Item 1. Business
GENERAL
Dominion Energy, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s strategy is to be a leading sustainable provider of electricity, natural gas and related services to customers primarily in the eastern and Rocky Mountain regions of the U.S. As of December 31, 2018, Dominion Energy’s portfolio of assets included approximately 26,000 MW of electric generating capacity, 6,700 miles of electric transmission lines, 58,300 miles of electric distribution lines, 14,800 miles of natural gas transmission, gathering and storage pipelines and 52,300 miles of gas distribution pipeline, exclusive of service lines. As of December 31, 2018, Dominion Energy served more than 5 million utility and retail energy customers and operated one of the nation’s largest underground natural gas storage systems, with approximately 1 trillion cubic feet of storage capacity.
In January 2019, Dominion Energy completed the SCANA Combination in a stock-for-stock merger valued at $13.4 billion. SCANA is primarily engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. In addition, SCANA markets natural gas to retail customers in the southeast U.S. Following the completion of the SCANA Combination, Dominion Energy’s portfolio of assets includes approximately 32,000 MW of electric generating capacity, 10,200 miles of electric transmission lines, 84,800 miles of electric distribution lines, 15,900 miles of natural gas transmission, gathering and storage pipelines and 92,900 miles of gas distribution pipeline, exclusive of service lines. Dominion Energy operates approximately 1 trillion cubic feet of natural gas storage capacity and serves nearly 7.5 million utility and retail energy customers. SCANA operates as a wholly-owned subsidiary of Dominion Energy. SCANA and one of its wholly-owned subsidiaries, SCE&G, are currently SEC registrants. SCANA and SCE&G file a combined Form 10-K, which is not combined herein.
Dominion Energy continues to focus on expanding and improving its regulated and long-term contracted electric and natural gas businesses while transitioning to a cleaner energy future. The capital investment program for 2019 through 2023 includes a focus on upgrading the electric grid in Virginia through investments in additional renewable generation facilities, strategic undergrounding, energy conservation programs and smart-grid devices. Renewable generation facilities are expected to include investments in utility-scale solar and offshore wind projects. In addition, Dominion Energy is currently seeking, or intends to seek, license extensions for its regulated nuclear power stations in Virginia. Other drivers for the capital investment program include the construction of infrastructure to handle the increase in natural gas production from the Marcellus and Utica Shale formations, including investing in Atlantic Coast Pipeline which is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, to increase natural gas supplies in the region. Dominion Energy also plans to upgrade its gas and electric transmission and distribution networks and meet environmental requirements and standards set by various regulatory bodies.
Dominion Energy has transitioned over the past decade to a more regulated, less volatile earnings mix as evidenced by its capital investments in regulated infrastructure, including the SCANA Combination and Dominion Energy Questar Combination, and in infrastructure whose output is sold under long-term purchase agreements, as well as the sales of certain merchant generating facilities and equity method investments in 2018 and the electric retail energy marketing business in March 2014. Dominion Energy expects approximately 95% of earnings from its primary operating segments to come from regulated and long-term contracted businesses. Dominion Energy’s nonregulated operations include merchant generation, energy marketing and price risk management activities and natural gas retail energy marketing operations. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas.
Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a wholly-owned subsidiary of Dominion Energy and a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina. In Virginia, Virginia Power conducts business under the name “Dominion Energy Virginia” and primarily serves retail customers. In North Carolina, it conducts business under the name “Dominion Energy North Carolina” and serves retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, Virginia Power sells and transmits electricity at wholesale prices to rural electric cooperatives, municipalities and into wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion Energy.
Dominion Energy Gas, a limited liability company formed in September 2013, is a wholly-owned subsidiary of Dominion Energy and a holding company. It serves as the intermediate parent company for certain of Dominion Energy’s regulated natural gas operating subsidiaries, which conduct business activities through a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution operations in Ohio, and gas gathering and processing activities primarily in West Virginia, Ohio and Pennsylvania. Dominion Energy Gas’ principal wholly-owned subsidiaries are DETI, East Ohio, DGP and Dominion Iroquois. DETI is an interstate natural gas transmission pipeline company serving a broad mix of customers such as local gas distribution companies, marketers, interstate and intrastate pipelines, electric power generators and natural gas producers. The DETI system links to other major pipelines and markets in the mid-Atlantic, Northeast, and Midwest including Dominion Energy’s Cove Point Pipeline. DETI also operates one of the largest underground natural gas storage systems in the U.S. In August 2016, DETI transferred its gathering and processing facilities to DGP. East Ohio is a regulated natural gas distribution operation serving residential, commercial and industrial gas sales and transportation customers. Its service territory includes Cleveland, Akron, Canton, Youngstown and other eastern and western Ohio communities. At December 31, 2018, Dominion Energy Gas holds a 24.07% noncontrolling partnership interest in Iroquois, a FERC-regulated interstate natural gas pipeline in New York and Connecticut. All of Dominion Energy Gas’ membership interests are owned by Dominion Energy.
Amounts and information disclosed for Dominion Energy are inclusive of Virginia Power and/or Dominion Energy Gas, where applicable.
EMPLOYEES
Immediately following the SCANA Combination, Dominion Energy had approximately 21,300 full-time employees, of which approximately 6,200 are subject to collective bargaining agreements, including approximately 6,800 full-time employees at Virginia Power, of which approximately 2,900 are subject to collective bargaining agreements and approximately 3,100 full-time employees at Dominion Energy Gas, of which approximately 2,100 are subject to collective bargaining agreements.
WHERE YOU CAN FIND MORE INFORMATION ABOUT THE COMPANIES
The Companies file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov.
The Companies make their SEC filings available, free of charge, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, through Dominion Energy’s website, http://www.dominionenergy.com, as soon as reasonably practicable after filing or furnishing the material to the SEC. Information contained on Dominion Energy’s website, including but not limited to reports mentioned in Environmental Strategy, is not incorporated by reference in this report.
ACQUISITIONS AND DISPOSITIONS
The following are significant acquisitions and divestitures by the Companies during the last five years.
ACQUISITION OF SCANA
In January 2019, Dominion Energy and SCANA completed a stock-for-stock merger valued at $13.4 billion, inclusive of SCANA’s outstanding debt, which totaled $6.9 billion at closing. Following completion of the SCANA Combination, SCANA operates as a wholly-owned subsidiary of Dominion Energy. In connection with the SCANA Combination, SCE&G will provide refunds and restitution of $2.0 billion over 20 years with capital support from Dominion Energy that, along with the benefit of the 2017 Tax Reform Act, is expected to result in an approximate 15% reduction to SCE&G electric service customers’ bills, compared to May 2017, as well as exclude from rate recovery $2.4 billion of costs related to the NND Project and $180 million of costs associated with the purchase of the Columbia Energy Center power station. See Note 3 to the Consolidated Financial Statements for additional information.
PURCHASE OF DOMINION ENERGY MIDSTREAM UNITS
In January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned
by Dominion Energy through the issuance of 22.5 million common shares. See Note 19 to the Consolidated Financial Statements for additional information.
SALE OF CERTAIN MERCHANT GENERATION FACILITIES
In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. See Note 10 to the Consolidated Financial Statements for additional information.
SALE OF INTEREST IN BLUE RACER
In December 2018, Dominion Energy completed the sale of its 50% limited partner interest in Blue Racer for total consideration of $1.2 billion. In addition, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. See Note 9 to the Consolidated Financial Statements for additional information.
ACQUISITION OF DOMINION ENERGY QUESTAR
In September 2016, Dominion Energy completed the Dominion Energy Questar Combination for total consideration of $4.4 billion and Dominion Energy Questar became a wholly-owned subsidiary of Dominion Energy. See Note 3 to the Consolidated Financial Statements for additional information.
ACQUISITION OF WHOLLY-OWNED MERCHANT SOLAR PROJECTS
Throughout 2017, Dominion Energy completed the acquisition of various wholly-owned merchant solar projects in California, North Carolina and Virginia for $356 million. The projects cost $541 million to construct, including the initial acquisition cost, and generate 259 MW.
Throughout 2016, Dominion Energy completed the acquisition of various wholly-owned merchant solar projects in North Carolina, South Carolina and Virginia for $32 million. The projects cost $421 million to construct, including the initial acquisition cost, and generate 221 MW.
Throughout 2015, Dominion Energy completed the acquisition of various wholly-owned merchant solar projects in California and Virginia for $381 million. The projects cost $588 million to construct, including the initial acquisition cost, and generate 182 MW.
Throughout 2014, Dominion Energy completed the acquisition of various wholly-owned solar development projects in California for $200 million. The projects cost $578 million to construct, including the initial acquisition cost, and generate 179 MW.
See Note 3 to the Consolidated Financial Statements for additional information.
ACQUISITION OF VIRGINIA POWER SOLAR PROJECTS
In 2018, Virginia Power entered into agreements to acquire two solar development projects in North Carolina and Virginia. The projects are expected to close in 2019 and 2020 with a total expected cost of $250 million once constructed, including the initial acquisition cost, and will generate approximately 155 MW combined.
In 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The first proj-
ect closed in 2018 and the second is expected to close in 2019 with a total expected cost of $280 million once constructed, including the initial acquisition cost, and will generate approximately 155 MW combined.
See Note 10 to the Consolidated Financial Statements for additional information.
SALE OF CERTAIN RETAIL ENERGY MARKETING ASSETS
In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations for total consideration of $143 million, subject to customary approvals and certain adjustments. In December 2017, the first phase of the agreement closed for $79 million. In October 2018, the second phase of the agreement closed for $63 million. Pursuant to the agreement, Dominion Energy entered into a commission agreement with the buyer upon the first closing in December 2017, under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a ten-year term. See Note 10 to the Consolidated Financial Statements for additional information.
ASSIGNMENT OF TOWER RENTAL PORTFOLIO
Virginia Power rents space on certain of its electric transmission towers to various wireless carriers for communications antennas and other equipment. In March 2017, Virginia Power sold its rental portfolio to Vertical Bridge Towers II, LLC for $91 million in cash. See Note 10 to the Consolidated Financial Statements for additional information.
ACQUISITION OF NON-WHOLLY-OWNED MERCHANT SOLAR PROJECTS
In 2015, Dominion Energy acquired 50% of the units in Four Brothers and Three Cedars from SunEdison for $107 million. In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison. In August 2018, NRG’s ownership in Four Brothers and Three Cedars was transferred to GIP. The facilities began commercial operations in the third quarter of 2016, with generating capacity of 530 MW, at a cost of $1.1 billion. See Note 3 to the Consolidated Financial Statements for additional information.
SALE OF INTEREST IN MERCHANT SOLAR PROJECTS
In September 2015, Dominion Energy signed an agreement to sell a noncontrolling interest (consisting of 33% of the equity interests) in all of its then wholly-owned merchant solar projects, 24 solar projects totaling 425 MW, to SunEdison. In December 2015, the sale of interest in 15 of the solar projects closed for $184 million with the sale of interest in the remaining projects completed in January 2016 for $117 million. Upon closing, SunEdison sold its interest in these projects to Terra Nova Renewable Partners. See Note 3 to the Consolidated Financial Statements for additional information.
DOMINION ENERGY MIDSTREAM ACQUISITION OF INTEREST IN IROQUOIS
In September 2015, Dominion Energy Midstream acquired from NG and NJNR a 25.93% noncontrolling partnership interest in Iroquois. The investment was recorded at $216 million based on
the value of Dominion Energy Midstream’s common units at closing. The common units issued to NG and NJNR are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements.
ACQUISITION OF DECG
In January 2015, Dominion Energy completed the acquisition of 100% of the equity interests of DECG from SCANA for $497 million in cash, as adjusted for working capital.
ASSIGNMENTS OF SHALE DEVELOPMENT RIGHTS
In December 2013, Dominion Energy Gas closed on agreements with natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several natural gas storage fields. The agreements provided for payments to Dominion Energy Gas, subject to customary adjustments, of up to approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from that acreage. In March 2015, Dominion Energy Gas and a natural gas producer closed on an amendment to a December 2013 agreement, which included the immediate conveyance of approximately 9,000 acres of Marcellus Shale development rights and a two-year extension of the term of the original agreement. The conveyance of development rights resulted in the recognition of $43 million of previously deferred revenue. In April 2016, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of a 32% partial interest in the remaining approximately 70,000 acres. This conveyance resulted in the recognition of the remaining $35 million of previously deferred revenue. In August 2017, Dominion Energy Gas and a natural gas producer signed an amendment to the agreement, which included the finalization of contractual matters on previous conveyances, the conveyance of Dominion Energy Gas’ remaining 68% interest in approximately 70,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. As a result of this amendment, Dominion Energy Gas received total consideration of $130 million, with $65 million received in November 2017 and $65 million received in September 2018 in connection with the final conveyance.
In March 2015, Dominion Energy Gas conveyed to a natural gas producer approximately 11,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields and received proceeds of $27 million and an overriding royalty interest in gas produced from the acreage.
In September 2015, Dominion Energy Gas closed on an agreement with a natural gas producer to convey approximately 16,000 acres of Utica and Point Pleasant Shale development rights underneath one of its natural gas storage fields. The agreement provided for a payment to Dominion Energy Gas, subject to customary adjustments, of $52 million and an overriding royalty interest in gas produced from the acreage.
In November 2014, Dominion Energy Gas closed on an agreement with a natural gas producer to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas
produced from the acreage. In January 2018, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the conveyance of Dominion Energy Gas’ remaining 50% interest in approximately 18,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage for proceeds of $28 million.
See Note 10 to the Consolidated Financial Statements for additional information on certain of these sales of Marcellus acreage.
SALE OF ELECTRIC RETAIL ENERGY MARKETING BUSINESS
In March 2014, Dominion Energy completed the sale of its electric retail energy marketing business. The proceeds were $187 million, net of transaction costs.
SALE OF PIPELINES AND PIPELINE SYSTEMS
In March 2014, Dominion Energy Gas sold the Northern System to an affiliate that subsequently sold the Northern System to Blue Racer for consideration of $84 million. Dominion Energy Gas’ consideration consisted of $17 million in cash proceeds and the extinguishment of affiliated current borrowings of $67 million and Dominion Energy’s consideration consisted of cash proceeds of $84 million.
OPERATING SEGMENTS
Effective January 2019, Dominion Energy manages its daily operations through four primary operating segments: Power Delivery, Power Generation, Gas Infrastructure and Southeast Energy. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s other operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.
Virginia Power manages its daily operations through two primary operating segments: Power Delivery and Power Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.
Dominion Energy Gas manages its daily operations through its primary operating segment: Gas Infrastructure. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources and the effect of certain items recorded at Dominion Energy Gas as a result of Dominion Energy’s basis in the net assets contributed.
While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by the Companies and their respective legal subsidiaries.
A description of the operations included in the Companies’ primary operating segments is as follows:
(1) Includes remaining producer services activities.
(2) Consists of the operations of SCANA.
Power Delivery
The Power Delivery Operating Segment of Dominion Energy and Virginia Power includes Virginia Power’s regulated electric transmission and distribution (including customer service) operations, which serve approximately 2.6 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.
Power Delivery’s investment plan includes spending approximately $10.0 billion from 2019 through 2023 to upgrade or add new transmission, including RTEP projects, and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability and regulatory compliance. The proposed electric delivery infrastructure projects are intended to address both continued customer growth and increases in electricity consumption which are partially driven by new and larger data center customers. Additionally, Power Delivery has created a ten-year plan to transform its electric grid into a smarter, stronger and greener grid. This plan will address the structural limitations of Virginia Power’s distribution grid in a systematic manner in order to recognize and accommodate fundamental changes and requirements in the energy industry. The objective is to address both customer and system needs by (i) achieving even higher levels of reliability and resiliency against natural and man-made threats, (ii) leveraging technology to enhance the customer experience and improve the
operation of the system and (iii) safely and effectively integrating new utility-scale renewable generation and storage as well as customer-level distributed energy resources such as rooftop solar and battery storage.
Revenue provided by electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Approximately 85% of revenue comes from serving Virginia jurisdictional customers. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures. Operationally, electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 134 minutes for the three- year average ending 2018, up from the previous three-year average of 125 minutes primarily due to increased storm activity during the year. In the future, safety, electric service reliability, outage durations and customer service will remain key focus areas for electric distribution.
Revenue provided by Virginia Power’s electric transmission operations is based primarily on rates approved by FERC. The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings primarily results from changes in rates and the timing of property additions, retirements and depreciation.
Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to NERC by EPACT, Virginia Power’s electric transmission operations are committed to meeting NERC standards, modernizing its infrastructure and maintaining superior system reliability. Virginia Power’s electric transmission operations will continue to focus on safety, operational performance, NERC compliance and execution of PJM’s RTEP.
COMPETITION
There is no competition for electric distribution service within Virginia Power’s service territory in Virginia and North Carolina and no such competition is currently permitted. Historically, since its electric transmission facilities are integrated into PJM and electric transmission services are administered by PJM, there was no competition in relation to transmission service provided to customers within the PJM region. However, competition from non-incumbent PJM transmission owners for development, construction and ownership of certain transmission facilities in Virginia Power’s service territory is permitted pursuant to Order 1000, subject to state and local siting and permitting approvals. This could result in additional competition to build and own transmission infrastructure in Virginia Power’s service area in the future and could allow Dominion Energy to seek opportunities to build and own facilities in other service territories.
REGULATION
Virginia Power’s electric distribution service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia and North Carolina Commissions. Virginia Power’s wholesale electric transmission rates, tariffs and terms of service
are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. See State Regulations and Federal Regulations in Regulation and Note 13 to the Consolidated Financial Statements for additional information.
PROPERTIES
For a description of Dominion Energy and Virginia Power’s existing transmission facilities see Item 2. Properties.
As a part of PJM’s RTEP process, PJM authorized the following material reliability projects (including Virginia Power’s estimated cost):
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Surry-to-Skiffes Creek-to-Whealton ($435 million);
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Idylwood substation ($110 million);
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Dooms-to-Lexington ($130 million);
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Warrenton (including Remington CT-to-Warrenton, Vint Hill-to-Wheeler-to-Gainesville, and Vint Hill and Wheeler switching stations) ($120 million);
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Remington/Gordonsville/Pratts Area Improvement (including Remington-to-Gordonsville, and new Gordonsville substation transformer) ($115 million);
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Gainesville-to-Haymarket ($180 million);
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Cunningham-to-Dooms ($65 million);
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Carson-to-Rogers Road ($55 million);
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Dooms-to-Valley ($65 million);
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Mt. Storm-to-Valley ($285 million);
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Glebe substation and North Potomac Yard terminal station underground ($125 million); and
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Idylwood-to-Tysons ($125 million).
In addition, in December 2017, the Virginia Commission granted Virginia Power a CPCN to rebuild and operate in Lancaster County, Virginia and Middlesex County, Virginia, approximately 2 miles of existing 115 kV transmission lines to be constructed under the Rappahannock River between Harmony Village Substation and White Stone Substation. The total estimated cost of the project is approximately $105 million.
Virginia Power is investing in transmission substation physical security and expects to invest an additional $150 million to $200 million through 2023 to strengthen its electrical system to better protect critical equipment, enhance its spare equipment process and create multiple levels of security.
For a description of Dominion Energy and Virginia Power’s existing distribution facilities see Item 2. Properties.
Virginia legislation provides for the recovery of costs, subject to approval by the Virginia Commission, for Virginia Power to move approximately 4,000 miles of electric distribution lines underground. The program is designed to reduce restoration outage time by moving Virginia Power’s most outage-prone overhead distribution lines underground, has an annual investment cap of approximately $175 million and is expected to be completed by 2028. The Virginia Commission has approved three phases of the program encompassing approximately 1,100 miles of converted lines and $422 million in capital spending (with $404 million recoverable through Rider U).
See Note 13 to the Consolidated Financial Statements for more information.
SOURCES OF ENERGY SUPPLY
Power Delivery’s supply of electricity to serve Virginia Power customers is produced or procured by Power Generation. See Power Generation for additional information.
SEASONALITY
Power Delivery’s earnings vary seasonally as a result of the impact of changes in temperature, the impact of storms and other catastrophic weather events, and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, respectively. An increase in heating degree days for Power Delivery’s electric utility-related operations does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
Power Generation
The Power Generation Operating Segment of Virginia Power includes the generation operations of the Virginia Power regulated electric utility and its related energy supply operations. Virginia Power’s utility generation operations primarily serve the supply requirements for Power Delivery’s utility customers. Virginia Power’s non-jurisdictional operations serve certain large-scale customers.
The Power Generation Operating Segment of Dominion Energy includes Virginia Power’s generation facilities and its related energy supply operations as well as the generation operations of Dominion Energy’s merchant fleet and energy marketing and price risk management activities for these assets.
Power Generation’s investment plan includes spending approximately $10.3 billion from 2019 through 2023 to maintain existing and construct new generation capacity to meet growing electricity demand within its service territory and maintain reliability. The most significant investments are expanding the renewable generation asset portfolio and the subsequent license renewal projects seeking 20-year license extensions for the regulated nuclear power stations in Virginia. See Properties and Environmental Strategy for additional information on this and other utility projects.
In addition, Dominion Energy’s merchant generation fleet includes numerous renewable generation facilities, including solar generation and wind facilities in operation or development in ten states, including Virginia. The output of these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. See Notes 3 and 10 to the Consolidated Financial Statements for additional information regarding certain solar projects.
Earnings for the Power Generation Operating Segment of Virginia Power primarily result from the sale of electricity generated by its utility fleet. Revenue is based primarily on rates established by state regulatory authorities and state law. Approximately 76% of revenue comes from serving Virginia jurisdictional customers. Base rates for the Virginia jurisdiction are set using a modified cost-of-service rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. Earnings variability may arise when revenues are impacted by
factors not reflected in current rates, such as the impact of weather on customers’ demand for services. Likewise, earnings may reflect variations in the timing or nature of expenses as compared to those contemplated in current rates, such as labor and benefit costs, capacity expenses, and the timing, duration and costs of scheduled and unscheduled outages. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. The cost of new generation facilities is generally recovered through rate adjustment clauses in Virginia. Variability in earnings from rate adjustment clauses reflects changes in the authorized ROE and the carrying amount of these facilities, which are largely driven by the timing and amount of capital investments, as well as depreciation. See Note 13 to the Consolidated Financial Statements for additional information.
The Power Generation Operating Segment of Dominion Energy derives its earnings primarily from the sale of electricity generated by Virginia Power’s utility and Dominion Energy’s merchant generation assets, as well as from associated capacity and ancillary services. Variability in earnings provided by Dominion Energy’s nonrenewable merchant assets relates to changes in market-based prices received for electricity and capacity. Market-based prices for electricity are largely dependent on commodity prices and the demand for electricity. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion Energy manages the electric price volatility of its merchant generation fleet by hedging a substantial portion of its expected near-term energy sales with derivative instruments. Variability also results from changes in weather, the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages.
COMPETITION
Power Generation Operating Segment-Dominion Energy and Virginia Power
Virginia Power’s generation operations are not subject to significant competition as only a limited number of its Virginia jurisdictional electric utility customers have retail choice. See Electric under State Regulations in Regulation for more information. Currently, North Carolina does not offer retail choice to electric customers.
Virginia Power’s non-jurisdictional operations are not currently subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 16 to 25 years. However, in the future, such operations may compete with other power generation facilities to serve certain large-scale customers after the power purchase agreements expire.
Power Generation Operating Segment-Dominion Energy
Power Generation’s renewable generation projects are not currently subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. Competition for the merchant fleet is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological
advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact the merchant fleet’s ability to profit from the sale of electricity and related products and services.
Unlike Power Generation’s regulated generation fleet, its merchant generation fleet is dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that provides for a rate of return on its capital investments. Power Generation’s nonrenewable merchant assets operate within functioning RTOs and primarily compete on the basis of price. Competitors include other generating assets bidding to operate within the RTOs. Power Generation’s nonrenewable merchant units compete in the wholesale market with other generators to sell a variety of products including energy, capacity and ancillary services. It is difficult to compare various types of generation given the wide range of fuels, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, Dominion Energy applies its expertise in operations, dispatch and risk management to maximize the degree to which its nonrenewable merchant fleet is competitive compared to similar assets within the region.
In November 2017, Connecticut adopted the Act Concerning Zero Carbon Solicitation and Procurement, which allows nuclear generating facilities to compete for power purchase agreements in a state sponsored procurement for electricity. In February 2018, Connecticut regulators recommended pursuing the procurement and, in May 2018, issued a request for proposals. Millstone participated in the state sponsored procurement for electricity. In December 2018, Connecticut’s Public Utility Regulatory Authority confirmed that Millstone should be considered an “existing resource confirmed at risk” in the state’s Department of Energy and Environmental Protection zero carbon procurement. Being considered “at risk” allows the Department of Energy and Environmental Protection to consider factors other than price, such as environmental and economic benefits, when evaluating Dominion Energy’s bids. Also in December 2018, Millstone was awarded the right to negotiate a ten-year agreement for nine million MWh per year. Dominion Energy continues to engage with applicable parties in Connecticut to ensure pricing that recognizes Millstone’s environmental and economic benefits.
REGULATION
Virginia Power and Dominion Energy’s generation fleet are subject to regulation by FERC, the NRC, the EPA, the DOE, the Army Corps of Engineers and other federal, state and local authorities. Virginia Power’s utility generation fleet is also subject to regulation by the Virginia and North Carolina Commissions. See Regulation, Future Issues and Other Matters in Item 7. MD&A and Notes 13 and 22 to the Consolidated Financial Statements for more information.
PROPERTIES
For a listing of Dominion Energy and Virginia Power’s existing generation facilities, see Item 2. Properties.
Virginia Power is developing, financing and constructing new generation capacity to meet growing electricity demand within its service territory. Significant projects under construction or development are set forth below:
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Virginia Power plans to acquire or construct certain solar facilities in Virginia and North Carolina. See Notes 10 and 13 to the Consolidated Financial Statements for more information.
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Virginia Power continues to consider the construction of a third nuclear unit at a site located at North Anna. See Future Issues and Other Matters in Item 7 for more information on this project.
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Virginia Power is considering the construction of an up to $2 billion hydroelectric pumped storage facility in Southwest Virginia.
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In November 2018, Virginia Power received approval from the Virginia Commission to develop two 6 MW wind turbines off the coast of Virginia for the Coastal Virginia Offshore Wind project. The project is expected to cost approximately $300 million and to be in service in late 2020.
SOURCES OF ENERGY SUPPLY
Power Generation Operating Segment-Dominion Energy and Virginia Power
Power Generation uses a variety of fuels to power its electric generation and purchases power for utility system load requirements and to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are included as contractual obligations in Future Cash Payments for Contractual Obligations and Planned Capital Expenditures in Item 7. MD&A.
Nuclear Fuel-Power Generation primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.
Fossil Fuel-Power Generation primarily utilizes natural gas and coal in its fossil fuel plants. All recent fossil fuel plant construction for Power Generation involves natural gas generation.
Power Generation’s natural gas and oil supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, purchases from local producers in the Appalachian area and Marcellus and Utica regions, purchases from gas marketers and withdrawals from underground storage fields owned by Dominion Energy or third parties. Power Generation manages a portfolio of natural gas transportation contracts (capacity) that provides for reliable natural gas deliveries to its gas turbine fleet, while minimizing costs.
Power Generation’s coal supply is obtained through long-term contracts and short-term spot agreements from domestic suppliers.
Biomass-Power Generation’s biomass supply is obtained through long-term contracts and short-term spot agreements from local suppliers.
Purchased Power-Power Generation purchases electricity from the PJM spot market and through power purchase agree-
ments with other suppliers to provide for utility system load requirements.
Power Generation also occasionally purchases electricity from the ISO-NE spot market to satisfy physical forward sale requirements as part of its merchant generation operations.
Power Generation Operating Segment-Virginia Power
Presented below is a summary of Virginia Power’s actual system output by energy source:
(1) Excludes ODEC’s 11.6% ownership interest in North Anna.
(2) Excludes ODEC’s 50.0% ownership interest in the Clover power station.
(3) Includes oil, hydro, biomass and solar.
SEASONALITY
Power Generation Operating Segment-Dominion Energy and Virginia Power
Sales of electricity for Power Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. See Power Delivery-Seasonality above for additional considerations that also apply to Power Generation.
NUCLEAR DECOMMISSIONING
Power Generation Operating Segment-Dominion Energy and Virginia Power
Virginia Power has a total of four licensed, operating nuclear reactors at Surry and North Anna in Virginia.
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. Amounts collected from ratepayers are placed into trusts and are invested to fund the expected future costs of decommissioning the Surry and North Anna units.
Virginia Power believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected 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 the long-term investment horizon, since the units will not be decommissioned for decades, and a positive long-term outlook for trust fund investment returns. Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial
assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC.
The estimated cost to decommission Virginia Power’s four nuclear units is reflected in the table below and is primarily based upon site-specific studies completed in 2014. These cost studies are generally completed every four to five years. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire.
Under the current operating licenses, Virginia Power is scheduled to decommission the Surry and North Anna units during the period 2032 to 2078. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. Virginia Power has filed an application with the NRC to renew operating licenses for Surry for an additional 20 years. Under its current licenses, the two nuclear units are allowed to generate electricity through 2032 and 2033. A relicensing would extend their lives through 2052 and 2053. Virginia Power expects to submit a license extension application for the two units at North Anna in 2020. Between the four units, Virginia Power estimates that it could spend approximately $3 billion to $4 billion over the next several years on the relicensing process. The existing regulatory framework in Virginia provides rate recovery mechanisms for such costs.
Power Generation Operating Segment-Dominion Energy
In addition to the four nuclear units discussed above, Dominion Energy has two licensed, operating nuclear reactors at Millstone in Connecticut. A third Millstone unit ceased operations before Dominion Energy acquired the power station. In May 2013, Dominion Energy ceased operations at its single Kewaunee unit in Wisconsin and commenced decommissioning activities using the SAFSTOR methodology. The planned decommissioning completion date is 2073, which is within the NRC allowed 60-year window.
As part of Dominion Energy’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunee’s trust after decommissioning is completed are required to be refunded to Wisconsin ratepayers. Dominion Energy believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Dominion Energy will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. The estimated cost to decommission Dominion Energy’s eight units is reflected in the table below and is primarily based upon site-specific studies completed for Surry, North Anna and Millstone in 2014 and for Kewaunee in 2018.
The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion Energy and Virginia Power are shown in the following table:
(1) The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on Dominion Energy and Virginia Power’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Dominion Energy and Virginia Power’s nuclear decommissioning AROs.
(2) North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect 89.26% of the decommissioning cost for both of North Anna’s units.
(3) Unit 1 permanently ceased operations in 1998, before Dominion Energy’s acquisition of Millstone.
(4) Millstone Unit 3 is jointly owned by Dominion Energy Nuclear Connecticut, Inc., with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. Decommissioning cost is shown at Dominion Energy’s ownership percentage. At December 31, 2018, the minority owners held $41 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.
