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 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 litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations 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 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 financial position, liquidity or results of operations of the Companies.

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

In December 2011, the EPA issued MATS for coal and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance was required by April 16, 2015, with certain limited exceptions. However, in June 2014, the Virginia Department of Environmental Quality granted a one-year MATS compliance extension for two coal-fired units at Yorktown to defer planned retirements and allow for continued operation of the units to address reliability concerns while necessary electric transmission upgrades are being completed. These coal units will need to continue operating until at least April 2017 due to delays in transmission upgrades needed to maintain electric reliability, which based on assumptions about the timing for required agency actions and construction schedules are expected to be completed by no earlier than the second quarter of 2017. Therefore, in October 2015 Virginia Power submitted a request to the EPA for an additional one year compliance extension under an EPA Administrative Order.

In June 2015, the U.S. Supreme Court issued a decision holding that the EPA failed to take cost into account when the agency first decided to regulate the emissions from coal- and oil-fired plants, and remanded the MATS rule back to the D.C. Circuit Court. However, the Supreme Court did not vacate or stay the effective date and implementation of the MATS rule. On November 20, 2015, in response to the Supreme Court decision, the EPA proposed a supplemental finding that consideration of cost does not alter the agency’s previous conclusion that it is appropriate and necessary to regulate coal- and oil-fired electric utility steam generating units under Section 112 of the CAA. On December 15, 2015, the D.C. Court of Appeals issued an order remanding the MATS rulemaking proceeding back to the EPA without setting aside judgment, noting that EPA had represented it was on track to issue by April 15, 2016, a final finding regarding its consideration of cost. These actions do not change Virginia Power’s plans to close coal units at Yorktown or the need to complete necessary electricity transmission upgrades by 2017. Since the MATS rule remains in effect and Dominion is complying with the requirements of the rule, Dominion does not expect any adverse impacts to its operations at this time.

CAIR

The EPA established CAIR with the intent to require significant reductions in SO₂ and NO_Xemissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO₂ and NO_Xemissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO₂ and NO_X emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NO_X emissions caps, NO_X emissions caps during the ozone season (May 1 through September 30) and annual SO₂ emission caps with differing requirements for two groups of affected states.

CSAPR

Following numerous petitions by industry participants for review and a successful motion for stay, in October 2014, the U.S. Court of Appeals for the D.C. Circuit ordered that the EPA's motion to lift the stay of CSAPR be granted. Further, the Court granted the EPA's request to shift the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets (which would have gone into effect in 2012 and 2013) will apply in 2015 and 2016, and Phase 2 emissions budgets will apply in 2017 and beyond. CSAPR replaced CAIR beginning in January 2015. The cost to comply is not expected to be material to the Consolidated Financial Statements. Future outcomes of any additional litigation and/or any action to issue a revised rule could affect the assessment regarding cost of compliance.

Ozone Standards

In October 2015, the EPA issued a final rule tightening the ozone standard from 75-ppb to 70-ppb. The EPA is expected to complete attainment designations for a new standard by December 2017 and states will have until 2020 or 2021 to develop plans to address the new standard. Until the states have developed implementation plans, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significant expenditures are required to implement additional controls, it could adversely affect the Companies' results of operations and cash flows.

Hazardous Air Pollutants Standards

In August 2010, the EPA issued revised National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines, which was amended in March 2011 and January 2013. The rule establishes emission standards for control of hazardous air pollutants for engines at smaller facilities, known as area sources. As a result of these regulations, Dominion Gas has spent $2 million to install emissions controls on several compressor engines. Further capital spending is not expected to be material.

NSPS

In August 2012, the EPA issued the first NSPS impacting 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 September 2015, the EPA issued a proposed NSPS to regulate methane and VOC emissions from transmission and storage, gathering and boosting, production and processing facilities. All projects which commence construction after September 2015 will be required to comply with this regulation. Dominion is evaluating the proposed regulation and cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.

Methane Emissions

In January 2015, as part of its Climate Action Plan, the EPA announced plans to reduce methane emissions from the oil and gas sector including natural gas processing and transmission sources. In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR program, the Natural Gas STAR Methane Challenge Program. The proposed 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. Dominion is evaluating the proposed program and cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.

