved for recovery through Rider U. Virginia Power also proposed a total $73 million revenue requirement for the rate year beginning February 1, 2019 for continuing recovery of the previously approved first and second phase conversions and the proposed second and third phase conversions. 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 June 2017, the Virginia Commission issued a final order approving an alternative route for the project, and granted the necessary CPCN. In July 2017, the Virginia Commission retained jurisdiction over the case to evaluate two requests to reconsider its decisions. Also in July 2017, Virginia Power requested that the Virginia Commission stay the proceeding while Virginia Power discussed the proposed route with leaders of Prince William County. In December 2017, the Virginia Commission granted in part the two motions for reconsideration, retained jurisdiction for further proceedings in the case and stayed the effectiveness of its final order. In March 2018, Virginia Power and the two parties seeking reconsideration entered into a stipulated settlement filed with the Virginia Commission agreeing that the project should be placed into an underground pilot program created by the Grid Transformation and Security Act of 2018. This matter is pending.

Ohio Regulation

PIR Program

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In April 2018, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2017 costs. The filing reflects gross plant investment for 2017 of $204 million, cumulative gross plant investment of $1.4 billion and a revenue requirement of $165 million.

AMR Program

In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. In April 2018, the Ohio Commission approved East Ohio’s application to adjust the AMR cost recovery rate for 2017 costs. The filing reflects a revenue requirement of approximately $5 million.