(5) Permanently ceased operations in 2013.
Also see Notes 14 and 22 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively, and Note 9 to the Consolidated Financial Statements for information about nuclear decommissioning trust investments.
Gas Infrastructure
The Gas Infrastructure Operating Segment of Dominion Energy Gas includes certain of Dominion Energy’s regulated natural gas operations. DETI, the gas transmission pipeline and storage business, serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. East Ohio, the primary gas distribution business of Dominion Energy Gas, serves residential, commercial and industrial gas sales, transportation and gathering service customers primarily in Ohio. DGP conducts gas gathering and processing activities, which include the sale of extracted products at market rates, primarily in West Virginia, Ohio and Pennsylvania. Dominion Iroquois holds a 24.07% noncontrolling partnership interest in Iroquois, which provides service to local gas distribution companies, electric utilities and electric power
generators, as well as marketers and other end users, through interconnecting pipelines and exchanges primarily in New York.
The Gas Infrastructure Operating Segment of Dominion Energy includes Dominion Energy Gas’ regulated natural gas operations as well as LNG operations, Dominion Energy Questar operations, Hope’s gas distribution operations in West Virginia, DECG’s FERC-regulated interstate natural gas transportation services in South Carolina and southeastern Georgia and nonregulated retail natural gas marketing, as well as Dominion Energy’s investments in Atlantic Coast Pipeline and Iroquois. See Properties and Investments below for additional information regarding the Atlantic Coast Pipeline investment. Dominion Energy’s LNG operations involve the import, export and storage of LNG at Cove Point, transportation of regasified LNG to the interstate pipeline grid and mid-Atlantic and Northeast markets and liquefaction of natural gas for export as LNG.
In September 2016, Dominion Energy completed the Dominion Energy Questar Combination and Dominion Energy Questar, a Rockies-based integrated natural gas company consisting of Questar Gas, Wexpro and Dominion Energy Questar Pipeline, became a wholly-owned subsidiary of Dominion Energy. Questar Gas’ regulated gas distribution operations serves customers in Utah, southwestern Wyoming and southeastern Idaho. Wexpro develops and produces natural gas from reserves supplied to Questar Gas under a cost-of-service framework. Dominion Energy Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage services in Utah, Wyoming and western Colorado. See Acquisitions and Dispositions above and Note 3 to the Consolidated Financial Statements for a description of the Dominion Energy Questar Combination.
Gas Infrastructure’s investment plan includes spending approximately $8.5 billion from 2019 through 2023 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability. Demand for natural gas is expected to continue to grow as initiatives to transition to gas from more carbon-intensive fuels are implemented. This plan includes Dominion Energy’s portion of spending for the Atlantic Coast Pipeline Project.
Earnings for the Gas Infrastructure Operating Segment of Dominion Energy Gas primarily result from rates established by FERC and the Ohio Commission. The profitability of this business is dependent on Dominion Energy Gas’ ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.
Approximately 92% of DETI’s transmission capacity is subscribed including 86% under long-term contracts (two years or greater) and 6% on a year-to-year basis. DETI’s storage services are 100% subscribed with long-term contracts.
Revenue from processing and fractionation operations largely results from the sale of commodities at market prices. For DGP’s processing plants, Dominion Energy Gas receives the wet gas product from producers and may retain the extracted NGLs as compensation for its services. This exposes Dominion Energy Gas to commodity price risk for the value of the spread between the NGL products and natural gas. In addition, Dominion Energy
Gas has volumetric risk as the majority of customers receiving these services are not required to deliver minimum quantities of gas.
East Ohio utilizes a straight-fixed-variable rate design for a majority of its customers. Under this rate design, East Ohio recovers a large portion of its fixed operating costs through a flat monthly charge accompanied by a reduced volumetric base delivery rate. Accordingly, East Ohio’s revenue is less impacted by weather-related fluctuations in natural gas consumption than under the traditional rate design.
Earnings for the Gas Infrastructure Operating Segment of Dominion Energy primarily include the results of rates established by FERC and the Ohio, West Virginia, Utah, Wyoming and Idaho Commissions. Additionally, Dominion Energy receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain LNG storage and terminalling services. The Liquefaction Project has a firm contracted capacity for LNG loading onto ships of approximately 4.6 Mtpa (0.66 Bcfe/day), under normal operating conditions and after accounting for maintenance downtime and other losses. Dominion Energy Questar Pipeline and DECG’s revenues are primarily derived from reservation charges for firm transportation and storage services as provided for in their FERC-approved tariffs. Revenue provided by Questar Gas’ operations is based primarily on rates established by the Utah and Wyoming Commissions. The Idaho Commission has contracted with the Utah Commission for rate oversight of Questar Gas operations in a small area of southeastern Idaho. Hope’s gas distribution operations in West Virginia serve residential, commercial, sale for resale and industrial gas sales, transportation and gathering service customers. Revenue provided by Hope’s operations is based primarily on rates established by the West Virginia Commission. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.
COMPETITION
Gas Infrastructure Operating Segment-Dominion Energy and Dominion Energy Gas
Dominion Energy Gas’ natural gas transmission operations compete with domestic and Canadian pipeline companies. Dominion Energy Gas also competes with gas marketers seeking to provide or arrange transportation, storage and other services. Alternative fuel sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain long-line pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enable Dominion Energy to tailor its services to meet the needs of individual customers.
DGP’s processing and fractionation operations face competition in obtaining natural gas supplies for its processing and related
services. Numerous factors impact any given customer’s choice of processing services provider, including the location of the facilities, efficiency and reliability of operations, and the pricing arrangements offered.
In Ohio, there has been no legislation enacted to require supplier choice for natural gas distribution consumers. However, East Ohio has offered an Energy Choice program to residential and commercial customers since October 2000. East Ohio has since taken various steps approved by the Ohio Commission toward exiting the merchant function, including restructuring its commodity service and placing Energy Choice-eligible customers in a direct retail relationship with participating suppliers. Further, in April 2013, East Ohio fully exited the merchant function for its nonresidential customers, which are now required to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2018, approximately 1.1 million of East Ohio’s 1.2 million Ohio customers were participating in the Energy Choice program.
Gas Infrastructure Operating Segment-Dominion Energy
Questar Gas and Hope do not currently face direct competition from other distributors of natural gas for residential and commercial customers in their service territories as state regulations in Utah, Wyoming and Idaho for Questar Gas, and West Virginia for Hope, do not allow customers to choose their provider at this time. See State Regulations in Regulation for additional information.
Cove Point’s gas transportation, LNG import and storage operations, as well as the Liquefaction Project’s capacity are contracted primarily under long-term fixed reservation fee agreements. However, in the future Cove Point may compete with other independent terminal operators as well as major oil and gas companies on the basis of terminal location, services provided and price. Competition from terminal operators primarily comes from refiners and distribution companies with marketing and trading arms. In addition, Cove Point’s Liquefaction Project may face competition on a global scale as international customers explore other options to meet their energy needs.
Dominion Energy Questar Pipeline and DECG’s pipeline systems generate a substantial portion of their revenue from long-term firm contracts for transportation services and are therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, Dominion Energy Questar Pipeline’s pipeline system faces competitive pressures from similar facilities that serve the Rocky Mountain region and DECG’s pipeline system faces competitive pressures from similar facilities that serve the South Carolina and southeastern Georgia area in terms of location, rates, terms of service, and flexibility and reliability of service.
Dominion Energy’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas, and provides service to approximately 380,000 customer accounts in five states. The heaviest concentration of customers in these markets is located in states where utilities have the advantage of long-standing commitment to customer choice, primarily Ohio and Pennsylvania.
REGULATION
Gas Infrastructure Operating Segment-Dominion Energy and Dominion Energy Gas
Dominion Energy Gas’ natural gas transmission and storage operations are regulated primarily by FERC. East Ohio’s gas distribution operations, including the rates that it may charge to customers, are regulated by the Ohio Commission. See State Regulations and Federal Regulations in Regulation for more information.
Gas Infrastructure Operating Segment-Dominion Energy
Cove Point’s transportation, LNG import and storage operations and Dominion Energy Questar Pipeline and DECG’s operations are regulated primarily by FERC. Questar Gas’ distribution operations, including the rates it may charge customers, are regulated by the Utah, Wyoming and Idaho Commissions. Hope’s gas distribution operations, including the rates that it may charge customers, are regulated by the West Virginia Commission. See State Regulations and Federal Regulations in Regulation for more information.
PROPERTIES
For a description of Dominion Energy and Dominion Energy Gas’ existing facilities see Item 2. Properties.
Gas Infrastructure Operating Segment-Dominion Energy and Dominion Energy Gas
Dominion Energy Gas has the following significant projects under construction or development to better serve customers or expand its service offerings within its service territory.
In August 2018, DETI executed a binding precedent agreement with a customer for the West Loop project. The project is expected to cost approximately $95 million and provide 150,000 Dths per day of firm transportation service from Pennsylvania to Ohio for delivery to a proposed combined-cycle, natural gas-fired electric power generation facility to be located in Columbiana County, Ohio. In December 2018, DETI filed an application to request FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service by the end of 2021.
In January 2018, DETI filed an application to request FERC authorization to construct and operate certain facilities located in Ohio and Pennsylvania for the Sweden Valley project. The project is expected to cost approximately $50 million and provide 120,000 Dths per day of firm transportation service from Pennsylvania to Ohio for delivery to Transco. The project’s capacity is fully subscribed pursuant to a precedent agreement with one customer and is expected to be placed into service in the fourth quarter of 2019.
In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header project, a project to provide approximately 1,500,000 Dths per day of firm transportation service to various customers. During the third and fourth quarters of 2018, a FERC stop work order together with delays in obtaining permits necessary for construction and delays in construction due to judicial actions impacted the cost and schedule for the project. As a result, project cost estimates have increased from between $550 million to $600 million to between
$650 million to $700 million, excluding financing costs. DETI anticipates a late 2020 in-service date.
In 2008, East Ohio began PIR, aimed at replacing approximately 4,100 miles of its pipeline system at a cost of $2.7 billion. In 2011, approval was obtained to include an additional 1,450 miles and to increase annual capital investment to meet the program goal. The program will replace approximately 25% of the pipeline system and is anticipated to take place over a total of 25 years. In September 2016, East Ohio received approval to extend the PIR program for an additional five years and to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio. Costs associated with calendar year 2016 investment will be recovered under the existing terms. In April 2018, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2017 costs. The filing reflects gross plant investment for 2017 of $204 million, cumulative gross plant investment of $1.4 billion and a revenue requirement of $165 million.
Gas Infrastructure Operating Segment-Dominion Energy
Dominion Energy has the following significant projects under construction or development.
Cove Point-In June 2015, Cove Point executed binding agreements with two customers for the approximately $150 million Eastern Market Access Project. In January 2018, Cove Point received FERC authorization to construct and operate the project facilities, which are expected to be placed into service in the second half of 2019. In October 2018, Cove Point announced it was evaluating alternatives to a proposed Charles County, Maryland compressor station that was initially part of this project and in December 2018, after working with project customers for alternative solutions, decided not to pursue further construction at this location resulting in a revised project cost estimate of approximately $45 million.
Questar Gas-In 2010, Questar Gas began replacing aging high pressure infrastructure under a cost-tracking mechanism that allows it to place into rate base and earn a return on capital expenditures associated with a multi-year natural gas infrastructure-replacement program upon the completion of each project. At that time, the commission-allowed annual spending in the replacement program was approximately $55 million.
In its 2014 Utah general rate case, Questar Gas received approval to include intermediate high pressure infrastructure in the replacement program and increase the annual spending limit to approximately $65 million, adjusted annually using a gross domestic product inflation factor. At that time, 420 miles of high pressure pipe and 70 miles of intermediate high pressure pipe were identified to be replaced in the program over a 17-year period. Questar Gas has spent about $65 million each year through 2018 under this program. The program is evaluated in each Utah general rate case. The next Utah general rate case is anticipated to occur in 2019.
INVESTMENTS
Iroquois-In September 2015, Dominion Energy, through Dominion Energy Midstream, acquired an additional 25.93% interest in Iroquois. Dominion Energy Gas holds a 24.07% interest with TransCanada holding a 50% interest. Iroquois owns and
operates a 416-mile FERC regulated interstate natural gas pipeline providing service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end-users, through interconnecting pipelines and exchanges. Iroquois’ pipeline extends from the U.S.-Canadian border at Waddington, New York through the state of Connecticut to South Commack, Long Island, New York and continuing on from Northport, Long Island, New York through the Long Island Sound to Hunts Point, Bronx, New York. See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Iroquois.
Atlantic Coast Pipeline-In September 2014, Dominion Energy, along with Duke and Southern Company Gas, announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion Energy an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. The members hold the following membership interests: Dominion Energy, 48%; Duke, 47%; and Southern Company Gas, 5%. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. See Future Issues and Other Matters in Item 7 for information on estimated project costs and in-service date and Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Atlantic Coast Pipeline.
Align RNG-In November 2018, Dominion Energy announced the formation of Align RNG, an equal partnership with Smithfield Foods, Inc. Align RNG expects to invest $250 million to develop assets to capture methane from hog farms across Virginia, North Carolina and Utah and convert it into pipeline quality natural gas.
SOURCES OF ENERGY SUPPLY
Dominion Energy and Dominion Energy Gas’ natural gas supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area, gas marketers and, for Questar Gas specifically, from Wexpro and other producers in the Rocky Mountain region. Wexpro’s gas development and production operations serve the majority of Questar Gas’ gas supply requirements in accordance with the Wexpro Agreement and the Wexpro II Agreement, comprehensive agreements with the states of Utah and Wyoming. Dominion Energy and Dominion Energy Gas’ large underground natural gas storage network and the location of their pipeline systems are a significant link between the country’s major interstate gas pipelines and large markets in the Northeast, mid-Atlantic and Rocky Mountain regions. Dominion Energy and Dominion Energy Gas’ pipelines are part of an interconnected gas transmission system, which provides access to supplies nationwide for local distribution companies, marketers, power generators and industrial and commercial customers.
Dominion Energy and Dominion Energy Gas’ underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Northeast, mid-Atlantic, Midwest and Rocky Mountain regions. In addition,
storage capacity is an important element in the effective management of both gas supply and pipeline transmission capacity.
The supply of gas to serve Dominion Energy’s retail energy marketing customers is procured through Dominion Energy’s energy marketing group and market wholesalers.
SEASONALITY
Gas Infrastructure’s natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March; however, implementation of rate mechanisms in Ohio for East Ohio, and Utah, Wyoming and Idaho for Questar Gas and transportation services provided to gas producers and electric power generators at East Ohio have reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion Energy’s gas transmission and storage business can also be weather sensitive. Earnings are also impacted by changes in commodity prices driven by seasonal weather changes, the effects of unusual weather events on operations and the economy.
The earnings of Dominion Energy’s retail energy marketing operations also vary seasonally. Generally, the demand for gas peaks during the winter months to meet heating needs.
Southeast Energy
The Southeast Energy Operating Segment of Dominion Energy, established in January 2019, includes the generation, transmission and distribution of electricity through SCE&G, the distribution of natural gas through SCE&G and PSNC and the marketing of natural gas to retail customers through SEMI.
SCE&G is engaged in the generation, transmission and distribution of electricity to approximately 730,000 customers in the central, southern and southwestern portions of South Carolina. Additionally, SCE&G and PSNC sell natural gas to approximately 960,000 residential, commercial and industrial customers in South Carolina and North Carolina. SEMI markets natural gas and provides energy-related services, selling natural gas to approximately 420,000 customers in the southeast U.S.
Southeast Energy’s investment plan includes spending approximately $4.6 billion from 2019 through 2023 to upgrade or add new equipment and infrastructure in response to increasing customer growth and demand and an effort to maintain reliability for customers.
Revenue provided by SCE&G’s electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures.
SCE&G’s electric transmission operations serve its electric distribution operations as well as certain wholesale customers. Revenue provided by such electric transmission operations is primarily based on a FERC-approved formula rate mechanism under SCE&G’s open access transmission tariff.
Revenue provided by SCE&G’s electric generation operations is primarily derived from the sale of electricity generated by its utility generation assets and is based on rates established by state regulatory authorities and state law. Variability in earnings may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather, or the timing and nature of expenses or outages.
Revenue provided by SCE&G and PSNC’s natural gas distribution operations primarily results from rates established by the South Carolina and North Carolina Commissions, respectively. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, the availability and prices of alternative fuels and the economy.
SCE&G is a member of the Virginia-Carolinas Reliability Group, one of several geographic divisions within the SERC Reliability Corporation. The SERC Reliability Corporation is one of seven regional entities with delegated authority from NERC for the purpose of proposing and enforcing reliability standards approved by NERC.
COMPETITION
There is no competition for electric distribution or generation service within SCE&G’s service territory in South Carolina and no such competition is currently permitted. However, competition from third-party owners for development, construction and ownership of certain transmission facilities in SCE&G’s service territory is permitted pursuant to Order 1000, subject to state and local siting and permitting approvals. This could result in additional competition to build and own transmission infrastructure in SCE&G’s service area in the future.
Competition in Southeast Energy’s natural gas distribution operations is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and the ability to retain large commercial and industrial customers.
Southeast Energy’s marketing services for natural gas and other energy-related services face competition from affiliates of large energy companies and electric membership cooperatives, among others. The ability of Southeast Energy to maintain its market share primarily depends on the prices it charges customers relative to the prices charged by its competitors and its ability to provide high levels of customer service.
REGULATION
SCE&G’s electric distribution service, including the rates it may charge to jurisdictional customers, is subject to regulation by the South Carolina Commission. SCE&G’s electric generation operations are subject to regulation by the South Carolina Commission, FERC, the NRC, the EPA, the DOE and various other federal, state and local authorities. SCE&G’s electric transmission service is primarily regulated by FERC and the DOE. SCE&G and PSNC’s gas distribution operations are subject to regulation by the South Carolina and North Carolina Commissions, respectively, as well as PHMSA, the U.S. Department of Transportation, the South Carolina Office of Regulatory Staff and the North Carolina Commission for enforcement of federal and state pipeline safety requirements in their respective service territories. SEMI’s energy marketing activities are subject to regulation by the Georgia Public Service Commission as to retail prices for customers served under regulated provider contracts and FERC.
See State Regulations and Federal Regulations in Regulation for more information.
PROPERTIES
For a listing of existing property and facilities associated with Southeast Energy at January 1, 2019, see Item 2. Properties.
The following material reliability projects are currently under construction or development at SCE&G:
In response to revised Effluent Limitations Guidelines mandated by the EPA, SCE&G intends to upgrade the wastewater discharge filtration systems at the Williams and Wateree coal-fired generation facilities. The scope and scheduling of these projects is dependent on the finalization of the Effluent Limitations Guidelines, but is expected to cost approximately $250 million and be placed into service by the end of 2025.
In an effort to maintain the reliability and safety of the baghouse at its Cope coal-fired generation facility, SCE&G is currently replacing the existing carbon steel baghouse structure with a corrosion resistant material to address corrosion issues resulting from the dry scrubber system. The project is estimated to cost approximately $40 million and be placed into service by the end of 2020.
The following material reliability projects are currently under construction or development at PSNC:
PSNC plans to construct approximately 38 miles of transmission pipeline between Franklinton, North Carolina and Clayton, North Carolina, which will improve system reliability and provide the capacity necessary to support the growing natural gas demand in PSNC’s service territory. The project is expected to cost approximately $130 million and provide approximately 170,000 Dths per day. The project is expected to be placed into service in 2020.
PSNC is constructing a high-pressure distribution pipeline that will ultimately span 35 miles between Forest City, North Carolina and Marion, North Carolina, which will provide enhanced system reliability and safety. The project is expected to cost approximately $60 million and provide approximately 60,000 Dths per day. The project is expected to be placed into service in late 2019.
SOURCES OF ENERGY SUPPLY
Southeast Energy uses a variety of fuels to power its electric generation and purchases power for utility system load requirements. Presented below is a summary of SCANA’s actual system output by energy source :
(1) Excludes Santee Cooper’s 33.3% undivided ownership interest in Summer.
(2) Includes hydro, biomass and solar.
Natural gas-SCE&G purchases natural gas under contracts with producers and marketers on both a short-term and long-term basis at market-based prices. The gas is delivered to South Carolina through firm transportation agreements with various
counterparties, which expire between 2019 and 2084. PSNC purchases natural gas under contracts with producers and marketers on a short-term basis at market-based prices and on a long-term basis for reliability assurance at first of the month index prices plus a reservation charge in certain cases. The gas is delivered to North Carolina through transportation agreements with Transco, which expire at various dates through 2031.
Coal-Southeast Energy primarily obtains coal through short-term and long-term contracts with suppliers located in eastern Kentucky, Tennessee, Virginia and West Virginia. These contracts provide for approximately 2.1 million tons annually. These contracts expire at various times through 2020. Spot market purchases may occur when needed or when prices are believed to be favorable.
Nuclear-Southeast Energy primarily utilizes long-term contracts to support its nuclear fuel requirements. SCE&G, for itself and as agent for Santee Cooper, and Westinghouse are parties to a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, SCE&G supplies enriched products to Westinghouse, who in turn supplies nuclear fuel assemblies for Summer. Westinghouse is SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements through 2033.
In addition, SCE&G has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates through 2024. SCE&G believes that it will be able to renew these contracts as they expire or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services and that sufficient capacity for nuclear fuel supplies and processing exists to allow for normal operations of its nuclear generating unit. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal fuel and inventory levels.
SEASONALITY
Southeast Energy’s electric operations vary seasonally as a result of the impact of changes in temperature, the impact of storms and other catastrophic weather events and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
Southeast Energy’s gas operations vary seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. The majority of these earnings are generated during the heating season, which is generally from November to March; however, North Carolina and South Carolina have certain mechanisms designed to reduce the impact of weather-related fluctuations.
The earnings of Southeast Energy’s natural gas marketing operations also vary seasonally, and generally peak during the winter months to meet heating needs.
NUCLEAR DECOMMISSIONING
SCE&G has a two-thirds interest in one licensed, operating nuclear reactor at Summer in South Carolina.
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. Amounts collected by ratepayers are placed into trusts and are invested to fund the expected future costs of decommissioning Summer.
SCE&G believes that the decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to this trust, if such future collections and contributions are required. SCE&G will continue to monitor this trust to ensure that it meets the NRC minimum financial assurance requirements, which may include, if needed, the use of Dominion Energy guarantees, surety bonding or other financial instruments recognized by the NRC.
The current estimated cost to SCE&G to decommission Summer is $626 million (stated in 2018 dollars), which is primarily based upon site-specific studies completed in 2016. These cost studies are generally completed every four to five years. Santee Cooper is responsible for the remaining 33.3% of decommissioning costs, proportionate with its ownership in Summer. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating license expires. The cost estimate reflects reductions for the expected future recovery of certain spent nuclear fuel costs based on SCE&G’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in SCANA’s nuclear decommissioning ARO. Currently, SCE&G has $190 million in a trust for its proportionate share of these decommissioning activities.
Under the current operating license, SCE&G is scheduled to decommission Summer in 2042. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. SCE&G is considering an operating license renewal for Summer.
Corporate and Other
Corporate and Other Segment-Virginia Power and Dominion Energy Gas
Virginia Power and Dominion Energy Gas’ Corporate and Other segments primarily include certain specific items attributable to their operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.
Corporate and Other Segment-Dominion Energy
Dominion Energy’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.
REGULATION
The Companies are subject to regulation by various federal, state and local authorities, including the state commissions of Virginia, North Carolina, South Carolina, Ohio, West Virginia, Georgia, Utah, Wyoming and Idaho, SEC, FERC, EPA, DOE, NRC, Army Corps of Engineers and the U.S. Department of Transportation.
State Regulations
ELECTRIC
Virginia Power and SCE&G’s electric utility retail services are subject to regulation by the Virginia and North Carolina Commissions and the South Carolina Commission, respectively.
Virginia Power and SCE&G hold CPCNs which authorize them to maintain and operate their electric facilities now in operation and to sell electricity to customers. However, Virginia Power and SCE&G may not construct generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies. In addition, the Virginia Commission and the North Carolina Commission regulate Virginia Power’s and the South Carolina Commission regulates SCE&G’s transactions with affiliates and transfers of certain facilities. The Virginia, North Carolina and South Carolina Commissions also regulate the issuance of certain securities.
Electric Regulation in Virginia
The Regulation Act instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers.
The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, including pumped hydroelectricity generation and storage facilities as well as extensions of operating licenses of nuclear power generation facilities, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs and renewable energy programs, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.
In March 2018, the GTSA reinstated base rate reviews on a triennial basis other than the first review, which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020. This review for Virginia Power will occur one year earlier than under the Regulation Act legislation enacted in February 2015.
In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized return on equity that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include in a customer credit reinvestment offset. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a customer credit reinvestment offset. Any costs that are the subject of a customer credit reinvestment offset may not be recovered in base
rates for the service life of the projects and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized return on equity, base rates are subject to reduction prospectively and customer refunds would be due unless the total customer credit reinvestment offset elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. In the 2021 review, any such rate reduction is limited to $50 million.
The legislation also included provisions requiring Virginia Power to provide current customers one-time rate credits totaling $200 million and to reduce base rates to reflect reductions in income tax expense resulting from the 2017 Tax Reform Act. In addition, Virginia Power reduced base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act, which is subject to adjustment effective April 2019. In May and June 2018, Virginia Power submitted filings detailing the implementation plan for interim reductions in rates for generation and distribution services pursuant to the GTSA.
If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.
See Futures Issues and Other Matters in Item 7. MD&A and Note 13 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.
Electric Regulation in North Carolina
Virginia Power’s retail electric base rates in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes and the rules and procedures of the North Carolina Commission. North Carolina base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, Virginia Power’s future earnings could be negatively impacted. Fuel rates are subject to revision under annual fuel cost adjustment proceedings.
Virginia Power’s transmission service rates in North Carolina are regulated by the North Carolina Commission as part of Virginia Power’s bundled retail service to North Carolina customers. See Note 13 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.
Electric Regulation in South Carolina
SCE&G’s retail electric base rates in South Carolina are regulated on a cost-of-service/rate-of-return basis subject to South Carolina statutes and the rules and procedures of the South Carolina Commission. South Carolina base rates are set by a process that allows SCE&G to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the South Carolina Commission, retail electric rates may by sub-
ject to review and possible reduction, which may decrease SCE&G’s future earnings. Additionally, if the South Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, SCE&G’s future earnings could be negatively impacted. Fuel costs are reviewed annually by the South Carolina Commission, as required by statute, and fuel rates are subject to revision in these annual fuel proceedings.
SCE&G offers to its retail electric customers several DSM programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the South Carolina Commission related to these programs. As actual DSM program costs are incurred, they are deferred as regulatory assets and recovered through a rider approved by the South Carolina Commission. The rider also provides for recovery of any net lost revenues and for a shared savings incentive.
In connection with the SCANA Combination, SCE&G agreed not to file a general rate case with the South Carolina Commission with a requested rate effective date earlier than January 2021. Rate adjustments are permitted prior to 2021 for fuel and environmental costs, DSM costs and other rates routinely adjusted on an annual or biennial basis.
See Note 3 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.
GAS
Dominion Energy Questar’s natural gas development, production, transportation, and distribution services, including the rates it may charge its customers, are regulated by the state commissions of Utah, Wyoming and Idaho. East Ohio’s natural gas distribution services, including the rates it may charge its customers, are regulated by the Ohio Commission. Hope’s natural gas distribution services are regulated by the West Virginia Commission. SCE&G and PSNC’s natural gas distribution services are regulated by the South Carolina Commission and North Carolina Commission, respectively.
Gas Regulation in Utah, Wyoming and Idaho
Questar Gas is subject to regulation of rates and other aspects of its business by the Utah, Wyoming and Idaho Commissions. The Idaho Commission has contracted with the Utah Commission for rate oversight of Questar Gas’ operations in a small area of southeastern Idaho. When necessary, Questar Gas seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. Base rates for Questar Gas are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. The volumetric charges for the residential and small commercial customers in Utah and Wyoming are subject to revenue decoupling and adjusted for changes in usage per customer.
In addition to general rate increases, Questar Gas makes routine separate filings with the Utah and Wyoming Commissions to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through the Wexpro Agreement and Wexpro II Agreement. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas recovery filings generally cover a prospective twelve-month period. Approved increases or decreases in
gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.
In connection with the Dominion Energy Questar Combination, Questar Gas withdrew its general rate case filed in July 2016 with the Utah Commission and agreed not to file a general rate case with the Utah Commission to adjust its base distribution non-gas rates prior to July 2019, unless otherwise ordered by the Utah Commission. In addition Questar Gas agreed not to file a general rate case with the Wyoming Commission with a requested rate effective date earlier than January 2020. This does not impact Questar Gas’ ability to adjust rates through various riders. See Notes 3 and 13 to the Consolidated Financial Statements for additional information.
Gas Regulation in Ohio
East Ohio is subject to regulation of rates and other aspects of its business by the Ohio Commission. When necessary, East Ohio seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. A straight-fixed-variable rate design, in which the majority of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohio’s customers pursuant to a 2008 rate case settlement.
In addition to general base rate increases, East Ohio makes routine filings with the Ohio Commission to reflect changes in the costs of gas purchased for operational balancing on its system. These purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The rider filings cover unrecovered gas costs plus prospective annual demand costs. Increases or decreases in gas cost rider rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.
The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure projects and certain other costs that vary widely over time; such costs are excluded from general base rates. See Note 13 to the Consolidated Financial Statements for additional information.
Gas Regulation in West Virginia
Hope is subject to regulation of rates and other aspects of its business by the West Virginia Commission. When necessary, Hope seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. Base rates for Hope are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges.
In addition to general rate increases, Hope makes routine separate filings with the West Virginia Commission to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings gen-
erally cover a prospective twelve-month period. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.
Legislation was passed in West Virginia authorizing a stand-alone cost recovery mechanism to recover specified costs and a return for infrastructure upgrades, replacements and expansions between general base rate cases. See Note 13 to the Consolidated Financial Statements for additional information.
Gas Regulation in North Carolina
PSNC is subject to regulation of rates and other aspects of its business by the North Carolina Commission. PSNC’s base rates are set in a general rate case based on the cost-of-service by rate class. Such rates are designed primarily based on a rate design methodology in which the majority of operating costs are recovered through volumetric charges.
PSNC has certain riders to its tariff that allow it to make periodic rate adjustment filings with the North Carolina Commission outside of a general rate case. PSNC’s purchased gas adjustment allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses. The purchased gas adjustment provides for a benchmark cost of gas rate component and a fixed gas cost component, both of which may be periodically adjusted to reflect changes in the costs of purchased gas, including transportation costs. In addition, PSNC utilizes a customer usage tracker, a decoupling mechanism, which allows it to adjust rates semi-annually for residential and commercial customers based on average customer consumption. PSNC also utilizes an integrity management tracker, which provides for semi-annual rate adjustments to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. All of these riders utilize deferral accounting to track over- and under-collected costs for subsequent rate consideration.
