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Commitments And Contingencies | 12 Months Ended
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Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract] |
Commitments And Contingencies | NOTE 22. COMMITMENTS AND CONTINGENCIES As a result of issues generated in the ordinary course of business, the Companies are involved in legal proceedings before various courts and are periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such 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 litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations 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 accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the Companies’ financial position, liquidity or results of operations. Environmental Matters The Companies are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. AIR CAA The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements. MATS The MATS rule requires coal- and oil-fired electric utility steam generating units to meet strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. Virginia Power ceased operating the coal units at Yorktown power station in April 2017 to comply with the rule. In June 2017, the DOE issued an order to PJM to direct Virginia Power to operate Yorktown power station’s Units 1 and 2 as needed to avoid reliability issues on the Virginia Peninsula. The order was effective for 90 days and can be reissued upon PJM’s request, if necessary, until required electricity transmission upgrades are completed. Beginning in August 2017, PJM filed requests for 90-day renewals of the DOE order which the DOE has granted. The current renewal is effective until March 2019. The Sierra Club has challenged the DOE order and certain renewal requests, all of which have been denied by the DOE. In December 2018, the EPA issued a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate toxic emissions from power plants. However, the emissions standards and other requirements of the MATS rule would remain in place as the EPA is not proposing to remove coal and oil fired power plants from the list of sources that are regulated under MATS. Although litigation of the MATS rule and the outcome of the EPA’s rulemaking are still pending, the regulation remains in effect and Virginia Power is complying with the applicable requirements of the rule and does not expect any adverse impacts to its operations at this time. Ozone Standards In October 2015, the EPA issued a final rule tightening the ozone standard from 75-ppb to 70-ppb. To comply with this standard, in April 2016 Virginia Power submitted the NOX Reasonable Available Control Technology analysis for Unit 5 at Possum Point power station. In December 2016, the VDEQ determined that NOX reductions are required on Unit 5. In October 2017, Virginia Power proposed to install NOX controls by mid-2019 with an expected cost in the range of $25 million to $35 million. In April 2018, Virginia Power submitted an application with the VDEQ containing an alternative plan for compliance in lieu of installing NOX controls on Unit 5 at Possum Point. The alter-native plan includes operating restrictions during the ozone season through 2021 while allowing for continued operation to meet PJM capacity commitments and calls for the permanent retirement of the unit by 2021. In January 2019, the VDEQ issued a state operating permit that requires either the installation and operation of selective non-catalytic NOX reduction technology by June 2019 or for Virginia Power to enter into an agreement with the VDEQ by June 2019 committing to retiring the unit by June 2021 with ozone season operating restrictions in the interim. In addition, Virginia Power placed two natural gas-fired units at the facility into cold reserve in December 2018. Virginia Power is currently evaluating its options. Dominion Energy and Virginia Power are unable to estimate the expenditures associated with this matter, however, they could be material to Dominion Energy and Virginia Power’s results of operations, financial condition and/or cash flows. The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the standard, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on the Companies’ results of operations and cash flows. NOx and VOC Emissions In April 2016, the Pennsylvania Department of Environmental Protection issued final regulations, with an effective date of January 2017, to reduce NOX and VOC emissions from combustion sources. To comply with the regulations, Dominion Energy Gas installed emission control systems on existing engines at several compressor stations in Pennsylvania, which was completed in December 2018. The compliance costs associated with engineering and installation of controls and compliance demonstration with the regulation was approximately $35 million. Oil and Gas NSPS In August 2012, the EPA issued an NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In June 2016, the EPA issued a new NSPS regulation, for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 are required to comply with this regulation. In October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. Until the proposed rule is final, Dominion Energy and Dominion Energy Gas are implementing the 2016 regulation. Dominion Energy and Dominion Energy Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material. GHG REGULATION Carbon Regulations In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant emissions rate at 75,000 tons per year of CO2 equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their financial statements. In addition, the EPA continues to evaluate its policy regarding the consideration of CO2 emissions from biomass projects when determining whether a stationary source meets the PSD and Title V applicability thresholds, including those for the application of BACT. It is unclear how the final policy will affect Virginia