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Regulatory Matters | 12 Months Ended
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Dec. 31, 2018
Regulated Operations [Abstract] |
Regulatory Matters | 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 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. FERC—ELECTRIC Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public util-ities. Virginia Power purchases and sells electricity in the PJM wholesale market and sells electricity to wholesale purchasers in Virginia and North Carolina. 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. 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 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. 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. 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. In May 2018, FERC issued an order accepting the settlement agreement and directed PJM to make a compliance filing with revised tariff records. As a result, in August 2018, Virginia Power began to make payments to PJM, to continue for the next 10 years totaling $276 million, under the terms of revised tariff records, which was partially offset by a $265 million regulatory asset for the amount that will be recovered through retail rates in Virginia. At December 31, 2018, Virginia Power’s Consolidated Balance Sheet includes $126 million in other current liabilities and $50 million included in other deferred credits and other liabilities for amounts owed to PJM. FERC—GAS 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 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 impairment of assets and related charges in Dominion Energy 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. DETI recognized a charge of $129 million ($94 million after-tax) recorded primarily within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income during 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with FERC. 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. 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. 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 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 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 advance of the April 1, 2019 implementation as required by legislation. In October 2018, Virginia Power filed testimony with the Virginia Commission to implement adjustments in its base rates reflecting actual annual reductions in corporate income taxes resulting from the 2017 Tax Reform Act, which included a proposed annual revenue reduction of approximately $151 million effective April 2019. In December 2018, the Staff of the Virginia Commission proposed an annual revenue reduction of approximately $190 million. In January 2019, Virginia Power filed updated testimony 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. Based on Virginia Power’s current proposed annual revenue reduction, this one-time bill credit is expected to total approximately $120 million. The actual credit will be based on actual billing data and customer usage during that 15-month period. This matter is pending. 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. 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. This matter is pending. In May 2018, the Utah Commission approved a stipulation submitted by Questar Gas proposing the cost-of-service component of customer rates be reduced by $15 million annually beginning in June 2018. In July 2018, the Utah Commission approved Questar Gas’ request to return an additional $9 million to Utah customers representing the amounts related to the corporate income tax reduction that had been deferred from January 1, 2018 to May 31, 2018. This additional reduction began amortizing on August 1, 2018 and will be amortized over a one-year period. In October 2018, the Wyoming Commission approved Questar Gas’ request to return deferred amounts through a surcredit beginning November 1, 2018. The surcredit will remain in effect until rates become effective in the next Wyoming general rate case. The impact of excess deferred income taxes resulting from the 2017 Tax Reform Act on rates charged to customers will be reported to the Utah and Wyoming Commissions by the first quarter of 2019. 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. As directed by the West Virginia Commission, Hope is utilizing regulatory accounting to track the effects of the 2017 Tax Reform Act beginning in January 2018 and submitted testimony in July 2018 detailing such effects. In August 2018, the West Virginia Commission approved a settlement implementing base rate reductions effective September 1, 2018. In November 2018, the West Virginia Commission issued an order requiring Hope to file a calculation of prospective tax reform savings based on 2017 financial statements, using federal income tax rates reduced for consolidated tax savings, and to record as a regulatory liability the difference between the amount calculated based on 2017 financial statements and the amount included in the voluntary base rate reduction effective September 1, 2018. In December 2018, Hope filed the required calculation setting forth an annual regulatory liability deferral amount of $0.4 million. The disposition of the additional regulatory liability will be determined in a future rate proceeding. These reductions are not expected to have a material impact on Hope’s financial condition. 