In connection with the SCANA Combination, PSNC agreed not to file a general rate case with the North Carolina Commission with a requested rate effective date earlier than November 2021 other than for rate adjustments pursuant to the customer usage tracker, the integrity management tracker and the purchased gas adjustment.
See Note 3 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.
Gas Regulation in South Carolina
SCE&G is subject to regulation of rates and other aspects of its natural gas distribution service by the South Carolina Commission. SCE&G provides retail natural gas service to customers in areas in which it has received authorization from the South Carolina Commission and in municipalities in which it holds a franchise. SCE&G’s base rates can be adjusted annually, pursuant to the Natural Gas Rate Stabilization Act, for recovery of costs related to natural gas infrastructure. Base rates are set based on the cost-of-service by rate class approved by the South Carolina Commission in the latest general rate case. Base rates for SCE&G are designed primarily based on a rate design methodology in which the majority of operating costs are recovered through volumetric charges. SCE&G also utilizes a weather normalization adjustment to adjust its base rates during the winter billing
months for residential and commercial customers to mitigate the effects of unusually cold or warm weather.
In addition, SCE&G’s natural gas tariffs include a purchased gas adjustment that provides for the recovery of prudently incurred gas costs, including transportation costs. SCE&G is authorized to adjust its purchased gas rates monthly and makes routine filings with the South Carolina Commission to provide notification of changes in these rates. Costs that are under or over recovered are deferred as regulatory assets or liabilities, respectively, and considered in subsequent purchased gas adjustments. The purchased gas adjustment filings generally cover a prospective twelve-month period. Increases or decreases in purchased gas costs can result in corresponding changes in purchased gas adjustment rates and the revenue generated by those rates. The South Carolina Commission reviews SCE&G’s gas purchasing policies and practices, including its administration of the purchased gas adjustment, annually.
See Note 3 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.
Status of Competitive Retail Gas Services
The states of Ohio and West Virginia, in which Dominion Energy and Dominion Energy Gas have gas distribution operations, have considered legislation regarding a competitive deregulation of natural gas sales at the retail level.
Ohio-Since October 2000, East Ohio has offered the Energy Choice program, under which residential and commercial customers are encouraged to purchase gas directly from retail suppliers or through a community aggregation program. In October 2006, East Ohio restructured its commodity service by entering into gas purchase contracts with selected suppliers at a fixed price above the New York Mercantile Exchange month-end settlement and passing that gas cost to customers under the Standard Service Offer program. Starting in April 2009, East Ohio buys natural gas under the Standard Service Offer program only for customers not eligible to participate in the Energy Choice program and places Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills.
In January 2013, the Ohio Commission granted East Ohio’s motion to fully exit the merchant function for its nonresidential customers, beginning in April 2013, which requires those customers to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2018, approximately 1.1 million of Dominion Energy Gas’ 1.2 million Ohio customers were participating in the Energy Choice program. Subject to the Ohio Commission’s approval, East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. East Ohio continues to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.
West Virginia-At this time, West Virginia has not enacted legislation allowing customers to choose providers in the retail natural gas markets served by Hope. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customers a choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.
Federal Regulations
FEDERAL ENERGY REGULATORY COMMISSION
Electric
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and sells electricity to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s merchant generators sell electricity in the PJM, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. In addition, Virginia Power and SCE&G have FERC approval of a tariff to sell wholesale power at capped rates based on their respective embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power and SCE&G’s service territories. Any such sales would be voluntary.
Dominion Energy and Virginia Power are subject to FERC’s Standards of Conduct that govern conduct between transmission function employees of interstate gas and electricity transmission providers and the marketing function employees of their affiliates. The rule defines the scope of transmission and marketing-related functions that are covered by the standards and is designed to prevent transmission providers from giving their affiliates undue preferences.
Dominion Energy and Virginia Power are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between merchant plants and utility plants without first receiving FERC authorization, (2) require the merchant and utility plants to conduct their wholesale power sales operations separately, and (3) prohibit utilities from sharing market information with merchant plant operating personnel. The rules are designed to prohibit utilities from giving the merchant plants a competitive advantage.
EPACT included provisions to create an ERO. The ERO is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC has certified NERC as the ERO and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of up to $1.2 million per day, per violation and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
Dominion Energy and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion Energy and Virginia Power employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. Dominion Energy and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cybersecurity programs. In addition, NERC has redefined critical assets which expanded the number of assets subject to NERC reliability standards, including cybersecurity assets. NERC continues to develop additional requirements specifically regarding supply chain standards and control centers
that impact the bulk electric system. While Dominion Energy and Virginia Power expect to incur additional compliance costs in connection with NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
Gas
FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion Energy Questar Pipeline, DETI, DECG, Iroquois and certain services performed by Cove Point. The design, construction and operation of Cove Point’s LNG facility, including associated natural gas pipelines, the Liquefaction Project and the import and export of LNG are also regulated by FERC.
Dominion Energy and Dominion Energy Gas’ interstate gas transmission and storage activities are conducted on an open access basis, in accordance with certificates, tariffs and service agreements on file with FERC and FERC regulations.
Dominion Energy and Dominion Energy Gas operate in compliance with FERC standards of conduct, which prohibit the sharing of certain non-public transmission information or customer specific data by its interstate gas transmission and storage companies with non-transmission function employees. Pursuant to these standards of conduct, Dominion Energy and Dominion Energy Gas also make certain informational postings available on Dominion Energy’s website.
See Note 13 to the Consolidated Financial Statements for additional information.
Safety Regulations
Dominion Energy and Dominion Energy Gas are also subject to the Pipeline Safety Improvement Act of 2002 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which mandate inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those located in areas of high-density population. Dominion Energy and Dominion Energy Gas have evaluated their natural gas transmission and storage properties, as required by the U.S. Department of Transportation regulations under these Acts, and have implemented a program of identification, testing and potential remediation activities. These activities are ongoing.
The Companies are subject to a number of federal and state laws and regulations, including Occupational Safety and Health Administration, and comparable state statutes, whose purpose is to protect the health and safety of workers. The Companies have an internal safety, health and security program designed to mon-
itor and enforce compliance with worker safety requirements, which is routinely reviewed and considered for improvement. The Companies believe that they are in material compliance with all applicable laws and regulations related to worker health and safety. Notwithstanding these preventive measures, incidents may occur that are outside of the Companies’ control.
Environmental Regulations
Each of the Companies’ operating segments faces substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Companies. If compliance expenditures and associated operating costs are not recoverable from customers through regulated rates (in regulated businesses) or market prices (in unregulated businesses), those costs could adversely affect future results of operations and cash flows. The Companies have applied for or obtained the necessary environmental permits for the construction and operation of their facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance required to be discussed in this Item, see Environmental Matters in Future Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 22 to the Consolidated Financial Statements, which information is incorporated herein by reference.
AIR
The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. Regulated emissions include, but are not limited to, carbon, methane, VOC, other GHGs, mercury, other toxic metals, hydrogen chloride, NOX, SO2 and particulate matter. At a minimum, delegated 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.
GLOBAL CLIMATE CHANGE
The Companies support national climate change legislation that would provide a consistent, economy-wide approach to addressing this issue and are currently taking action to protect the environment and reduce GHG emissions while meeting the growing needs of their customers. Dominion Energy’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including GHG emissions, and Dominion Energy’s Board of Directors receives periodic updates on these matters. See Environmental Strategy below, Environmental Matters in Future Issues and Other Matters in Item 7. MD&A and Note 22 to the Consolidated Financial Statements for information on climate change legislation and regulation, which information is incorporated herein by reference.
WATER
The CWA 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 CWA and analogous state laws impose restrictions and strict controls regarding discharges of effluent into surface waters and require permits to be obtained from the EPA or the analogous state agency for those discharges. Containment berms and similar structures may be required to help prevent accidental releases. Dominion Energy must comply with applicable CWA requirements at its current and former operating facilities. Stormwater related to construction activities is also regulated under the CWA and by state and local stormwater management and erosion and sediment control laws. From time to time, Dominion Energy’s projects and operations may impact tidal and non-tidal wetlands. In these instances, Dominion Energy must obtain authorization from the appropriate federal, state and local agencies prior to impacting wetlands. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for such impacts to wetlands.
WASTE AND CHEMICAL MANAGEMENT
Dominion Energy is subject to various federal and state laws and implementing regulations governing the management, storage, treatment, reuse and disposal of waste materials and hazardous substances, including the Resources Conservation and Recovery Act of 1976, CERCLA, the Emergency Planning and Community Right-to-Know Act of 1986 and the Toxic Substance Control Act of 1976. Dominion Energy’s operations and construction activities, including activities associated with oil and gas production and gas storage wells, generate waste. Across Dominion Energy, completion water is disposed at commercial disposal facilities. Produced water is either hauled for disposal, evaporated or injected into company and third-party owned underground injection wells. Wells drilled in tight-gas-sand and shale reservoirs require hydraulic-fracture stimulation to achieve economic production rates and recoverable reserves. The majority of Wexpro’s current and future production and reserve potential is derived from reservoirs that require hydraulic-fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic-fracture stimulation and management and disposal of hydraulic fracturing fluids, are regulated by federal and state agencies that review and approve all aspects of gas- and oil-well design and operation.
PROTECTED SPECIES
The ESA and analogous state laws prohibit activities that can result in harm to specific species of plants and animals, as well as impacts to the habitat on which those species depend. In addition to ESA programs, the MBTA and BGEPA establish broader prohibitions on harm to protected birds. Many of the Companies’ facilities are subject to requirements of the ESA, MBTA and BGEPA. The ESA and BGEPA require potentially lengthy coordination with the state and federal agencies to ensure potentially affected species are protected. Ultimately, the suite of species protections may restrict company activities to certain times of year, project modifications may be necessary to avoid harm, or a permit may be needed for unavoidable taking of the species. The authorizing agency may impose mitigation requirements and costs
to compensate for harm of a protected species or habitat loss. These requirements and time of year restrictions can result in adverse impacts on project plans and schedules such that the Companies’ businesses may be materially affected.
OTHER REGULATIONS
Other significant environmental regulations to which the Companies are subject include federal and state laws protecting graves, sacred sites, historic sites and cultural resources, including those of American Indian tribal nations and tribal communities. These can result in compliance and mitigation costs as well as potential adverse effects on project plans and schedules such that the Companies’ businesses may be materially affected.
Nuclear Regulatory Commission
All aspects of the operation and maintenance of Dominion Energy and Virginia Power’s nuclear power stations are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.
From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining Dominion Energy and Virginia Power’s nuclear generating units. See Note 22 to the Consolidated Financial Statements for further information.
The NRC also requires Dominion Energy and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and Dominion Energy and Virginia Power are required by the NRC to be financially prepared. For information on decommissioning trusts, see Power Generation-Nuclear Decommissioning and Southeast Energy-Nuclear Decommissioning above and Notes 3 and 9 to the Consolidated Financial Statements. See Notes 3 and 22 to the Consolidated Financial Statements for information on spent nuclear fuel.
ENVIRONMENTAL STRATEGY
The Companies’ environmental strategy is a component of the overall long-term strategic planning overseen by the CEO and Board of Directors, including oversight by the sustainability and corporate responsibility board committee which was formed in 2018. The Companies are committed to continuing to be an industry leader, delivering safe, reliable, clean and affordable energy while fully complying with all applicable environmental laws and regulations. Additionally, the Companies seek to build partnerships and engage with local communities, stakeholders and customers on environmental issues important to them, including environmental justice considerations such as fair treatment, inclusive involvement and effective communication. The Companies believe in being transparent about their environmental commitments, policies, including the Environmental Justice Policy adopted in 2018, and initiatives which have been
disclosed in reports included on Dominion Energy’s website. The Companies are dedicated to meeting their customers’ growing energy needs with innovative, sustainable solutions. It is the Companies’ belief that sustainable solutions should strive to balance the interdependent goals of environmental stewardship and economic effects. The integrated strategy to meet these objectives consists of three major elements:
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Reduction of GHG emissions;
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Energy infrastructure modernization, including natural gas and electric operations; and
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Conservation and energy efficiency.
Reduction of GHG Emissions
The Companies’ integrated strategy has resulted in a reduction in GHG emission intensity. Over the past two decades, the Companies have made changes to the generation mix and to natural gas operations which have significantly improved environmental performance. For example, Power Generation has reduced both its carbon emissions and its carbon intensity while generating electricity with an increasingly clean portfolio. From 2000 through 2017, Dominion Energy’s carbon intensity decreased by 50%. This strategy has also resulted in measurable reductions of other air pollutants such as NOX, SO2 and mercury and also reduced the amount of coal ash generated and the amount of water withdrawn. The principal components of the strategy include initiatives that address electric energy production and delivery, natural gas storage, transmission and delivery and energy management.
See Operating Segments for more information on certain of the projects described above.
CLEANER GENERATION
Renewable energy is an important component of a diverse and reliable energy mix that helps to mitigate the environmental aspects of energy production. Dominion Energy has nearly 2,600 MW of solar generating capacity in operation or under development in nine states, including offtake agreements for Virginia Power’s utility customers. Virginia, North Carolina and South Carolina have passed legislation setting targets for renewable power. Dominion Energy continues to add utility-scale solar capacity and is committed to meeting Virginia’s goals of 12% of base year electric energy sales from renewable power sources by 2022, and 15% by 2025, North Carolina’s Renewable Portfolio Standard of 12.5% by 2021 and South Carolina’s goal of 2% of aggregate generation capacity from renewable power sources by 2021. Backed by a $1 billion investment from 2018 through 2020, Dominion Energy has grown its solar fleet in Virginia and North Carolina to about 1,700 MW in service, in construction or under development.
See Operating Segments and Item 2. Properties for additional information, including Dominion Energy’s merchant solar properties.
GHG EMISSIONS
Since 2000, Dominion Energy and Virginia Power have tracked the emissions of their electric generation fleet, which employs a mix of fuel and renewable energy sources. Comparing annual year 2017 to annual year 2000, the entire electric generating fleet
(based on ownership percentage) reduced its average CO2 emissions per MWh of energy produced from electric generation by approximately 50%. Comparing annual year 2017 to annual year 2000, the regulated electric generating fleet (based on ownership percentage) reduced its average CO2 emissions per MWh of energy produced from electric generation by approximately 35%. Dominion Energy and Virginia Power’s 2018 emissions data is not yet available.
Dominion Energy also develops a comprehensive GHG inventory annually. For Power Generation, Dominion Energy and Virginia Power’s direct CO2 equivalent emissions (based on ownership percentage) were 30.1 million metric tons and 26.4 million metric tons, respectively, in 2017, compared to 37.2 million metric tons and 33.1 million metric tons, respectively, in 2016. The corresponding Power Generation carbon intensity rates for Dominion Energy were 0.295 metric tons CO2 equivalent emissions per net MWh in 2017 and 0.339 metric tons CO2 equivalent emissions per net MWh in 2016.
For Power Delivery’s regulated electric transmission and distribution operations, direct CO2 equivalent emissions for 2017 were 37,841 metric tons, compared to 42,847 metric tons in 2016.
Dominion Energy’s natural gas companies have been reporting GHG emissions to the EPA since 2011 under the GHG Reporting Program. In January 2016, the GHG Reporting Program was expanded to also include GHG inputs and emissions associated with natural gas gathering and boosting sources and transmission pipeline blowdowns for facilities that exceed 25,000 metric tons per year of CO2 equivalent emissions. The sources within these new facilities were not previously covered under the rule and the first reports for these new sources were submitted to the EPA on March 31, 2017.
Hope and East Ohio’s direct CO2 equivalent emissions together increased to 0.88 million metric tons in 2017 from 0.86 in 2016. DETI and Cove Point’s direct CO2 equivalent emissions together were 1.6 million metric tons in 2017, increasing from 1.3 million metric tons in 2016, attributable to increased operational activity related to new construction.
The Companies’ GHG inventory follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98 for calculating emissions. Total CO2 equivalent emissions reported for our natural gas assets, as estimated in Dominion Energy’s corporate inventory, were 3.51 million metric tons in 2017. This estimate includes emissions reported under the GHG Reporting Program, as well as other emissions not required to be reported under the federal program. The 2017 corporate GHG inventory emission estimate includes Dominion Energy Questar Pipeline, Questar Gas and Wexpro for the entire calendar year. Dominion Energy’s 2017 methane emissions reported under Subpart W of the Greenhouse Gas Reporting Rule are as follows:
Energy Infrastructure Modernization
Dominion Energy’s investment plan from 2019 through 2023 includes a focus on upgrading the electric grid in Virginia through investments in additional renewable generation facilities, smart meters, customer information platform, intelligent grid devices and associated control systems, physical and cyber security investments, strategic undergrounding and energy conservation programs. Dominion Energy also plans to upgrade its gas and electric transmission and distribution networks and meet environmental requirements and standards set by various regulatory bodies. These enhancements are primarily aimed at meeting Dominion Energy’s continued goal of providing reliable service and to address increases in electricity consumption. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed, or to be developed in the future, to meet our customers’ preference for cleaner energy. See Operating Segments for additional information.
The Companies have also implemented infrastructure improvements and improved operational practices to reduce the GHG emissions from our natural gas facilities. Dominion Energy and Dominion Energy Gas, in connection with the investment plan, are also pursuing the construction or upgrade of regulated infrastructure in their natural gas businesses. The Companies have made voluntary commitments as part of the EPA Methane Challenge Program to continue to reduce methane emissions as part of these improvements. See Operating Segments for additional information, including natural gas infrastructure projects.
Conservation and Energy Efficiency
Conservation and load management play a significant role in meeting the growing demand for electricity and natural gas, while also helping to reduce the environmental footprint of our customers. The Companies offer various energy efficiency programs in Virginia,
North Carolina, Ohio, South Carolina, Utah and Wyoming designed to reduce energy consumption including programs such as:
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Energy audits and assessments;
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Incentives for customers to upgrade or install certain energy efficient measures and/or systems;
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Weatherization assistance to help income-eligible customers reduce their energy usage;
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Home energy planning, which provides homeowners with a step-by-step roadmap to efficiency improvements to reduce gas usage; and
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Rebates for installing high-efficiency equipment.
CYBERSECURITY
In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In November 2018, Dominion Energy appointed a Chief Security Officer who is responsible for the further development and implementation of corporate security policies and procedures that protect cyber assets. In addition, the Companies are subject to mandatory cybersecurity regulatory requirements, including those enacted in December 2018 by FERC with compliance requirements effective in 2020, interface regularly with a wide range of external organizations and participate in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. The Companies’ current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats. See Item 1A.
Item 1A. Risk Factors
The Companies’ businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond their control. A number of these factors have been identified below. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in Item 7. MD&A.
The Companies’ results of operations can be affected by changes in the weather. Fluctuations in weather can affect demand for the Companies’ services. For example, milder than normal weather can reduce demand for electricity and gas transmission and distribution services. In addition, severe weather, including hurricanes, winter storms, earthquakes, floods and other natural disasters can stress systems, disrupt operation of the Companies’ facilities and cause service outages, production delays and property damage that require incurring additional expenses. Changes in weather conditions can result in reduced water levels or changes in water temperatures that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level or sea temperatures.
The rates of Dominion Energy and Dominion Energy Gas’ gas transmission and distribution operations and Dominion Energy and Virginia Power’s electric transmission, distribution and generation operations are subject to regulatory review. Revenue provided by Dominion Energy and Virginia Power’s electric transmission, distribution and generation operations and Dominion Energy and Dominion Energy Gas’ gas transmission and distribution operations is based primarily on rates approved by state and federal regulatory agencies. However, certain large scale customers are able to enter into negotiated-rate contracts rather than pay cost-of-service rates which are subject to regulatory review. The profitability of these businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.
Dominion Energy and Virginia Power’s wholesale rates for electric transmission service are updated on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism, Dominion Energy and Virginia Power’s wholesale rates for electric transmission reflect the estimated cost-of-service for each calendar year. The difference in the estimated cost-of-service and actual cost-of-service for each calendar year is included as an adjustment to the wholesale rates for electric transmission service in a subsequent calendar year. These wholesale rates are subject to FERC review and prospective adjustment in the event that customers and/or interested state commissions file a complaint with FERC and are able to demonstrate that Dominion Energy or Virginia Power’s wholesale revenue requirement is no longer just and reasonable. They are also subject to retroactive corrections to the extent that the formula rate was not properly populated with the actual costs.
Similarly, various rates and charges assessed by Dominion Energy and Dominion Energy Gas’ gas transmission businesses are subject to review by FERC. In addition, the rates of Dominion Energy and Dominion Energy Gas’ gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate. A failure by Dominion Energy or Dominion Energy Gas to support these rates could result in rate decreases from current rate levels, which could adversely affect Dominion Energy and Dominion Energy Gas’ results of operations, cash flows and financial condition.
Virginia Power’s base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a historic test period, and the determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances described in the Regulation Act, Virginia Power may be required to share a portion of its earnings with customers through a refund process.
Dominion Energy and Virginia Power’s retail electric base rates for bundled generation, transmission, and distribution services to customers in South Carolina and North Carolina, respectively, are regulated on a cost-of-service/rate-of-return basis subject to South Carolina and North Carolina statutes, and the rules and procedures of the South Carolina and North Carolina Commissions. If retail electric earnings exceed the returns established by the South Carolina Commission and the North Carolina Commission, retail electric rates may be subject to review and
possible reduction by the South Carolina Commission and the North Carolina Commission, which may decrease Dominion Energy and Virginia Power’s future earnings, respectively. Additionally, if the South Carolina and the North Carolina Commission do not allow recovery through base rates, on a timely basis, of costs incurred in providing service, Dominion Energy and Virginia Power’s future earnings could be negatively impacted.
Governmental officials, stakeholders and advocacy groups may challenge these regulatory reviews. Such challenges may lengthen the time, complexity and costs associated with such regulatory reviews.
The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of operations and subject the Companies to monetary penalties. The Companies’ operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. Such laws and regulations govern the terms and conditions of the services we offer, our relationships with affiliates, protection of our critical electric infrastructure assets and pipeline safety, among other matters. These operations are also subject to legislation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that the business is conducted in accordance with applicable laws. The Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if any of the Companies is found not to be in compliance, including mandatory reliability standards and interaction in the wholesale markets. New laws or regulations, the revision or reinterpretation of existing laws or regulations, changes in enforcement practices of regulators, or penalties imposed for non-compliance with existing laws or regulations may result in substantial additional expense. Recent legislative and regulatory changes that are impacting the Companies include the 2017 Tax Reform Act and tariffs imposed on imported solar panels by the U.S. government in 2018.
The 2017 Tax Reform Act could have a material impact on our operations, cash flows, and financial results. Reductions in the estimated annual cost-of-service effect (commonly referred to as the gross-up factor) due to the reduction in the corporate income tax rates to 21% under the provisions of the 2017 Tax Reform Act have been recognized as a regulatory liability and are expected to be refunded to customers, generally through reductions in future rates or in the form of credits to customer bills. In addition, the Companies’ regulators may require the reduction in accumulated deferred income tax balances under the provisions of the 2017 Tax Reform Act to be shared with customers, generally through reductions in future rates or in the form of credits to customer bills. The 2017 Tax Reform Act includes provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential reductions in future rates attributable to other, non-plant related excess deferred taxes may be determined by our regulators.
The 2017 Tax Reform Act could have a material impact on Dominion Energy and Dominion Energy Gas’ FERC-regulated gas operations including rates charged to customers. In light of the reduction in the income tax rate in the 2017 Tax Reform Act, our FERC-regulated gas subsidiaries were required to file
informational reports to substantiate the rates charged for transportation and storage of natural gas in interstate commerce, when viewed holistically, are “just and reasonable” taking into account the effects of the 2017 Tax Reform Act and all other drivers. It is unclear if FERC will mandate a one-time rate reset or Section 5 rate case for Dominion Energy and Dominion Energy Gas’ FERC-regulated gas subsidiaries; however, any such action could have a material impact on our operations, cash flows and financial results.
The interpretation of provisions of the 2017 Tax Reform Act that take effect in 2019 may significantly impact our operations. The 2017 Tax Reform Act contains provisions that limit the deductibility of interest expense. The provisions generally limit the interest deduction on business interest to (1) business interest income, plus (2) 30 percent of the taxpayer’s adjusted taxable income. Business interest and business interest income is defined as that allocable to a trade or business and not investment interest and income. Dominion Energy is a consolidated group with both regulated and nonregulated lines of businesses. In November 2018, the U.S. Department of Treasury issued proposed regulations defining interest as any amounts associated with the time value of money or use of funds. These proposed regulations provide guidance for purposes of the exception to the interest limitation for regulated public utilities, the application of the interest limitation to consolidated groups, such as Dominion Energy, and the interest limitation with respect to partnerships and partners in those partnerships. It is unclear when that guidance may be finalized, or whether that guidance could result in a disallowance of a portion of our interest deductions in the future.
Dominion Energy and Virginia Power’s generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. Dominion Energy and Virginia Power’s generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs to make changes in market design. FERC also periodically reviews Dominion Energy’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets or its interpretation of market rules, Dominion Energy or Virginia Power’s authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of Dominion Energy or Virginia Power’s generation business. For example, in June 2018, FERC issued an order on PJM’s Minimum Offer Price Rule proposals finding the PJM tariff unjust and unreasonable because state out-of-market support for resources is suppressing PJM capacity prices and the current tariff provisions do not adequately address the price suppression. FERC is evaluating an alternative that would pull any state supported resource out of the capacity market along with an equivalent amount of load. In addition, there have been changes to the interpretation and application of FERC’s market manipulation rules. A failure to comply with these rules could lead to civil and criminal penalties.
The Companies’ infrastructure build and expansion plans often require regulatory approval, including environmental permits, before commencing construction and completing projects. The Companies may not complete facility construction, pipeline, conversion or other infrastructure projects that they commence, or they may complete projects on materially different terms or timing than initially anticipated, and they may not be able to achieve the intended benefits of any such project, if completed. Several facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects have been announced and additional projects may be considered in the future. The Companies compete for projects with companies of varying size and financial capabilities, including some that may have competitive advantages. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies, and such approvals could include mitigation costs which may be material to the Companies. Projects may not be able to be completed on time as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of counterparties or vendors, or other factors beyond the Companies’ control. For example, Atlantic Coast Pipeline has experienced certain delays in obtaining permits necessary for construction along with construction delays due to judicial actions which has impacted the cost and schedule for the Atlantic Coast Pipeline Project. Even if facility construction, pipeline, expansion, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations. Start-up and operational issues can arise in connection with the commencement of commercial operations at our facilities. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, the Companies may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects.
The development, construction and commissioning of several large-scale infrastructure projects simultaneously involves significant execution risk. The Companies are currently simultaneously developing, constructing or commissioning several major projects, including the Atlantic Coast Pipeline Project, the Supply Header project and the Coastal Virginia Offshore Wind project. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas or in difficult terrain, for example, the Atlantic Coast Pipeline Project. The advancement of the Companies’ ventures is also affected by the interventions, litigation or other activities of stakeholder and advocacy groups, some of which oppose natural gas-related and energy infrastructure projects. For example, certain landowners and stakeholder groups oppose the Atlantic Coast Pipeline
Project, which could impede construction activities or the acquisition of rights-of-way and other land rights on a timely basis or on acceptable terms. Given that these projects provide the foundation for the Companies’ strategic growth plan, if the Companies are unable to obtain or maintain the required approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies’ financial position, results of operations and cash flows. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect the Companies’ ability to execute their business plan.
The Companies are dependent on their contractors for the successful and timely completion of large-scale infrastructure projects. The construction of such projects is expected to take several years, is typically confined within a limited geographic area or difficult terrain and could be subject to delays, cost overruns, labor disputes and other factors that could cause the total cost of the project to exceed the anticipated amount and adversely affect the Companies’ financial performance and/or impair the Companies’ ability to execute the business plan for the project as scheduled.
Further, an inability to obtain financing or otherwise provide liquidity for the projects on acceptable terms could negatively affect the Companies’ financial condition, cash flows, the projects’ anticipated financial results and/or impair the Companies’ ability to execute the business plan for the projects as scheduled.
The Companies’ operations and construction activities are subject to a number of environmental laws and regulations which impose significant compliance costs to the Companies. The Companies’ operations and construction activities are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of environmental control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and the Companies expect that they will remain significant in the future. Certain facilities have become uneconomical to operate and have been shut down, converted to new fuel types or sold. These types of events could occur again in the future.
We expect that existing environmental laws and regulations may be revised and/or new laws may be adopted including regulation of GHG emissions which could have an impact on the Companies’ business. Risks relating to expected regulation of GHG emissions from existing fossil fuel-fired electric generating units are discussed below. In addition, further regulation of air quality and GHG emissions under the CAA have been imposed on the natural gas sector, including rules to limit methane leakage. The Companies are also subject to federal water and waste regulations, including regulations concerning cooling water intake structures, coal combustion by-product handling and disposal
practices, wastewater discharges from steam electric generating stations, management and disposal of hydraulic fracturing fluids and the potential further regulation of polychlorinated biphenyls.
Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new environmental rules or regulations. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liabilities on all responsible parties. However, such expenditures, if material, could make the Companies’ facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect the Companies’ results of operations, financial performance or liquidity.
Any additional federal and/or state requirements imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements may result in compliance costs that alone or in combination could make some of the Companies’ electric generation units or natural gas facilities uneconomical to maintain or operate. The EPA has proposed the Affordable Clean Energy rule targeted at reducing CO2 emissions from existing fossil fuel-fired power generation facilities as a replacement for the Clean Power Plan which has been stayed. The Affordable Clean Energy rule would require states to develop plans within three years of the final rule to implement these performance standards. States are also contemplating regulations regarding GHG emissions. For example, the Virginia General Assembly recently considered legislation which would authorize the state to directly join the RGGI program as a full participant. Compliance with the proposed Affordable Clean Energy rule or other federal or state carbon regulations is expected to require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon reduction programs, purchase of allowances and/or emission rate credits, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower-emitting generation facilities. Given these developments and uncertainties, Dominion Energy and Virginia Power cannot estimate the aggregate effect of such requirements on their results of operations, financial condition or their customers. However, such expenditures, if material, could make Dominion Energy and Virginia Power’s generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion Energy or Virginia Power’s results of operations, financial performance or liquidity.
There are also potential impacts on Dominion Energy and Dominion Energy Gas’ natural gas businesses as federal or state GHG regulations may require GHG emission reductions from the natural gas sector which, in addition to resulting in increased costs, could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products, which could impact the natural gas businesses.
Dominion Energy and Virginia Power are subject to risks associated with the disposal and storage of coal ash. Dominion Energy and Virginia Power historically produced and continue to produce coal ash, or CCRs, as a by-product of their coal-fired generation operations. The ash is stored and managed in
impoundments (ash ponds) and landfills located at 11 different facilities, eight of which are at Virginia Power.