Power’s Altavista, Hopewell and Southampton power stations which were converted from coal to biomass under the prior biomass deferral policy; however, the expenditures to comply with any new requirements could be material to Dominion Energy and Virginia Power’s financial statements. Methane Emissions In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR Program, the Natural Gas STAR Methane Challenge Program. The program covers the entire natural gas sector from production to distribution, with more emphasis on transparency and increased reporting for both annual emissions and reductions achieved through implementation measures. In March 2016, East Ohio, Hope, DETI and Questar Gas joined the EPA as founding partners in the new Methane Challenge program and submitted implementation plans in September 2016. Wexpro, DECG and Dominion Energy Questar Pipeline joined the Methane Challenge in 2018. DECG joined the EPA’s voluntary Natural Gas STAR Program in July 2016 and submitted an implementation plan in September 2016 with Questar Gas and Dominion Energy Questar Pipeline joining in 2018. Dominion Energy and Dominion Energy Gas do not expect the costs related to these programs to have a material impact on their results of operations, financial condition and/or cash flows. WATER The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The Companies must comply with applicable aspects of the CWA programs at their operating facilities. In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion Energy and Virginia Power have 13 and 11 facilities, respectively, that may be subject to the final regulations. Nine units at Virginia Power’s facilities that are subject to regulations under Section 316(b) of the CWA have been or will be placed into cold reserve. While in cold reserve, applicable requirements under Section 316(b) of the CWA continue to apply to these units. Dominion Energy anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion Energy and Virginia Power are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. While the impacts of this rule could be material to Dominion Energy and 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 for Virginia Power. In September 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule establishes updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. In April 2017, the EPA granted two separate petitions for reconsideration of the Effluent Limitations Guidelines final rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the U.S.’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates for certain waste streams regulations in the Effluent Limitations Guidelines final rule from November 2018 to November 2020; however, the latest date for compliance for these regulations remains December 2023. The EPA is proposing to complete new rulemaking for these waste streams. While the impacts of this rule could be material to Dominion Energy and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for Dominion Energy and Virginia Power. WASTE MANAGEMENT AND REMEDIATION The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight. From time to time, Dominion Energy, Virginia Power, or Dominion Energy Gas may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion Energy, Virginia Power, or Dominion Energy Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. The Companies do not believe these matters will have a material effect on results of operations, financial condition and/or cash flows. Dominion Energy has determined that it is associated with 22 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion Energy Gas. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which the Companies are associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion Energy is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. In addition, a Virginia Power site has been accepted into a state-based voluntary remediation program. In June 2018, Virginia Power submitted a proposed remedial action plan to remove material from this site at an estimated cost of $18 million. Pending VDEQ approval, Virginia Power expects to begin remedial work at this site in mid-2019. As a result, in June 2018, Virginia recorded a charge of $16 million ($12 million after-tax) in other operations and maintenance expense in the Consolidated Statements of Income. The four sites Dominion Energy acquired in the SCANA Combination associated with SCE&G are in various states of investigation, remediation and monitoring under work plans approved by, or under review by, the SCDHEC or the EPA. Dominion Energy anticipates that activities at these sites will continue through 2020 at an estimated cost of $10 million. In September 2018, SCE&G submitted an updated remediation work plan at one site to SCDHEC, which if approved, would increase costs by approximately $8 million. SCE&G expects to recover costs arising from the remediation work at all four sites through rate recovery mechanisms. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts. See below for discussion on ash pond and landfill closure costs. Other Legal Matters The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows. APPALACHIAN GATEWAY Pipeline Contractor Litigation Following the completion of the Appalachian Gateway project in 2012, DETI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2015, the contractor filed a complaint against DETI in U.S. District Court for the Western District of Pennsylvania. In March 2016, the Pennsylvania court granted DETI’s motion to transfer the case to the U.S. District Court for the Eastern District of Virginia. In July 2016, DETI filed a motion to dismiss. In March 2017, the court dismissed three of eight counts in the complaint. In May 2017, the contractor withdrew one of the counts in the complaint. In November 2017, DETI and the contractor entered into a partial settlement agreement for a release of certain claims. In August 2018, DETI paid $14 