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.

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 have been material to Dominion Energy’s 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. In November 2020, Dominion Energy completed the sale of DETI as part of the GT&S Transaction.

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 Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

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. In March 2020, the Utah Commission issued an order approving Questar Gas’ proposal to refund the January 2019 through February 2020 amortization of excess deferred income taxes over 12 months beginning in June 2020. In April 2020, at the request of the Wyoming Commission, this matter was considered in conjunction with the base rate case that was filed in November 2019. In June 2020, the Wyoming Commission approved a proposal to share the benefits of deferred income taxes for the period January 2018 through August 2020 with customers over a one-year period beginning in September 2020. In addition, new base rates that went into effect in September 2020 include the prospective impacts of sharing excess deferred income taxes with customers.

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. In December 2019, the Ohio Commission issued an order approving customer credits of approximately $600 million that will be shared with customers primarily over the remaining book life of the property to which the excess deferred income taxes relate. In addition, East Ohio will reduce rates approximately $19 million per year to account for the 2017 Tax Reform Act’s impact on its equity return component of rates charged to customers. A tax savings credit, which passes through the reduction in the federal income tax rate under the 2017 Tax Reform Act to customers in accordance with the settlement agreement approved by the Ohio Commission, became effective with the first billing cycle in April 2020.

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, 2019.

In April 2020, the Governor of Virginia signed into law the VCEA, which along with related legislation forms a comprehensive framework affecting Virginia Power’s operations. The VCEA replaces Virginia’s voluntary renewable energy portfolio standard for Virginia Power with a mandatory program setting annual renewable energy portfolio standard requirements based on the percentage of total electric energy sold by Virginia Power, excluding existing nuclear generation and certain new carbon-free resources, reaching 100% by the end of 2045. The VCEA includes related requirements concerning deployment of wind, solar and energy storage resources, as well as provides for certain measures to increase net-metering, including an allocation for low-income customers, incentivizes energy efficiency programs and directs Virginia to participate in a carbon trading program. While the legislation affects several portions of Virginia Power’s operations, key provisions of the GTSA remain in effect, including the triennial review structure and timing, the use of the customer credit reinvestment offset and the $50 million cap on revenue reductions in the first triennial review proceeding. Key provisions of the VCEA and related legislation passed include the following:

Virginia Power expects to incur significant costs, including capital expenditures, to comply with the legislative requirements discussed above. The legislation allows for cost recovery under the existing or modified regulatory framework through rate adjustment clauses, rates for generation and distribution services or Virginia Power’s fuel factor, as approved by the Virginia Commission. Costs allocated to the North Carolina jurisdiction will be recovered, subject to approval by the North Carolina Commission, in accordance with the existing regulatory framework.

In May 2020 and July 2020, Virginia Power entered into and closed on separate agreements to acquire Grassfield Solar, Norge Solar and Sycamore Solar. The projects are expected to cost approximately $170 million in aggregate once constructed, including the initial acquisition cost. The facilities are expected to generate 82 MW combined and be placed into service by the end of 2022. In October 2020, Virginia Power filed an application with the Virginia Commission for CPCNs to construct and operate these projects. Virginia Power also applied for approval of Rider CE associated with the projects with a proposed $11 million revenue requirement for the rate year beginning June 1, 2021. This matter is pending.

In July 2018, Virginia Power filed a petition with the Virginia Commission for approval of the first three years of its ten-year plan for electric distribution grid transformation projects as authorized by the GTSA. During the first three years of the plan, Virginia Power proposed to focus on the following seven foundational components of the overall grid transformation plan: (i) smart meters; (ii) customer information platform; (iii) reliability and resilience; (iv) telecommunications infrastructure; (v) cyber and physical security; (vi) predictive analytics; and (vii) emerging technology. The total estimated capital investment during 2019-2021 was $816 million and the proposed operations and maintenance expenses were $102 million. In January 2019, the Virginia Commission issued its final order approving capital spending for the first three years of the plan totaling $68 million on cyber and physical security and related telecommunications infrastructure (Phase IA). The Virginia Commission declined to approve the remainder of the proposed components for the first three years of the plan, the proposed spending for which was not found reasonable and prudent based on the record in the proceeding.

In September 2019, Virginia Power filed a revised plan which includes six components: (i) smart meters; (ii) customer information platform; (iii) grid improvement projects; (iv) telecommunications infrastructure; (v) cyber security; and (vi) a smart charging electric vehicle infrastructure pilot program (Phase IB). For Phase IB, the total proposed capital investment during 2019 – 2021 was $503 million and the proposed operations and maintenance investment was $78 million. In March 2020, the Virginia Commission issued an order approving $212 million of costs related to a new customer information platform, targeted grid hardening and corridor improvements, an electric vehicle Smart Charging Infrastructure Pilot Program, cyber security, stakeholder engagement and customer education and denied the costs associated with AMI, self-healing grid and certain other grid hardening projects alleging that Virginia Power did not prove the reasonableness and prudency of these costs. In April 2020, Virginia Power filed a petition for reconsideration of the Virginia Commission’s order and requested clarification of certain matters, including the Smart Charging Infrastructure Pilot Program. Additionally, Virginia Power requested clarification of certain matters relating to an AMI time-of-use rate and the smart charging electric vehicle infrastructure pilot program. Subsequently, in April 2020, the Virginia Commission denied in full Virginia Power’s petition for reconsideration; however, it stated that its March 2020 order contained all necessary approvals for the smart charging electric vehicle infrastructure pilot program. Virginia Power intends to file a revised plan that will address the elements needed for a comprehensive plan, as outlined by the Virginia Commission in its order.