The EPA has issued regulations concerning the management and storage of CCRs, which Virginia has adopted. These CCR regulations require Dominion Energy and Virginia Power to make additional capital expenditures and increase operating and maintenance expenses. In addition, Dominion Energy and Virginia Power will incur expenses and other costs associated with closing, corrective action and ongoing monitoring of certain ash ponds. Dominion Energy and Virginia Power also may face litigation concerning their coal ash facilities.
Further, while Dominion Energy and Virginia Power operate their ash ponds and landfills in compliance with applicable state safety regulations, a release of coal ash with a significant environmental impact, such as the Dan River ash basin release by a neighboring utility, could result in remediation costs, civil and/or criminal penalties, claims, litigation, increased regulation and compliance costs, and reputational damage, and could impact the financial condition of Dominion Energy and/or Virginia Power.
The Companies’ operations are subject to operational hazards, equipment failures, supply chain disruptions and personnel issues which could negatively affect the Companies. Operation of the Companies’ facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply, pipeline integrity or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, changes to the environment and performance below expected levels. The Companies’ businesses are dependent upon sophisticated information technology systems and network infrastructure, the failure of which could prevent them from accomplishing critical business functions. Because the Companies’ transmission facilities, pipelines and other facilities are interconnected with those of third parties, the operation of their facilities and pipelines could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
Operation of the Companies’ facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of the Companies’ facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less output or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement output from third parties in the open market to satisfy forward energy and capacity or other contractual obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.
In addition, there are many risks associated with the Companies’ operations and the transportation, storage and processing of natural gas and NGLs, including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environ-
mental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk. Further, the location of pipelines and storage facilities, or generation, transmission, substations and distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.
Dominion Energy and Virginia Power have substantial ownership interests in and operate nuclear generating units; as a result, each may incur substantial costs and liabilities. Dominion Energy and Virginia Power’s nuclear facilities are subject to operational, environmental, health and financial risks such as the on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. Dominion Energy and Virginia Power maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If Dominion Energy and Virginia Power’s decommissioning trust funds are insufficient, and they are not allowed to recover the additional costs incurred through insurance or regulatory mechanisms, their results of operations could be negatively impacted.
Dominion Energy and Virginia Power’s nuclear facilities are also subject to complex government regulation which could negatively impact their results of operations. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending on its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require Dominion Energy and Virginia Power to make substantial expenditures at their nuclear plants. In addition, although the Companies have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could materially and adversely affect their results of operations and/or financial condition. A major incident at a nuclear facility anywhere in the world, such as the nuclear events in Japan in 2011, could cause the NRC to adopt increased safety regulations or otherwise limit or restrict the operation or licensing of domestic nuclear units.
Sustained declines in natural gas and NGL prices have resulted in, and could result in further, curtailments of third-party producers’ drilling programs, delaying the production of volumes of natural gas and NGLs that Dominion Energy and Dominion Energy Gas gather, process, and transport and reducing the value of NGLs retained by Dominion Energy Gas, which may adversely affect Dominion Energy and Dominion
Energy Gas’ revenues and earnings. Dominion Energy and Dominion Energy Gas obtain their supply of natural gas and NGLs from numerous third-party producers. Most producers are under no obligation to deliver a specific quantity of natural gas or NGLs to Dominion Energy and Dominion Energy Gas’ facilities. A number of other factors could reduce the volumes of natural gas and NGLs available to Dominion Energy and Dominion Energy Gas’ pipelines and other assets. Increased regulation of energy extraction activities could result in reductions in drilling for new natural gas wells, which could decrease the volumes of natural gas supplied to Dominion Energy and Dominion Energy Gas. Producers with direct commodity price exposure face liquidity constraints, which could present a credit risk to Dominion Energy and Dominion Energy Gas. Producers could shift their production activities to regions outside Dominion Energy and Dominion Energy Gas’ footprint. In addition, the extent of natural gas reserves and the rate of production from such reserves may be less than anticipated. If producers were to decrease the supply of natural gas or NGLs to Dominion Energy and Dominion Energy Gas’ systems and facilities for any reason, Dominion Energy and Dominion Energy Gas could experience lower revenues to the extent they are unable to replace the lost volumes on similar terms. In addition, Dominion Energy Gas’ revenue from processing and fractionation operations largely results from the sale of commodities at market prices. Dominion Energy Gas receives the wet gas product from producers and may retain the extracted NGLs as compensation for its services. This exposes Dominion Energy Gas to commodity price risk for the value of the spread between the NGL products and natural gas, and relative changes in these prices could adversely impact Dominion Energy Gas’ results.
Dominion Energy’s merchant power business operates in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion Energy’s merchant power business depends upon favorable market conditions including the ability to sell power at prices sufficient to cover its operating costs. Dominion Energy operates in active wholesale markets that expose it to price volatility for electricity and nuclear fuel as well as the credit risk of counterparties. Dominion Energy attempts to manage its price risk by entering into hedging transactions, including short-term and long-term fixed price sales and purchase contracts.
In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion Energy does not enter into long-term power purchase agreements or otherwise effectively hedge its output, these changes in market prices could adversely affect its financial results.
Dominion Energy purchases nuclear fuel primarily under long-term contracts. Dominion Energy is exposed to nuclear fuel cost volatility for the portion of its nuclear fuel obtained through short-term contracts or on the spot market, including as a result
of market supply shortages. Nuclear fuel prices can be volatile and the price that can be obtained for power produced may not change at the same rate as nuclear fuel costs, thus adversely impacting Dominion Energy’s financial results. In addition, in the event that any of the merchant generation facilities experience a forced outage, Dominion Energy may not receive the level of revenue it anticipated.
The Companies’ financial results can be adversely affected by various factors driving supply and demand for electricity and gas and related services. Technological advances required by federal laws mandate new levels of energy efficiency in end-use devices, including lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Further, Virginia Power’s business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility generation. However, advances in distributed generation technologies, such as solar cells, gas microturbines and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use our services. Virginia Power has an exclusive franchise to serve retail electric customers in Virginia. However, Virginia’s Retail Access Statutes allow certain Power Generation customers exceptions to this franchise. As market conditions change, Virginia Power’s customers may further pursue exceptions and Virginia Power’s exclusive franchise may erode.
Reduced energy demand or significantly slowed growth in demand due to customer adoption of energy efficient technology, conservation, distributed generation, regional economic conditions, or the impact of additional compliance obligations, unless substantially offset through regulatory cost allocations, could adversely impact the value of the Companies’ business activities.
Dominion Energy Gas has experienced a decline in demand for certain of its processing services due to competing facilities operating in nearby areas.
Dominion Energy and Dominion Energy Gas may not be able to maintain, renew or replace their existing portfolio of customer contracts successfully, or on favorable terms. Upon contract expiration, customers may not elect to re-contract with Dominion Energy and Dominion Energy Gas as a result of a variety of factors, including the amount of competition in the industry, changes in the price of natural gas, their level of satisfaction with Dominion Energy and Dominion Energy Gas’ services, the extent to which Dominion Energy and Dominion Energy Gas are able to successfully execute their business plans and the effect of the regulatory framework on customer demand. The failure to replace any such customer contracts on similar terms or with counterparties with similar credit profiles could result in a loss of revenue for Dominion Energy and Dominion Energy Gas and related decreases in their earnings and cash flows.
Certain of Dominion Energy and Dominion Energy Gas’ gas pipeline services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if the cost to perform such services exceeds the revenues received from such contracts. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or
below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as a result of these “negotiated rate” contracts could decrease Dominion Energy and Dominion Energy Gas’ earnings and cash flows.
Dominion Energy and Dominion Energy Gas conduct certain operations through joint ventures that may limit our operational flexibility. Certain operations are conducted through joint venture arrangements, such as Atlantic Coast Pipeline and Iroquois, to which Dominion Energy and Dominion Energy Gas have significant influence but do not control the operations of such entities. The joint ventures operate in accordance with the applicable governing provisions of each entity. Accordingly, Dominion Energy and Dominion Energy Gas may have limited ability to influence or control certain day to day activities affecting the operations and do have not unilateral control over decisions that may have a material financial impact on the joint venture participants. Dominion Energy and Dominion Energy Gas are dependent upon third parties satisfying their respective obligations, including, as applicable, funding of their required share of capital expenditures. In addition, Dominion Energy and Dominion Energy Gas may be subject to restrictions or limitations on their ability to sell or transfer their interests in the joint venture arrangements. The third-party participants in the joint ventures have their own interests and objectives which may differ from those of Dominion Energy and Dominion Energy Gas. Accordingly, any disputes amongst the joint venture partners may result in delays, litigation or operational impasses.
Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. The Companies are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Some of Dominion Energy’s operations are conducted through less than wholly-owned subsidiaries, as noted above. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Defaults or failure to perform by customers, suppliers, contractors, joint venture partners, financial institutions or other third parties may adversely affect the Companies’ financial results.
Dominion Energy is exposed to counterparty credit risk relating to the terminal services agreements for the Liquefaction Project. While the counterparties’ obligations are supported by parental guarantees and letters of credit, there is no assurance that such credit support would be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under either agreement resulting in a judgment in Dominion Energy’s favor, Dominion Energy may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process.
Market performance and other changes may decrease the value of Dominion Energy and Virginia Power’s decommissioning trust funds and Dominion Energy and Dominion Energy Gas’ benefit plan assets or increase Dominion Energy and Dominion Energy Gas’ liabilities, which could then require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trusts to
satisfy future obligations to decommission Dominion Energy and Virginia Power’s nuclear plants and under Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans. The Companies have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates.
With respect to decommissioning trust funds, a decline in the market value of these assets may increase the funding requirements of the obligations to decommission Dominion Energy and Virginia Power’s nuclear plants or require additional NRC-approved funding assurance.
A decline in the market value of the assets held in trusts to satisfy future obligations under Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates will affect the liabilities under Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in mortality assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans.
If the decommissioning trust funds and benefit plan assets are negatively impacted by market fluctuations or other factors, the Companies’ results of operations, financial condition and/or cash flows could be negatively affected.
The use of derivative instruments could result in financial losses and liquidity constraints. The Companies use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity, currency and financial market risks. In addition, Dominion Energy and Dominion Energy Gas purchase and sell commodity-based contracts for hedging purposes.
The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The CEA, as amended by Title VII of the Dodd-Frank Act, requires certain over-the-counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, may elect the end-user exception to the CEA’s clearing requirements. The Companies have elected to exempt their swaps from the CEA’s clearing requirements. If, as a result of changes to the rulemaking process, the Companies’ derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs due to decreased market liquidity or increased margin payments. In addition, the Companies’ swap dealer counterparties may attempt to pass-through additional trading costs in connection with changes to or the elimination of rulemaking that implements Title VII of the Dodd-Frank Act.
Changing rating agency requirements could negatively affect the Companies’ growth and business strategy. In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, the Companies may find it necessary to take steps or change their
business plans in ways that may adversely affect their growth and earnings. A reduction in the Companies’ credit ratings could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require the Companies to post additional collateral in connection with some of its price risk management activities.
An inability to access financial markets could adversely affect the execution of the Companies’ business plans. The Companies rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for business plans with increasing capital expenditure needs, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of the Companies’ control could increase their cost of borrowing or restrict their ability to access one or more financial markets. Further market disruptions could stem from delays in the current economic recovery, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, or the failure of financial institutions on which the Companies rely. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.
Potential changes in accounting practices may adversely affect the Companies’ financial results. The Companies cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or their operations specifically. New accounting standards could be issued that could change the way they record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect earnings or could increase liabilities.
War, acts and threats of terrorism, intentional acts and other significant events could adversely affect the Companies’ operations. The Companies cannot predict the impact that any future terrorist attacks may have on the energy industry in general, or on the Companies’ business in particular. Any retaliatory military strikes or sustained military campaign may affect the Companies’ operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets. In addition, the Companies’ infrastructure facilities, including projects under construction, could be direct targets of, or indirect casualties of, an act of terror. For example, there have been multiple instances of vandalism or attempted sabotage on third-party oil and gas pipelines either under construction or in operation. Furthermore, the physical compromise of the Companies’ facilities could adversely affect the Companies’ ability to manage these facilities effectively. Instability in financial markets as a result of terrorism, war, intentional acts, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy and increase the cost of insurance coverage. This could negatively impact the Companies’ results of operations and financial condition.
Hostile cyber intrusions could severely impair the Companies’ operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on the Companies’ business.
The Companies own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run the Companies’ facilities are not completely isolated from external networks. There appears to be an increasing level of activity, sophistication and maturity of threat actors, in particular nation state actors, that wish to disrupt the U.S. bulk power system and the U.S. gas transmission or distribution system. Such parties could view the Companies’ computer systems, software or networks as attractive targets for cyber attack. For example, malware has been designed to target software that runs the nation’s critical infrastructure such as power transmission grids and gas pipelines. In addition, the Companies’ businesses require that they and their vendors collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.
A successful cyber attack on the systems that control the Companies’ electric generation, electric or gas transmission or distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data at the Companies or one of their vendors could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. While the Companies maintain property and casualty insurance, along with other contractual provisions, that may cover certain damage caused by potential cyber incidents, all damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect the Companies’ business, financial condition and results of operations.
Failure to attract and retain key executive officers and an appropriately qualified workforce could have an adverse effect on the Companies’ operations. The Companies’ business strategy is dependent on their ability to recruit, retain and motivate employees. The Companies’ key executive officers are the CEO, CFO and presidents and those responsible for financial, operational, legal, regulatory and accounting functions. Competition for skilled management employees in these areas of the Companies’ business operations is high. Certain events, such as an aging workforce, mismatch of skill set, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base and the length of time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or future availability and cost of contract labor may adversely affect the ability to manage and operate the Companies’ business. In addition, certain specialized knowledge is required of the Companies’ technical employees for construction and oper-
ation of transmission, generation and distribution assets. The Companies’ inability to attract and retain these employees could adversely affect their business and future operating results.
Following the SCANA Combination, Dominion Energy may be unable to successfully integrate SCANA’s businesses. Dominion Energy is devoting significant management attention and resources to integrating SCANA’s businesses. While Dominion Energy has assumed that a certain level of transaction and integration expenses will be incurred, there are a number of factors beyond its control that could affect the total amount or the timing of its integration expenses. Potential difficulties Dominion Energy may encounter in the integration process include the following:
•
The complexities associated with integrating SCANA, including its utility businesses, while at the same time continuing to provide consistent, high quality services;
•
The complexities of integrating a company with different markets and customers;
•
The inability to attract and retain key employees;
•
Potential unknown liabilities and unforeseen increased expenses associated with the SCANA Combination;
•
Difficulties in managing political and regulatory conditions related to SCANA’s utility businesses;
•
The moratorium on filing requests for adjustments in SCE&G’s base electric rates until May 2020 with no changes in rates until January 1, 2021, which limits Dominion Energy’s ability to recover increases in non-fuel related costs of electric operations for SCE&G’s customers;
•
The stipulation agreement approved by the North Carolina Commission, which provides for a rate moratorium at PSNC until November 1, 2021, with certain exceptions; and
•
Performance shortfalls as a result of the diversion of Dominion Energy management’s attention caused by integrating SCANA’s businesses.
For these reasons, it is possible that the integration process could result in the distraction of Dominion Energy’s management, the disruption of Dominion Energy’s ongoing business or inconsistencies in its services, standards, controls, procedures and policies, any of which could adversely affect the ability of Dominion Energy to maintain or establish relationships with current and prospective customers, vendors and employees or could otherwise adversely affect the business and financial results of Dominion Energy.
Dominion Energy may be materially adversely affected by negative publicity related to the SCANA Combination and in connection with other related matters, including the abandonment of the NND Project. From time to time, political and public sentiment in connection with the merger and in connection with other matters, including the abandonment of the NND Project, may result in a significant amount of adverse press coverage and other adverse public statements affecting Dominion Energy. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceedings, as well as responding to and addressing adverse press coverage and other adverse public statements, can divert the time and effort of senior management from the management of Dominion Energy’s business.
Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of Dominion Energy, on the morale and performance of their employees and on their relationships with their respective regulators, customers and commercial counterparties. It may also have a negative impact on their ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on Dominion Energy’s business, financial condition and results of operations.
The SCANA Combination may not be accretive to operating earnings and may cause dilution to Dominion Energy’s earnings per share, which may negatively affect the market price of Dominion Energy common stock. Dominion Energy currently anticipates that the SCANA Combination will be immediately accretive to Dominion Energy’s forecasted operating earnings per share on a standalone basis. This expectation is based on preliminary estimates, which may materially change. Dominion Energy may encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates or its ability to realize operational efficiencies. Any of these factors could cause a decrease in Dominion Energy’s operating earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Dominion Energy’s common stock. Dominion Energy expects the initial effect of the SCANA Combination on its GAAP earnings will be a decrease in such earnings due to the anticipated charges for refunds to SCE&G customers and transaction and transition costs.
Through the SCANA Combination, Dominion Energy acquired SCANA and SCE&G which are subject to numerous legal proceedings and ongoing governmental investigations and examinations. SCANA and SCE&G are defendants in numerous federal and state legal proceedings and governmental investigations relating to the decision to abandon construction at the
NND Project. Among other things, the lawsuits and investigations allege misrepresentation, failure to properly manage the NND Project, unfair trade practices and violation of anti-trust laws. The plaintiffs seek a judgment that SCE&G may not charge its customers for any past or continuing costs of the NND Project, among other remedies.
Additionally, SCANA and SCE&G are defendants in federal and state legal proceedings relating to the SCANA Combination. Among other things, the lawsuits allege breaches of various fiduciary duties. Remedies sought include rescinding the SCANA Combination.
The outcome of these legal proceedings, investigations and examinations is uncertain and may adversely affect Dominion Energy’s financial condition or results of operation.
Dominion Energy has goodwill and other intangible assets on its balance sheet, and these amounts will increase as a result of the SCANA Combination. If its goodwill or other intangible assets become impaired in the future, Dominion Energy may be required to record a significant, non-cash charge to earnings and reduce its shareholders’ equity. Dominion Energy will record as goodwill the excess of the purchase price paid by Dominion Energy over the fair value of SCANA’s assets and liabilities as determined for financial accounting purposes in its Consolidated Balance Sheet beginning in the first quarter of 2019. Under GAAP, intangible assets are reviewed for impairment on an annual basis or more frequently whenever events or circumstances indicate that its carrying value may not be recoverable. If Dominion Energy’s intangible assets, including goodwill as a result of the SCANA Combination, are determined to be impaired in the future, Dominion Energy may be required to record a significant, non-cash charge to earnings during the period in which the impairment is determined.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
As of December 31, 2018, Dominion Energy owned its principal executive office in Richmond, Virginia and five other corporate offices. Dominion Energy also leases corporate offices in other cities in which its subsidiaries operate. Virginia Power and Dominion Energy Gas share Dominion Energy’s principal office in Richmond, Virginia, which is owned by Dominion Energy. In addition, Virginia Power’s Power Delivery and Power Generation segments share certain leased buildings and equipment.
Dominion Energy’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described below.
Certain of Virginia Power’s properties are subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2018; however, by leaving the indenture open, Virginia Power expects to retain the flexibility to issue mortgage bonds in the future. Certain of Dominion Energy’s merchant generation facilities are also subject to liens. Additionally, SCE&G’s bond indenture, which secures its First Mortgage Bonds, constitutes a direct mortgage lien on substantially all of its electric utility property. GENCO’s Williams Station is also subject to a first mortgage lien which secures certain outstanding debt of GENCO.
POWER DELIVERY
Virginia Power has approximately 6,700 miles of electric transmission lines of 69 kV or more located in North Carolina, Virginia and West Virginia. Portions of Virginia Power’s electric transmission lines cross national parks and forests under permits
entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.
In addition, Virginia Power’s electric distribution network includes approximately 58,300 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, Virginia Power owns 475 substations.
POWER GENERATION
Dominion Energy and Virginia Power generate electricity for sale on a wholesale and a retail level. Dominion Energy and Virginia Power supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2018, Power Generation’s total utility, non-jurisdictional and merchant generating capacity was approximately 26,000 MW. The following tables list Power Generation’s utility, non-jurisdictional and merchant generating units and capability, as of December 31, 2018.
VIRGINIA POWER UTILITY GENERATION
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) Virginia Power has placed certain units at this facility in cold storage.
(2) Coal-fired units are expected to be retired at Yorktown power station as early as 2019 as a result of the issuance of MATS.
(3) Excludes 50% undivided interest owned by ODEC.
(4) Excludes 11.6% undivided interest owned by ODEC.
(5) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of FirstEnergy Corp.
VIRGINIA POWER NON-JURISDICTIONAL GENERATION
(1) All solar facilities are alternating current.
DOMINION ENERGY MERCHANT GENERATION
(1) Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain.
(2) All solar facilities are alternating current.
(3) Excludes 50% noncontrolling interest owned by GIP. Dominion Energy’s interest is subject to a lien securing Dominion Solar Projects III, Inc.’s debt.
(4) Excludes 33% noncontrolling interest owned by Terra Nova Renewable Partners. Dominion Energy’s interest is subject to a lien securing SBL Holdco’s debt.
(5) Dominion Energy’s interest is subject to a lien securing Eagle Solar’s debt.
(6) Subject to a lien securing the facility’s debt.
(7) Excludes 50% membership interest owned by BP.
(8) Excludes 50% membership interest owned by Shell.
GAS INFRASTRUCTURE
Dominion Energy and Dominion Energy Gas
East Ohio’s gas distribution network is located in Ohio. This network involves approximately 18,900 miles of pipe, exclusive of service lines. The right-of-way grants for many natural gas pipelines have been obtained from the actual owners of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.
Dominion Energy Gas has approximately 10,800 miles, excluding interests held by others, of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy Gas also owns NGL processing plants capable of processing over 270,000 mcf per day of natural gas. Hastings is the largest plant and is capable of processing over 180,000 mcf per day of natural gas. Hastings can also fractionate over 580,000 Gals per day of NGLs into marketable products, including propane, isobutane, butane and natural gasoline. NGL operations have storage capacity of 1,340,000 Gals of propane, 118,000 Gals of isobutane, 242,000 Gals of butane, 2,000,000 Gals of natural gasoline and 1,012,500 Gals of mixed NGLs. Dominion Energy Gas also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with approximately 2,000 storage wells and approximately 399,000 acres of operated leaseholds.
The total designed capacity of the underground storage fields operated by Dominion Energy Gas is approximately 926 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy Gas. The capacity of those fields owned by Dominion Energy Gas’ partners totals approximately 223 bcf.
Dominion Energy
Cove Point’s LNG Facility has an operational peak regasification daily send-out capacity of approximately 1.8 million Dths and an aggregate LNG storage capacity of approximately 14.6 bcfe. In addition, Cove Point has a liquefier that has the potential to create approximately 15,000 Dths/day. The Liquefaction Project consists of one LNG train with a nameplate outlet capacity of 5.25 Mtpa. Cove Point has authorization from the DOE to export up to 0.77 Bcfe/day (approximately 5.75 Mtpa) should the liquefaction facilities perform better than expected.
The Cove Point Pipeline is a 36-inch diameter underground, interstate natural gas pipeline that extends approximately 88 miles
from Cove Point to interconnections with Transco in Fairfax County, Virginia, and with Columbia Gas Transmission, LLC and DETI in Loudoun County, Virginia. In 2009, the original pipeline was expanded to include a 36-inch diameter expansion that extends approximately 48 miles, roughly 75% of which is parallel to the original pipeline.
Dominion Energy Questar Pipeline operates 2,200 miles of natural gas transportation pipelines that interconnect with other pipelines in Utah, Wyoming and western Colorado. Dominion Energy Questar Pipeline’s system ranges in diameter from lines that are less than four inches to 36-inches. Dominion Energy Questar Pipeline owns the Clay Basin storage facility in northeastern Utah, which has a certificated capacity of 120 bcf, including 54 bcf of working gas.
DECG’s interstate natural gas pipeline system in South Carolina and southeastern Georgia is comprised of nearly 1,500 miles of transmission pipeline.
Questar Gas owns and operates distribution systems in Utah, Wyoming and Idaho with a total of 30,100 miles of street mains, service lines and interconnecting pipelines.
Hope’s gas distribution network located in West Virginia is comprised of 3,200 miles of pipe, exclusive of service lines.
In total, Dominion Energy has 172 compressor stations with approximately 1,340,000 installed compressor horsepower.
SOUTHEAST ENERGY
SCE&G has approximately 3,500 miles and 26,500 miles of electric transmission and distribution lines, respectively, exclusive of service level lines, in South Carolina. The grants for most of SCE&G’s electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying property titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, SCE&G owns 440 substations.
SCE&G and PSNC’s natural gas system includes approximately 1,100 miles of transmission pipeline of up to 24 inches in diameter that connect their distribution systems with Southern Natural Gas Company, Transco and DECG. SCE&G and PSNC’s natural gas distribution system consists of approximately 40,600 miles of distribution mains and related service facilities.
SCE&G owns two LNG facilities, one located near Charleston, South Carolina, and the other in Salley, South Carolina. The Charleston facility can store the liquefied equivalent of 1.0 bcf of natural gas, can regasify approximately 6% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day. The Salley facility can store the liquefied equivalent of 0.9 bcf of natural gas and can regasify approximately 10% of its storage capacity per day. The Salley facility has no liquefying capabilities.
PSNC owns one LNG facility that stores the liquefied equivalent of 1.0 bcf of natural gas, can regasify approximately 10% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day.
To meet the requirements of their high priority natural gas customers during periods of maximum demand, SCE&G and
PSNC have contracted for approximately 6 bcf of natural gas storage capacity on the systems of Southern Natural Gas Company and Transco.
Dominion Energy acquired through the SCANA Combination total utility generating capacity of approximately 6,000 MW, as detailed in the following table:
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) Capable of burning fuel oil as a secondary source.
(2) Capable of burning natural gas as a secondary source.
(3) Excludes 33.3% undivided interest owned by Santee Cooper.
Item 3.
Item 3. Legal Proceedings
From time to time, the Companies are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Companies, or permits issued by various local, state and/or federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Companies and their subsidiaries are involved in various legal proceedings.
See Notes 13 and 22 to the Consolidated Financial Statements and Future Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference, for discussion of various legal, environmental and other regulatory proceedings to which the Companies are a party. See also Note 3 to the Consolidated Financial Statements, which information is incorporated herein by reference, for a discussion of various legal proceedings to which SCANA and SCE&G were a party to at the closing of the SCANA Combination.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
Executive Officers of Dominion Energy
Information concerning the executive officers of Dominion Energy, each of whom is elected annually, is as follows:
(1) All positions held at Dominion Energy, unless otherwise noted. Any service listed for Virginia Power, DETI, East Ohio, Dominion Cove Point, Inc., and DES reflects service at a subsidiary of Dominion Energy.
Part II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Dominion Energy
Dominion Energy’s common stock is listed on the NYSE under the ticker symbol D. At February 15, 2019, there were approximately 137,000 record holders of Dominion Energy’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion Energy’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion Energy Direct®. Discussions of expected dividend payments required by this Item are contained in Liquidity and Capital Resources in Item 7. MD&A.
The following table presents certain information with respect to Dominion Energy’s common stock repurchases during the fourth quarter of 2018:
(1) 27,800, 3,630 and 1,494 shares were tendered by employees to satisfy tax withholding obligations on vested restricted stock in October, November and December 2018, respectively.
(2) Represents the weighted-average price paid per share.
(3) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Energy Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion Energy Board of Directors was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion.
Virginia Power
There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion Energy. Virginia Power intends to pay quarterly cash dividends in 2019 but is neither required to nor restricted, except as described in Note 20 to the Consolidated Financial Statements, from making such payments.
Dominion Energy Gas
All of Dominion Energy Gas’ membership interests are owned by Dominion Energy. Dominion Energy Gas intends to pay quarterly cash dividends in 2019 but is neither required to nor restricted, except as described in Note 20 to the Consolidated Financial Statements, from making such payments.
Item 6.
Item 6. Selected Financial Data
The following table should be read in conjunction with the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.
Beginning in 2019, Dominion Energy’s result of operations will include the results of operations of SCANA. Additionally, in connection with the SCANA Combination, SCE&G will provide refunds and restitution of $2.0 billion over 20 years with capital support from Dominion Energy as well as exclude from rate recovery $2.4 billion of costs related to the NND Project and $180 million of costs associated with the purchase of the Columbia Energy Center power station. See Note 3 to the Consolidated Financial Statements for further information including charges expected to be recognized in the first quarter of 2019.
DOMINION ENERGY
(1) Includes $568 million after-tax gains on sales of certain merchant generation facilities and equity method investments partially offset by $164 million after-tax charge related to the impairment of certain gathering and processing assets and a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.
(2) Includes $851 million of tax benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate, partially offset by $96 million of after-tax charges associated with equity method investments in wind-powered generation facilities.
(3) Includes a $122 million after-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities.
(4) Includes $248 million of after-tax charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, a $193 million after-tax charge related to Dominion Energy’s restructuring of its producer services business and a $174 million after-tax charge associated with the Liability Management Exercise.
(5) Includes capital leases.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
MD&A discusses Dominion Energy’s results of operations and general financial condition and Virginia Power and Dominion Energy Gas’ results of operations. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power and Dominion Energy Gas meet the conditions to file under the reduced disclosure format, and therefore have omitted certain sections of MD&A.
CONTENTS OF MD&A
MD&A consists of the following information:
•
Forward-Looking Statements
•
Accounting Matters-Dominion Energy
•
Dominion Energy
•
Results of Operations
•
Segment Results of Operations
•
Virginia Power
•
Results of Operations
•
Dominion Energy Gas
•
Results of Operations
•
Liquidity and Capital Resources-Dominion Energy
•
Future Issues and Other Matters-Dominion Energy
FORWARD-LOOKING STATEMENTS
This report contains statements concerning the Companies’ expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words.
The Companies make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:
•
Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;
•
Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities;
•
Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;
•
Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances;
•
Cost of environmental compliance, including those costs related to climate change;
•
Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;
•
Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;
•
Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;
•
Unplanned outages at facilities in which the Companies have an ownership interest;
•
Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy and Dominion Energy Gas’ earnings and the Companies’ liquidity position and the underlying value of their assets;
•
Counterparty credit and performance risk;
•
Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;
•
Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;
•
Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion Energy and Virginia Power and in benefit plan trusts by Dominion Energy and Dominion Energy Gas;
•
Fluctuations in interest rates or foreign currency exchange rates;
•
Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;
•
Changes in financial or regulatory accounting principles or policies imposed by governing bodies;
•
Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;
•
Risks of operating businesses in regulated industries that are subject to changing regulatory structures;
•
Impacts of acquisitions, including the recently completed SCANA Combination, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews;
•
Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;
•
Changes in rules for RTOs and ISOs in which Dominion Energy and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;
•
Political and economic conditions, including inflation and deflation;
•
Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;
•
Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy and Dominion Energy Gas’ pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;
•
Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;
•
Competition in the development, construction and ownership of certain electric transmission facilities in Dominion Energy and Virginia Power’s service territories in connection with Order 1000;
•
Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;
•
Changes to regulated electric rates collected by Dominion Energy and Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas;
•
Changes in operating, maintenance and construction costs;
•
Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals;
•
The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement or intervention in such projects;
•
Adverse outcomes in litigation matters or regulatory proceedings, including matters acquired in the SCANA Combination; and
•
The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events.
Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.
The Companies’ forward-looking statements are based on beliefs and assumptions using information available at the time the statements are made. The Companies caution the reader not to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. The Companies undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.
ACCOUNTING MATTERS
Critical Accounting Policies and Estimates
Dominion Energy has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions. Dominion Energy has discussed the development, selection
and disclosure of each of these policies with the Audit Committee of its Board of Directors.
ACCOUNTING FOR REGULATED OPERATIONS
The accounting for Dominion Energy’s regulated electric and gas operations differs from the accounting for nonregulated operations in that Dominion Energy is required to reflect the effect of rate regulation in its Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.
Dominion Energy evaluates whether or not recovery of its regulatory assets through future rates is probable and makes various assumptions in its analysis. The expectations of future recovery are generally based on orders issued by regulatory commissions, legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.
ASSET RETIREMENT OBLIGATIONS
Dominion Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists and the ARO can be reasonably estimated. These AROs are recognized at fair value as incurred or when sufficient information becomes available to determine fair value and are generally capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Dominion Energy estimates the fair value of its AROs using present value techniques, in which it makes various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. The impact on measurements of new AROs or remeasurements of existing AROs, using different cost escalation or credit-adjusted risk free rates in the future, may be significant. When Dominion Energy revises any assumptions used to calculate the fair value of existing AROs, it adjusts the carrying amount of both the ARO liability and the related long-lived asset for assets that are in service; for assets that have ceased operations, Dominion Energy adjusts the carrying amount of the ARO liability with such changes recognized in income. Dominion Energy accretes the ARO liability to reflect the passage of time. In 2018, Dominion Energy recorded an increase in AROs of $140 million primarily related to future ash pond and landfill closure costs at certain generation facilities. See Note 22 to the Consolidated Financial Statements for additional information.
In 2018, 2017 and 2016, Dominion Energy recognized $119 million, $117 million and $104 million, respectively, of accretion, and expects to recognize approximately $145 million in 2019. Dominion Energy records accretion and depreciation associated with utility nuclear decommissioning AROs and regulated pipeline replacement AROs as an adjustment to the regulatory liabilities related to these items.
A significant portion of Dominion Energy’s AROs relates to the future decommissioning of its merchant and utility nuclear facilities. These nuclear decommissioning AROs are reported in the Power Generation segment. Subsequent to the SCANA Combination, SCANA’s nuclear decommissioning AROs will be reported in the Southeast Energy segment. At December 31, 2018, Dominion Energy’s nuclear decommissioning AROs totaled $1.6 billion, representing approximately 62% of its total AROs. Subsequent to the SCANA Combination, Dominion Energy’s nuclear decommissioning AROs will total approximately $1.8 billion, representing approximately 55% of its total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with Dominion Energy’s nuclear decommissioning obligations.
Dominion Energy obtains from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. In addition, Dominion Energy’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion Energy determines cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be critical assumptions.
INCOME TAXES
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws, including the provisions of the 2017 Tax Reform Act, involves uncertainty, since tax authorities may interpret the laws differently. In addition, the states in which the Companies operate may or may not conform to some or all the provisions in the 2017 Tax Reform Act. Ultimate resolution or clarification of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.
Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2018, Dominion Energy had
$44 million of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.
Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion Energy evaluates quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. Dominion Energy establishes a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2018, Dominion Energy had established $158 million of valuation allowances.
The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies, including changes in corporate tax rates and business deductions. Many of these provisions differ significantly from prior U.S. tax law, resulting in pervasive financial reporting implications for the Companies. The 2017 Tax Reform Act included significant changes to the Internal Revenue Code of 1986, including amendments which significantly change the taxation of individuals and business entities and included specific provisions related to regulated public utilities including Dominion Energy subsidiaries Questar Gas, Hope, and SCE&G and PSNC, following the SCANA Combination, Virginia Power and Dominion Energy Gas’ subsidiaries DETI and East Ohio. The more significant changes that impact the Companies included in the 2017 Tax Reform Act are (i) reducing the corporate federal income tax rate from 35% to 21%; (ii) effective in 2018, limiting the deductibility of interest expense to 30% of adjusted taxable income for certain businesses with any disallowed interest allowed to be carried forward indefinitely; (iii) permitting 100% expensing (100% bonus depreciation) for certain qualified property; (iv) eliminating the deduction for qualified domestic production activities; and (v) limiting the utilization of net operating losses arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward. The specific provisions related to regulated public utilities in the 2017 Tax Reform Act generally allow for the continued deductibility of interest expense, the exclusion from full expensing for tax purposes of certain property acquired and placed in service after September 27, 2017 and continued certain rate normalization requirements for accelerated depreciation benefits.
At the date of enactment, the Companies’ deferred taxes were remeasured based upon the new tax rate expected to apply when temporary differences are realized or settled. For regulated operations, many of the changes in deferred taxes represented amounts probable of collection from or refund to customers, and were recorded as either an increase to a regulatory asset or liability. The 2017 Tax Reform Act included provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred taxes will be determined by the Companies’ regulators. For nonregulated operations, the changes in deferred taxes were recorded as an adjustment to deferred tax expense.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
ACCOUNTING FOR DERIVATIVE CONTRACTS AND FINANCIAL INSTRUMENTS AT FAIR VALUE
Dominion Energy uses derivative contracts such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity, interest rate and foreign currency exchange rate risks of its business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. The majority of investments held in Dominion Energy’s nuclear decommissioning and rabbi trusts and pension and other postretirement funds are also subject to fair value accounting. See Notes 6 and 21 to the Consolidated Financial Statements for further information on these fair value measurements.
Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, Dominion Energy considers whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if Dominion Energy believes that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, Dominion Energy must estimate prices based on available historical and near-term future price information and use of statistical methods, including regression analysis, that reflect its market assumptions.
Dominion Energy maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value.
USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING
As of December 31, 2018, Dominion Energy reported $6.4 billion of goodwill in its Consolidated Balance Sheet. A significant portion resulted from the acquisition of the former CNG in 2000 and the Dominion Energy Questar Combination in 2016. As discussed in Note 3 to the Consolidated Financial Statements, Dominion Energy expects to reflect a significant amount of goodwill in connection with the SCANA Combination in its Consolidated Balance Sheet in the first quarter of 2019.
In April of each year, Dominion Energy tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2018, 2017 and 2016 annual tests and any interim tests did not result in the recognition of any goodwill impairment.
In general, Dominion Energy estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. Fair value estimates are dependent on subjective factors such as Dominion Energy’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, partic-
ularly changes in discount rates or growth rates inherent in Dominion Energy’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion Energy has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present.
See Note 11 to the Consolidated Financial Statements for additional information.
USE OF ESTIMATES IN LONG-LIVED ASSET AND EQUITY METHOD INVESTMENT IMPAIRMENT TESTING
Impairment testing for an individual or group of long-lived assets, including intangible assets with definite lives, and equity method investments is required when circumstances indicate those assets may be impaired. When a long-lived asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. When an equity method investment’s carrying amount exceeds its fair value, and the decline in value is deemed to be other-than-temporary, an impairment is recognized to the extent that the fair value is less than its carrying amount. Performing an impairment test on long-lived assets and equity method investments involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets in the case of long-lived assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of a market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about the operations of the long-lived assets and equity method investments and the selection of an appropriate discount rate. When determining whether a long-lived asset or asset group has been impaired, management groups assets at the lowest level that has identifiable cash flows. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset or underlying assets of equity method investees, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. See Notes 6 and 9 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets and equity method investments.
As discussed in Future Issues and Other Matters, delays in obtaining permits necessary for construction and construction delays due to judicial actions have impacted the estimated cost and schedule for the Atlantic Coast Pipeline Project. As a result, Dominion Energy evaluated the carrying amount of its equity
method investment in Atlantic Coast Pipeline for an other-than-temporary impairment and determined that it was not impaired. Any significant changes affecting the discounted cash flow estimates associated with the Atlantic Coast Pipeline Project, such as future unfavorable judicial actions resulting in further construction and in-service delays along with an increase in construction costs, could result in an impairment charge.
EMPLOYEE BENEFIT PLANS
Dominion Energy sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit obligations, mortality rates and the anticipated rate of increase in healthcare costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between Dominion Energy’s assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.
The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality rates are critical assumptions. Dominion Energy determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:
•
Expected inflation and risk-free interest rate assumptions;
•
Historical return analysis to determine long-term historic returns as well as historic risk premiums for various asset classes;
•
Expected future risk premiums, asset classes’ volatilities and correlations;
•
Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and
•
Investment allocation of plan assets. The strategic target asset allocation for Dominion Energy’s pension funds is 28% U.S. equity, 18% non-U.S. equity, 35% fixed income, 3% real estate and 16% other alternative investments, such as private equity investments.
Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include those mentioned above such as employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the targets. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns.
Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions. Dominion Energy calculated its pension cost using an expected long-term rate of return on plan assets assumption of 8.75% for 2018, 2017 and 2016. For 2019, the expected long-term rate of return for pension cost assumption is 8.65% for Dominion Energy’s plans held as of December 31, 2018. Dominion Energy calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2018, 2017 and 2016. For 2019, the expected long-term rate of return for other postretirement benefit cost assumption is 8.50%. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets.
Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 3.80% to 3.81% for pension plans and 3.76% for other postretirement benefit plans in 2018, ranged from 3.31% to 4.50% for pension plans and 3.92% to 4.47% for other postretirement benefit plans in 2017 and ranged from 2.87% to 4.99% for pension plans and 3.56% to 4.94% for other postretirement benefit plans in 2016. Dominion Energy selected a discount rate ranging from 4.42% to 4.43% for pension plans and 4.37% to 4.38% for other postretirement benefit plans for determining its December 31, 2018 projected benefit obligations.
Dominion Energy establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected, and demographics of plan participants. Dominion Energy’s healthcare cost trend rate assumption as of December 31, 2018 was 6.50% and is expected to gradually decrease to 5.00% by 2025 and continue at that rate for years thereafter.
Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion Energy’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion Energy considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate. During 2016, Dominion Energy conducted a new experience study as scheduled and, as a result, updated its mortality assumptions.
The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed for Dominion Energy’s plans held as of December 31, 2018, while holding all other assumptions constant:
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
In addition to the effects on cost, at December 31, 2018, a 0.25% decrease in the discount rate would increase Dominion Energy’s projected pension benefit obligation by $294 million and its accumulated postretirement benefit obligation by $37 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $130 million.
See Note 21 to the Consolidated Financial Statements for additional information on Dominion Energy’s employee benefit plans.
New Accounting Standards
See Note 2 to the Consolidated Financial Statements for a discussion of new accounting standards.
Dominion Energy
RESULTS OF OPERATIONS
Presented below is a summary of Dominion Energy’s consolidated results:
Overview
VS. 2017
Net income attributable to Dominion Energy decreased 18%, primarily due to the absence of benefits in 2017 resulting from the remeasurement of deferred income taxes to the new corporate income tax rate, an impairment charge on certain gathering and processing assets, a charge associated with Virginia legislation enacted in March 2018, decreased net investment earnings on nuclear decommissioning trust funds, lower renewable energy investment tax credits and a charge for disallowance of FERC-regulated plant. These decreases were partially offset by gains on the sales of certain merchant generation facilities and equity method investments, the commencement of commercial operations of the Liquefaction Project and the absence of charges associated with equity method investments in wind-powered generation facilities.
2017 VS. 2016
Net income attributable to Dominion Energy increased 41%, primarily due to benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate, the Dominion Energy Questar Combination and an absence of charges related to future ash pond and landfill closures. These increases were partially offset by lower renewable energy investment tax credits and charges associated with equity method investments in wind-powered generation facilities.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion Energy’s results of operations:
An analysis of Dominion Energy’s results of operations follows:
2018 VS. 2017
Net revenue increased 2%, primarily reflecting:
•
A $500 million increase due to commencement of commercial operations of the Liquefaction Project, including terminalling services provided to the export customers ($508 million) and regulated gas transportation contracts to serve the export customers ($58 million), partially offset by credits associated with the start-up phase of the Liquefaction Project ($66 million);
•
An increase in sales to electric utility retail customers from an increase in heating degree days during the heating season of 2018 ($71 million) and an increase in cooling degree days during the cooling season of 2018 ($69 million);
•
A $130 million increase due to favorable pricing at merchant generation facilities;
•
A $92 million increase due to growth projects placed in service, other than the Liquefaction Project;
•
A $74 million increase in services performed for Atlantic Coast Pipeline; and
•
A $46 million increase in sales to electric utility retail customers due to customer growth.
These increases were partially offset by:
•
A $325 million decrease for regulated electric generation and electric and gas distribution operations as a result of the 2017 Tax Reform Act;
•
A $215 million charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers;
•
A $94 million increase in net electric capacity expense related to the annual PJM capacity performance market effective June 2017 ($112 million) and the annual PJM capacity perform-
ance market effective June 2018 ($39 million), partially offset by a benefit related to non-utility generators ($57 million);
•
An $89 million decrease in rate adjustment clauses associated with electric utility operations, which includes the impacts of the 2017 Tax Reform Act; and
•
A $38 million decrease from scheduled declines in or expiration of certain DETI and Cove Point contracts.
Net revenue does not reflect an impact from a reduction in planned outage days at Millstone as there was an offsetting increase in unplanned outage days.
Other operations and maintenance increased 8%, primarily reflecting:
•
A $102 million increase in storm damage and service restoration costs in the regulated electric service territory;
•
An $81 million increase due to a charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018;
•
A $73 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;
•
A $47 million increase in operating expenses from the commercial operations of the Liquefaction Project and costs associated with regulated gas transportation contracts to serve the export customers; and
•
A $38 million increase in salaries, wages and benefits, partially offset by
•
A $74 million decrease from a reduction in planned outage days at certain merchant and utility generation facilities.
Depreciation, depletion and amortization increased 5%, primarily due to an increase from various growth projects being placed into service ($187 million), including the Liquefaction Project ($81 million), partially offset by revised depreciation rates for regulated nuclear plants to comply with the Virginia Commission requirements ($61 million).
Impairment of assets and related charges increased $388 million, primarily due to a $219 million impairment charge on certain gathering and processing assets, a $135 million charge for disallowance of FERC-regulated plant and a $37 million write-off associated with the Eastern Market Access Project.
Gains on sales of assets increased $233 million, primarily due to the sale of Fairless and Manchester ($210 million) and an increase in gains related to agreements to convey shale development rights under natural gas storage fields ($46 million).
Other income increased $663 million, primarily reflecting a gain on the sale of Dominion Energy’s 50% limited partnership interest in Blue Racer ($546 million), the absence of charges associated with equity method investments in wind-powered generation facilities ($158 million), a gain on the sale of Dominion Energy’s 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership ($87 million) and a decrease in the non-service components of pension and other postretirement employee benefit credits capitalized to property, plant and equipment in 2018 ($45 million), partially offset by a decrease in net investment earnings on nuclear decommissioning trust funds ($209 million).
Interest and related charges increased 24%, primarily due to the absence of capitalization of interest expense associated with the Liquefaction Project upon completion of construction ($111
million), higher long-term debt interest expense resulting from net debt issuances in 2018 and 2017 ($92 million) and charges associated with the early redemption of certain debt securities ($69 million).
Income tax expense increased $610 million, primarily due to the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($851 million) and lower renewable energy investment tax credits ($138 million), partially offset by the reduced corporate income tax rate ($414 million).
2017 VS. 2016
Net revenue increased 8%, primarily reflecting:
•
A $663 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017;
•
A $97 million electric capacity benefit related to non-utility generators ($133 million) and a benefit due to the annual PJM capacity performance market effective June 2016 ($123 million), partially offset by the annual PJM capacity performance market effective June 2017 ($159 million);
•
An $86 million increase due to additional generation output from merchant solar generating projects;
•
A $71 million increase in sales to electric utility retail customers due to the effect of changes in customer usage and other factors, including $25 million related to customer growth;
•
A $63 million increase from regulated natural gas transmission growth projects placed in service;
•
A $46 million increase from rate adjustment clauses associated with electric utility operations; and
•
A $34 million increase in services performed for Atlantic Coast Pipeline.
These increases were partially offset by:
•
A $144 million decrease from Cove Point import contracts;
•
A $114 million decrease due to unfavorable pricing at merchant generation facilities; and
•
A decrease in sales to electric utility retail customers from a decrease in cooling degree days during the cooling season of 2017 ($53 million) and a reduction in heating degree days during the heating season of 2017 ($28 million).
Other operations and maintenance decreased 2%, primarily reflecting:
•
A $197 million absence of charges related to future ash pond and landfill closure costs at certain utility generation facilities;
•
A $115 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;
•
The absence of organizational design initiative costs ($64 million); and
•
A $46 million decrease in storm damage and service restoration costs associated with electric utility operations, partially offset by
•
A $162 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017;
•
A $92 million increase in salaries, wages and benefits;
•
A $36 million increase in outage costs; and
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
•
A $33 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income.
Depreciation, depletion and amortization increased 22%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($162 million) and various growth projects being placed into service ($151 million).
Other taxes increased 12%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($35 million) and increased property taxes related to growth projects placed into service ($27 million).
Gains on sales of assets increased $107 million, primarily due to the sale of certain assets associated with nonregulated retail energy marketing operations.
Other income decreased 17%, primarily due to charges associated with equity method investments in wind-powered generation facilities ($158 million), partially offset by an increase in earnings, excluding charges, from equity method investments ($29 million) an increase in AFUDC associated with rate-regulated projects ($23 million) and an increase in the non-service cost components of pension and other postretirement employee benefit credits ($14 million).
Interest and related charges increased 19%, primarily due to higher long-term debt interest expense resulting from debt issuances in 2016 and 2017 ($171 million) and debt acquired in the Dominion Energy Questar Combination ($37 million).
Income tax expense decreased $685 million, primarily due to benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($851 million), partially offset by lower renewable energy investment tax credits ($133 million).
Outlook
Dominion Energy’s 2019 net income is expected to decrease on a per share basis as compared to 2018 primarily from the following:
•
Charges incurred for refunds to SCE&G electric customers and transaction and transition costs related to the SCANA Combination;
•
The absence of earnings from, and gains on, the sales of certain merchant generation facilities and equity method investments;
•
A charge associated with the early retirement of the existing automated meter reading infrastructure;
•
Return to normal weather;
•
An increase in pension-related expenses; and
•
Share dilution.
These decreases are expected to be partially offset by the following:
•
Commercial operation of the Liquefaction Project for the entire year;
•
The inclusion of operations acquired in the SCANA Combination;
•
The absence of charges associated with the impairment of certain gathering and processing assets and disallowance of FERC-regulated plant;
•
The absence of charges associated with Virginia legislation enacted in March 2018;
•
Construction and operation of growth projects in gas transmission and distribution; and
•
Construction and operation of growth projects in electric utility operations.
SEGMENT RESULTS OF OPERATIONS
Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. Presented below is a summary of contributions by Dominion Energy’s operating segments to net income attributable to Dominion Energy:
Power Delivery
Presented below are operating statistics related to Power Delivery’s operations:
(1) Period average.
Presented below, on an after-tax basis, are the key factors impacting Power Delivery’s net income contribution:
2018 VS. 2017
2017 VS. 2016
Power Generation
Presented below are operating statistics related to Power Generation’s operations:
Presented below, on an after-tax basis, are the key factors impacting Power Generation’s net income contribution:
2018 VS. 2017
2017 VS. 2016
Gas Infrastructure
Presented below are selected operating statistics related to Gas Infrastructure’s operations.
(1) Includes Dominion Energy Questar effective September 2016.
(2) Period average.
(3) Includes Dominion Energy Questar customer accounts for the entire year.
Presented below, on an after-tax basis, are the key factors impacting Gas Infrastructure’s net income contribution:
2018 VS. 2017
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
2017 VS. 2016
(1) Represents the portion of earnings attributable to Dominion Energy Midstream’s public unitholders.
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results:
TOTAL SPECIFIC ITEMS
Corporate and Other includes specific items attributable to Dominion Energy’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. See Note 25 to the Consolidated Financial Statements for discussion of these items in more detail. Corporate and Other also includes specific items attributable to the Corporate and Other segment. In 2018, this primarily included $51 million of after-tax charges associated with the early redemption of certain debt securities and $31 million of after-tax transaction and transition costs associated with the Dominion Energy Questar Combination and SCANA Combination. In 2017, this primarily included $124 million of tax benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate. In 2016, this primarily included $53 million of after-tax transaction and transition costs associated with the Dominion Energy Questar Combination.
VIRGINIA POWER
RESULTS OF OPERATIONS
Presented below is a summary of Virginia Power’s consolidated results:
Overview
2018 VS. 2017
Net income decreased 17%, primarily due to a charge associated with Virginia legislation enacted in March 2018, an increase in storm damage and service restoration costs, a charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018 and an increase in net electric capacity expense, partially offset by an increase in heating and cooling degree days in the service territory.
2017 VS. 2016
Net income increased 26%, primarily due to the absence of charges related to future ash pond and landfill closure costs, a benefit from the remeasurement of deferred income taxes to the new corporate income tax rate and an electric capacity benefit.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Power’s results of operations:
An analysis of Virginia Power’s results of operations follows:
2018 VS. 2017
Net revenue decreased 8%, primarily reflecting:
•
A $238 million decrease for regulated generation and distribution operations as a result of the 2017 Tax Reform Act;
•
A $215 million charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers;
•
A $94 million increase in net electric capacity expense related to the annual PJM capacity performance market effective June
2017 ($112 million) and the annual PJM capacity performance market effective June 2018 ($39 million), partially offset by a benefit related to non-utility generators ($57 million); and
•
An $89 million decrease from rate adjustment clauses, which includes the impacts of the 2017 Tax Reform Act; partially offset by
•
An increase in sales to retail customers from an increase in heating degree days during the heating season of 2018 ($71 million) and an increase in cooling degree days during the cooling season of 2018 ($69 million); and
•
A $46 million increase in sales to retail customers due to customer growth.
Other operations and maintenance increased 13%, primarily reflecting:
•
A $102 million increase due to storm damage and service restoration costs; and
•
An $81 million increase due to a charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018; partially offset by
•
A $19 million decrease from a reduction in planned outage days at certain generation facilities.
Depreciation and amortization was substantially consistent as a decrease due to revised depreciation rates for regulated nuclear plants to comply with the Virginia Commission requirements ($61 million) was substantially offset by various growth projects being placed into service ($56 million).
Other income decreased 71%, primarily related to lower realized gains (including investment income) on nuclear decommissioning trust funds ($23 million), the electric transmission tower rental portfolio, including the absence of the assignment of such amounts to Vertical Bridge Towers II, LLC ($18 million) and the absence of interest income associated with the settlement of state income tax refund claims ($11 million), partially offset by the absence of a charge associated with a customer settlement ($16 million).
Income tax expense decreased 61%, primarily due to lower pre-tax income ($256 million), the reduced corporate income tax rate ($235 million) and higher renewable energy investment tax credits ($35 million), partially offset by the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($93 million).
2017 VS. 2016
Net revenue increased 2%, primarily reflecting:
•
A $97 million electric capacity benefit related to non-utility generators ($133 million) and a benefit due to the annual PJM capacity performance market effective June 2016 ($123 million), partially offset by the annual PJM capacity performance market effective June 2017 ($159 million);
•
A $71 million increase in sales to retail customers due to the effect of changes in customer usage and other factors, including $25 million related to customer growth; and
•
A $46 million increase from rate adjustment clauses; partially offset by
•
A decrease in sales to retail customers from a decrease in cooling degree days during the cooling season of 2017 ($53 million) and a reduction in heating degree days during the heating season of 2017 ($28 million).
Other operations and maintenance decreased 20%, primarily reflecting:
•
A $197 million decrease due to the absence of charges related to future ash pond and landfill closure costs at certain utility generation facilities;
•
A $115 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;
•
A $46 million decrease in storm damage and service restoration costs; and
•
The absence of organizational design initiative costs ($32 million); partially offset by
•
A $37 million increase in salaries, wages and benefits and general administrative expenses.
Depreciation and amortization increased 11%, primarily due to various growth projects being placed into service ($58 million) and revised depreciation rates ($40 million).
Other income increased 36%, primarily reflecting:
•
An $11 million increase in interest income associated with the settlement of state income tax refund claims;
•
An $11 million increase from the assignment of Virginia Power’s electric transmission tower rental portfolio; and
•
An $8 million increase in AFUDC associated with rate-regulated projects; partially offset by
•
A $16 million charge associated with a customer settlement.
Income tax expense increased 6% primarily due to higher pretax income ($139 million), partially offset by benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($93 million).
DOMINION ENERGY GAS
RESULTS OF OPERATIONS
Presented below is a summary of Dominion Energy Gas’ consolidated results:
Overview
2018 VS. 2017
Net income decreased 51%, primarily due to an impairment charge on certain gathering and processing assets, a charge for disallowance of FERC-regulated plant and the absence of benefits from the 2017 Tax Reform Act partially offset by regulated natural gas transmission activities from growth projects placed into service and an increase in gains from agreements to convey shale development rights underneath several natural gas storage fields.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
2017 VS. 2016
Net income increased 57%, primarily due to a benefit from the remeasurement of deferred income taxes to the new corporate income tax rate and gas transportation and storage activities from growth projects placed into service.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion Energy Gas’ results of operations:
An analysis of Dominion Energy Gas’ results of operations follows:
2018 VS. 2017
Net revenue increased 6%, primarily reflecting:
•
A $74 million increase in services performed for Atlantic Coast Pipeline;
•
A $57 million increase due to regulated natural gas transmission growth projects placed in service; and
•
A $20 million increase in PIR program revenues; partially offset by
•
A $36 million decrease for regulated distribution operations as a result of the 2017 Tax Reform Act; and
•
A $25 million decrease from scheduled declines in certain DETI contracts.
Other operations and maintenance increased 14%, primarily reflecting:
•
A $73 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income; and
•
A $7 million increase in salaries, wages and benefits.
Depreciation and amortization increased 7%, primarily due to an increase from various growth projects being placed into service.
Impairment of assets and related charges increased $330 million, primarily due to an impairment charge on certain gathering and processing assets ($219 million) and a charge for disallowance of FERC-regulated plant ($127 million) partially offset by the absence of a charge to write-off the balance of a regulatory asset no longer considered probable of recovery ($15 million).
Gains on sales of assets increased 70%, primarily due to increased gains related to agreements to convey shale development rights under natural gas storage fields.
Earnings from equity method investee increased 14%, primarily due to higher earnings from unsubscribed capacity as a result of an increase in heating degree days at Iroquois.
Other income increased 28%, primarily due to a decrease in the non-service components of pension and other postretirement employee benefit credits capitalized to property, plant and equipment in 2018 ($24 million) partially offset by AFUDC on rate-regulated projects ($5 million).
Interest and related charges increased 8%, primarily due to higher interest expense on long-term debt due to an issuance in the second quarter of 2018 and increased interest rates ($10 million), partially offset by an increase in deferred carrying costs ($6 million).
Income tax expense increased 69%, primarily due to the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($197 million) and the absence of a settlement with state tax authorities ($5 million), partially offset by the reduced corporate income tax rate ($67 million) and lower pre-tax income ($98 million).
2017 VS. 2016
Net revenue increased 9%, primarily reflecting:
•
A $55 million increase due to regulated natural gas transmission growth projects placed in service;
•
A $34 million increase in services performed for Atlantic Coast Pipeline;
•
A $24 million increase in PIR program revenues; and
•
A $16 million increase in rate recovery for low income assistance programs associated with regulated natural gas distribution operations.
Other operations and maintenance increased 12%, primarily reflecting:
•
A $33 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;
•
A $16 million increase in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income; and
•
A $13 million increase in salaries, wages and benefits and general administrative expenses.
Depreciation and amortization increased 11%, primarily due to growth projects being placed into service.
Impairment of assets and related charges increased $16 million, primarily due to a charge to write-off the balance of a regulatory asset no longer considered probable of recovery.
Gains on sales of assets increased 56% primarily due to increased gains from agreements to convey shale development rights underneath several natural gas storage fields.
Other income increased 20%, primarily due to a $12 million increase in AFUDC associated with rate-regulated projects and an $8 million increase in the non-service cost components of pension and other postretirement employee benefit credits, partially offset by the absence of the 2016 sale of a portion of Dominion Energy Gas’ interest in Iroquois ($5 million).
Income tax expense decreased 76%, primarily due to benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($197 million), partially offset by higher pre-tax income ($22 million).
LIQUIDITY AND CAPITAL RESOURCES
Dominion Energy depends on both internal and external sources of liquidity to provide working capital and as a bridge to long-term debt financings. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.
At December 31, 2018, Dominion Energy had $5.6 billion of unused capacity under its credit facility. See additional discussion below under Credit Facilities and Short-Term Debt.
A summary of Dominion Energy’s cash flows is presented below:
Operating Cash Flows
Net cash provided by Dominion Energy’s operating activities increased $271 million, primarily due to the commencement of commercial operations of the Liquefaction Project, higher merchant generation margin, derivative activities and the favorable impact of weather, partially offset by lower deferred fuel cost recoveries in the Virginia jurisdiction, increased interest expense and one-time rate credits to electric utility customers.
Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2018, Dominion Energy’s Board of Directors established an annual dividend rate for 2019 of $3.67 per share of common stock, a 10.0% increase over the 2018 rate. Dividends are subject to declaration by the Board of Directors. In January 2019, Dominion Energy’s Board of Directors declared dividends payable in March 2019 of 91.75 cents per share of common stock.
Dominion Energy’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, and which are discussed in Item 1A. Risk Factors.
CREDIT RISK
Dominion Energy’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure as of December 31, 2018 for these
activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.
(1) Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 60% of the total net credit exposure.
(2) The five largest counterparty exposures, combined, for this category represented less than 1% of the total net credit exposure.
(3) The five largest counterparty exposures, combined, for this category represented approximately 2% of the total net credit exposure.
(4) The five largest counterparty exposures, combined, for this category represented approximately 26% of the total net credit exposure.
Investing Cash Flows
Net cash used in Dominion Energy’s investing activities decreased $3.6 billion, primarily due to proceeds from the sale of certain merchant generation facilities and equity method investments and decreases in plant construction due to the commencement of commercial operations of the Liquefaction Project and Greensville County.