million in accordance with the terms of a settlement agreement reached between the parties, resolving this matter. Gas Producers Litigation In connection with the Appalachian Gateway project, Dominion Energy Field Services, Inc. entered into contracts for firm purchase rights with a group of small gas producers. In June 2016, the gas producers filed a complaint in the Circuit Court of Marshall County, West Virginia against Dominion Energy, DETI and Dominion Energy Field Services, Inc., among other defendants, claiming that the contracts are unenforceable and seeking compensatory and punitive damages. During the third quarter of 2016, Dominion Energy, DETI and Dominion Energy Field Services, Inc. were served with the complaint. Also in the third quarter of 2016, Dominion Energy and DETI, with the consent of the other defendants, removed the case to the U.S. District Court for the Northern District of West Virginia. In October 2016, the defendants filed a motion to dismiss and the plaintiffs filed a motion to remand. In February 2017, the U.S. District Court entered an order remanding the matter to the Circuit Court of Marshall County, West Virginia. In March 2017, Dominion Energy was voluntarily dismissed from the case; however, DETI and Dominion Energy Field Services, Inc. remain parties to the matter. In April 2017, the case was transferred to the Business Court Division of West Virginia. In January 2018, the court granted the motion to dismiss filed by the defendants on two counts. Claims are pending in the Business Court Division of West Virginia. Dominion Energy and Dominion Energy Gas cannot currently estimate financial statement impacts, but there could be a material impact to their financial condition and/or cash flows. ASH POND AND LANDFILL CLOSURE COSTS In March 2015, the Sierra Club filed a lawsuit alleging CWA violations at Chesapeake power station. In March 2017, the U.S. District Court for the Eastern District of Virginia ruled that impacted groundwater associated with the on-site coal ash storage units was migrating to adjacent surface water, which constituted an unpermitted point source discharge in violation of the CWA. The court, however, rejected Sierra Club’s claims that Virginia Power had violated specific conditions of its water discharge permit. Finding no harm to the environment, the court further declined to impose civil penalties or require excavation of the ash from the site as Sierra Club had sought. In July 2017, the court issued a final order requiring Virginia Power to perform additional specific sediment, water and aquatic life monitoring at and around the Chesapeake power station for a period of at least two years. The court further directed Virginia Power to apply for a solid waste permit from VDEQ that includes corrective measures to address on-site groundwater impacts. In July 2017, Virginia Power appealed the court’s July 2017 final order to the U.S. Court of Appeals for the Fourth Circuit. In August 2017, the Sierra Club filed a cross appeal. In September 2018, the U.S. Court of Appeals for the Fourth Circuit ruled that impacted groundwater associated with coal ash storage at the Chesapeake power station did not constitute point source pollution in violation of the CWA or the station’s water discharge permit. The Sierra Club subsequently filed a petition for rehearing with the U.S. Court of Appeals for the Fourth Circuit, which was denied. In April 2015, the EPA enacted a final rule regulating CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store, CCRs. Dominion Energy currently operates inactive ash ponds, existing ash ponds and CCR landfills subject to the final rule at 11 different facilities, eight of which are at Virginia Power. This rule created a legal obligation for Dominion Energy and Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary. In 2015, Virginia Power recorded a $386 million ARO related to future ash pond and landfill closure costs. In 2016, Virginia Power recorded an increase to this ARO of $238 million, which resulted in a $197 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $17 million increase in property, plant and equipment and a $24 million increase in regulatory assets. In December 2016, legislation was enacted that creates a framework for EPA- approved state CCR permit programs. In August 2017, the EPA issued interim guidance outlining the framework for state CCR program approval. The EPA has enforcement authority until state programs are approved. The EPA and states with approved programs both will have authority to enforce CCR requirements under their respective rules and programs. In September 2017, the EPA agreed to reconsider portions of the CCR rule in response to two petitions for reconsideration. In March 2018, the EPA proposed certain changes to the CCR rule related to issues remanded as part of the pending litigation and other issues the EPA is reconsidering. Several of the proposed changes would allow states with approved CCR permit programs additional flexibilities in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to the CCR rule. Until all phases of the CCR rule are promulgated, Dominion Energy and Virginia Power cannot forecast potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the 2016 CCR legislation and reconsideration of the CCR rule. In August 2018, the U.S. Court of Appeals for the D.C. Circuit issued its decision in the pending challenges of the CCR rule, vacating and remanding to the EPA three provisions of the rule. Dominion Energy and Virginia Power do not expect the scope of the U.S. Court of Appeals for the D.C. Circuit’s decision to impact their closure plans, but cannot forecast incremental impacts associated with any future changes to the CCR rule in connection with the court’s remand. In April 2017, the Governor of Virginia signed legislation into law that places a moratorium on the VDEQ issuing solid waste permits for