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 nonregulated 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, Ohio, 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 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 had 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. In 2018, DETI recognized a charge of $129 million ($94 million after-tax) recorded within discontinued operations in Dominion Energy’s Consolidated Statements of Income for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with FERC. In November 2020, Dominion Energy completed the sale of DETI as part of the GT&S Transaction.

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.

The Companies began to reserve the impacts of the cost-of-service reduction as regulatory liabilities in January 2018 and will continue until rates are reset pursuant to state regulators’ approvals. The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate.

In September 2018, the Virginia Commission issued an order directing Virginia Power to submit a filing quantifying the impacts of the 2017 Tax Reform Act. In March 2019, the Virginia Commission issued an order approving an annual revenue reduction of approximately $183 million effective April 2019 and ordered Virginia Power to implement the one-time customer credit on or before July 1, 2019. In the second quarter of 2019, Virginia Power refunded to customers $132 million.

In August 2018, Virginia Power filed with FERC to waive protocols and begin reflecting projected tax reform benefits of approximately $100 million through the transmission formula rate prior to the normal formula rate process. FERC granted the waiver and the amounts began being reflected in customer billings in November 2018 reflecting the adjustment effective January 1, 2018.

In October 2018, the North Carolina Commission issued an order requesting companies file to reduce base rates expeditiously. In March 2019, the North Carolina Commission issued an order approving Virginia Power’s proposed annual base rate revenue decrease of approximately $14 million effective in early 2019 and one-time bill credit for its 2018 tax savings collected provisionally from customers. In the second quarter of 2019, Virginia Power refunded to customers $13 million.

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. The Utah Commission issued an order effective March 2020 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. Additionally, new base rates that went into effect in Utah on March 1, 2020 include the prospective impacts of sharing excess deferred income taxes with customers. 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 Wyoming 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.

In connection with the SCANA Merger Approval Order, the South Carolina Commission approved DESC’s provision of approximately $100 million in bill credits related to the 2017 Tax Reform Act’s impact on retail electric customer rates for the period beginning January 2018 through January 2019. These credits have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved a tax rider whereby the effects of the reduction in the corporate income tax rate resulting from the 2017 Tax Reform Act will benefit retail electric customers. This tax rider reduced base rates to customers by $63 million in 2019 and $66 million in 2020. Unamortized excess deferred income taxes that remained at the end of 2020 will be considered in future rate proceedings.

In October 2018, the South Carolina Commission issued an order approving adjustment to DESC’s natural gas rate schedules, under the terms of the Natural Gas Rate Stabilization Act, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. The approved natural gas rate schedules also included a tax reform rate rider to refund certain income tax amounts previously collected from customers. These lower rates, representing a $20 million decreased revenue requirement, became effective for bills rendered on and after the first billing cycle in November 2018.

In December 2018, the North Carolina Commission issued an order approving PSNC’s proposed adjustments to customer rates, representing a $13 million decreased revenue requirement, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. These lower rates became effective for service rendered on and after January 1, 2019. Amounts collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC’s next general rate case proceeding or in three years, whichever is sooner. The reduction in the federal corporate tax rate and its impact on PSNC’s various rate riders will be addressed in future proceedings related to those riders.

The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers.

The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs, renewable energy programs and nuclear license renewals, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.

If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.

In November 2019, the Virginia Commission approved a 9.2% 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 Triennial Review.

In 2020, Virginia Power recorded a charge of $130 million ($97 million after-tax) in impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment) for benefits expected to be provided through the use of a CCRO in accordance with the GTSA. This charge reflects benefits expected to be provided to jurisdictional customers as a result of the 2021 Triennial Review as well as the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology.

In March 2018, the GTSA reinstated base rate reviews commencing with the 2021 Triennial Review which 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 ROE that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include in a CCRO. 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 CCRO. Any costs that are the subject of a CCRO 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. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized ROE, base rates are subject to reduction prospectively and customer refunds would be due unless the total CCRO elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. In the 2021 review, any such rate reduction is limited to $50 million.

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 (reflected in the Corporate and Other segment during 2018) in connection with this legislation, including the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology. In July 2018 and January 2019, Virginia Power credited $138 million and $77 million, respectively, to current customers’ bills.

In addition, Virginia Power reduced base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act. In March 2019, the Virginia Commission directed an annual revenue reduction of $183 million in rates for generation and distribution services pursuant to the GTSA effective April 2019.

In January 2019, the Virginia Commission issued an order approving capital spending for the first three years of Virginia Power’s ten-year plan totaling $68 million for electric distribution grid transformation projects as authorized by the GTSA on cyber and physical security and related telecommunications infrastructure (Phase IA). The Virginia Commission declined to approve certain 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 included 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 is $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 in 2021.

In November 2020, legislation was enacted in Virginia relating to the moratorium on utility disconnections during the COVID-19 pandemic and resulted in Virginia Power forgiving Virginia jurisdictional retail electric customer balances that were more than 30 days past due as of September 30, 2020. As a result, Virginia Power recorded a charge of $127 million ($94 million after-tax) in impairment of assets and other charges (reflected in the Corporate and Other segment). For the purposes of Virginia Power’s 2021 Triennial Review, the charge is excluded from Virginia Power’s cost of service for purposes of determining any test period earnings and determining any future rates. To the extent that the Virginia Commission determines total earnings for the test period to be above Virginia Power’s authorized earnings band, the forgiven balance amounts are offset against the excess earnings in the determination of any customer bill credits, or utilization of a CCRO, as part of the 2021 Triennial Review.

