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Regulatory Matters | 6 Months Ended
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Jun. 30, 2017
Regulated Operations [Abstract] |
Regulatory Matters | Note 12. 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, MISO, 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. While Virginia Power cannot predict the outcome of the hearing, 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. Under the terms of the settlement, Virginia Power would be required to pay in excess of $200 million to PJM over the next 10 years. Although the settlement agreement has not been accepted by FERC, and the settlement is opposed by a small group of parties to the proceeding, Virginia Power believes it is probable it will be required to make payment as an outcome of the settlement. Accordingly, as of June 30, 2017, Virginia Power has recorded a contingent liability of $215 million in other deferred credits and other liabilities, which is offset by a $207 million regulatory asset for the amount that will be recovered through retail rates in Virginia. 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 that have the potential to result in adjustments which could be material to Dominion Energy and Dominion Energy Gas’ results of operations. DETI is evaluating the preliminary recommendations and determining the nature of its formal response to the audit staff. In connection with one preliminary recommendation that management does not anticipate challenging, 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 for the three and six months ended June 30, 2017 to write-off the balance of a regulatory asset, originally established in 2008, that is no longer considered probable of recovery. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the other preliminary recommendations and no amounts have been recognized. 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, 2016 and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2017. Virginia Regulation Virginia Fuel Expenses In May 2017, Virginia Power submitted its annual fuel factor to the Virginia Commission to recover an estimated $1.6 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2017. Virginia Power’s proposed fuel rate represented a fuel revenue increase of $279 million when applied to projected kilowatt-hour sales for the period July 1, 2017 to June 30, 2018. In June 2017, the Virginia Commission approved Virginia Power’s proposed fuel rate. Rate Adjustment Clauses Below is a discussion of significant riders associated with various Virginia Power projects:
• | The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2017, Virginia Power proposed a $245 million revenue requirement for the rate year beginning April 1, 2018, which represents a $2 million increase over the previous year. This case is pending.
• | The Virginia Commission previously approved Rider W in conjunction with Warren County. In June 2017, Virginia Power proposed a $126 million revenue requirement for the rate year beginning April 1, 2018, which represents a $5 million increase over the previous year. This case is pending.
• | The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In June 2017, Virginia Power proposed a $74 million revenue requirement for the rate year beginning April 1, 2018, which represents a $2 million increase over the previous year. This case is pending.
• | The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2017, Virginia Power proposed a $42 million revenue requirement for the rate year beginning April 1, 2018, which represents a $15 million increase over the previous year. This case is pending.
• | The Virginia Commission previously approved Rider GV in conjunction with Greensville County. In June 2017, Virginia Power proposed a $104 million revenue requirement for the rate year beginning April 1, 2018, which represents a $22 million increase over the previous year. This case is pending.
• | The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In June 2017, the Virginia Commission approved a $28 million revenue requirement, subject to true-up, for the rate year beginning July 1, 2017. It also established a 9.4% ROE for Riders C1A and C2A effective July 1, 2017. The Virginia Commission approved one new energy efficiency program at a reduced cost cap, and denied a second energy efficiency program. It also approved the extension of an existing peak shaving program at an additional $5 million incremental cost, and denied the extension of an existing energy efficiency program.
• | The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In June 2017, the Virginia Commission approved a $127 million revenue requirement, subject to true-up, for the rate year beginning September 1, 2017.
• | The Virginia Commission previously approved Rider US-2 in conjunction with the Scott Solar, Whitehouse, and Woodland solar facilities. In June 2017, the Virginia Commission approved a $10 million revenue requirement, subject to true-up, for the rate year beginning September 1, 2017.
• | The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2017, Virginia Power proposed a $625 million total revenue requirement consisting of $490 million for the transmission component of Virginia Power’s base rates and $135 million for Rider T1. This total revenue requirement represents a $55 million decrease versus the previous year. In July 2017, the Virginia Commission approved the proposed total revenue requirement, including Rider T1, subject to true-up, for the rate year beginning September 1, 2017.
Electric Transmission Projects In March 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 33 miles of the existing 500 kV transmission line between the Cunningham switching station and the Dooms substation, along with associated station work. In May 2017, the Virginia Commission granted a CPCN to construct and operate the project. The total estimated cost of the project is approximately $60 million. 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 is obligated to make payments in the third quarter of 2017 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. Also 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 project and requested a preliminary injunction against the permit. This lawsuit is pending. In April 2017, the Virginia Commission approved Virginia Power’s proposal to convert an existing transmission line to 230kV in Prince William County, Virginia and Loudoun County, Virginia, and to construct and operate a new approximately five mile overhead 230kV double circuit transmission line between a tap point near the Gainesville substation and a new to-be-constructed Haymarket substation, subject to Virginia Power obtaining all necessary rights-of-way and other approvals. In June 2017, the Virginia Commission issued an order approving the 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. This matter is pending. North Anna Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna nuclear power station. If Virginia Power decides to build a new unit, it would require a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In June 2017, the NRC issued the COL. Virginia Power has not yet committed to building a new nuclear unit at North Anna nuclear power station. 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 July 2017, 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 the recovery over the twelve-month period from July 2017 through June 2018 of projected deferred program costs of approximately $19 million from April 2017 through June 2018, net of a refund for over-recovery of accumulated arrearages of approximately $20 million as of March 31, 2017. 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 2017, 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 $12 million as of March 31, 2017, and recovery of prospective net bad debt expense projected to total approximately $22 million for the twelve-month period from April 2017 to March 2018. This case is pending.

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