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 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. In July 2018, FERC issued a final rule adopting and modifying the procedures for determining whether jurisdictional natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate. Specifically, this final rule does not require master limited partnerships to eliminate their income tax allowances when completing the informational filing and allows entities that are wholly-owned by corporations to include an income tax allowance. During 2018, Dominion Energy’s FERC-regulated pipelines, including those accounted for as equity method investments, filed the required informational reports with FERC. Dominion Energy Overthrust Pipeline, LLC, White River Hub, Dominion Energy Questar Pipeline and Cove Point have reached resolution through settlement, which did not result in a material impact to results of operations, financial condition and/or cash flows of Dominion Energy, waiver or FERC terminating the 501-G proceeding. In January 2019, Iroquois reached a settlement in principle with its customers, which if approved would not have a material impact to Dominion Energy or Dominion Energy Gas, and expects to file a settlement agreement with FERC in the first quarter of 2019. The FERC dockets for DETI and DECG remain open. While the informational filings for these two pipelines indicated that no changes to current rates charged to customers were necessary, given the 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. Other Regulatory Matters VIRGINIA REGULATION 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. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects. 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. Grid Transformation and Security Act of 2018 In March 2018, the GTSA reinstated 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 and served as the basis for a reduction in future rates, 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. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized return on equity, base rates are subject to reduction prospectively and customer refunds would be due unless the total customer credit reinvestment offset 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 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, which is subject to adjustment effective April 2019. In May and June 2018, Virginia Power submitted filings detailing the implementation plan for interim reductions in rates for generation and distribution services pursuant to the GTSA. 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 proposes 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 is $816 million and the proposed operations and maintenance expenses are $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. 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. Virginia Power intends to file a revised plan in mid-2019 that will address the elements needed for a comprehensive plan, as outlined by the Virginia Commission in its order. Virginia Fuel Expenses In May 2018, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.5 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2018. Virginia Power’s proposed fuel rate represented a fuel revenue increase of $222 million when applied to projected kilowatt-hour sales for the period July 1, 2018 to June 30, 2019. In August 2018, the Virginia Commission approved Virginia Power’s fuel rate with an increase of $209 million. Solar Facility Projects In July 2018, Virginia Power filed an application with the Virginia Commission for CPCNs to construct two solar facilities. Colonial Trail West and Spring Grove 1 are estimated to cost approximately $410 million, excluding financing costs. Colonial Trail West and Spring Grove 1 are expected to commence commercial operations, subject to regulatory approvals associated with the projects, in the fourth quarter of 2019 and the fourth quarter of 2020, respectively. Virginia Power also applied for approval of Rider US-3 associated with these projects with a proposed $10 million total revenue requirement for the rate year beginning March 1, 2019. In January 2019, the Virginia Commission issued a final order granting CPCNs to construct the solar facilities, subject to a 20-year performance guarantee of the facilities at a 25% solar capacity factor when normalized for force majeure events. The matter regarding Rider US-3 is pending. Rate Adjustment Clauses Below is a discussion of significant riders associated with various Virginia Power projects:
• |  | The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2018, Virginia Power proposed a $755 million total revenue requirement consisting of $468 million for the transmission component of Virginia Power’s base rates and $287 million for Rider T1. This total revenue requirement represents a $146 million increase versus the revenues to be produced during the rate year under current rates. In August 2018, the Virginia Commission approved a total revenue requirement of $630 million, including Rider T1, subject to true-up, for the rate year beginning September 1, 2018. The Virginia Commission’s order required an adjustment to Rider T1 to begin providing projected benefits associated with the 2017 Tax Reform Act to customers in rates effective September 1, 2018. Such projected benefits were not included in the underlying transmission formula rates approved by FERC. Also in August 2018, Virginia Power filed a petition with the Virginia Commission seeking limited reconsideration and rehearing of this approval to adjust the total revenue requirement to $636 million. In November 2018, the Virginia Commission denied the petition for limited reconsideration and rehearing and adjusted the total revenue requirement to $628 million.
• |  | 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. In December 2018, the Virginia Commission approved a total $70 million annual revenue requirement effective February 1, 2019, a total capital investment of $179 million for third phase conversions and a balance of $64 million for second phase conversions not previously approved for recovery through Rider U.