CLIMATE CHANGE LEGISLATION AND REGULATION

In October 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the D.C. Circuit Court’s June 2012 decision upholding the EPA’s regulation of GHG emissions from stationary sources under the CAA’s permitting programs. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the EPA’s ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting

for conventional pollutants. In July 2014, the EPA issued a memorandum specifying that it will no longer apply or enforce

federal regulations or EPA-approved PSD state implementation plan provisions that require new and modified stationary sources to obtain a PSD permit when GHGs are the only pollutant that would be emitted at levels that exceed the permitting thresholds. In August 2015, the EPA published a final rule rescinding the requirement for all new and modified major sources to obtain permits based solely on their GHG emissions. In addition, the EPA stated that it will continue to use the existing thresholds to apply to sources that are otherwise subject to PSD for conventional pollutants until it completes a new rulemaking either justifying and upholding those thresholds or setting new ones. Some states have issued interim guidance that follows the EPA guidance. Due to uncertainty regarding what additional actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the Court ruling under a new rulemaking, the Companies cannot predict the impact to their financial statements at this time.

In July 2011, the EPA signed a final rule deferring the need for PSD and Title V permitting for CO₂ emissions for biomass projects. This rule temporarily deferred for a period of up to three years 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. The deferral policy expired in July 2014. In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however, a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the CO₂ deferral period. It is unclear how the court’s decision or the EPA’s final policy regarding the treatment of specific feedstock will affect biomass sources that were permitted during the deferral period; however, the expenditures to comply with any new requirements could be material to Dominion’s and Virginia Power’s financial statements.

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 and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion 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's 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. Virginia Power has eight facilities that may be subject to additional wastewater treatment requirements associated with the final rule. The expenditures to comply with these new requirements are expected to be material.

SOLID AND HAZARDOUS WASTE

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, Virginia Power, or Dominion 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. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion, Virginia Power, or Dominion 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. Except as noted below, the Companies do not believe this will have a material effect on results of operations, financial condition and/or cash flows.

In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. In November 2011, Virginia Power and a number of other parties notified the EPA that they are declining to undertake the work set forth in the UAO.

The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO. Virginia Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter.

Dominion has determined that it is associated with 17 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion 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 is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. 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

Following the completion of the Appalachian Gateway project in 2012, DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DTI filed a complaint in U.S. District Court for the Eastern District of Virginia for breach of contract as well as accounting and declaratory relief. The contractor filed a motion to dismiss, or in the alternative, a motion to transfer venue to Pennsylvania and/or West Virginia, where the pipelines were constructed. DTI filed an opposition to the contractor’s motion in August 2013. In November 2013, the court granted the contractor’s motion on the basis that DTI must first comply with the dispute resolution process. In July 2015, the contractor filed a complaint against DTI in U.S. District Court for the Western District of Pennsylvania. In August 2015, DTI filed a motion to dismiss, or in the alternative, a motion to transfer venue to Virginia. This case is pending. DTI has accrued a liability of $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.

Ash Pond and Landfill Closure Costs

In September 2014, Virginia Power received a notice from the SELC on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at Possum Point. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point's historical and active ash storage facilities. A similar notice from the SELC on behalf of the Sierra Club was subsequently received related to Chesapeake. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum Point, Chesapeake and Bremo as settlement of the potential litigation. While the issue is open to potential further negotiations, the SELC declined the offer as presented in January 2015 and, in March 2015, filed a lawsuit related to its claims of the alleged CWA violations at Chesapeake. Virginia Power filed a motion to dismiss in April 2015, which was denied in November 2015. As a result of the December 2014 settlement offer, Virginia Power recognized a charge of $121 million in other operations and maintenance expense in its Consolidated Statements of Income in the Companies' Annual Report on Form 10-K for the year ended December 31, 2014.

In April 2015, the EPA's final rule regulating the management of CCRs stored in impoundments (ash ponds) and landfills was published in the Federal Register. The final rule regulates CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store CCRs. Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. The enactment of the final rule in April 2015 created a legal obligation for 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. Recognition of the ARO also resulted in a $99 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $166 million increase in property, plant, and equipment associated with asset retirement costs, and a $121 million reduction in other noncurrent liabilities related to reversal of the contingent liability described above since the ARO obligation created by the final CCR rule represents similar activities. Virginia Power is in the process of obtaining the necessary permits to complete the work. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the increased obligation in 2015.

Cove Point

Dominion is constructing the Liquefaction Project at the Cove Point facility, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project. In October 2014, several parties filed a motion with FERC to stay the order and requested rehearing. In May 2015, FERC denied the requests for stay and rehearing.