Financing Cash Flows and Liquidity
Dominion Energy relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed in Credit Ratings, Dominion Energy’s ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.
Dominion Energy currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows Dominion Energy to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.
From time to time, Dominion Energy may reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity and repurchases in the open market, in privately negotiated transactions, through tender offers or otherwise.
Net cash used by Dominion Energy’s financing activities in 2018 was $2.2 billion compared to net cash provided by financing activities in 2017 of $1.3 billion, primarily due to net debt repayments in 2018 compared to net debt issuances in 2017, partially offset by the issuance of common stock.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
CREDIT FACILITIES AND SHORT-TERM DEBT
Dominion Energy uses short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.
In connection with commodity hedging activities, Dominion Energy is required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, Dominion Energy may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, Dominion Energy may vary the form of collateral provided to counterparties after weighing the costs and benefits of various factors associated with the different forms of collateral. These factors include short-term borrowing and short-term investment rates, the spread over these short-term rates at which Dominion Energy can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives.
Dominion Energy’s commercial paper and letters of credit outstanding, as well as capacity available under its credit facility, were as follows:
(1) The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facility was 2.93% at December 31, 2018.
(2) This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.
In connection with the SCANA Combination, Dominion Energy intends to terminate SCANA, SCE&G and PSNC’s existing credit facilities, which have limits of $400 million, $700 million and $200 million, respectively, and add SCE&G as a co-borrower to its $6.0 billion joint revolving credit facility in the first quarter of 2019 once certain regulatory approvals are obtained. In January 2019, Virginia Power and SCE&G, as co-borrowers, filed with the Virginia Commission and the South Carolina Commission, respectively, for approval. In February 2019, the Virginia Commission approved the request. SCE&G is required to obtain FERC approval to issue short-term indebtedness, including commercial paper, and to assume liabilities as a guarantor. In February 2019, Dominion Energy terminated South Carolina Fuel Company, Inc.’s existing credit facility of $500 million.
In November 2017, Dominion Energy filed an SEC shelf registration statement for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. The registration limits the
principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. The balance as of December 31, 2018 was $10 million. The notes are short-term debt obligations on Dominion Energy’s Consolidated Balance Sheets. The proceeds will be used for general corporate purposes and to repay debt.
In March 2018, Dominion Energy Midstream entered into a $500 million revolving credit facility. The credit facility was scheduled to mature in March 2021, bore interest at a variable rate, and was used to support bank borrowings and the issuance of commercial paper, as well as to support up to $250 million of letters of credit. At December 31, 2018, Dominion Energy Midstream had $73 million outstanding under this credit facility. In February 2019, Dominion Energy Midstream terminated the facility subsequent to repaying the outstanding balance, plus accrued interest.
In October 2018, Dominion Energy entered into a credit agreement, which allows Dominion Energy to issue up to approximately $21 million in letters of credit. At December 31, 2018, approximately $21 million in letters of credit were outstanding under this agreement. The facility terminates in June 2020.
In February and June 2018, Dominion Energy borrowed $950 million and $500 million, respectively, under 364-Day Term Loan Agreements that bore interest at a variable rate. In September 2018, the principal outstanding plus accrued interest for both borrowings was repaid.
LONG-TERM DEBT
During 2018, Dominion Energy issued the following long-term public debt:
During 2018, Dominion Energy also issued the following long-term private debt:
•
In January 2018, Dominion Energy Questar Pipeline issued, through private placement, $100 million of 3.53% senior notes and $150 million of 3.91% senior notes that mature in 2028 and 2038, respectively. The proceeds were used to repay maturing long-term debt.
•
In April 2018, Questar Gas issued through private placement $50 million of 3.30% senior notes and $100 million of 3.97% senior notes that mature in 2030 and 2047, respectively. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper.
•
In May 2018, Dominion Energy issued through private placement $500 million of variable rate senior notes that mature in 2020. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper. In November 2018, the notes were redeemed at the principal outstanding plus accrued interest.
•
In November 2018, Eagle Solar issued through private placement $362 million of 4.82% senior secured notes which mature in December 2042. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar’s interest in certain merchant solar facilities. The proceeds were used for the reimbursement of equity amounts previously invested by Dominion Energy in the acquisition, development or construction of the projects in Eagle Solar.
During 2018, Dominion Energy also borrowed the following under a term loan agreement:
•
In September 2018, Cove Point closed on an up to $3.0 billion term loan that is secured by Dominion Energy’s common equity interest in Cove Point, bears interest at a variable rate and matures in 2021. In accordance with the terms of the term loan, Cove Point borrowed $2.0 billion and $1.0 billion in September 2018 and December 2018, respectively. Under the terms of the term loan, Cove Point faces certain restrictions on issuing additional debt, divesting the Cove Point LNG Facility, paying distributions to Dominion Energy or taking certain other actions without necessary approvals.
During 2018, in addition to the November 2018 redemption described above, Dominion Energy redeemed the following long-term debt:
•
In March 2018, Virginia Power redeemed $100 million of its variable rate tax-exempt financings which would otherwise have matured in 2024, 2026 and 2027.
•
In December 2018, Virginia Power redeemed its $14 million 5.60% Economic Development Authority of the County of Chesterfield Solid Waste and Sewage Disposal Revenue Bonds, Series 2007A, due in 2031 at the principal outstanding plus accrued interest.
•
In December 2018, Dominion Energy redeemed the following outstanding series of senior notes: 2011 Series A 4.45% Senior Notes due 2021, 2014 Series B 2.50% Senior Notes due 2019 and 2014 Series C 3.625% Senior Notes due 2024 with an aggregate outstanding principal of $1.7 billion plus accrued interest and the applicable make-whole premium of $34 million. See Note 17 to the Consolidated Financial Statements for a description of senior note redemptions.
During 2018, Dominion Energy repaid and repurchased $5.7 billion of long-term debt, including redemption premiums.
In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan agreement due in December 2019 at the principal outstanding plus accrued interest.
In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of $1.0 billion.
SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer.
NONCONTROLLING INTEREST IN DOMINION ENERGY MIDSTREAM
In May 2018, all of the subordinated units of Dominion Energy Midstream held by Dominion Energy were converted into common units on a 1:1 ratio following the payment of Dominion Energy Midstream’s distribution for the first quarter of 2018. In June 2018, Dominion Energy, as general partner, exercised an incentive distribution right reset as defined in Dominion Energy Midstream’s partnership agreement and received 26.7 million common units representing limited partner interests in Dominion Energy Midstream. As a result of the increase in its ownership interest in Dominion Energy Midstream, Dominion Energy recorded a decrease in noncontrolling interest, and a corresponding increase in shareholders’ equity, of $375 million reflecting the change in the carrying value of the interest in the net assets of Dominion Energy Midstream held by others.
In January 2019, Dominion Energy and Dominion Energy Midstream closed on an agreement and plan of merger pursuant to which Dominion Energy acquired each outstanding common unit representing limited partner interests in Dominion Energy Midstream not already owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. Under the terms of the agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in Dominion Energy Midstream was converted into the right to receive 0.2492 shares of Dominion Energy common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Dominion Energy Midstream was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement.
ISSUANCE OF COMMON STOCK AND OTHER EQUITY SECURITIES
Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. Currently, Dominion Energy is issuing new shares of common stock for these direct stock purchase plans.
During 2018, Dominion Energy received cash proceeds of $2.5 billion, net of fees and commissions from the issuance of approximately 36 million shares of common stock through various programs including the forward sale agreements described in Note 19 resulting in approximately 681 million shares of common stock outstanding at December 31, 2018. These proceeds include cash of $315 million from the issuance of 4.5 million of shares through Dominion Energy Direct® and employee savings plans.
In 2018, Dominion Energy issued 9.3 million shares and received cash proceeds of $692 million, net of fees and commissions paid of $7 million through its at-the-market programs. See Note 19 for a description of the at-the-market programs.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion Energy entered in March 2018, and closed in April 2018, separate forward sale agreements with Goldman Sachs & Co. LLC and Credit Suisse Capital LLC, as forward purchasers, and an underwriting agreement with Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, as representatives of the several underwriters named therein, relating to an aggregate of 20.0 million shares of Dominion Energy common stock. The underwriting agreement granted the underwriters a 30-day option to purchase up to an additional three million shares of Dominion Energy common stock, which the underwriters exercised with respect to approximately 2.1 million shares in April 2018. Dominion Energy entered into separate forward sale agreements with the forward purchasers with respect to the additional shares. In December 2018, Dominion Energy received proceeds of $1.4 billion upon the physical settlement of 22.1 million shares. See Note 19 to the Consolidated Financial Statements for a description of the forward sale agreements.
In January 2019, in connection with the SCANA Combination, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock outstanding at closing. SCANA’s outstanding debt totaled $6.9 billion at closing. Also in January 2019, Dominion Energy issued 22.5 million shares of common stock to acquire interests in Dominion Energy Midstream as noted above. In addition, during 2019, Dominion Energy plans to issue shares for employee savings plans and direct stock purchase and dividend reinvestment plans.
REPURCHASE OF COMMON STOCK
Dominion Energy did not repurchase any shares in 2018 and does not plan to repurchase shares during 2019, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not count against its stock repurchase authorization.
Credit Ratings
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Dominion Energy believes that its current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion Energy may affect its ability to access these funding sources or cause an increase in the return required by investors. Dominion Energy’s credit ratings affect its liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which it is able to offer its debt securities.
Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for Dominion Energy are affected by its financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.
In December 2018, Moody’s and Standard & Poor’s affirmed Dominion Energy’s ratings and changed Dominion Energy’s rating outlook to stable from negative.
Credit ratings and outlooks as of February 25, 2019 follow:
(1) Securities do not have an interest deferral feature.
(2) Securities have an interest deferral feature.
A downgrade in an individual company’s credit rating does not necessarily restrict its ability to raise short-term and long-term financing as long as its credit rating remains investment grade, but it could result in an increase in the cost of borrowing. Dominion Energy works closely with Fitch, Moody’s and Standard & Poor’s with the objective of achieving its targeted credit ratings. Dominion Energy may find it necessary to modify its business plan to maintain or achieve appropriate credit ratings and such changes may adversely affect growth and EPS.
Debt Covenants
As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion Energy must enter into enabling agreements. These agreements contain covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion Energy.
Some of the typical covenants include:
•
The timely payment of principal and interest;
•
Information requirements, including submitting financial reports and information about changes in Dominion Energy’s credit ratings to lenders;
•
Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation and restrictions on disposition of all or substantially all assets;
•
Compliance with collateral minimums or requirements related to mortgage bonds; and
•
Limitations on liens.
Dominion Energy is required to pay annual commitment fees to maintain its credit facility. In addition, Dominion Energy’s credit agreement contains various terms and conditions that could affect its ability to borrow under the facility. They include a maximum debt to total capital ratio and cross-default provisions.
As of December 31, 2018, the calculated total debt to total capital ratio, pursuant to the terms of the agreement, was as follows:
(1) Indebtedness as defined by the bank agreements excludes certain junior subordinated and remarketable subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets.
(2) At January 1, 2019, the calculated total debt to total capital ratio, as adjusted for the SCANA Combination was 52.8%.
If Dominion Energy or any of its material subsidiaries fails to make payment on various debt obligations in excess of $100 million, the lenders could require the defaulting company, if it is a borrower under Dominion Energy’s credit facility, to accelerate its repayment of any outstanding borrowings and the lenders could terminate their commitments, if any, to lend funds to that company under the credit facility. In addition, if the defaulting company is Virginia Power, Dominion Energy’s obligations to repay any outstanding borrowing under the credit facility could also be accelerated and the lenders’ commitments to Dominion Energy could terminate.
Dominion Energy executed RCCs in connection with its issuance of the June 2006 hybrids and September 2006 hybrids. See Note 17 to the Consolidated Financial Statements for additional information, including terms of the RCCs.
At December 31, 2018, the termination dates and covered debt under the RCCs associated with Dominion Energy’s hybrids were as follows:
Dominion Energy monitors these debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2018, there have been no events of default under Dominion Energy’s debt covenants.
Dividend Restrictions
Certain agreements associated with Dominion Energy’s credit facility contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion Energy’s ability to pay dividends or receive dividends from its subsidiaries at December 31, 2018.
See Note 17 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion Energy, including in connection with the deferral of interest payments and contract adjustment payments on certain junior subordinated notes and equity units, initially in the form of corporate units, which information is incorporated herein by reference.
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
CONTRACTUAL OBLIGATIONS
Dominion Energy is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion Energy is a party as of December 31, 2018. In addition, see Note 3 to the Consolidated Financial Statements for a description of significant contractual obligations acquired in the SCANA Combination. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in the Consolidated Balance Sheets, other than current maturities of long-term debt, interest payable and certain derivative instruments. The majority of Dominion Energy’s current liabilities will be paid in cash in 2019.
(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.
(2) Includes capital leases. See Note 17 to the Consolidated Financial Statements for more information.
(3) Includes interest payments over the terms of the debt and payments on related stock purchase contracts. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2018 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 17 to the Consolidated Financial Statements. Does not reflect Dominion Energy’s ability to defer interest and stock purchase contract payments on certain junior subordinated notes or RSNs and equity units, initially in the form of Corporate Units.
(4) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.
(5) Includes capital, operations, and maintenance commitments.
(6) Excludes regulatory liabilities, AROs and employee benefit plan obligations, which are not contractually fixed as to timing and amount. See Notes 12, 14 and 21 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $29 million of income taxes payable associated with unrecognized tax
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 5 to the Consolidated Financial Statements.
(7) Includes interest rate and foreign currency swap agreements.
PLANNED CAPITAL EXPENDITURES
Dominion Energy’s planned capital expenditures are expected to total approximately $6.3 billion, $7.3 billion and $6.9 billion in 2019, 2020 and 2021, respectively. Dominion Energy’s planned expenditures are expected to include construction and expansion of electric generation and natural gas transmission and storage facilities, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel, maintenance and expected contributions to Atlantic Coast Pipeline.
Dominion Energy expects to fund its capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the Board of Directors.
See Power Delivery, Power Generation, Gas Infrastructure and Southeast Energy-Properties in Item 1. Business for a discussion of Dominion Energy’s expansion plans.
These estimates are based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in late 2018 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.
Use of Off-Balance Sheet Arrangements
LEASING ARRANGEMENT
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.
The respective transactions have been structured so that Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. In accordance with revised accounting guidance pertaining to the recognition, measurement, presentation and disclosure of leasing arrangements, which is effective in January 2019, Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.
GUARANTEES
Dominion Energy primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others. In addition, Dominion Energy has provided a guarantee to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility. See Note 22 to the Consolidated Financial Statements for additional information, which information is incorporated herein by reference.
FUTURE ISSUES AND OTHER MATTERS
See Item 1. Business and Notes 13 and 22 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other matters that may impact future results of operations, financial condition and/or cash flows.
Environmental Matters
Dominion Energy is 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.
ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES
Dominion Energy incurred $198 million, $200 million and $394 million of expenses (including accretion and depreciation) during, 2018, 2017 and 2016 respectively, in connection with environmental protection and monitoring activities. Dominion Energy expects these expenses to be approximately $191 million and $183 million in 2019 and 2020, respectively. In addition, capital expenditures related to environmental controls were $104 million, $201 million, and $191 million for 2018, 2017 and 2016, respectively. Dominion Energy expects these expenditures to be approximately $192 million and $203 million for 2019 and 2020, respectively.
FUTURE ENVIRONMENTAL REGULATIONS
Air
In August 2018, the EPA proposed the Affordable Clean Energy rule as a replacement for the Clean Power Plan. The Affordable Clean Energy rule applies to fossil fuel-fired steam electric generating units greater than or equal to 25 MW, however, it does not apply to combustion turbines or units that burn biomass. The proposed rule includes unit-specific performance standards based on the degree of emission reduction levels achievable from unit efficiency improvements to be determined by the permitting agency. The Affordable Clean Energy rule would require states to develop plans within three years of the final rule to implement these performance standards. These state plans must be approved by the EPA. Given these developments and the associated federal and state regulatory and legal uncertainties, Dominion Energy cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.
Climate Change
In December 2015, the Paris Agreement was formally adopted under the United Nations Framework Convention on Climate Change. A key element of the initial U.S. commitment to the agreement was the implementation of the Clean Power Plan, which the EPA has proposed to repeal. In June 2017, the Administration announced that the U.S. intends to file to withdraw from the Paris Agreement in 2019. Several states, including Virginia, subsequently announced a commitment to achieving the carbon reduction goals of the Paris Agreement. It is not possible at this time to predict the timing and impact of this withdrawal, or how any legal requirements in the U.S. at the federal, state or local levels pursuant to the Paris Agreement could impact the Companies’ customers or the business.
State Actions Related to Air and GHG Emissions
In August 2017, the Ozone Transport Commission released a draft model rule for control of NOX emissions from natural gas pipeline compressor fuel-fire prime movers. States within the ozone transport region, including states in which Dominion Energy has natural gas operations, are expected to develop reasonably achievable control technology rules for existing sources based on the Ozone Transport Commission model rule. States outside of the Ozone Transport Commission may also consider the model rules in setting new reasonably achievable control technology standards.
In January 2018, the VDEQ published for comment a proposed state carbon regulation program linked to RGGI. In February 2019, the VDEQ proposed a revised rule with a 28 million ton initial carbon cap, which is 15% lower than the original proposal, based on revised modeling that uses projections of lower natural gas prices and additional solar capacity. A final rule is expected in mid-2019. Several other states in which Dominion Energy operates, including Pennsylvania, New York, Maryland and Ohio are developing or have announced plans to develop state-specific regulations to control GHG emissions, including methane. Dominion Energy cannot currently estimate the potential financial statement impacts related to these matters, but there could be a material impact to its financial condition and/or cash flows.
PHMSA Regulation
The most recent reauthorization of PHMSA included new provisions on historical records research, maximum-allowed operating pressure validation, use of automated or remote-controlled valves on new or replaced lines, increased civil penalties and evaluation of expanding integrity management beyond high-consequence areas. PHMSA has not yet issued new rulemaking on most of these items.
Dodd-Frank Act
The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The CEA, as amended by Title VII of the Dodd-Frank Act, requires certain over-the counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, may elect the end-user exception to the CEA’s clearing requirements. Dominion Energy has elected to exempt its swaps from the CEA’s clearing requirements. If, as a result of changes to the rulemaking process, Dominion Energy’s derivative activities are not exempted from clearing, exchange trading or margin requirements, it could be subject to higher costs due to decreased market liquidity or increased margin payments. In addition, Dominion Energy’s swap dealer counterparties may attempt to pass-through additional trading costs in connection with changes to or the elimination of rulemaking that implements Title VII of the Dodd-Frank Act. Due to the evolving rulemaking process, Dominion Energy is currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on its financial condition, results of operations or cash flows.
Virginia Legislation
In February 2019, legislation was passed by the Virginia General Assembly, and is awaiting signature by the Governor of Virginia, which would require any CCR unit located at Virginia Power’s Bremo, Chesapeake, Chesterfield or Possum Point power stations that stop accepting CCR prior to July 2019 be closed by removing the CCR to an approved landfill or through recycling for beneficial reuse. The legislation further would require that at least 6.8 million cubic yards of CCR be beneficially reused and that costs associated with the closure of these CCR units be recoverable through a rate adjustment clause approved by the Virginia Commission with a revenue requirement that cannot exceed $225 million in any 12-month period. While the impacts of this rule could be material to Dominion Energy and Virginia Power’s financial condition and/or cash flows, such rate adjustment clause would substantially mitigate any impact to Dominion Energy and Virginia Power’s results of operations.
Atlantic Coast Pipeline
In September 2014, Dominion Energy, along with Duke and Southern Company Gas, announced the formation of Atlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. During the third and fourth quarters of 2018, a FERC stop work order together with delays in obtaining permits necessary for construction and delays in construction due to judicial actions impacted the cost and schedule for the project. As a result project
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
cost estimates have increased from between $6.0 billion to $6.5 billion to between $7.0 billion to $7.5 billion, excluding financing costs. Atlantic Coast Pipeline expects to achieve a late 2020 in-service date for at least key segments of the project, while the remainder may extend into early 2021. Alternatively, if it takes longer to resolve the judicial issues, such as through appeal to the Supreme Court of the U.S., full in-service could extend to the end of 2021 with total project cost estimated to increase an additional $250 million, resulting in total project cost estimates of $7.25 billion to $7.75 billion excluding financing costs. Abnormal weather, work delays (including due to judicial or regulatory action) and other conditions may result in further cost or schedule modifications in the future, which could result in a material impact to Dominion Energy’s cash flows, financial position and/or results of operations.
North Anna
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it would require a Combined Construction Permit and Operating License from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In June 2017, the NRC issued the Combined Construction Permit and Operating License. Virginia Power has not yet committed to building a new nuclear unit at North Anna.
Other Matters
While management currently has no plans which may affect the carrying value of Millstone, based on potential future economic and other factors, including, but not limited to, market power prices, results of capacity auctions, legislative and regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free generation, and the impact of potential EPA carbon rules; there is risk that Millstone may be evaluated for an early retirement date. Should management make any decision on a potential early retirement date, the precise date and the resulting financial statement impacts, which could be material to Dominion Energy, may be affected by a number of factors, including any potential regulatory or legislative solutions, results of any transmission system reliability study assessments and decommissioning requirements, among other factors.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact the Companies.
MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT
The Companies’ financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in Dominion Energy and Virginia Power’s electric operations and Dominion Energy and Dominion Energy Gas’
natural gas procurement and marketing operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt and future issuances of debt. In addition, the Companies are exposed to investment price risk through various portfolios of equity and debt securities.
The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in commodity prices or interest rates.
Commodity Price Risk
To manage price risk, Dominion Energy and Virginia Power hold commodity-based derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products and Dominion Energy Gas primarily holds commodity-based financial derivative instruments held for non-trading purposes associated with sales of NGLs.
The derivatives used to manage commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on observable market prices.
A hypothetical 10% decrease in commodity prices would have resulted in a decrease in fair value of $6 million and $5 million of Dominion Energy’s commodity-based derivative instruments as of December 31, 2018 and December 31, 2017, respectively.
A hypothetical 10% decrease in commodity prices of Virginia Power’s commodity-based derivative instruments would have resulted in a decrease in fair value of $51 million as of both December 31, 2018 and December 31, 2017, respectively.
A hypothetical 10% increase in commodity prices of Dominion Energy Gas’ commodity-based financial derivative instruments would have resulted in a decrease in fair value of $1 million and $4 million as of December 31, 2018 and December 31, 2017, respectively.
The impact of a change in energy commodity prices on the Companies’ commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity-based financial derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.
Interest Rate Risk
The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt and interest rate swaps designated under fair value hedging and outstanding for Dominion Energy, a hypothetical 10%
increase in market interest rates would result in a $24 million and $12 million decrease in earnings at December 31, 2018 and December 31, 2017, respectively. For variable rate debt outstanding for Virginia Power and Dominion Energy Gas, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at December 31, 2018 or December 31, 2017.
The Companies also use interest rate derivatives, including forward-starting swaps, as cash flow hedges of forecasted interest payments. As of December 31, 2018, Dominion Energy, Virginia Power and Dominion Energy Gas had $5.9 billion, $1.9 billion and $1.1 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $147 million, $94 million and $17 million, respectively, in the fair value of Dominion Energy, Virginia Power and Dominion Energy Gas’ interest rate derivatives at December 31, 2018. As of December 31, 2017, Dominion Energy and Virginia Power had $3.5 billion and $1.5 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $86 million and $67 million, respectively, in the fair value of Dominion Energy and Virginia Power’s interest rate derivatives at December 31, 2017. Dominion Energy Gas had no interest rate derivatives outstanding at December 31, 2017.
During 2016, Dominion Energy Gas entered into foreign currency swaps with the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of December 31, 2018 and December 31, 2017, Dominion Energy and Dominion Energy Gas had $280 million ( 250 million) in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $8 million and $6 million, in the fair value of Dominion Energy Gas’ foreign currency swaps at December 31, 2018 and December 31, 2017, respectively.
The impact of a change in interest rates on the Companies’ interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.
Investment Price Risk
Dominion Energy and Virginia Power are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value.
Dominion Energy recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $135 million for the year ended December 31, 2018. Dominion Energy recognized net realized gains (including
investment income) on nuclear decommissioning trust investments of $167 million for the year ended December 31, 2017. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion Energy recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $36 million for the year ended December 31, 2018 and recorded a net increase in unrealized gains on debt and equity investments of $462 million for the year ended December 31, 2017.
Virginia Power recognized net investment losses (including investment income) on nuclear decommissioning trust investments of $44 million for the year ended December 31, 2018. Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $76 million for the year ended December 31, 2017. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $21 million for the year ended December 31, 2018 and recorded a net increase in unrealized gains on debt and equity investments of $216 million for the year ended December 31, 2017.
Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power and Dominion Energy Gas employees participate in these plans. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $(605) million and $1.6 billion in 2018 and 2017, respectively, versus expected returns of $806 million and $767 million, respectively. Dominion Energy Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns (losses) of $(129) million and $335 million in 2018 and 2017, respectively, versus expected returns of $178 million and $165 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Energy’s plan assets would result in an increase in net periodic cost of $19 million as of both December 31, 2018 and 2017, for pension benefits and $4 million as of both December 31, 2018 and 2017, for other postretirement benefits. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Energy Gas’ plan assets, for employees represented by collective bargaining units, would result in an increase in net periodic cost of $4 million as of both December 31, 2018 and 2017, for pension benefits and $1 million as of both December 31, 2018 and 2017, for other postretirement benefits.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Risk Management Policies
The Companies have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion Energy has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies of all subsidiaries, including Virginia Power and Dominion Energy Gas. Dominion Energy maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and
the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion Energy also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and the Companies’ December 31, 2018 provision for credit losses, management believes that it is unlikely that a material adverse effect on the Companies’ financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
Item 8.
Item 8. Financial Statements and Supplementary Data
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
Dominion Energy, Inc.
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Dominion Energy, Inc. and subsidiaries (“Dominion Energy”) at December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Dominion Energy at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), Dominion Energy’s internal control over financial reporting at December 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2019, expressed an unqualified opinion on Dominion Energy’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of Dominion Energy’s management. Our responsibility is to express an opinion on Dominion Energy’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Dominion Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 28, 2019
We have served as Dominion Energy’s auditor since 1988.
Dominion Energy, Inc.
Consolidated Statements of Income
(1) See Note 9 for amounts attributable to related parties.
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
Dominion Energy, Inc.
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
Dominion Energy, Inc.
Consolidated Balance Sheets
(1) See Note 9 for amounts attributable to related parties.
(1) See Note 9 for amounts attributable to related parties.
(2) 1 billion shares authorized; 681 million shares and 645 million shares outstanding at December 31, 2018 and 2017, respectively.
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
Dominion Energy, Inc.
Consolidated Statements of Equity
(1) See Note 17 for further information.
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements
Dominion Energy, Inc.
Consolidated Statements of Cash Flows
(1) See Note 9 for noncash activities related to equity method investments.
(2) See Note 19 for noncash activities related to the remeasurement of Dominion Energy’s noncontrolling interest in Dominion Energy Midstream.
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Virginia Electric and Power Company
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries (“Virginia Power”) at December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Virginia Power at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of Virginia Power’s management. Our responsibility is to express an opinion on Virginia Power’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Virginia Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Virginia Power’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 28, 2019
We have served as Virginia Power’s auditor since 1988.
Virginia Electric and Power Company
Consolidated Statements of Income
(1) See Note 24 for amounts attributable to affiliates.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Balance Sheets
(1) See Note 24 for amounts attributable to affiliates.
(1) See Note 24 for amounts attributable to affiliates.
(2) 500,000 shares authorized; 274,723 shares outstanding at December 31, 2018 and 2017.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Common Shareholder’s Equity
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Dominion Energy Gas Holdings, LLC
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Dominion Energy Gas Holdings, LLC (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries (“Dominion Energy Gas”) at December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Dominion Energy Gas at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of Dominion Energy Gas’ management. Our responsibility is to express an opinion on Dominion Energy Gas’ consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Dominion Energy Gas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Dominion Energy Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Dominion Energy Gas’ internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 28, 2019
We have served as Dominion Energy Gas’ auditor since 2012.
Dominion Energy Gas Holdings, LLC
Consolidated Statements of Income
(1) See Note 24 for amounts attributable to related parties.
The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.
Dominion Energy Gas Holdings, LLC
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.
Dominion Energy Gas Holdings, LLC
Consolidated Balance Sheets
(1) See Note 24 for amounts attributable to related parties.
(1) See Note 24 for amounts attributable to related parties.
The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.
Dominion Energy Gas Holdings, LLC
Consolidated Statements of Equity
The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.
Dominion Energy Gas Holdings, LLC
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.
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Combined Notes to Consolidated Financial Statements
NOTE 1. NATURE OF OPERATIONS
Dominion Energy, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas. Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion Energy. Dominion Energy Gas is a holding company that conducts business activities through a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution operations in Ohio, and gas gathering and processing activities primarily in West Virginia, Ohio and Pennsylvania. All of Dominion Energy Gas’ membership interests are held by Dominion Energy. The SCANA Combination was completed in January 2019. See Note 3 for a description of operations acquired in the SCANA Combination.
Dominion Energy’s operations also include the Cove Point LNG Facility, Cove Point Pipeline, Liquefaction Project, an equity investment in Atlantic Coast Pipeline and regulated gas transportation and distribution operations primarily in the eastern and Rocky Mountain regions of the U.S. Dominion Energy’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations.
At December 31, 2018, Dominion Energy owned the general partner, 60.9% of the common units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owned a preferred equity interest and the general partner interest in Cove Point, DECG, Dominion Energy Questar Pipeline and a 25.93% noncontrolling partnership interest in Iroquois. In January 2019, Dominion Energy acquired all outstanding partnership interests not owned by Dominion Energy and Dominion Energy Midstream became a wholly-owned subsidiary of Dominion Energy. At December 31, 2018, the public’s ownership interest in Dominion Energy Midstream is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements.
Through December 2018, Dominion Energy managed its daily operations through three primary operating segments: Power Delivery, Power Generation and Gas Infrastructure. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. Subsequent to the SCANA Combination, Dominion Energy manages the operations of SCANA through an additional operating segment, Southeast Energy.
Virginia Power manages its daily operations through two primary operating segments: Power Delivery and Power Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by
executive management in assessing the segments’ performance or in allocating resources.
Dominion Energy Gas manages its daily operations through one primary operating segment: Gas Infrastructure. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources and the effect of certain items recorded at Dominion Energy Gas as a result of Dominion Energy’s basis in the net assets contributed.
See Note 25 for further discussion of the Companies’ operating segments.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
General
The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates.