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 CCRO 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 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 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 from the prior year balance as of June 30, 2020.

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 in 2021 and 2022. In October 2020, Virginia Power filed an application with the Virginia Commission for CPCNs to construct and operate these projects as part of its efforts to meet the renewable generation development requirements under VCEA. This matter is pending.

In December 2020, Virginia Power entered into and closed on separate agreements to acquire Fountain Creek Solar and Otter Creek Solar. The projects are expected to cost approximately $280 million in aggregate once constructed, including the initial acquisition cost. The facilities are expected to generate 140 MW combined and be placed into service by the end of 2023. Virginia Power expects to file with the Virginia Commission for CPCNs to construct and operate these projects as well as a rider to recover the costs associated with the recovery of certain renewable generation facilities in Virginia by the end of 2021.

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

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

—

Rider E

January 2021

Pending

November 2021

(18

)

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. In May 2019, the U.S. Court of Appeals for the D.C. Circuit denied the request for rehearing and ordered the U.S. District Court for the D.C. Circuit to consider and issue a ruling on whether the permit should be vacated during the U.S. Army Corps of Engineers’ preparation of an environmental impact statement. In November 2019, the U.S. District Court for the D.C. Circuit issued an order allowing the permit to remain in effect while an environmental impact statement is prepared. In November 2020, the U.S. Army Corps of Engineers issued a draft environmental impact statement noting there is no better alternative. This matter is pending

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 significant Virginia Power electric transmission projects approved or applied for 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	19	70
Build new Lockridge substation and line loop in Loudon County, Virginia	December 2019	October 2020	230 kV	< 1	35
Bristers-Ladysmith Rebuild Project in the Counties of Fauquier, Stafford, Spotsylvania and Caroline, Virginia	May 2020	February 2021	500 kV	37	110
Relocate and replace a transmission line underground between the Tysons substation and the future Spring Hill substation	September 2020	Pending	230 kV	< 1	30
Rebuild an existing transmission line and install new line adjacent thereto in the Counties of New Kent, King William, King and Queen, Essex and Richmond, Virginia	October 2020	Pending	230 kV	41	100
Rebuild Clubhouse - Dry Bread Line and Dry Bread - Lakeview Line in Greensville County, Virginia	November 2020	Pending	230 kV	13	20
Rebuild transmission lines and related projects in the Counties of York and James City and the City of Williamsburg, Virginia	January 2021	Pending	230 kV	11	30

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. In January 2021, the North Carolina Commission approved a total $16 million decrease to the fuel component of its electric rates for the rate year beginning February 1, 2021.

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 September 2020, the North Carolina Commission approved PSNC’s request to increase the integrity management annual revenue requirement to $31 million, an increase of $3 million over its previous filing, effective September 2020.

In February 2021, the North Carolina Commission approved PSNC’s request to increase the integrity management annual revenue requirement to $33 million, an increase of $2 million over its previous filing, effective March 2021.

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%, based on an adjusted test year data, 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% established in the previous rate case in 2012. In January 2021, the South Carolina Commission approved a proposal made by the South Carolina Office of Regulatory Staff, and agreed to by DESC and other intervenors, to stay the base rate case due to the current economic conditions and to allow the parties more time to negotiate a settlement with a final order to be issued no later than August 2021. In connection with this order, DESC, the South Carolina Office of Regulatory Staff and other parties of record are to provide monthly updates to the South Carolina Commission on the progress towards reaching a negotiated settlement. 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 January 2021, DESC filed an application with the South Carolina Commission seeking approval to recover $48 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. This matter is pending.

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.

DESC’s retail electric rates include a cost of fuel component approved by the South Carolina Commission which may be adjusted periodically to reflect changes in the price of fuel purchased by DESC. 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 approximately $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 February 2021, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment would increase annual base fuel component recoveries by approximately $36 million and is designed to recover DESC’s current base fuel costs, net of the existing over-collected balance, over the 12-month period beginning with the first billing cycle of May 2021. In addition, DESC proposed a decrease to its variable environmental component and an increase to its distributed energy resource component. This matter is pending.

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 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to continue the PIR program and associated cost recovery for another five-year term, calendar years 2017 through 2021, and to permit East Ohio to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio.

In April 2020, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2019 costs. The filing reflects gross plant investment for 2019 of $209 million, cumulative gross plant investment of $1.8 billion and a revenue requirement of $218 million.

In December 2020, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years upon expiration of the current authorization at the end of 2021. East Ohio proposed continued capital investment increases of 3% per year, with related increases in the annual rate-increase caps. In its application, East Ohio proposed that the new five-year period should include investment through December 31, 2026. This case is pending.

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. In December 2020, the Ohio Commission approved a cumulative gross plant investment of $721 million and a revenue requirement of $83 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 September 2020, Questar Gas submitted a filing with the Utah Commission for a $40 million gas cost increase. In October 2020, the Utah Commission approved the application on an interim basis, with rates effective November 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%.