closure of ash ponds at Virginia Power’s Bremo, Chesapeake, Chesterfield and Possum Point power stations until May 2018. The law also required Virginia Power to conduct an assessment of closure alternatives for the ash ponds at these four stations, to include an evaluation of excavation for recycling or off-site disposal, surface and groundwater conditions and safety. Virginia Power completed the assessments and provided the report on December 1, 2017. In April 2018, the Governor of Virginia signed legislation into law extending the existing permit moratorium until July 2019. The legislation also requires Virginia Power to solicit and compile by November 2018, information from third parties on the suitability, cost and market demand for beneficiation or recycling of coal ash from these units. The coal ash recycling business plan was submitted to the legislature in November 2018. The extended moratorium does not apply to a permit required for an impoundment where CCRs have already been removed and placed in another impoundment on-site, are being removed from an impoundment, or are being processed in connection with a recycling or beneficial use project. In connection with this legislation, in the second quarter of 2018 Virginia Power recorded an increase to its ARO and a related environmental liability related to future ash pond and landfill closure costs of $131 million, which resulted in an $81 million ($60 million after-tax) charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $46 million increase in property, plant and equipment associated with asset retirement costs and a $4 million increase in regulatory assets. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the obligation. COVE POINT In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project at the Cove Point facility, which enables the facility to liquefy domestically-produced natural gas and export it as LNG. In March 2018, Cove Point received authorization from FERC to commence service of the Liquefaction Project, which commenced commercial operations in April 2018. Two parties have separately filed petitions for review of the FERC order in the U.S. Court of Appeals for the D.C. Circuit, which petitions were consolidated. In July 2016, the court denied one party’s petition for review of the FERC order authorizing the Liquefaction Project. The court also issued a decision remanding the other party’s petition for review of the FERC order to FERC for further explanation of FERC’s decision that a previous transaction with an existing import shipper was not unduly discriminatory. In September 2017, FERC issued its order on remand from the U.S. Court of Appeals for the D.C. Circuit, and reaffirmed its ruling in its prior orders that Cove Point did not violate the prohibition against undue discrimination by agreeing to a capacity reduction and early contract termination with the existing import shipper. In October 2017, the party filed a request for rehearing of the FERC order on remand. In August 2018, FERC issued its rehearing order affirming and clarifying its previous orders. No appeals were filed and FERC’s orders are final and no longer subject to further review. FERC FERC staff in the Office of Enforcement, Division of Investigations, conducted a non-public investigation of Virginia Power’s offers of combustion turbines generators into the PJM day-ahead markets from April 2010 through September 2014. FERC staff notified Virginia Power of its preliminary findings relating to Virginia Power’s alleged violation of FERC’s rules in connection with these activities. Virginia Power provided its response to FERC staff’s preliminary findings letter explaining why Virginia Power’s conduct was lawful and refuting any allegation of wrongdoing. This matter is pending. Virginia Power has recorded a liability of $14 million in its Consolidated Balance Sheet at December 31, 2018. Nuclear Matters In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as the Institute of Nuclear Power Operations. Like other U.S. nuclear operators, Dominion Energy has been gathering supporting data and participating in industry initiatives focused on the ability to respond to and mitigate the consequences of design-basis and beyond-design-basis events at its stations. In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3, with the Tier 1 recommendations consisting of actions which the staff determined should be started without unnecessary delay. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible. Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion Energy requiring implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation have been implemented. The information requests issued by the NRC request each reactor to reevaluate the seismic and external flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. The walkdowns of each unit have been completed, audited by the NRC and found to be adequate. Reevaluation of the emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevalua-tion of the seismic hazards was completed or in review with the NRC in 2018. Reevaluation of the external flooding hazards is expected to continue through 2019. Dominion Energy and Virginia Power do not currently expect that compliance with the NRC’s information requests will materially impact their financial position, results of operations or cash flows during the implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion Energy and Virginia Power do not expect material financial impacts related to compliance with Tier 2 and Tier 3 recommendations. Nuclear Operations NUCLEAR DECOMMISSIONING—MINIMUM FINANCIAL ASSURANCE The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 2018 calculation for the NRC minimum financial assurance amount, aggregated for Dominion Energy and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.7 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2018 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2018 