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 regulatory matters that the Companies cannot estimate, 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 that 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.

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and, under its market based rate authority, sells electricity in the PJM wholesale market and to wholesale purchasers in Virginia and North Carolina. DESC sells electricity to wholesale purchasers in its balancing authority area under its electric cost based tariff and to wholesale purchasers outside of its balancing authority area under its market based rate authority. 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. 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.

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 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 investment in electric transmission infrastructure.

In March 2010, ODEC 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. In July 2018, FERC denied the rehearing requests related to the October 2017 order determining the calculation of the undergrounding costs. Several parties have appealed FERC’s decision to the U.S. Court of Appeals for the D.C. Circuit. This matter is pending. While Virginia Power cannot predict the outcome of the matter, it is not expected to have a material effect on results of operations.

In January 2019, FERC issued an order denying PJM’s request to waive certain provisions of the PJM Tariff regarding the liquidation of a portfolio of FTRs owned by GreenHat who had defaulted on its financial obligations. As a result of FERC’s order, PJM is required to use the existing tariff provisions to liquidate GreenHat’s FTR portfolio and allocate the resulting costs to PJM members. In February 2019, PJM filed a request for clarification and rehearing with FERC. Also in February 2019, Virginia Power and certain other PJM members filed a request for rehearing with FERC. While the impacts of this order could be material to Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts.

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 and Dominion Energy Gas’ results of operations. In December 2017, DETI provided its response to the audit report. DETI reached resolution of certain matters with FERC in the fourth quarter of 2018. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the remaining finding and no amounts have been recognized.

Other than the items discussed below, which are pending or have been resolved during the period, there have been no changes to the 2017 Tax Reform Act matters discussed in Notes 3 and 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2018.

In January 2019, Virginia Power filed updated testimony in response to the Virginia Commission’s September 2018 order with a proposed annual revenue reduction of approximately $171 million. Additionally, Virginia Power proposed to issue a one-time bill credit to customers within 90 days of this effective date, to true-up the difference between the final revenue reduction for the period January 1, 2018 through March 31, 2019 and the $125 million interim rate reduction implemented on July 1, 2018. In March 2019, the Virginia Commission issued an order approving an annual revenue reduction of approximately $183 million effective April 2019 and ordering Virginia Power to implement the one-time customer credit, estimated to total approximately $135 million, on or before July 1, 2019.

In October 2018, the North Carolina Commission issued an order requesting companies file to reduce base rates expeditiously. Virginia Power made its compliance filing in October 2018 and submitted an annual base rate revenue decrease of approximately $14 million effective in early 2019. Virginia Power also proposed to issue a one-time bill credit in early 2019 for its 2018 tax savings collected provisionally from customers, which is estimated to be approximately $13 million. The order allowed for the disposition of excess deferred income taxes to be deferred for consideration until the utilities’ next base rate case, but no longer than 3 years, and initiated a quarterly reporting requirement for such deferred amounts. In March 2019, the North Carolina Commission issued an order approving Virginia Power’s proposed annual base rate revenue decrease and one-time bill credit.

In March 2019, Questar Gas filed with the Utah and Wyoming Commissions as to the impact of excess deferred income taxes resulting from the 2017 Tax Reform Act. Questar Gas proposed to return the 2018 amortization of excess deferred income taxes to customers and to incorporate the remaining excess deferred income tax impact in its next general rate cases in each jurisdiction. This matter is pending.

In October 2018, the Ohio Commission issued an order requiring rate-regulated utilities to file an application reflecting the impact of the 2017 Tax Reform Act on current rates by January 1, 2019. In December 2018, East Ohio filed its application proposing an approach to establishing rates and charges by and through which to return tax reform benefits to its customers. This case is pending.

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 required all interstate natural gas pipelines to make a one-time informational filing with FERC on Form 501-G 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.

During 2018, Dominion Energy’s FERC-regulated pipelines, including those accounted for as equity method investments, filed the Form 501-G with FERC. Dominion Energy Overthrust Pipeline, LLC, White River Hub, Dominion Energy Questar Pipeline, DETI, DECG, Cove Point and Iroquois have reached resolution through a FERC waiver or FERC terminating the 501-G proceeding, or through settlement, which did not result in a material impact to results of operations, financial condition and/or cash flows of Dominion Energy or Dominion Energy Gas.

