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.

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, 2020.

In March 2021, Virginia Power filed its base rate case and accompanying schedules in support of the 2021 Triennial Review. In its filing, Virginia Power did not request an increase in base rates for generation and distribution services and proposed that base rates remain at their existing level. Virginia Power’s earnings test analysis, as filed, demonstrates it earned a combined ROE of 10.85% on its generation and distribution services for the test period, before accounting for forgiven customer balances. Pursuant to Virginia legislation, forgiven customer balances are excluded from the cost of service in determining test period revenues as part of the 2021 Triennial Review. 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 available revenues in the determination of any customer bill credits, or utilization of a CCRO. Test period earnings may be further 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 as a CCRO under the GTSA. In its filing, Virginia Power has elected to utilize $26 million of the Coastal Virginia Offshore Wind Pilot project investment as a CCRO to offset available revenues. The Virginia Commission will determine whether Virginia Power’s earnings for the test period, considered as a whole, were within 70 basis points above or below the authorized ROE of 9.2%. Should the Virginia Commission determine that there are additional available revenues for earnings sharing, then Virginia Power has contingently elected to offset those revenues with additional Virginia Commission approved qualifying CCRO investments. The Virginia Commission will also authorize an ROE for Virginia Power that will be applied to Virginia Power’s riders prospectively and that will also be utilized to measure base rate earnings as of January 1, 2021. Virginia Power is requesting authorization of an ROE of 10.8% based on Virginia Power’s current cost of equity. Pursuant to the Regulation Act, Virginia Power’s authorized ROE shall not be set lower than the average of either (i) the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., with certain limitations as described in the Regulation Act, or (ii) the authorized returns that are set by the applicable regulatory commissions for the same select peer group. This matter is pending.

In the third and fourth quarters of 2020, Virginia Power recorded a net charge of $130 million related to the use of a CCRO in accordance with the GTSA. In the first quarter of 2021, Virginia Power recorded a benefit of $130 million ($97 million after-tax) in impairment of assets and other charges in its Consolidated Statements of Income to adjust its reserve related to the use of a CCRO in accordance with the GTSA. These amounts reflect the impact related 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 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 in the fourth quarter of 2020. In connection with the Virginia 2021 budget process, in the first quarter of 2021 Virginia Power recorded a charge of $76 million ($56

million after-tax) in impairment of assets and other charges in its Consolidated Statements of Income for Virginia jurisdictional retail electric customer balances that were more than 30 days past due as of December 31, 2020 that Virginia Power is required to forgive. These forgiven customer balances are factored into Virginia Power’s 2021 Triennial Review as discussed above.

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 the VCEA. In April 2021, the Virginia Commission approved the application.

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 B

June 2020

February 2021

April 2021

)

Rider GV

June 2020

February 2021

April 2021

153

Rider R

June 2020

February 2021

April 2021

Rider S

June 2020

February 2021

April 2021

194

)

Rider W

June 2020

February 2021

April 2021

120

Rider US-3

July 2020

March 2021

June 2021

Rider US-4

July 2020

March 2021

June 2021

Description and Location

of Project

Application

Date

Approval

Date

Type of

Line

Miles of

Lines

Cost Estimate

(millions)

Elmont-Ladysmith rebuild and related projects in the Counties of Hanover and Caroline, Virginia

April 2021

Pending

500 kV

In April 2021, PSNC filed its general rate case application, direct testimony, exhibits, and schedules with the North Carolina Commission. PSNC proposed a non-fuel, base rate increase of $53 million to be effective November 1, 2021. After considering the benefits of the 2017 Tax Reform Act, the net revenue increase to customers would be approximately $42 million. The base rate increase was proposed to recover the significant investment in infrastructure to serve a growing customer base, improve safety and reliability of the transmission and distribution system and enhance energy efficiency and sustainability. The proposed rates would provide for an ROE of 10.25% compared to the currently authorized ROE of 9.7%. This matter is pending.

DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. 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. In April 2021, the South Carolina Commission approved the filing.

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 2021, DESC filed a proposal with the South Carolina Commission to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment would increase annual base fuel component recoveries by $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. In April 2021, the South Carolina Commission approved the filing.

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In February 2021, East Ohio filed an application requesting approval to adjust the PIR cost recovery rates for 2020 costs. The filing reflects gross plant investment for 2020 of $178 million, cumulative gross plant investment of $2.0 billion and an annual revenue requirement of $243 million.

In 2011, East Ohio began CEP which enables East Ohio to defer depreciation expense, property tax expense and carrying costs associated with CEP investments. In April 2021, East Ohio filed an application requesting approval to adjust the CEP cost recovery rates for 2019 and 2020 costs. The filing reflects gross plant investment for 2019 of $137 million, gross plant investment for 2020 of $99 million, cumulative gross plant investment of $957 million and a revenue requirement of $119 million. This matter is pending.

In April 2021, Questar Gas submitted a filing with the Utah Commission for a $43 million gas cost increase with rates effective June 2021. This matter is pending.