• |  | The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2018, Virginia Power requested approval to implement ten new energy efficiency programs and one new demand-response DSM program for five years, subject to future extensions, with a $262 million cost cap, and proposed a total $49 million revenue requirement for the rate year beginning July 1, 2019, which represents an $18 million increase over the previous year. This matter is pending.
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 S |  | June 2018 |  | February 2019 |  | April 2019 |  | $ | 215 |  |  | $ | (3 | )
Rider GV |  | June 2018 |  | February 2019 |  | April 2019 |  |  | 120 |  |  |  | 38 |
Rider W |  | June 2018 |  | February 2019 |  | April 2019 |  |  | 105 |  |  |  | (4 | )
Rider R |  | June 2018 |  | February 2019 |  | April 2019 |  |  | 57 |  |  |  | (9 | )
Rider B |  | June 2018 |  | February 2019 |  | April 2019 |  |  | 38 |  |  |  | (9 | )
Rider BW |  | October 2018 |  | Pending |  | September 2019 |  |  | 123 |  |  |  | 7 |
Rider US-2 |  | October 2018 |  | Pending |  | September 2019 |  |  | 16 |  |  |  | 3 |
Rider E |  | December 2018 |  | Pending |  | November 2019 |  |  | 114 |  |  |  | N/A |
Coastal Virginia Offshore Wind Project In November 2018, Virginia Power received approval from the Virginia Commission for its petition seeking a prudency determination as provided in the GTSA with respect to the proposed Coastal Virginia Offshore Wind project consisting of two 6 MW wind turbine generators located approximately 27 miles off the coast of Virginia Beach, Virginia in federal waters, and for a CPCN, for the generation tie line connecting the generators to shore. This project is expected to cost approximately $300 million and to be placed into service by the end of 2020. Electric Transmission 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. As of July 2017, Virginia Power has received all major required permits and approvals and is proceeding with construction of the project. In connection with the receipt of the permit from the U.S. Army Corps of Engineers in July 2017, Virginia Power was required to make payments totaling approximately $90 million to fund improvements to historical and cultural resources near the project. Accordingly, in July 2017, Virginia Power recorded an increase to property, plant and equipment and a corresponding liability for these payment obligations. Through December 31, 2017, Virginia Power had made $90 million of such payments. Also in July 2017, the National Parks Conservation Association filed a lawsuit in U.S. District Court for the D.C. Circuit seeking to set aside the permit granted by the U.S. Army Corps of Engineers for the project and requested a preliminary injunction against the permit. In August 2017, the National Trust for Historic Preservation and Preservation Virginia filed a similar lawsuit in U.S. District Court for the D.C. Circuit. In October 2017, the preliminary injunction requests were denied. In May 2018, the District Court granted summary judgment in favor of the U.S. Army Corps of Engineers and Virginia Power and dismissed both lawsuits. In June 2018, the National Parks Conservation Association and the National Trust for Historic Preservation and Preservation Virginia appealed that decision to the U.S. Court of Appeals for the D.C. Circuit. The appeal is pending. Also in June 2018, the National Parks Conservation Association filed requests with the U.S. District Court for the District of Columbia and the U.S. Court of Appeals for the D.C. Circuit for an injunction against the permit pending appeal. The U.S. District Court for the District of Columbia denied the injunction request in June 2018 and the U.S. Court of Appeals for the D.C. Circuit similarly denied the request in July 2018. In November 2015, Virginia Power 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. The total estimated cost of the project is approximately $180 million. In April 2017, the Virginia Commission issued an interim order instructing Virginia Power to construct and operate the project along an approved route if Virginia Power could obtain all necessary rights-of-way. Otherwise, the Virginia Commission ruled that Virginia Power can construct and operate the project along an approved alternative route. In June 2017, the Virginia Commission issued a final order approving the 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 discusses 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 stipulation settlement filed with the Virginia Commission agreeing that the project should be placed into an underground pilot program created by the GTSA. In July 2018, Virginia Power filed a request with the Virginia Commission to allow the project to participate in