In July 2019, Virginia Power filed an application with the Virginia Commission for a CPCN to construct Sadler Solar, which is estimated to cost approximately $146 million, excluding financing costs. Sadler Solar is expected to commence commercial operations, subject to regulatory approvals associated with the project, in the first quarter of 2021. Virginia Power also applied for approval of Rider US-4 associated with this project with a proposed $9 million total revenue requirement for the rate year beginning June 1, 2020. In January 2020, the Virginia Commission issued a final order granting the CPCN to construct Sadler Solar, subject to a

20 year performance guarantee of the facility at a 22% solar capacity factor when normalized for force majeure events. In March 2020, the Virginia Commission approved a $7 million total annual revenue requirement.

In February 2020, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.2 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2020 and a projected over-recovery of approximately $81 million for the prior year balance as of June 30, 2020. Virginia Power requested that the new fuel factor rate be implemented on an interim basis two months early, beginning on May 1, 2020. In March 2020, the Virginia Commission approved the interim rates. Virginia Power’s proposed fuel rate represents a fuel revenue decrease of approximately $393 million when applied to projected kilowatt-hour sales for the rate year beginning May 1, 2020. In June 2020, the Virginia Commission approved a revised fuel rate based on an updated projected over-recovery of $103 million for the prior year balance as of June 30, 2020.

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

Additional significant riders associated with various Virginia Power projects are as follows:

Rider Name

Application Date

Approval Date

Rate Year

Beginning

Total Revenue

Requirement

(millions)

Increase (Decrease)

Over Previous Year

(millions)

Rider US-3

July 2019

March 2020

June 2020

Rider BW

October 2019

June 2020

September 2020

(20

)

Rider US-2

October 2019

July 2020

September 2020

)

Rider E

January 2020

September 2020

November 2020

(19

)

Rider B

June 2020

Pending

April 2021

)

Rider GV

June 2020

Pending

April 2021

154

Rider R

June 2020

Pending

April 2021

Rider S

June 2020

Pending

April 2021

194

)

Rider W

June 2020

Pending

April 2021

120

Rider US-3

July 2020

Pending

June 2021

Rider US-4

July 2020

Pending

June 2021

Rider BW

October 2020

Pending

September 2021

113

Rider US-2

October 2020

Pending

September 2021

In December 2019, Virginia Power filed an application with the Virginia Commission for a CPCN to construct a new Evergreen Mills switching station and add approximately one mile of overhead 230 kV double circuit transmission lines from both the existing Brambleton-Yardley Ridge line and Brambleton-Poland Road line in Loudoun County, Virginia, estimated to cost approximately $30 million. In May 2020, the Virginia Commission issued an order approving in part and denying in part the petition. The Virginia Commission approved Virginia Power’s request to construct the new Evergreen Mills switching station and the new 230 kV double circuit transmission line from the existing Brambleton-Yardley Ridge line with a total estimated cost of $25 million.

Additional Virginia Power electric transmission projects applied for and/or approved are as follows:

Description and Location

of Project

Application

Date

Approval

Date

Type of

Line

Miles of

Lines

Cost Estimate

(millions)

Rebuild and operate five segments between the Loudoun and Ox substations

August 2019

June 2020

230 kV

Build new Lockridge substation and line loop in Loudoun County, Virginia

December 2019

October 2020

230 kV

Rebuild and operate two lines in Chesterfield County, Virginia

January 2020

June 2020

230 kV

Bristers-Ladysmith Rebuild Project in the counties of Fauquier, Stafford, Spotsylvania, and Caroline, Virginia

May 2020

Pending

500 kV

110

Relocate and replace a transmission line underground between the Tysons substation and the future Spring Hill substation

September 2020

Pending

230 kV

Rebuild and install new line in the Counties of New Kent, King William, King and Queen, Essex and Richmond, Virginia

October 2020

Pending

230 kV

100

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. In September 2019, Virginia Power revised its filing to reduce the non-fuel base rate increase to $24 million. In January 2020, the North Carolina Commission approved a 9.75% ROE and disallowed certain costs associated with coal ash remediation at Chesterfield power station. In February 2020, the North Carolina Commission issued its final order relating to base rates. In July 2020, Virginia Power filed a notice of appeal and exceptions to the Supreme Court of North Carolina, arguing that the North Carolina Commission committed reversible error on certain issues relating to the ratemaking treatment of certain coal ash remediation costs. This matter is pending.