The Companies’ Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. At December 31, 2018, Dominion Energy owns 50% of the voting interests in Four Brothers and Three Cedars and has a controlling financial interest over the entities through its rights to control operations. In August 2018, NRG’s ownership interest in Four Brothers and Three Cedars was transferred to GIP. GIP’s ownership interest in Four Brothers and Three Cedars, Terra Nova Renewable Partners’ 33% interest in certain of Dominion Energy’s merchant solar projects and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019), is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion Energy’s remaining 67% ownership in certain merchant projects upon the occurrence of certain events, none of which are expected to occur in 2019.
The Companies report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.
The Companies consider acquisitions or dispositions in which substantially all of the fair value of the gross assets acquired or disposed of is concentrated into a single identifiable asset or group of similar identifiable assets to be an acquisition or a disposition of an asset, rather than a business. See Notes 3 and 10 for further information on such transactions.
Dominion Energy maintains pension and other postretirement benefit plans. Virginia Power and Dominion Energy Gas participate in certain of these plans. See Note 21 for further information on these plans.
Certain amounts in the Companies’ 2017 and 2016 Consolidated Financial Statements and Notes have been reclassified to
Combined Notes to Consolidated Financial Statements, Continued
conform to the 2018 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.
Amounts disclosed for Dominion Energy are inclusive of Virginia Power and/or Dominion Energy Gas, where applicable.
Operating Revenue
Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Dominion Energy and Virginia Power collect sales, consumption and consumer utility taxes and Dominion Energy Gas collects sales taxes; however, these amounts are excluded from revenue. Dominion Energy’s customer receivables at December 31, 2018 and 2017 included $626 million and $661 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2018 and 2017 included $392 million and $400 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. Dominion Energy Gas’ customer receivables at December 31, 2018 and 2017 included $131 million and $121 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its customers. See Note 24 for amounts attributable to related parties.
The primary types of sales and service activities reported as operating revenue for Dominion Energy, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:
REVENUE FROM CONTRACTS WITH CUSTOMERS
•
Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;
•
Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated hedging activity;
•
Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;
•
Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties and associated hedging activity;
•
Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;
•
Nonregulated gas transportation and storage sales consist primarily of LNG terminalling services;
•
Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and
•
Other nonregulated revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity. Other nonregulated revenue also includes services performed for Atlantic Coast Pipeline, sales of energy-related products
and services from Dominion Energy’s retail energy marketing operations, service concession arrangements and gas processing and handling revenue.
OTHER REVENUE
•
Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.
The primary types of sales and service activities reported as operating revenue for Dominion Energy, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:
•
Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;
•
Nonregulated electric sales consisted primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;
•
Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity;
•
Nonregulated gas sales consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity;
•
Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; and
•
Other revenue consisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also included miscellaneous service revenue from electric and gas distribution operations, sales of energy-related products and services from Dominion Energy’s retail energy marketing operations and gas processing and handling revenue.
The primary types of sales and service activities reported as operating revenue for Virginia Power, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:
REVENUE FROM CONTRACTS WITH CUSTOMERS
•
Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services;
•
Other regulated revenue consists primarily of sales of excess capacity and other commodities and miscellaneous service revenue from electric distribution operations; and
•
Other nonregulated revenue consists primarily of sales to non-jurisdictional customers from certain solar facilities, revenue from renting space on certain electric transmission poles and distribution towers and service concession arrangements.
OTHER REVENUE
•
Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.
The primary types of sales and service activities reported as operating revenue for Virginia Power, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:
•
Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; and
•
Other revenue consisted primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.
The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:
REVENUE FROM CONTRACTS WITH CUSTOMERS
•
Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;
•
Nonregulated gas sales consist primarily of sales of gas purchased from third parties and royalty revenues;
•
Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;
•
NGL revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity;
•
Management service revenue consists primarily of services performed for Atlantic Coast Pipeline;
•
Other regulated revenue consists primarily of miscellaneous regulated revenues; and
•
Other nonregulated revenue consists primarily of miscellaneous service revenue.
OTHER REVENUE
•
Other revenue consists primarily of gains and losses from derivative instruments not subject to hedge accounting.
The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:
•
Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services;
•
Nonregulated gas sales consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices and sales of gas purchased from third parties. Revenue from sales of gas production was recognized based on actual volumes of gas sold to purchasers and was reported net of royalties;
•
Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;
•
NGL revenue consisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity; and
•
Other revenue consisted primarily of miscellaneous service revenue, gas processing and handling revenue.
Dominion Energy and Virginia Power record refunds to customers as required by state commissions as a reduction to regulated electric sales or regulated gas sales, as applicable. Dominion Energy and Virginia Power’s revenue accounted for under the alternative revenue program guidance primarily consists of the equity return for under-recovery of certain riders. Alternative revenue programs compensate Dominion Energy and Virginia Power for certain projects and initiatives. Revenues arising from these programs are presented separately from revenue arising from contracts with customers in the categories above.
Revenues from electric and gas sales are recognized over time, as the customers of the Companies consume gas and electricity as it is delivered. Transportation and storage contracts are primarily stand-ready service contracts that include fixed reservation and variable usage fees. LNG terminalling services are also stand-ready service contracts, primarily consisting of fixed fees, offset by service credits associated with the start-up phase of the Liquefaction Project. Fixed fees are recognized ratably over the life of the contract as the stand-ready performance obligation is satisfied, while variable usage fees are recognized when Dominion Energy and Dominion Energy Gas have a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the performance obligation completed to date. Sales of products and services, including NGLs, typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type, but is typically due within a month of billing.
Dominion Energy and Dominion Energy Gas typically receive or retain NGLs and natural gas from customers when providing natural gas processing, transportation or storage services. The revised guidance for revenue from contracts with customers requires entities to include the fair value of the noncash consideration in the transaction price. Therefore, subsequent to the adoption of the revised guidance for revenue recognition from contracts with customers, Dominion Energy and Dominion Energy Gas record the fair value of NGLs received during natural gas processing as service revenue recognized over time, and continue to recognize revenue from the subsequent sale of the NGLs to customers upon delivery. Dominion Energy and Dominion Energy Gas typically retain natural gas under certain transportation service arrangements that are intended to facilitate performance of the service and allow for natural losses that occur. As the intent of the allowance is to enable fulfillment of the contract rather than to provide compensation for services, the fuel allowance is not included in revenue.
Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs
Where permitted by regulatory authorities, the differences between Dominion Energy and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion Energy and Dominion Energy Gas’ purchased gas expenses and the related
Combined Notes to Consolidated Financial Statements, Continued
levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.
Of the cost of fuel used in electric generation and energy purchases to serve utility customers, at December 31, 2018, approximately 84% is subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.
Virtually all of Dominion Energy Gas, Cove Point, Questar Gas, Hope and SCE&G and PSNC’s, following the SCANA Combination, natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale.
Income Taxes
A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including Virginia Power and Dominion Energy Gas’ subsidiaries. In addition, where applicable, combined income tax returns for Dominion Energy and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed.
Although Dominion Energy Gas is disregarded for income tax purposes, a provision for income taxes is recognized to reflect the inclusion of its business activities in the tax returns of its parent, Dominion Energy. Virginia Power and Dominion Energy Gas participate in intercompany tax sharing agreements with Dominion Energy and its subsidiaries. Current income taxes are based on taxable income or loss and credits determined on a separate company basis.
Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.
The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies, including changes in corporate tax rates and business deductions. The 2017 Tax Reform Act reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. Deferred tax assets and liabilities are classified as noncurrent in the Consolidated Balance Sheets and measured at the enacted tax rate expected to apply when temporary differences are realized or settled. Thus, at the date of enactment, federal deferred taxes were remeasured based upon the new 21% tax rate. The total effect of tax rate changes on deferred tax balances was recorded as a component of the income tax provision related to continuing operations for the period in which the law is enacted, even if the assets and liabilities relate to other components of the financial statements, such as items of accumulated other comprehensive income. For Dominion Energy subsidiaries that are not rate-regulated utilities, existing deferred income tax assets or liabilities were adjusted for the reduction in the corporate income tax rate and allocated to continuing operations. Dominion Energy’s rate-regulated utility subsidiaries likewise were required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in
income tax rates will be recovered or refunded in future rates, the regulated utility recorded a regulatory asset or liability instead of an increase or decrease to deferred income tax expense.
Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. The Companies establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.
The Companies recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.
If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in accrued interest, payroll and taxes on the Consolidated Balance Sheets.
The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income, respectively. Penalties are also recognized in other income.
Interest for the Companies was immaterial in 2018 and 2016. Dominion Energy and Virginia Power both recognized interest income of $11 million in 2017. Dominion Energy Gas’ interest was immaterial in 2017. Dominion Energy, Virginia Power and Dominion Energy Gas’ penalties were immaterial in 2018, 2017 and 2016.
At December 31, 2018, Virginia Power had an income tax-related affiliated receivable of $36 million, comprised of $34 million of federal income taxes and $2 million of state income taxes due from Dominion Energy. Dominion Energy Gas also had a net affiliated receivable of $2 million due from Dominion Energy, representing $8 million of federal income taxes receivable and $6 million of state income taxes payable to Dominion Energy. The net affiliated receivables are expected to be received from Dominion Energy.
In addition, Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018 included $13 million of state income taxes receivable. State income taxes receivable at Virginia Power were immaterial at December 31, 2018.
At December 31, 2017, Virginia Power had an income tax-related affiliated payable of $16 million, comprised of $16 million of federal income taxes due to Dominion Energy. Dominion Energy Gas also had an affiliated payable of $25 million due to Dominion Energy, representing $21 million of federal income taxes and $4 million of state income taxes. The net affiliated payables were paid to Dominion Energy.
In addition, Virginia Power’s Consolidated Balance Sheet at December 31, 2017 included $1 million of noncurrent federal income taxes receivable, less than $1 million of state income taxes receivable and $1 million of noncurrent state income taxes receivable. Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2017 included $14 million of state income taxes receivable.
Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.
Cash, Restricted Cash and Equivalents
Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.
Current banking arrangements generally do not require checks to be funded until they are presented for payment. The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies:
RESTRICTED CASH AND EQUIVALENTS
The Companies hold restricted cash and equivalent balances that primarily consist of amounts held for customer deposits, future debt payments on SBL Holdco and Dominion Solar Projects III, Inc.’s term loan agreements and on Eagle Solar’s senior note agreement.
The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within the Companies’ Consolidated Balance Sheets to the corresponding amounts reported within the Companies’ Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016:
(1) Restricted cash and equivalent balances are presented within other current assets in the Companies’ Consolidated Balance Sheets.
DISTRIBUTIONS FROM EQUITY METHOD INVESTEES
Dominion Energy and Dominion Energy Gas each hold investments that are accounted for under the equity method of accounting. Dominion Energy and Dominion Energy Gas classify distributions from equity method investees as either cash flows from operating activities or cash flows from investing activities in the Consolidated Statements of Cash Flows according to the nature of the distribution. Distributions received are classified on the basis of the nature of the activity of the investee that generated the distribution as either a return on investment (classified as cash flows from operating activities) or a return of an investment (classified as cash flows from investing activities) when such information is available to Dominion Energy and Dominion Energy Gas.
Combined Notes to Consolidated Financial Statements, Continued
Derivative Instruments
The Companies are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as interest rate and foreign currency exchange rate risks of their business operations. Dominion Energy uses derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage the commodity, interest rate and foreign currency exchange rate risks of its business operations. Virginia Power uses derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity and interest rate risks. Dominion Energy Gas uses derivative instruments such as physical and financial forwards, futures and swaps to manage commodity, interest rate and foreign currency exchange rate risks.
All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.
The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion Energy had margin assets of $95 million and $92 million associated with cash collateral at December 31, 2018 and 2017, respectively. Dominion Energy’s margin liabilities associated with cash collateral were less than $1 million at December 31, 2018 and 2017. Virginia Power had margin assets of $23 million associated with cash collateral at December 31, 2017. Virginia Power had no margin assets associated with cash collateral at December 31, 2018 and no margin liabilities associated with cash collateral at December 31, 2018 and 2017. Dominion Energy Gas had no margin assets or liabilities associated with cash collateral at December 31, 2018 and 2017. See Note 7 for further information about derivatives.
To manage price risk, the Companies hold certain derivative instruments that are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices. All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses, interest and related charges or other income based on the nature of the underlying risk.
Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.
DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS
In accordance with accounting guidance pertaining to derivatives and hedge accounting, the Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.
Cash Flow Hedges-A majority of the Companies’ hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and NGLs. The Companies also use interest rate swaps to hedge their exposure to variable interest rates on long-term debt as well as foreign currency swaps to hedge their exposure to interest payments denominated in Euros. For transactions in which the Companies are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.
Dominion Energy entered into interest rate derivative instruments to hedge its forecasted interest payments related to planned debt issuances in 2014. These interest rate derivatives were designated by Dominion Energy as cash flow hedges prior to the formation of Dominion Energy Gas. For the purposes of the Dominion Energy Gas financial statements, the derivative balances, AOCI balance, and any income statement impact related to these interest rate derivative instruments entered into by Dominion Energy have been, and will continue to be, included in the Dominion Energy Gas’ Consolidated Financial Statements as the forecasted interest payments related to the debt issuances now occur at Dominion Energy Gas.
Fair Value Hedges-Dominion Energy has also designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. In addition, Dominion Energy has used fair value hedges to mitigate the fixed price exposure inherent in commodity inventory. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.
Property, Plant and Equipment
Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred.
In 2018, 2017 and 2016, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $134 million, $236 million and $159 million, respectively. In 2018, 2017 and 2016, Virginia Power capitalized AFUDC to property, plant and equipment of $56 million, $37 million and $21 million, respectively. In 2018, 2017 and 2016, Dominion Energy Gas capitalized AFUDC to property, plant and equipment of $18 million, $25 million and $8 million, respectively.
Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2018, 2017 and 2016, Virginia Power recorded $4 million, $22 million and $31 million of AFUDC related to these projects, respectively.
For property subject to cost-of-service rate regulation, including Dominion Energy and Virginia Power electric distribution, electric transmission and generation property, Dominion Energy Gas natural gas distribution and transmission property, and for certain Dominion Energy natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be abandoned. In January 2019, Virginia Power committed to a plan to retire certain automated meter reading infrastructure associated with its electric operations before the end of its useful life and replace such equipment with more current AMI technology. As a result, Virginia Power expects to incur a charge of approximately $190 million ($141 million after-tax) in 2019.
For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.
Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows:
In the second quarter of 2018, Virginia Power recorded an adjustment for the retroactive application of depreciation rates for regulated nuclear plants to comply with Virginia Commission requirements. This adjustment resulted in a decrease of $60 million ($44 million after-tax) in depreciation expense in Virginia Power’s Consolidated Statements of Income for the year ended December 31, 2018. This resulted in an increase to Dominion Energy’s EPS of $0.07 per share for the year ended December 31, 2018. This revision is expected to decrease annual depreciation expense by approximately $30 million ($23 million after-tax).
In the first quarter of 2017, Virginia Power revised the depreciation rates for its assets to reflect the results of a new depreciation study. This change resulted in an increase in annual depreciation expense of $40 million ($25 million after-tax) for 2017. Additionally, Dominion Energy revised the depreciable lives for its merchant generation assets, excluding Millstone, which resulted in a decrease in annual depreciation expense of $26 million ($16 million after-tax) for 2017.
Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved gas and oil reserves, at a rate of $1.89 and $2.11 per mcfe in 2018 and 2017, respectively.
Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:
Combined Notes to Consolidated Financial Statements, Continued
Depreciation and amortization related to Virginia Power and Dominion Energy Gas’ nonutility property, plant and equipment and exploration and production properties was immaterial for the years ended December 31, 2018, 2017 and 2016, except for Dominion Energy Gas’ nonutility gas gathering and processing properties which are depreciated using the straight-line method over estimated useful lives between 10 and 50 years.
Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion Energy and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.
Long-Lived and Intangible Assets
The Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for further discussion on the impairment of long-lived assets.
Regulatory Assets and Liabilities
The accounting for Dominion Energy and Dominion Energy Gas’ regulated gas and Dominion Energy and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.
The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions, legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made.
Asset Retirement Obligations
The Companies recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair
value is estimated using discounted cash flow analyses. Quarterly, the Companies assess their AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. Dominion Energy and Dominion Energy Gas report accretion of AROs and depreciation on asset retirement costs associated with their natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Dominion Energy, following the SCANA Combination, and Virginia Power report accretion of AROs and depreciation on asset retirement costs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Additionally, Dominion Energy and Virginia Power report accretion of AROs and depreciation on asset retirement costs associated with certain rider and prospective rider projects as an adjustment to the regulatory asset for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs are reported in other operations and maintenance expense and depreciation expense, respectively, in the Consolidated Statements of Income.
Debt Issuance Costs
The Companies defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction in long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt securities prior to stated maturity dates are generally recognized and recorded in interest expense immediately. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized.
Investments
DEBT AND EQUITY SECURITIES WITH READILY DETERMINABLE FAIR VALUES
Dominion Energy accounts for and classifies investments in debt securities as trading or available-for-sale securities. Virginia Power classifies investments in debt securities as available-for-sale securities.
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Debt securities classified as trading securities include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.
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Debt securities classified as available-for-sale securities include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability
for certain jurisdictions subject to cost-based regulation. For all other available-for-sale debt securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.
In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method.
Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by Dominion Energy and Virginia Power in the nuclear decommissioning trusts. Dominion Energy and Virginia Power record all equity securities with a readily determinable fair value, or for which they are permitted to estimate fair value using NAV (or its equivalent), at fair value in nuclear decommissioning trust funds and other investments in the Consolidated Balance Sheets. However, Dominion Energy and Virginia Power may elect a measurement alternative for equity securities without a readily determinable fair value. Under the measurement alternative, equity securities are reported at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. Dominion Energy and Virginia Power qualitatively assess equity securities reported using the measurement alternative to determine whether an investment is impaired on an ongoing basis. Net realized and unrealized gains and losses on equity securities held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other equity securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts and rabbi trusts, net realized and unrealized gains and losses are included in other income in the Consolidated Statements of Income.
EQUITY SECURITIES WITHOUT READILY DETERMINABLE FAIR VALUES
The Companies account for illiquid and privately held securities without readily determinable fair values under either the equity method or cost method. Equity securities without readily determinable fair values include:
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Equity method investments when the Companies have the ability to exercise significant influence, but not control, over the investee. Dominion Energy’s investments are included in investments in equity method affiliates and Dominion Energy Gas’ investments are included in investments in their Consolidated Balance Sheets. Dominion Energy and Dominion Energy Gas record equity method adjustments in other income and earnings from equity method investee, respectively, in their Consolidated Statements of Income, including their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.
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Cost method investments when Dominion Energy and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion Energy and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds. Cost method investments are reported at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer.
OTHER-THAN-TEMPORARY IMPAIRMENT
The Companies periodically review their investments in debt securities and equity method investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in the fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period.
Decommissioning Trust Investments -Special Considerations for Debt Securities
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The recognition provisions of other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity.
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Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion Energy and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, Dominion Energy and Virginia Power record the credit loss in earnings and any remaining portion of the unrealized loss in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.
Inventories
Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory is valued using the weighted-average cost method, except for East Ohio gas distribution operations, which are valued using the LIFO method. Under the LIFO method, current stored gas inventory was valued at $12 million and $9 million at December 31, 2018 and December 31, 2017, respectively. Based on the average price of gas purchased during 2018 and 2017, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $87 million and $79 million, respectively.
Gas Imbalances
Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion Energy and Dominion Energy Gas value these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion Energy from other parties are reported in other current assets and imbalances that Dominion Energy and Dominion Energy Gas owe to other parties are
Combined Notes to Consolidated Financial Statements, Continued
reported in other current liabilities in the Consolidated Balance Sheets.
Goodwill
Dominion Energy and Dominion Energy Gas evaluate goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.
New Accounting Standards
REVENUE RECOGNITION
In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. The Companies adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. Upon the adoption of the standard, Dominion Energy and Dominion Energy Gas recorded the cumulative-effect of a change in accounting principle of $3 million to retained earnings and membership interests, respectively, and to establish a contract asset related to changes in the timing of revenue recognition for three existing contracts with customers at DETI.
As a result of adopting this revised accounting guidance, Dominion Energy and Dominion Energy Gas record offsetting operating revenue and other energy-related purchases for non-cash consideration of performing processing and fractionation services related to NGLs. Such amounts at Dominion Energy were $107 million and at Dominion Energy Gas were $103 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2018. No such amounts were recorded during the year ended December 31, 2017. Dominion Energy and Dominion Energy Gas no longer record offsetting operating revenue and purchased gas for fuel retained to offset costs on certain transportation and storage arrangements. Such amounts at Dominion Energy were $111 million and at Dominion Energy Gas were $79 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2017.
FINANCIAL INSTRUMENTS
In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018 and the Companies adopted the standard using the modified retrospective method. Upon adoption of this guidance for equity securities held at January 1, 2018, Dominion Energy and Virginia Power recorded the cumulative-effect of a change in accounting principle to reclassify net unrealized gains from AOCI to retained earnings and to recognize equity securities previously categorized as cost method investments at fair value (using NAV) in nuclear decommissioning trust funds in the Consolidated Balance Sheets and a cumulative-effect adjustment to retained earnings. Dominion Energy and Virginia Power reclassified approximately $1.1 billion ($734 million after-tax) and $119 million ($73 million after-tax), respectively, of net unrealized gains from AOCI to retained earnings. Dominion Energy and Virginia Power also recorded approximately $36 million ($22 million after-tax) in net unrealized gains on
equity securities previously classified as cost method investments, of which $3 million was recorded to retained earnings and $33 million was recorded to regulatory liabilities for net unrealized gains subject to cost-based regulation. As a result of adopting this revised accounting guidance, Dominion Energy recorded unrealized losses on equity securities, net of regulatory deferrals, of $190 million ($142 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018, resulting in an $0.22 loss per share for the year ended December 31, 2018. Virginia Power recorded unrealized losses on equity securities, net of regulatory deferrals, of $24 million ($18 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018.
LEASES
In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.
The guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2019. The Companies will adopt this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Companies are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Companies will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. Dominion Energy, Virginia Power and Dominion Energy Gas anticipate that the adoption of this guidance will result in approximately $450 million to $500 million, $200 million to $250 million and $60 million to $70 million, respectively, of offsetting right-of-use assets and liabilities added to their Consolidated Balance Sheets for operating leases in effect at the adoption date. Dominion Energy’s anticipated right-of-use asset and liability associated with operating leases includes those acquired as part of the SCANA Combination of approximately $30 million to $35 million. No material changes are expected to the Companies’ results of operations.
DERECOGNITION AND PARTIAL SALES OF NONFINANCIAL ASSETS
In February 2017, the FASB issued revised accounting guidance clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, and the Companies adopted the standard using the modified retrospective method. Upon adoption of the standard, Dominion Energy recorded the cumulative-effect of a change in accounting principle to reclassify
$127 million from noncontrolling interests to common stock related to the sale of a noncontrolling interest in certain merchant solar projects completed in December 2015 and January 2016.
NET PERIODIC PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS
In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. This guidance became effective for the Companies beginning January 1, 2018 and requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement costs are classified outside of income from operations. In addition, only the service cost component remains eligible for capitalization during construction. These changes do not impact the accounting by participants in a multi-employer plan. The standard also recognizes that in the event that a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. For costs not capitalized for which regulators are expected to provide recovery, a regulatory asset will be established. As such, the amounts eligible for capitalization in the Consolidated Financial Statements of Virginia Power and Dominion Energy Gas, as subsidiary participants in Dominion Energy’s multi-employer plans, will differ from the amounts eligible for capitalization in the Consolidated Financial Statements of Dominion Energy, the plan administrator. These differences will result in a regulatory asset or liability recorded in the Consolidated Financial Statements of Dominion Energy.
TAX REFORM
In December 2017, the staff of the SEC issued guidance which clarifies accounting for income taxes if information is not yet available or complete and provided for up to a one-year measurement period in which to complete the required analyses and accounting. The guidance described three scenarios associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply accounting for income taxes based on the provisions of the tax laws that were in effect immediately prior to the 2017 Tax Reform Act being enacted. The Companies have accounted for the effects of the 2017 Tax Reform Act, although additional changes could occur as guidance is issued and finalized as described below. In addition, certain states in which the Companies operate may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to results of operations and cash flows, and adjustments to tax-related assets and liabilities, and could be material.
In August 2018, the U.S. Department of Treasury issued proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017
through December 31, 2017. The application of these changes decreased Dominion Energy’s net operating loss carryforward utilization on its 2017 tax return as discussed in Note 5.
In November 2018, the U.S. Department of Treasury issued proposed regulations defining interest as any amounts associated with the time value of money or use of funds. These proposed regulations provide guidance for purposes of the exception to the interest limitation for regulated public utilities, the application of the interest limitation to consolidated groups, such as Dominion Energy, and the interest limitation with respect to partnerships and partners in those partnerships. It is unclear when the guidance may be finalized, or whether that guidance could result in a disallowance of a portion of the Companies’ interest deductions in the future.
In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. The Companies adopted this guidance for interim and annual reporting periods beginning January 1, 2018 on a prospective basis. In connection with the adoption of this guidance, Dominion Energy reclassified a benefit of $289 million from AOCI to retained earnings, Virginia Power reclassified a benefit of $3 million from AOCI to retained earnings and Dominion Energy Gas reclassified a benefit of $26 million from AOCI to membership interests. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of the Companies’ AOCI.
NOTE 3. ACQUISITIONS AND DISPOSITIONS
DOMINION ENERGY
Acquisition of SCANA
In January 2019, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock, in connection with the completion of the SCANA Combination. SCANA, through its regulated subsidiaries, is primarily engaged in the generation, transmission and distribution of electricity in the central, southern, and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. In addition, SCANA markets natural gas to retail customers in the southeast U.S. Following completion of the SCANA Combination, SCANA operates as a wholly-owned subsidiary of Dominion Energy. In addition, SCANA’s outstanding debt totaled $6.9 billion at closing. The SCANA Combination expands Dominion Energy’s portfolio of regulated electric generation, transmission and distribution and regulated natural gas distribution infrastructure and operations.
MERGER APPROVAL AND CONDITIONS
Merger Approval
The SCANA Combination required approval of SCANA’s shareholders, FERC, the North Carolina Commission, the South Carolina Commission, the Georgia Public Service Commission
Combined Notes to Consolidated Financial Statements, Continued
and the NRC and clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. All such approvals were received prior to closing of the SCANA Combination.
Various parties filed petitions for rehearing or reconsideration of the SCANA Merger Approval Order. In January 2019, the South Carolina Commission issued a directive (1) granting the request of various parties and finding that SCE&G was imprudent in its actions by not disclosing material information to the South Carolina Office of Regulatory Staff and the South Carolina Commission with regard to costs incurred subsequent to March 2015 and (2) denying the petitions for rehearing or consideration as to other issues raised in the various petitions. The SCANA Merger Approval Order and the order on rehearing are subject to appeal by various parties.
Refunds to Customers
As a condition to the SCANA Merger Approval Order, SCE&G will provide refunds and restitution of $2.0 billion over 20 years with capital support from Dominion Energy.
In September and October 2017, SCE&G received proceeds from Toshiba Corporation totaling $1.1 billion in full satisfaction of its share of a settlement agreement between SCE&G, Santee Cooper and Toshiba Corporation in connection with Westinghouse and WECTEC, both wholly-owned subsidiaries of Toshiba Corporation and responsible for the engineering and construction of the NND Project, filing for bankruptcy. The purchase price allocation below includes a previously established regulatory liability at SCE&G totaling $1.1 billion associated with the monetization of the bankruptcy settlement with Toshiba Corporation. In accordance with the terms of the SCANA Merger Approval Order, this regulatory liability, net of amounts that may be required to satisfy any liens against NND Project property totaling $1.0 billion, will be refunded to SCE&G electric service customers over a 20-year period ending in 2039.
Additionally, SCE&G will reflect in the first quarter of 2019 a reduction in operating revenue and a corresponding regulatory liability of $1.0 billion of which approximately $140 million will be considered current, representing a refund of amounts previously collected from retail electric customers of SCE&G for the NND Project to be credited over an estimated 11-year period. This will result in a $756 million after-tax charge in Dominion Energy’s Consolidated Statements of Income in the first quarter of 2019.
NND Project
As a condition to the SCANA Merger Approval Order, SCE&G will exclude from rate recovery $2.4 billion of costs related to the NND Project and $180 million of costs associated with the purchase of the Columbia Energy Center power station. Regulatory assets included in SCANA’s historical balance sheet at December 31, 2018 reflected these disallowances.
The remaining regulatory asset associated with the NND Project of $2.8 billion will be collected over a 20-year period, including a return on investment. In January 2019, SCE&G filed the NND Project rider in accordance with the terms of the SCANA Merger Approval Order for rates effective in February 2019 for SCE&G’s retail electric customers. The South Carolina Commission approved this filing in January 2019.
Other Terms and Conditions
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SCE&G will not file an application for a general rate case with the South Carolina Commission with a requested effective date earlier than January 2021;
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PSNC will not file an application for a general rate case with the North Carolina Commission with a requested effective date earlier than April 2021;
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Dominion Energy has committed to increasing SCANA’s historical level of corporate contributions to charities by $1 million per year over the next five years;
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Dominion Energy will maintain SCE&G and PSNC’s headquarters in Cayce, South Carolina and Gastonia, North Carolina, respectively; and
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Dominion Energy will seek to minimize reductions in local employment by allowing some DES employees supporting shared and common services functions and activities to be located in Cayce, South Carolina where it makes economic and practical sense to do so.
PURCHASE PRICE ALLOCATION
SCANA’s assets acquired and liabilities assumed will be measured at estimated fair value at closing and will be included in the Southeast Energy operating segment, which was established following the closing of the SCANA Combination. The majority of the operations acquired are subject to the rate setting authority of FERC and the North and South Carolina Commissions and are therefore accounted for pursuant to ASC 980, Regulated Operations. The fair values of SCANA’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the unaudited pro forma financial information, reflect any adjustments related to these amounts.
The fair value of SCANA’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions discussed above and the fair values of SCANA’s investments accounted for under the equity method will be determined using the income approach and the market approach. The valuation of SCANA’s long-term debt is considered a Level 2 fair value measurement. All other valuations will be considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed will be reflected as goodwill in the first quarter of 2019. The goodwill reflects the value associated with enhancing Dominion Energy’s portfolio of regulated operations in the growing southeast region of the U.S. The goodwill to be recognized will not be deductible for income tax purposes, and as such, no deferred taxes will be recorded related to goodwill.
The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at closing to be reflected in Dominion Energy’s Consolidated Balance Sheet in the first quarter of 2019. The allocation is subject to change during the measurement period as additional information is obtained about the facts and circumstances that existed at closing. The allocation of the purchase price excludes certain contracts and intangible assets related to nonregulated operations, including SEMI, equity method investments and certain income tax-related amounts, which will be included as Dominion Energy completes its valuation analysis. As a result, the amount of goodwill included below may change by a material amount as Dominion Energy finalizes the allocation of the purchase price during the first quarter of 2019.
