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Regulatory Matters | 6 Months Ended
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Jun. 30, 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 matters for which the Companies cannot estimate a range of possible loss, 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 for which 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 utilities. 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. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in the wholesale market. 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 of 11.4%, 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 growing investment in electric transmission infrastructure. In March 2010, Old Dominion Electric Cooperative 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. While Virginia Power cannot predict the outcome of the matter, it is not expected to have a material effect on results of operations. 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, Virginia Power will begin to make payments to PJM over the next 10 years under the terms of revised tariff records beginning in August 2018. Accordingly, at June 30, 2018, Virginia Power’s Consolidated Balance Sheet includes $148 million included in other current liabilities and $98 million included in other deferred credits and other liabilities, which are partially offset by a $237 million regulatory asset for the amount that will be recovered through retail rates in Virginia. FERC – Gas DETI 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’s 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 other operations and maintenance expense in Dominion Energy’s and Dominion Energy Gas’ Consolidated Statements of Income during the second quarter of 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 other operations and maintenance expense in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income during the second quarter of 2018 for a disallowance of plant, originally established beginning in 2012, in anticipation of 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 January 2018, the Virginia Commission issued an order directing Virginia utilities to reflect the impacts of the 2017 Tax Reform Act in the annual informational filings submitted to the Virginia Commission. Virginia Power submitted this filing in June 2018. Also, 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 Grid Transformation and Security Act of 2018. The interim rate reduction totals approximately $125 million on an annual basis effective July 2018. In February 2018, Virginia Power submitted a response to the North Carolina Utilities Commission detailing the impact of the 2017 Tax Reform Act on base non-fuel cost of service and Virginia Power’s excess deferred income taxes clarifying that the amounts have been deferred to a regulatory liability. 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. 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 March 2018, East Ohio submitted responses to the Ohio Commission’s request for comments on those components of utility rates that will need to be reconciled with the 2017 Tax Reform Act, and on the process and mechanics by which the Ohio Commission should do so. This matter is pending. As directed by the Public Service Commission of West Virginia, 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. This matter is pending. In March 2018, FERC announced actions to address the income tax allowance component of regulated entities’ cost-of-service rates as a result of the 2017 Tax Reform Act. FERC issued a notice of proposed rulemaking introducing a process for determining whether jurisdictional natural gas pipelines may be collecting unjust and unreasonable rates as a result of the reduction in the corporate income tax rate. The proposed rule would require 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. FERC also issued a notice of inquiry seeking comments on whether it should take any additional actions to address changes in federal corporate income taxes, the elimination of an income tax allowance for master limited partnerships, excess or deficient accumulated deferred income taxes and bonus depreciation, among other items. 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. These procedures are generally the same as the proposals issued in March; however the final rule modifies the treatment of the income tax allowance for master limited partnerships and other pass-through entities in the informational filing. 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. Although the informational filing does not require the elimination of the income tax allowance for master limited partnerships, and provides options to master limited partnerships to address the income tax allowance that were previously unavailable including providing evidence that a double recovery of income taxes does not exist, there can be no assurance that master limited partnerships would be allowed to include an income tax allowance in the future. Given these developments and 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. Virginia Power’s regulated electric transmission formula rate mechanism includes provisions allowing changes in income tax rates to be incorporated in rates charged to customers. Other Regulatory Matters 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, 2017, as updated in Current Report on Form 8-K, filed June 6, 2018, and Note 13 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2018. Virginia Regulation 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. This matter is pending. Grid Transformation and Security Act of 2018 In March 2018, the Governor of Virginia signed into law legislation to reinstate 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 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. 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 addition, Virginia Power will reduce 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 in April 2019. 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 Grid Transformation and Security Act of 2018. 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. This matter 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, subject to true-up, for the rate year beginning September 1, 2018. This total revenue requirement represents a $146 million increase versus the revenues to be produced during the rate year under current rates. This matter is pending.
• | The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2018, Virginia Power proposed a $220 million total revenue requirement for the rate year beginning April 1, 2019, which represents a $2 million increase over the previous year. This matter is pending.
• | The Virginia Commission previously approved Rider W in conjunction with Warren County. In June 2018, Virginia Power proposed a $107 million total revenue requirement for the rate year beginning April 1, 2019, which represents a $2 million decrease over the previous year. This matter is pending.
• | The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In June 2018, Virginia Power proposed a $59 million total revenue requirement for the rate year beginning April 1, 2019, which represents a $7 million decrease over the previous year. This matter is pending.
• | The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2018, Virginia Power proposed a $54 million total revenue requirement for the rate year beginning April 1, 2019, which represents a $7 million increase over the previous year. This matter is pending.
• | The Virginia Commission previously approved Rider GV in conjunction with Greensville County. In June 2018, Virginia Power proposed a $121 million total revenue requirement for the rate year beginning April 1, 2019, which represents a $39 million increase over the previous year. This matter is pending.
• | The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2017, Virginia Power requested approval to extend one existing energy efficiency program for five years with a new $25 million cost cap, and proposed a total $31 million revenue requirement for the rate year beginning July 1, 2018, which represents a $3 million increase over the previous year. In May 2018, the Virginia Commission approved a total revenue requirement of $31 million, subject to true-up.
• | The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In October 2017, Virginia Power proposed a $132 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. In July 2018, the Virginia Commission approved a $116 million revenue requirement, subject to true-up, for the rate year beginning September 1, 2018.
• | The Virginia Commission previously approved Rider US-2 in conjunction with Scott Solar, Whitehouse, and Woodland. In October 2017, Virginia Power proposed a $15 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. In July 2018, the Virginia Commission approved a $13 million revenue requirement, subject to true-up, for the rate year beginning September 1, 2018.
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 $11 million total revenue requirement for the rate year beginning March 1, 2019. This matter is pending. Electric Transmission Projects In July 2017, the National Parks Conservation Association filed a lawsuit in U.S. District Court for the District of Columbia seeking to set aside the permit granted by the U.S. Army Corps of Engineers for the Surry-to-Skiffes Creek-to-Whealton electric transmission line 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 and request for preliminary injunction in U.S. District Court for the District of Columbia. 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. Virginia Power previously 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. In June 2017, the Virginia Commission issued a final order approving an 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 discussed 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 stipulated settlement filed with the Virginia Commission agreeing that the project should be placed into an underground pilot program created by the Grid Transformation and Security Act of 2018. In June 2018, the Virginia Commission issued an order finding that the project is still needed. 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 May 2018, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in Chesterfield County and the City of Hopewell, Virginia approximately 8 miles of 230 kV transmission line between the Chesterfield and Hopewell substations, along with associated substation work. The total estimated cost of the project is approximately $30 million. This matter is pending. In May 2018, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in Chesterfield and Henrico Counties, Virginia approximately 21 miles of 230 kV transmission line between the Chesterfield and Lakeside substations, along with associated substation work. The total estimated cost of the project is approximately $35 million. This matter is pending. In June 2018, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in the Cities of Virginia Beach and Chesapeake, Virginia approximately 8.5 miles of 230 kV transmission line between the Landstown and Thrasher substations, along with associated substation work. The total estimated cost of the project is approximately $20 million. This matter is pending. 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. The total estimated cost of the project is approximately $35 million. This matter is pending. Ohio Regulation 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. 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. This matter is pending. 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 May 2018, East Ohio filed an application with the Ohio Commission 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 approximately $16 million for the twelve-month period from April 2018 to March 2019. This matter is pending.

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