In August 2020, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $15 million decrease to the fuel component of its electric rates for the rate year beginning February 1, 2021. This matter is pending.

The North Carolina Commission has authorized PSNC to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. In February 2020, the North Carolina Commission approved PSNC’s request to increase the integrity management annual revenue requirement to $28 million, an increase of $7 million over its previous filing, effective March 2020.

In August 2020, DESC filed its retail electric base rate case and schedules with the South Carolina Commission. DESC proposed a non-fuel, base rate increase of $178 million, or 7.75%, effective on or after the first billing cycle of March 2021. The base rate increase was proposed to recover the significant investment in assets and operating resources required to serve an expanding customer base, maintain the safety, reliability and efficiency of DESC’s system and meet increasingly stringent reliability, security and environmental requirements for the benefit of South Carolina customers. DESC presented an earned ROE of 5.90% based upon a fully-adjusted test period. The proposed rates would provide for an earned ROE equal to the current authorized earned ROE of 10.25%. This matter is pending.

DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2020, DESC filed an application with the South Carolina Commission seeking approval to recover $40 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2020, the South Carolina Commission approved the filing.

In February 2020, DESC filed a proposal with the South Carolina Commission to decrease the total fuel cost component of retail electric rates. DESC’s proposed decrease would reduce annual base fuel component recoveries by $44 million and is projected to return to customers the existing over-collected balance while recovering DESC’s current base fuel costs over the 12-month period beginning with the first billing cycle of May 2020. In addition, DESC proposed an increase to its variable environmental and distributed energy resource components. In April 2020, the South Carolina Commission approved the filing.

In 2020, DESC began several electric transmission projects in connection with two new nuclear plants under development by Southern. These transmission projects are required to be in place prior to these plants beginning operations to maintain reliability. DESC anticipates the projects to go into service in phases, costing approximately $75 million in aggregate. In February 2020, DESC filed an application with the South Carolina Commission requesting approval to construct and operate 28 miles of 230 kV transmission lines in Aiken County, South Carolina estimated to cost approximately $30 million. In June 2020, the South Carolina Commission approved the filing.

In June 2020, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2020 with a total revenue requirement of $409 million. This represents a $9 million overall annual increase to its natural gas rates under the terms of the Natural Gas Rate Stabilization Act effective with the first billing cycle of November 2020. In October 2020, the South Carolina Commission approved a total revenue requirement of $406 million effective with the first billing cycle of November 2020. This represents a $6 million overall annual increase to DESC’s natural gas rates. Additionally, the South Carolina Commission authorized an allowed ROE of 9.90%, a reduction from the prior ROE of 10.25%. The South Carolina Commission also approved an agreement between the South Carolina Office of Regulatory Staff and DESC that DESC will file its next retail natural gas general rate proceeding no later than April 2023.

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In April 2020, the Ohio Commission approved East Ohio’s application to adjust the PIR recovery for 2019 costs. The filing reflects gross plant investment for 2019 of $209 million, cumulative gross plant investment of $1.8 billion and an annual revenue requirement of $218 million.

In September 2020, Hope filed its base rate case and schedules with the West Virginia Commission. Hope proposed a non-fuel, base rate increase of $28 million. The base rate increase was proposed to recover the significant investment in distribution infrastructure and costs associated with the acquisition of over 2,000 miles of gathering assets, both for the benefit of West Virginia customers. The proposed rates would provide for an ROE of 10.25% compared to the authorized ROE of 9.45%. The rates are expected to go into effect in July 2021. This matter is pending.

In May 2020, Hope filed a PREP application with the West Virginia Commission requesting approval to recover PREP costs related to $39 million and $54 million of projected capital investment for 2020 and 2021, respectively. The application also includes a true-up of PREP costs related to the 2019 actual capital investment of $27 million and sets forth $13 million of annual PREP costs to be recovered in proposed rates effective November 1, 2020. In October 2020, the West Virginia Commission approved PREP rates effective November 1, 2020.

In December 2019, Questar Gas filed an application with the Utah Commission for a CPCN to construct natural gas infrastructure to extend service to Eureka, Utah. The project is expected to include 11 miles of high-pressure pipeline and up to 360 service lines and to be in service in late 2021. Questar Gas also requested approval of a rural expansion rate adjustment tracker to recover the construction costs of the project. In August 2020, the Utah Commission approved the CPCN and the rural expansion rate adjustment tracker.

In November 2019, Questar Gas filed its base rate case and schedules with the Wyoming Commission. Questar Gas proposed a non-fuel, base rate increase of $4 million effective September 2020. The base rate increase was proposed to replace aging infrastructure and expand its system. Questar Gas presented an earned return of 7.46%, based upon a fully-adjusted test period, compared to its authorized 9.5% return, and proposed a 10.5% ROE. In June 2020, the Wyoming Commission approved a base rate increase of $2 million annually, with rates effective September 1, 2020. This revenue requirement increase was based on an approved ROE of 9.35%.