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 have been consolidated. Separately, one party requested a stay of the FERC order until the judicial proceedings are complete, which the court denied in June 2015.

In May 2014, the Maryland Commission granted the CPCN authorizing the construction of a generating station in connection with the Liquefaction Project. The CPCN obligates Cove Point to make payments totaling $48 million. These payments consist of $40 million to the Strategic Energy Investments Fund over a five-year period beginning in 2015 and $8 million to Maryland low income energy assistance programs over a twenty-year period expected to begin in 2018. In December 2014, upon receipt of applicable approvals to commence construction of the generating station, Dominion recorded the present value of the obligation as an increase to property, plant and equipment and a corresponding liability.

In June 2014, a party filed a notice of petition for judicial review of the CPCN with the Circuit Court for Baltimore City in Maryland. In September 2014, the party filed with the Maryland Commission a motion to stay the CPCN pending judicial review of the CPCN. In December 2014, the Circuit Court issued an order affirming the Maryland Commission’s grant of the CPCN and dismissing the appeal, and the motion for stay was denied by the Maryland Commission. In January 2015, the same party filed a Notice of Appeal of the Baltimore Circuit Court’s Order affirming the Maryland Commission’s grant of the CPCN with the Court of Special Appeals of Maryland. In February 2016, the Court of Special Appeals of Maryland issued an order affirming the judgment of the Circuit Court for Baltimore City in Maryland which affirmed the decision of the Maryland Commission granting the CPCN.

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 INPO. Like other U.S. nuclear operators, Dominion 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 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 seismic and external flooding hazards is expected to continue through 2018. Dominion 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 and Virginia Power are currently unable to estimate the potential 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 2015 calculation for the NRC minimum financial assurance amount, aggregated for Dominion's 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 $2.9 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 2015 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2015 U.S. Bureau of Labor Statistics indices. Dominion 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 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 up to $13.5 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. However, the NRC granted an exemption in March 2015 to remove Kewaunee from the Secondary Financial Protection program.

The current levels of nuclear property insurance coverage for Dominion's and Virginia Power's nuclear units is as follows:



	Coverage
(billions)
Dominion
Millstone	$	1.70
Kewaunee	1.06

Virginia Power⁽¹⁾
Surry	$	1.70
North Anna	1.70


(1)	Surry and North Anna share a blanket property limit of $200 million.

Dominion's 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. Kewaunee meets the NRC minimum requirement of $1.06 billion. 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's and Virginia Power's maximum retrospective premium assessment for the current policy period is $84 million and $48 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 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 and Virginia Power are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion's and Virginia Power's maximum retrospective premium assessment for the current policy period is $23 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 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 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's and Virginia Power's contracts with the DOE. Dominion and Virginia Power have previously received damages award payments and settlement payments related to these contracts.

In 2012, Dominion and Virginia Power resolved additional claims for damages incurred at Millstone, Kewaunee, Surry and North Anna with the Authorized Representative of the Attorney General. Dominion and Virginia Power entered into settlement agreements that resolved claims for damages incurred through December 31, 2010, and also provided for periodic payments after that date for damages incurred through December 31, 2013.

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 plants have been extended to provide for periodic payments for damages incurred through December 31, 2016. Possible extension of the Kewaunee settlement agreement is being evaluated.

In 2015, Virginia Power and Dominion received payments of $8 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2013 through December 31, 2013, and $17 million for resolution of claims incurred at Millstone for the period of July 1, 2013 through June 30, 2014.

In 2014, Virginia Power and Dominion received payments of $27 million for the resolution of claims incurred at North Anna and Surry for the period January 1, 2011 through December 31, 2012 and $17 million for the resolution of claims incurred at Millstone for the period of July 1, 2012 through June 30, 2013. In 2014, Dominion also received payments totaling $7 million for the resolution of claims incurred at Kewaunee for periods from January 1, 2011 through December 31, 2013.

Dominion 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's receivables for spent nuclear fuel-related costs totaled $87 million and $69 million at December 31, 2015 and 2014, respectively. Virginia Power's receivables for spent nuclear fuel-related costs totaled $54 million and $41 million at December 31, 2015 and 2014, respectively.