the underground pilot program. Subsequently, in July 2018, the Virginia Commission issued a final order granting the CPCN for the project and allowing the project to participate in the underground pilot program. In June 2018, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in King and Queen, King William, and New Kent Counties, Virginia four separate segments of 230 kV transmission line between Lanexa and the Northern Neck in Virginia. In February 2019, Virginia Power withdrew two of the segments from the application. As a result, the total estimated cost of the project is approximately $30 million. This matter is pending. Additional significant Virginia Power electric transmission projects approved and applied for in 2018 are as follows:
Description and Location of Project |  | Application Date |  | Approval Date |  | Type of Line |  |  | Miles of Lines |  |  | Cost Estimate (millions) |
Rebuild and operate existing 115 kV transmission lines between the Possum Point Switching Station and Northern Virginia Electric Cooperative’s Smoketown delivery point |  | June 2017 |  | February 2018 |  |  | 230 kV |  |  |  | 9 |  |  | $ | 20 |
Rebuild and operate between the Dooms substation and the Valley substation, along with associated substation work |  | September 2017 |  | September 2018 |  |  | 500 kV |  |  |  | 18 |  |  |  | 65 |
Build and operate between the Idylwood and Tysons substations, along with associated substation work |  | November 2017 |  | September 2018 |  |  | 230 kV |  |  |  | 4 |  |  |  | 125 |
Rebuild and operate between the Chesterfield and Hopewell substations, along with associated substation work |  | May 2018 |  | November 2018 |  |  | 230 kV |  |  |  | 8 |  |  |  | 30 |
Rebuild and operate between the Chesterfield and Lakeside substations, along with associated substation work |  | May 2018 |  | December 2018 |  |  | 230 kV |  |  |  | 21 |  |  |  | 35 |
Rebuild and operate between the Landstown and Thrasher substations, along with associated substation work |  | June 2018 |  | December 2018 |  |  | 230 kV |  |  |  | 8.5 |  |  |  | 20 |
Partial rebuild of overhead transmission lines in Alleghany County, Virginia and Covington, Virginia |  | August 2018 |  | Pending |  |  | 138 kV |  |  |  | 5 |  |  |  | 15 |
Build a new substation and connect three existing transmission lines thereto in Fluvanna County, Virginia |  | October 2018 |  | Pending |  |  | 230 kV |  |  |  | <1 |  |  |  | 30 |
NORTH CAROLINA REGULATION In August 2018, 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 $24 million increase to the fuel component of its electric rates for the rate year beginning February 1, 2019. As a mitigation alternative, Virginia Power proposed recovering 50% in the February 1, 2019 to the January 31, 2020 rate period and the remaining 50% in the following rate period. In January 2019, the North Carolina Commission approved Virginia Power’s full proposed fuel charge adjustment of $24 million. OHIO REGULATION PIR Program In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In March 2015, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years and to increase the annual capital investment, with corresponding increases in the annual rate-increase caps. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to settle East Ohio’s pending application. As requested, the PIR program and associated cost recovery will continue for another five-year term, calendar years 2017 through 2021, and East Ohio will be permitted 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 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. The AMR program approved by the Ohio Commission was completed in 2012. Although no further capital investment will be added, East Ohio is approved to recover depreciation, property taxes, carrying charges and a return until East Ohio has another rate case. In April 2018, the Ohio Commission approved East Ohio’s application to adjust its AMR cost recovery rate for 2017 costs. The filing reflects a revenue requirement of approximately $5 million. PIPP Plus Program Under the Ohio PIPP Plus Program, eligible customers can make reduced payments based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. In May 2018, East Ohio filed its annual update of the PIPP rider with the Ohio Commission. In July 2018, East Ohio’s annual update of the PIPP rider was automatically approved by the Ohio Commission after a 45-day waiting period from the date of the filing. The revised rider rate reflects recovery over the twelve-month period from July 2018 through June 2019 of projected deferred program costs of approximately $10 million from April 2018 through June 2019, net of a refund for over-recovery of accumulated arrearages of approximately $4 million as of March 