U.S. Bureau of Labor Statistics indices. Dominion Energy believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion Energy and Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. See Note 9 for additional information on nuclear decommissioning trust investments. NUCLEAR INSURANCE The Price-Anderson Amendments Act of 1988 provides the public with liability protection on a per site, per nuclear incident basis, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. During the second quarter of 2018, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreased from $13.4 billion to $13.1 billion. During the fourth quarter of 2018, this amount increased from $13.1 billion to $14.1 billion. Dominion Energy and Virginia Power have purchased $450 million of coverage from commercial insurance pools for Millstone, Surry and North Anna with the remainder provided through the mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., Dominion Energy and Virginia Power could be assessed up to $138 million for each of their licensed reactors not to exceed $21 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The NRC granted an exemption in March 2015 to remove Kewaunee from the Secondary Financial Protection program. This same exemption permitted Dominion Energy to reduce Kewaunee’s required level of liability coverage to $100 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. The current levels of nuclear property insurance coverage for Dominion Energy and Virginia Power’s nuclear units are as follows:
|  | Coverage |
(billions) |  |  |  |
Dominion Energy |  |  |  |
Millstone |  | $ | 1.70 |
Kewaunee |  |  | 0.05 |
Virginia Power(1) |  |  |  |
Surry |  | $ | 1.70 |
North Anna |  |  | 1.70 |
(1) | Surry and North Anna share a blanket property limit of $200 million.
Dominion Energy and Virginia Power’s nuclear property insurance coverage for Millstone, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. In March 2015, the NRC granted an exemption which allowed Kewaunee to reduce its property insurance limit to $50 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion Energy and Virginia Power’s maximum retrospective premium assessment for the current policy period is $83 million and $51 million, respectively. Based on the severity of the incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion Energy and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination. Millstone and Virginia Power also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, Dominion Energy and Virginia Power are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion Energy and Virginia Power’s maximum retrospective premium assessment for the current policy period is $21 million and $10 million, respectively. ODEC, a part owner of North Anna, and Massachusetts Municipal and Green Mountain, part owners of Millstone’s Unit 3, are responsible to Dominion Energy and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance. SPENT NUCLEAR FUEL Dominion Energy and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by Dominion Energy and Virginia Power’s contracts with the DOE. Dominion Energy and Virginia Power have previously received damages award payments and settlement payments related to these contracts. By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone nuclear power stations have been extended to provide for periodic payments for damages incurred through December 31, 2019. In June 2018, a lawsuit for Kewaunee was filed in the U.S. Court of Federal Claims for recovery of spent nuclear fuel storage costs incurred for the period January 1, 2014 through December 31, 2017. This matter is pending. In 2018, Virginia Power and Dominion Energy received payments of $16 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2016 through December 31, 2016, and $13 million for resolution of claims incurred at Millstone for the period of July 1, 2016 through June 30, 2017. In 2017, Virginia Power and Dominion Energy received payments of $22 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2015 through December 31, 2015, and $14 million for resolution of claims incurred at Millstone for the period of July 1, 2015 through June 30, 2016. In 2016, Virginia Power and Dominion Energy received payments of $30 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2014 through December 31, 2014, and $22 million for resolution of claims incurred at Millstone for the period of July 1, 2014 through June 30, 2015. Dominion Energy and Virginia Power continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion Energy’s receivables for spent nuclear fuel-related costs totaled $49 million and $46 million at December 31, 2018 and 2017, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $30 million at both December 31, 2018 and 2017. Dominion Energy and Virginia Power will continue to manage their spent fuel until it is accepted by the DOE. Long-Term Purchase Agreements At December 31, 2018, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that a third party has used to secure financing for the facility that will provide the contracted goods or services:
|  | 2019 |  | 2020 |  | 2021 |  | 2022 |  | 2023 |  | Thereafter |  | Total
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchased electric capacity(1) |  |  | $ | 60 |  |  |  | $ | 52 |  |  |  | $ | 46 |  |  |  | $ | — |  |  |  | $ | — |  |  |  | $ | — |  |  |  | $ | 158 |
(1) | Commitments represent estimated amounts payable for capacity under power purchase contracts with independent power producers, which end in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad based economic indices. At December 31, 2018, the present value of Virginia Power’s total commitment for capacity payments is $142 million. Capacity payments totaled $50 million, $114 million and $248 million, and energy payments totaled $42 million, $72 million and $126 million for the years ended 2018, 2017 and 2016, respectively.