Pursuant to a November 2013 decision of the U.S Court of Appeals for the D.C. Circuit, in January 2014 the Secretary of the DOE sent a recommendation to the U.S. Congress to adjust to zero the current fee of $1 per MWh for electricity paid by civilian nuclear power generators for disposal of spent nuclear fuel. The processes specified in the Nuclear Waste Policy Act for adjustment of the fee have been completed, and as of May 2014, Dominion and Virginia Power are no longer required to pay the waste fee. In 2014, Dominion and Virginia Power recognized fees of $16 million and $10 million, respectively.

Dominion and Virginia Power will continue to manage their spent fuel until it is accepted by the DOE.

Long-Term Purchase Agreements

At December 31, 2015, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:



	2016		2017		2018		2019		2020		Thereafter		Total
(millions)
Purchased electric capacity⁽¹⁾	$	249	$	157	$	104	$	65	$	52	$	46	$	673

(1)

Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends 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, 2015, the present value of Virginia Power's total commitment for capacity payments is $577 million. Capacity payments totaled $305 million, $330 million, and $345 million, and energy payments totaled $198 million, $304 million, and $236 million for the years ended 2015, 2014 and 2013, respectively.

Lease Commitments

The Companies' lease various facilities, 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 and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2015 are as follows:



	2016		2017		2018		2019		2020		Thereafter		Total
(millions)
Dominion	$	67	$	62	$	54	$	43	$	25	$	153	$	404

Virginia Power	$	30	$	27	$	23	$	17	$	14	$	27	$	138

Dominion Gas	$	26	$	25	$	23	$	18	$	6	$	19	$	117

Rental expense for Dominion totaled $99 million, $92 million, and $101 million for 2015, 2014 and 2013, respectively. Rental expense for Virginia Power totaled $51 million, $43 million, and $42 million for 2015, 2014, and 2013, respectively. Rental expense for Dominion Gas totaled $37 million, $35 million, and $15 million for 2015, 2014 and 2013, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.

Guarantees, Surety Bonds and Letters of Credit

At December 31, 2015, Dominion had issued $74 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2015, Dominion's exposure under these guarantees was $39 million, primarily related to certain reserve requirements associated with non-recourse financing.

Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion's consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion 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 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, 2015, Dominion had issued the following subsidiary guarantees:



	Stated Limit		Value⁽¹⁾
(millions)
Subsidiary debt⁽²⁾	$	27	$	27
Commodity transactions⁽³⁾	2,371		932
Nuclear obligations⁽⁴⁾	184		75
Cove Point⁽⁵⁾	1,910		—
Solar⁽⁶⁾	1,555		647
Other⁽⁷⁾	515		31
Total	$	6,562	$	1,712


(1)	Represents the estimated portion of the guarantee's stated limit that is utilized as of December 31, 2015 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.


(2)	Guarantee of debt of a DEI subsidiary. In the event of default by the subsidiary, Dominion would be obligated to repay such amounts.

(3)

Guarantees related to commodity commitments of certain subsidiaries, including subsidiaries of Virginia Power, Dominion Gas and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion would be obligated to satisfy such obligation. Dominion and its subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits.

(4)

Guarantees related to certain DEI subsidiaries' potential retrospective premiums that could be assessed if there is a nuclear incident under Dominion's nuclear insurance programs and guarantees for a DEI subsidiary's and Virginia Power's commitment to buy nuclear fuel. Excludes Dominion's agreement to provide up to $150 million and $60 million to two DEI subsidiaries to pay the operating expenses of Millstone (in the event of a prolonged outage) and Kewaunee, respectively, as part of satisfying certain NRC requirements concerned with ensuring adequate funding for the operations of nuclear power stations. The agreement for Kewaunee also provides for funds through the completion of decommissioning.


(5)	Guarantees related to Cove Point, in support of terminal services, transportation and construction. Two of the guarantees have no stated limit, one guarantee has a $150 million limit, and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million.


(6)	Includes guarantees to facilitate the development of solar projects including guarantees that do not have stated limits. Also includes guarantees entered into by DEI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.

(7)

Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries' obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of December 31, 2015, Dominion's maximum remaining cumulative exposure under these equity funding agreements is $55 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits.

Additionally, at December 31, 2015, Dominion had purchased $92 million of surety bonds, including $34 million at Virginia Power and $23 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $59 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.

As of December 31, 2015, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. The related debt matures in 2031 and is included in long-term debt in Virginia Power's Consolidated Balance Sheets. In the event of default by a conduit, Virginia Power would be obligated to repay such amounts, which are limited to the principal and interest then outstanding.

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, 2015, 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.