31, 2018. UEX Rider East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In September 2018, the Ohio Commission approved East Ohio’s application requesting approval of its UEX Rider to reflect a refund of over-recovered accumulated bad debt expense of approximately $11 million as of March 31, 2018, and recovery of prospective net bad debt expense projected to total $16 million for the twelve-month period from April 2018 to March 2019. DSM Rider East Ohio has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In November 2018, East Ohio filed an application with the Ohio Commission seeking approval of an adjustment to the DSM rider to recover a total of $4 million, which includes an over-recovery of costs during the preceding 12-month period. This application was approved by the Ohio Commission in January 2019. WEST VIRGINIA REGULATION In May 2018, Hope filed a PREP application with the West Virginia Commission requesting approval to recover PREP costs related to $31 million and $36 million of projected capital investment for 2018 and 2019, respectively. The application also includes a true-up of PREP costs related to the 2017 actual capital investment of $28 million and sets forth $8 million of annual PREP costs to be recovered in proposed rates effective November 2018. In October 2018, the West Virginia Commission approved PREP rates effective November 2018. Approved rates recover $7 million of annual PREP costs related to actual cumulative PREP investment through December 31, 2017 of $48 million and projected PREP investment for calendar years 2018 and 2019 of $31 million and $29 million, respectively. UTAH AND WYOMING REGULATION Fuel Deferral In May 2018, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $86 million gas cost decrease reflecting forecasted decreases in commodity costs. The Utah Commission and the Wyoming Commission both approved the filings in May 2018 with rates effective June 2018. In October 2018, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $48 million gas cost decrease reflecting forecasted decreases in commodity costs. The Utah Commission and the Wyoming Commission both approved the filings in October 2018 with rates effective November 2018. In October 2018, the Utah Commission denied Questar Gas’ request for pre-approval to construct an LNG peaking storage facility with a liquefaction rate of 8.2 million cubic feet per day. Questar Gas is reviewing the order and assessing its options, which include filing supplemental information with the Utah Commission for reconsideration. Infrastructure Replacement Tracker During 2018, Questar Gas filed applications with the Utah Commission to increase its infrastructure replacement surcharge to collect an additional $11 million in revenue in 2019 related to $85 million in 2018 capital investment. The Utah Commission approved the applications in the fourth quarter of 2018. FERC—GAS Cove Point In March 2018, Cove Point submitted its annual electric power cost adjustment to FERC requesting approval to recover $30 million. FERC approved the adjustment in March 2018. In June 2015, Cove Point executed two binding precedent agreements for the approximately $150 million Eastern Market Access Project. In January 2018, Cove Point received FERC authorization to construct and operate the project facilities, which are expected to be placed in service in the second half of 2019. In October 2018, Cove Point announced it is evaluating alternatives to a proposed Charles County, Maryland compressor station that was initially part of this project and in December 2018, after working with project customers for alternative solutions, decided not to pursue further construction at this location resulting in a revised project estimate of approximately $45 million and a write-off of $37 million pre-tax ($28 million after-tax) recorded within impairment of assets and related charges in Dominion Energy’s Consolidated Statements of Income. DETI In September 2018, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $37 million. Also in September 2018, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $7 million. In October 2018, FERC approved these adjustments. In August 2018, DETI executed a binding precedent agreement with a customer for the West Loop project. The project is expected to cost approximately $95 million and provide 150,000 Dth per day of firm transportation service from Pennsylvania to Ohio for delivery to a proposed combined-cycle, natural gas-fired electric power generation facility to be located in Columbiana County, Ohio. In December 2018, DETI filed an application to request FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service by the end of 2021.

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