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Notes 3 and 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2018.

In March 2019, Virginia Power filed an application for the Virginia Commission to determine the general ROE for Virginia Power’s non-transmission rate adjustment clauses and for purposes of determining Virginia Power’s base rate earnings in the 2021 quadrennial review for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020. The application supported a 10.75% ROE for these rate adjustment clauses and quadrennial review period. This case is pending.

In July 2018, Virginia Power applied for approval of Rider US-3 associated with the Colonial Trail West and Spring Grove 1 solar projects with a proposed $10 million total revenue requirement for the rate year beginning March 1, 2019. In April 2019, the Virginia Commission approved the revenue requirement for the rate year beginning June 1, 2019.

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

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. In February 2019, the transmission line project was placed into service. In March 2019, the U.S. Court of Appeals for the D.C. Circuit issued an order vacating the permit from the U.S. Army Corps of Engineers issued in July 2017 and ordered the U.S. Army Corps of Engineers to do a full environmental impact study of the project. In April 2019, Virginia Power and the U.S. Army Corps of Engineers filed petitions for rehearing with the U.S. Court of Appeals for the D.C. Circuit, asking that the permit from the U.S. Army Corps of Engineers remain in effect while an environmental impact study is performed. The mandate making the U.S. Court of Appeals for the D.C. Circuit’s March order effective will not be issued until May 2019 at the earliest and may be revised based on the petitions for rehearing. This matter is pending.

Additional Virginia Power electric transmission projects approved or applied for in 2019 are as follows:

Description and Location

of Project

Application

Date

Approval

Date

Type of

Line

Miles of

Lines

Cost Estimate

(millions)

Partial rebuild of overhead transmission lines in Alleghany County, Virginia and Covington, Virginia

August 2018

April 2019

138 kV

Rebuild and operate between Lanexa and the Northern Neck in Virginia

June 2018

February 2019

230 kV

Rebuild and operate the Glebe substation and relocate and operate in Arlington County, Virginia and the City of Alexandria, Virginia existing overhead line underground

March 2019

Pending

230 kV

125

Rebuild and operate between Valley, Virginia and Mt. Storm, West Virginia

April 2019

Pending

500 kV

290

In March 2019, Virginia Power filed its base rate case and schedules with the North Carolina Commission. Virginia Power proposed a non-fuel, base rate increase of $27 million effective November 1, 2019 on an interim basis subject to refund, with any permanent rates ordered by the North Carolina Commission effective January 1, 2020. The 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 presented an earned return of 7.52% based upon a fully-adjusted test period, compared to its authorized 9.90% return, and proposed a 10.75% ROE. This case is pending.

DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2019, DESC filed an application with the South Carolina Commission seeking approval to recover $30 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2019, the South Carolina Commission approved the request for the rate year beginning with the first billing cycle of May 2019.

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In April 2019, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery for 2018 costs. The filing reflects a gross plant investment for 2018 of $202 million, cumulative gross plant investment of $1.6 billion and a revenue requirement of $190 million.

In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. In April 2019, the Ohio Commission approved East Ohio’s application to adjust the AMR cost recovery for 2018 costs. The filing reflects a revenue requirement of $4 million.

In 2011, East Ohio began CEP which enables East Ohio to defer depreciation expense, property tax expense and carrying costs at the debt rate of 6.5% on capital investments not covered by its PIR program to expand, upgrade or replace its pipeline system and information technology systems as well as investments necessary to comply with the Ohio Commission or other government regulation. In May 2019, East Ohio filed an application for an alternative rate plan to establish a CEP rider to recover existing CEP-related deferrals and to establish an ongoing recovery mechanism for future deferrals. The filing reflects cumulative gross plant investment of $723 million through 2018 and a revenue requirement of $83 million. This matter is pending.

In April 2019, Questar Gas filed a request with the Utah Commission for pre-approval to construct an LNG storage facility with a liquefaction rate of 8.2 million cubic feet per day. This pre-approval process allows Questar Gas to receive a prudency determination from the Utah Commission before making a capital investment in the facility. Under the pre-approval statute, the Utah Commission has 180 days to make a prudency determination. This matter is pending.

In February 2019, Cove Point submitted its annual electric power cost adjustment to FERC requesting approval to recover $24 million. FERC approved the adjustment in March 2019.