Lease Commitments The Companies lease real estate, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating leases that have initial or remaining lease terms in excess of one year as of December 31, 2018 are as follows:
|  | 2019 |  | 2020 |  | 2021 |  | 2022 |  | 2023 |  | Thereafter |  | Total
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  |  | $ | 64 |  |  |  | $ | 61 |  |  |  | $ | 55 |  |  |  | $ | 47 |  |  |  | $ | 38 |  |  |  | $ | 384 |  |  |  | $ | 649 |
Virginia Power |  |  |  | 34 |  |  |  |  | 32 |  |  |  |  | 28 |  |  |  |  | 22 |  |  |  |  | 16 |  |  |  |  | 106 |  |  |  |  | 238 |
Dominion Energy Gas |  |  |  | 12 |  |  |  |  | 11 |  |  |  |  | 9 |  |  |  |  | 7 |  |  |  |  | 4 |  |  |  |  | 3 |  |  |  |  | 46 |
Rental expense for Dominion Energy totaled $109 million, $113 million, and $104 million for 2018, 2017 and 2016, respectively. Rental expense for Virginia Power totaled $63 million, $57 million, and $52 million for 2018, 2017 and 2016, respectively. Rental expense for Dominion Energy Gas totaled $22 million, $34 million, and $37 million for 2018, 2017 and 2016, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income. In July 2016, Dominion Energy signed an agreement with a lessor to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $365 million, to fund the estimated project costs. The project is expected to be completed by mid-2019. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $281 million as of December 31, 2018. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion Energy could be required to pay up to 100% of the then funded amount. The five-year lease term will commence once construction is substantially complete and the facility is able to be occupied. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor, up to 87% of project costs, for the difference between the project costs and sale proceeds. Guarantees, Surety Bonds and Letters of Credit In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility, also entered in October 2017, with a stated maturity date of October 2021. Dominion Energy’s maximum potential loss exposure under the terms of the guarantee is limited to 48% of the outstanding borrowings under the revolving credit facility, an equal percentage to Dominion Energy’s ownership in Atlantic Coast Pipeline. As of December 31, 2018, Atlantic Coast Pipeline has borrowed $1.4 billion against the revolving credit facility and borrowed an additional $113 million in January and February 2019. Dominion Energy’s Consolidated Balance Sheet includes a liability of $21 million and $28 million associated with this guarantee agreement at December 31, 2018 and 2017, respectively. In addition, at December 31, 2018, Dominion Energy had issued an additional $48 million of guarantees, primarily to support other equity method investees. No amounts related to the other guarantees have been recorded. Dominion Energy also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion Energy would be obligated to satisfy such obligation. To the extent that a liability subject to a guarantee has been incurred by one of Dominion Energy’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion Energy is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion Energy currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations. At December 31, 2018, Dominion Energy had issued the following subsidiary guarantees:
|  | Maximum Exposure
(millions) |  |
Commodity transactions(1) |  |  | $ | 2,186 |
Nuclear obligations(2) |  |  |  | 179 |
Cove Point(3) |  |  |  | 1,900 |
Solar(4) |  |  |  | 659 |
Other(5) |  |  |  | 420 |
Total(6) |  |  | $ | 5,344 |
(1) | Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction related commodities and services.
(2) | Guarantees related to certain DGI subsidiaries’ regarding all aspects of running a nuclear facility.
(3) | Guarantees related to Cove Point, in support of terminal services, transportation and construction. Cove Point has two guarantees that have no maximum limit and, therefore, are not included in this amount.
(4) | Includes guarantees to facilitate the development of solar projects. Also includes guarantees entered into by DGI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.
(5) | Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Due to the uncertainty of worker’s compensation claims, the parental guarantee has no stated limit. Also included are guarantees related to certain DGI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of December 31, 2018, Dominion Energy’s maximum remaining cumulative exposure under these equity funding agreements is $4 million through 2019 and its maximum annual future contribution is approximately $4 million.
(6) | Excludes Dominion Energy’s guarantee for the construction of the new corporate office property discussed further within Lease Commitments above.
Additionally, at December 31, 2018, Dominion Energy had purchased $171 million of surety bonds, including $72 million at Virginia Power and $26 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $88 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid. Indemnifications As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2018, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.

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