INFORMATION ON ASSETS AND LIABILITIES ACQUIRED
Cash, Restricted Cash and Equivalents
The total current assets line above includes $389 million of cash, restricted cash and equivalents, of which $115 million is considered restricted, acquired by Dominion Energy in connection with the SCANA Combination.
Investments
Investments acquired in connection with the SCANA Combination include $20 million pertaining to certain investments accounted for under the equity method, at carrying value. Dominion Energy is still assessing the fair value of these investments.
Income Taxes
Deferred income taxes include a deferred tax asset recorded on a federal net operating loss carryforward of $1.8 billion and a state net operating loss carryforward of $2.4 billion. Based on the available evidence, Dominion Energy believes it is more likely than not that the benefit of the federal net operating loss will be utilized during the carryforward period, and therefore no valuation allowance has been established. Dominion Energy is still assessing whether a valuation allowance is required on the state net operating loss carryforward. Deferred income taxes also include unrecognized tax benefits of $106 million, which could increase as Dominion Energy continues and completes its evaluation of positions taken on SCANA’s federal and state income tax returns.
Property, Plant and Equipment
At the date of the SCANA Combination, major classes of property, plant and equipment and their respective balances for SCANA are as follows:
In connection with the SCANA Combination, Dominion Energy intends to forego recovery of approximately $105 million of certain assets for which it expects to recognize a $79 million after-tax charge in the first quarter of 2019.
Regulated property will be depreciated on a straight-line basis based on projected service lives. Actual average composite depreciation rates for SCANA’s utility property, plant and equipment were as follows:
Nonregulated property, plant and equipment, excluding land, will be depreciated on a straight-line basis over the remaining useful lives of such property, primarily ranging from 5 to 78 years.
SCE&G jointly owns and is the operator of Summer. At December 31, 2018, and subsequent to the SCANA Combination, SCE&G had a 66.7% ownership interest in Summer, of which its proportionate share of plant in service, accumulated depreciation and plant under construction was $1.5 billion, $644 million and $128 million, respectively. The co-owners are obligated to pay their share of all future construction expenditures and operating costs of Summer in the same proportion as their respective ownership interest.
Regulatory Assets
In addition to the items discussed above related to the NND Project, Dominion Energy intends to forego recovery of approximately $190 million of regulatory assets related to certain deferred income taxes for which it expects to recognize a $145 million after-tax charge in the first quarter of 2019.
Intangible Assets
Other current assets presented in the table above include intangible assets subject to regulatory recovery with a gross carrying value of $281 million and related accumulated amortization of $181 million. Such intangible assets have an estimated
Combined Notes to Consolidated Financial Statements, Continued
weighted-average amortization period of approximately five years. Annual amortization expense for these intangible assets is estimated to be as follows:
Asset Retirement Obligations
The purchase price allocation above includes $577 million of AROs, of which $23 million is considered to be a current liability. These AROs are associated with SCANA’s legal obligation to decommission Summer, as well as conditional obligations related to generation, transmission and distribution properties, including gas pipelines.
Short-Term and Long-Term Debt
At closing of the SCANA Combination, commercial paper and letters of credit outstanding, as well as capacity available under SCANA’s existing credit facilities were as follows:
(1) Includes South Carolina Fuel Company, Inc.’s $500 million credit facility.
(2) In January 2019, SCANA repaid $40 million in letter of credit advances.
In connection with the SCANA Combination, Dominion Energy intends to terminate SCANA, SCE&G and PSNC’s existing credit facilities, scheduled to expire in December 2020, and add SCE&G as a co-borrower to its $6.0 billion joint revolving credit facility in the first quarter of 2019 once certain regulatory approvals are obtained. In January 2019, Virginia Power and SCE&G, as co-borrowers, filed with the Virginia Commission and the South Carolina Commission, respectively, for approval. In February 2019, the Virginia Commission approved the request. SCE&G is required to obtain FERC approval to issue short-term indebtedness, including commercial paper, and to assume liabilities as a guarantor. In February 2019, Dominion Energy terminated South Carolina Fuel Company, Inc.’s existing credit facility, scheduled to expire in December 2020.
At closing of the SCANA Combination, SCANA had the following long-term debt outstanding which is part of the total consideration provided for the transaction.
(1) Represents weighted-average coupon rates for debt outstanding at closing of the SCANA Combination.
(2) Includes variable rate debt of $68 million, with a weighted-average interest rate of 1.72%, which is hedged by fixed swaps.
Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at closing of the SCANA Combination, were as follows:
In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of $1.0 billion. SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer.
Preferred Stock
At the closing of the SCANA Combination, authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were held by SCANA.
REGULATORY MATTERS AND PROCEEDINGS
Base Load Review Act
In 2016, the South Carolina Commission approved revised rates under the Base Load Review Act allowing the incorporation of financing costs associated with SCE&G’s incremental construction work in progress incurred for the NND Project and setting an allowed ROE of 10.5%. In July 2018, the South Carolina Commission issued orders implementing a June 2018 legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from its electric utility customers under the Base Load Review Act and altering certain provisions previously applicable under the Base Load Review Act, including redefining the standard of care required by the associated regulations and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the NND Project. These orders reduced the portion of SCE&G’s retail electric rates associated with the NND Project from approximately 18% of the average residential electric customer’s bill, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 2018. These lower rates remained in effect until February 2019, when the new rates pursuant to the SCANA Merger Approval Order became effective.
In June 2018, SCE&G filed a lawsuit in the U.S. District Court for the District of South Carolina challenging the constitutionality of the rate reductions under the Base Load Review Act. In the lawsuit, which was subsequently amended, SCE&G sought a declaration that the new laws are unconstitutional. In January 2019, SCE&G voluntarily dismissed this lawsuit.
2017 Tax Reform Act
In connection with the SCANA Merger Approval Order, the South Carolina Commission approved SCE&G’s provision of approximately $100 million in bill credits related to the 2017 Tax Reform Act’s impact on retail electric customer rates for the period beginning January 2018 through January 2019. These credits have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved a tax rider whereby the effects of the reduction in the corporate income tax rate resulting from the 2017 Tax Reform Act will benefit retail electric customers. This tax rider is expected to reduce base rates to retail electric customers by approximately $67 million in each of 2019 and 2020, effective with the first billing cycle of February 2019.
In October 2018, the South Carolina Commission issued an order approving adjustment to SCE&G’s natural gas rate schedules, under the terms of the Natural Gas Rate Stabilization Act, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. The approved natural gas rate schedules also included a tax reform rate rider to refund certain income tax amounts previously collected from customers. These lower rates, representing a $20 million decreased revenue requirement, became effective for bills rendered on and after the first billing cycle in November 2018.
In December 2018, the North Carolina Commission issued an order approving PSNC’s proposed adjustments to customer rates, representing a $13 million decreased revenue requirement, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. These lower rates became effective for service rendered on and after January 1, 2019. Amounts collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC’s next general rate case proceeding or in three years, whichever is sooner. The reduction in the federal corporate tax rate and its impact on PSNC’s various rate riders will be addressed in future proceedings related to those riders.
DSM Programs
SCE&G has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2019, SCE&G filed an application with the South Carolina Commission seeking approval to recover $30 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. This matter is pending.
LEGAL PROCEEDINGS
The following describes certain legal proceedings to which SCANA or SCE&G were a party to at closing of the SCANA Combination. Dominion Energy intends to vigorously contest the lawsuits, claims and assessments which have been filed or initiated against SCANA and SCE&G. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. Due to the uncertainty surrounding these matters, Dominion Energy is unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on its results of operations, financial condition and/or cash flows.
Ratepayer Class Actions
In May 2018, a consolidated complaint against SCE&G, SCANA, and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the SCE&G Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that SCE&G was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NND Project, and that SCE&G committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and SCE&G’s assets frozen and all monies recovered from Toshiba Corporation and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project.
In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the SCE&G Ratepayer Case. The settlement agreement, contingent upon the closing of the SCANA Combination, provides that SCANA and SCE&G would establish an escrow account and proceeds from the escrow account would be distributed to the
Combined Notes to Consolidated Financial Statements, Continued
class members, after payment of certain taxes, attorneys’ fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain SCE&G-owned real estate or sales proceeds from the sale of such properties, which counsel for the SCE&G Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and SCE&G have funded this escrow account. The court has scheduled a fairness hearing on the settlement in May 2019. Any distribution from the escrow account is subject to court approval. As a result, Dominion Energy expects to reflect an approximately $180 million ($135 million after-tax) charge in the first quarter of 2019.
In September 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, South Carolina (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the SCE&G Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants, including certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs’ fourth amended complaint and filed cross claims against SCE&G. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.
RICO Class Action
In January 2018, a purported class action was filed, and subsequently amended, against SCANA, SCE&G and certain former executive officers in the U.S. District Court for the District of South Carolina. The plaintiff alleges, among other things, that SCANA, SCE&G and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The SCE&G Ratepayer Class Action settlement described previously contemplates dismissal of claims by SCE&G ratepayers in this case against SCE&G, SCANA and their officers. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.
State Court Shareholder Actions
In September 2017, a purported shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina. In September 2018, this action was consolidated with another action in the Business Court Pilot
Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the NND Project, and that the defendants were unjustly enriched by bonuses they were paid in connection with the project. The defendants have filed a motion to dismiss the consolidated action in favor of the pending federal derivative action. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.
In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal has been consolidated with a similar appeal and remains pending. In October 2018, the U.S. District Court for the District of South Carolina granted Dominion Energy’s motion to stay pending appeal. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.
In February 2018, a purported class action was filed against certain former directors of SCANA and SCE&G and Dominion Energy in the State Court of Common Pleas in Richland County, South Carolina. The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the State Court of Common Pleas in Richland County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal has been consolidated with the City of Warren Lawsuit. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.
Federal Court Shareholder Action
In November 2017, a purported shareholder derivative action was filed against SCANA and certain former executive officers and directors in the U.S. District Court of the District of South Carolina. Another purported shareholder derivative action was filed against nearly all of these defendants. In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint. The plaintiffs allege, among other things, that the defendants violated their fiduciary duties to shareholders by
disseminating false and misleading information about the NND Project, failing to maintain proper internal controls, failing to properly oversee and manage SCANA and that the individual defendants were unjustly enriched in their compensation. In June 2018, the court denied the defendants’ motions to dismiss and in October 2018, the court denied SCANA’s motion to stay all proceedings pending investigation by a Special Litigation Committee, with leave to refile after the SCANA Merger Approval Order was issued. The plaintiffs have agreed to a stay of this action on the condition that defendants file a motion for judgment on the pleadings, which was filed in January 2019. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.
Federal Court 10b-5 and Merger Actions
In September 2017, a purported class action was filed against SCANA and certain former executive officers and directors in the U.S. District Court for the District of South Carolina. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants. In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of same act. In June 2018, the defendants filed motions to dismiss, which are pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.
Employment Class Action and Indemnification
In July 2018, a case filed in the U.S. District Court for the District of South Carolina was certified as a class action on behalf of persons who were formerly employed at the NND Project. The plaintiffs allege, among other things, that SCANA, Fluor Corporation and Fluor Enterprises, Inc. violated the Worker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NND Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment, which is estimated to be as much as $75 million. SCE&G as co-owner of the NND project would have a 55% proportional share in the ultimate outcome. The ultimate loss could rise due to the Fluor defendants seeking indemnification from SCE&G.
In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against SCE&G and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants’ alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. These cases are pending.
FILOT Litigation and Related Matters
In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against SCE&G in the State Court of Common Pleas in Fairfield County, South Carolina,
making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to SCE&G’s termination of the FILOT agreement between SCE&G and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent SCE&G from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. Dominion Energy is currently unable to make an estimate of the potential impacts to its consolidated financial statements related to this matter. This case is pending.
Governmental Proceedings and Investigations
In June 2018, SCE&G received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of SCE&G’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that SCE&G’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. SCE&G has protested the proposed assessment, which remains pending, and recorded an $11 million liability in its Consolidated Balance Sheet as of December 31, 2018 for its share of any taxes ultimately due.
In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and SCE&G. These matters are pending. SCANA and SCE&G are cooperating fully with the investigations; however, Dominion Energy cannot currently predict whether or to what extent SCANA or SCE&G may incur a material liability.
Other
In December 2018, arbitration proceedings commenced between SCE&G and Cameco Corporation related to a supply agreement signed in May 2008. This agreement provides the terms and conditions under which SCE&G agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that SCE&G violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for 2017 and 2018 delivery years. SCE&G denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. Dominion Energy cannot determine the outcome or timing of this matter.
COMMITMENTS AND CONTINGENCIES
Abandoned NND Project
SCE&G, for itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with Westinghouse and WECTEC in 2008 for the design and construction of the NND Project, of which SCE&G’s ownership share is 55%. Various difficulties were encountered in connection with the project. The ability of Westinghouse and WECTEC to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the con
Combined Notes to Consolidated Financial Statements, Continued
struction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by Westinghouse and WECTEC in March 2017, and were the subject of comprehensive analyses performed by SCANA and Santee Cooper.
Based on the results of SCANA’s analysis, and in light of Santee Cooper’s decision to suspend construction on the NND Project, in July 2017, SCANA determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the Base Load Review Act or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings. Some of these proceedings remain unresolved and are described above under the heading Legal Proceedings.
In September 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of Westinghouse and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by Westinghouse and WECTEC of the contract, and assert against Westinghouse and WECTEC any and all claims that are based thereon or that may be related thereto. SCE&G and Santee Cooper remain responsible for any claims that may be made by Westinghouse and WECTEC against them relating to the contract.
Westinghouse’s reorganization plan was confirmed by the Bankruptcy Court and became effective in August 2018. In connection with the effectiveness of the reorganization plan, the contract associated with the NND Project was deemed rejected. SCE&G is contesting approximately $285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens are claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them are claims arising from work performed after the Westinghouse bankruptcy.
Westinghouse has indicated that some unsecured creditors have sought or may seek amounts beyond what Westinghouse allocated when it submitted its reorganization plan to the Bankruptcy Court. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the bankruptcy reorganization plan allocated by Westinghouse, it is possible that the reorganization plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant.
SCE&G and Santee Cooper are responsible for amounts owed to Westinghouse for valid work performed by Westinghouse subcontractors on the NND Project after the Westinghouse bankruptcy filing until termination of the interim assessment agreement. SCE&G does not believe that the claims asserted related to the interim assessment agreement period will exceed the amounts previously funded, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose
any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the interim assessment agreement. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.
Further, some Westinghouse subcontractors who have made claims against Westinghouse in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. Many of these claimants have also asserted construction liens against the NND Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of Westinghouse Subcontractors, SCE&G believes there were sufficient amounts previously funded during the interim assessment agreement period to pay such validly asserted claims. With respect to the Westinghouse subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to Westinghouse’s confirmed bankruptcy reorganization plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, SCE&G believes that the Westinghouse subcontractors may be paid substantially (and potentially in full) by Westinghouse. While Dominion Energy cannot be assured that it will not have any exposure on account of unpaid Westinghouse subcontractor claims, which SCE&G is presently disputing, Dominion Energy believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.
Environmental Matters
Contingencies involving environmental matters, including ash pond and landfill closure costs, affecting SCANA have been included within Note 22.
Nuclear Insurance and Spent Nuclear Fuel
SCE&G’s maximum assessment for a nuclear incident under the Price-Anderson Amendments Act of 1988 would be $92 million per incident, but not more than $14 million per year, for its proportionate ownership interest in Summer. SCE&G currently maintains insurance policies, for itself and on behalf of Santee Cooper, with NEIL. The policies provide coverage to Summer for property damage and outage costs up to $2.8 billion resulting from an event of nuclear origin. The NEIL policies, in aggregate, are subject to a maximum loss of $2.8 billion for any single loss occurrence. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $23 million.
In addition, SCE&G currently maintains an excess property insurance policy, for itself and on behalf of Santee Cooper. The policy provides coverage to Summer for property damage and outage costs up to $415 million resulting from an event of non-nuclear origin. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $2 million.
SCE&G entered into a contract with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982.
Long-Term Purchase Agreements
SCANA has 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:
(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities which expire at various dates through 2046. Capacity payments under the contracts are generally based on fixed dollar amounts per month.
Lease Commitments
SCANA is obligated under various operating leases for land, office space, furniture, equipment, rail cars and airplanes. Such leases expire at various dates through 2057.
Unaudited Pro Forma Information
Dominion Energy incurred transaction costs of $27 million, recorded in other operations and maintenance expense in the Consolidated Statements of Income for the year end December 31, 2018. These costs consist of professional fees and other miscellaneous costs.
The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the SCANA Combination had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and may change as Dominion Energy finalizes its valuation of certain assets acquired and liabilities assumed at the acquisition date. The unaudited pro forma financial information is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.
(1) Amounts include adjustments for non-recurring costs directly related to the SCANA Combination.
ACQUISITION OF DOMINION ENERGY QUESTAR
In September 2016, Dominion Energy completed the Dominion Energy Questar Combination and Dominion Energy Questar, a Rockies-based integrated natural gas company consisting of Questar Gas, Wexpro and Dominion Energy Questar Pipeline, became a wholly-owned subsidiary of Dominion Energy. Questar Gas has regulated gas distribution operations in Utah, southwestern Wyoming and southeastern Idaho. Wexpro develops and produces natural gas from reserves supplied to Questar Gas under a cost-of-service framework. Dominion Energy Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage services in Utah, Wyoming and western Colorado. The Dominion Energy Questar Combination provides Dominion Energy with pipeline infrastructure that provides a principal
source of gas supply to Western states. Dominion Energy Questar’s regulated businesses also provide further balance between Dominion Energy’s electric and gas operations.
In accordance with the terms of the Dominion Energy Questar Combination, at closing, each share of issued and outstanding Dominion Energy Questar common stock was converted into the right to receive $25.00 per share in cash. The total consideration was $4.4 billion based on 175.5 million shares of Dominion Energy Questar outstanding at closing.
Dominion Energy financed the Dominion Energy Questar Combination through the: (1) August 2016 issuance of $1.4 billion of 2016 Equity Units, (2) August 2016 issuance of $1.3 billion of senior notes, (3) September 2016 borrowing of $1.2 billion under a term loan agreement and (4) $500 million of the proceeds from the April 2016 issuance of common stock.
Purchase Price Allocation
Dominion Energy Questar’s assets acquired and liabilities assumed were measured at estimated fair value at the closing date and are included in the Gas Infrastructure operating segment. The majority of operations acquired are subject to the rate-setting authority of FERC, as well as the Utah Commission and/or the Wyoming Commission and therefore are accounted for pursuant to ASC 980, Regulated Operations. The fair values of Dominion Energy Questar’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.
The fair value of Dominion Energy Questar’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions discussed above was determined using the income approach. In addition, the fair value of Dominion Energy Questar’s 50% interest in White River Hub, accounted for under the equity method, was determined using the market approach and income approach. The valuations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future cash flows and future market prices.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill at the closing date. The goodwill reflects the value associated with enhancing Dominion Energy’s regulated portfolio of businesses, including the expected increase in demand for low-carbon, natural gas-fired generation in the Western states and the expected continued growth of rate-regulated businesses located in a defined service area with a stable regulatory environment. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill.
The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at closing which reflects the following adjustments from the preliminary valuation recognized during the measurement period. During the fourth quarter of 2016, certain modifications were made to preliminary valuation amounts for acquired property, plant and equipment, current liabilities, and deferred income taxes, resulting in a $6 million net decrease to goodwill, which related primarily to
Combined Notes to Consolidated Financial Statements, Continued
the sale of Questar Fueling Company in December 2016 as further described in the Sale of Questar Fueling Company. In the third quarter of 2017, certain modifications were made to the valuation amounts for regulatory liabilities, current liabilities and deferred income taxes, resulting in a $6 million net increase to goodwill recorded in Dominion Energy’s Consolidated Balance Sheets. The modifications relate primarily to the finalization of Dominion Energy Questar’s 2016 tax return for the period January 1, 2016 through the Dominion Energy Questar Combination, as well as certain regulatory adjustments.
(1) Includes $40 million for an equity method investment in White River Hub. The fair value adjustment on the equity method investment in White River Hub is considered to be equity method goodwill and is not amortized.
(2) Nonregulated property, plant and equipment, excluding land, will be depreciated over remaining useful lives primarily ranging from 9 to 18 years.
(3) Includes $301 million of short-term debt, of which no amounts remain outstanding at December 31, 2018, as well as a $250 million variable interest rate term loan due in August 2017 that was paid in July 2017.
(4) Unsecured senior and medium-term notes with maturities which range from 2017 to 2048 and bear interest at rates from 2.98% to 7.20%.
Regulatory Matters
The transaction required approval of Dominion Energy Questar’s shareholders, clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act and approval from both the Utah Commission and the Wyoming Commission. In February 2016, the Federal Trade Commission granted antitrust approval of the Dominion Energy Questar Combination under the Hart-Scott-Rodino Act. In May 2016, Dominion Energy Questar’s shareholders voted to approve the Dominion Energy Questar Combination. In August 2016 and September 2016, approvals were granted by the Utah Commission and the Wyoming Commission, respectively. Information regarding the transaction was also provided to the Idaho Commission, who acknowledged the Dominion Energy Questar Combination in October 2016, and directed Dominion Energy Questar to notify the Idaho Commission when it makes filings with the Utah Commission.
With the approval of the Dominion Energy Questar Combination in Utah and Wyoming, Dominion Energy agreed to the following:
•
Contribution of $75 million to Dominion Energy Questar’s qualified and non-qualified defined-benefit pension plans and its other post-employment benefit plans within
six months of the closing date. This contribution was made in January 2017.
•
Increasing Dominion Energy Questar’s historical level of corporate contributions to charities by $1 million per year for at least five years.
•
Withdrawal of Questar Gas’ general rate case filed in July 2016 with the Utah Commission and agreement to not file a general rate case with the Utah Commission to adjust its base distribution non-gas rates prior to July 2019, unless otherwise ordered by the Utah Commission. In addition, Questar Gas agreed not to file a general rate case with the Wyoming Commission with a requested rate effective date earlier than January 2020. Questar Gas’ ability to adjust rates through various riders is not affected.
Results of Operations and Unaudited Pro Forma Information
The impact of the Dominion Energy Questar Combination on Dominion Energy’s operating revenue and net income attributable to Dominion Energy in the Consolidated Statements of Income for the twelve months ended December 31, 2016 was an increase of $379 million and $73 million, respectively.
Dominion Energy incurred transaction and transition costs in 2018, 2017 and 2016, of which $9 million, $26 million and $58 million was recorded in other operations and maintenance expense, respectively, and $16 million was recorded in interest and related charges in 2016 in Dominion Energy’s Consolidated Statements of Income. These costs consist of the amortization of financing costs, the charitable contribution commitment described above, employee-related expenses, professional fees, and other miscellaneous costs.
The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the Dominion Energy Questar Combination had taken place on January 1, 2016. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.
(1) Amounts include adjustments for non-recurring costs directly related to the Dominion Energy Questar Combination.
Contribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream
In October 2016, Dominion Energy entered into the Contribution Agreement under which Dominion Energy contributed Dominion Energy Questar Pipeline to Dominion Energy Midstream. Upon closing of the agreement on December 1, 2016, Dominion Energy Midstream became the owner of all of the issued and outstanding membership interests of Dominion Energy Questar Pipeline in exchange for consideration consisting
of Dominion Energy Midstream common and convertible preferred units with a combined value of $467 million and cash payment of $823 million, $300 million of which is considered a debt-financed distribution, for a total of $1.3 billion. In addition, under the terms of the Contribution Agreement, Dominion Energy Midstream repurchased 6,656,839 common units from Dominion Energy, and repaid its $301 million promissory note to Dominion Energy in December 2016. The cash proceeds from these transactions were utilized in December 2016 to repay the $1.2 billion term loan agreement borrowed in September 2016. Since Dominion Energy consolidates Dominion Energy Midstream for financial reporting purposes, the transactions associated
with the Contribution Agreement were eliminated upon consolidation. See Note 5 for the tax impacts of the transactions.
Sale of Questar Fueling Company
In December 2016, Dominion Energy completed the sale of Questar Fueling Company. The proceeds from the sale were $28 million, net of transaction costs. No gain or loss was recorded in Dominion Energy’s Consolidated Statements of Income, as the sale resulted in measurement period adjustments to the net assets acquired of Dominion Energy Questar. See the Purchase Price Allocation section above for additional details on the measurement period adjustments recorded.
Wholly-Owned Merchant Solar Projects
ACQUISITIONS
The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion Energy.
(1) The purchase price was primarily allocated to Property, Plant and Equipment.
(2) Includes acquisition cost.
(3) In April 2017, Dominion Energy discontinued efforts on the acquisition of the additional 20 MW solar project from Solar Frontier Americas Holding LLC.
In addition during 2016, Dominion Energy acquired 100% of the equity interests of seven solar projects in Virginia, North Carolina and South Carolina for an aggregate purchase price of $32 million, all of which was allocated to property, plant and equipment. The projects cost $421 million in total, including initial acquisition costs, and generate 221 MW combined. One of the projects commenced commercial operations in 2016 and the remaining projects commenced commercial operations in 2017.
Long-term power purchase, interconnection and operation and maintenance agreements have been executed for all of the projects described above. These projects are included in the Power Generation operating segment. Dominion Energy has claimed federal investment tax credits on these solar projects.
SALE OF INTEREST IN MERCHANT SOLAR PROJECTS
In September 2015, Dominion Energy signed an agreement to sell a noncontrolling interest (consisting of 33% of the equity interests) in all of its then-currently wholly-owned merchant solar projects, 24 solar projects totaling 425 MW, to SunEdison. In December 2015, the sale of interest in 15 of the solar projects closed for $184 million with the sale of interest in the remaining projects completed in January 2016 for $117 million. Upon closing, SunEdison sold its interest in these projects to Terra Nova Renewable Partners.
Non-Wholly-Owned Merchant Solar Projects
ACQUISITIONS OF FOUR BROTHERS AND THREE CEDARS
In June 2015, Dominion Energy acquired 50% of the units in Four Brothers from SunEdison for $64 million of consideration. Four Brothers operates four solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, generating 320 MW, at a cost of approximately $670 million.
In September 2015, Dominion Energy acquired 50% of the units in Three Cedars from SunEdison for $43 million of consideration. Three Cedars operates three solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, generating 210 MW, at a cost of approximately $450 million.
The Four Brothers and Three Cedars facilities operate under long-term power purchase, interconnection and operation and maintenance agreements. Dominion Energy claimed 99% of the federal investment tax credits on the projects.
Combined Notes to Consolidated Financial Statements, Continued
Dominion Energy has assumed the majority of the agreements to provide administrative and support services in connection with operations and maintenance of the facilities and technical management services of the solar facilities. Costs related to services to be provided under these agreements were immaterial for the years ended December 31, 2018, 2017 and 2016.
In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison. Subsequent to Dominion Energy’s acquisition of Four Brothers and
Three Cedars, SunEdison and NRG made contributions to Four Brothers and Three Cedars of $301 million in aggregate through December 31, 2017, which are reflected as noncontrolling interests in the Consolidated Balance Sheets. In August 2018, NRG’s ownership in Four Brothers and Three Cedars was transferred to GIP.
DOMINION ENERGY AND DOMINION ENERGY GAS
Blue Racer
See Note 9 for a discussion of transactions related to Blue Racer.
NOTE 4. OPERATING REVENUE
The Companies’ operating revenue, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, consists of the following:
(1) See Notes 9 and 24 for amounts attributable to related parties and affiliates.
(2) Amounts above include $241 million and $206 million for the year ended December 31, 2018 primarily consisting of NGL sales at Dominion Energy and Dominion Energy Gas, respectively, which are considered to be goods transferred at a point in time. In addition, the amounts include $17 million and $11 million of sales of renewable energy credits at both Dominion Energy and Virginia Power for the year ended December 31, 2018, respectively, which are considered to be goods transferred at a point in time.
(3) Amounts above include $15 million of alternative revenue at Dominion Energy and Virginia Power for the year ended December 31, 2018.
The table below discloses the aggregate amount of the transaction price allocated to fixed-price performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and when the Companies expect to recognize this revenue. These revenues relate to contracts containing fixed prices where the Companies will earn the associated revenue over time as they stand ready to perform services provided. This disclosure does not include revenue related to performance obligations that are part of a contract with original durations of one year or less. In addition, this disclosure does not include expected consideration related to performance obligations for which the Companies elect to recognize revenue in the amount they have a right to invoice.
Contract assets represent an entity’s right to consideration in exchange for goods and services that the entity has transferred to a customer. At December 31, 2018 and December 31, 2017, Dominion Energy’s contract asset balances were $42 million and $46 million, respectively. Dominion Energy Gas’ contract asset balances were $58 million and $66 million at December 31, 2018 and December 31, 2017, respectively. Dominion Energy and Dominion Energy Gas’ contract assets are recorded in other deferred charges and other assets in the Consolidated Balance Sheets. Contract liabilities represent an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration, or the amount that is due, from the customer. At December 31, 2018 and December 31, 2017, Dominion Energy’s contract liability balances were $106 million and $132 million, respectively. At December 31, 2018 and December 31, 2017, Virginia Power’s contract liability balances were $22 million and $50 million, respectively. At December 31, 2018 and December 31, 2017, Dominion Energy Gas’ contract liability balances were $40 million and $41 million, respectively. During the year ended December 31, 2018, Dominion Energy, Virginia Power and Dominion Energy Gas recognized revenue of $94 million, $25 million and $41 million, respectively, from the beginning contract liability balances as the Companies fulfilled their obligations to provide service to their customers. The Companies’ contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets.
The Companies’ operating revenue, prior to the adoption of revised guidance for revenue recognition from contracts with customers, consisted of the following:
NOTE 5. INCOME TAXES
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. The Companies are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.
Combined Notes to Consolidated Financial Statements, Continued
The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies as discussed in Note 2. The 2017 Tax Reform Act reduced the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. At the date of enactment, deferred tax assets and liabilities were remeasured based upon the new 21% enacted tax rate expected to apply when temporary differences are realized or settled. The specific provisions related to regulated public utilities in the 2017 Tax Reform Act generally allow for the continued deductibility of interest expense, changed the tax depreciation of certain property acquired after September 27, 2017, and continued certain rate normalization requirements for accelerated depreciation benefits.
As indicated in Note 2, certain of the Companies’ operations, including accounting for income taxes, are subject to regulatory accounting treatment. For regulated operations, many of the changes in deferred taxes represent amounts probable of collection from or refund to customers, and were recorded as either an
increase to a regulatory asset or liability. The 2017 Tax Reform Act included provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred taxes may be determined by our regulators. See Note 13 for more information.
The Companies have accounted for the effects of the 2017 Tax Reform Act, although changes could occur as additional guidance is issued and finalized. In addition, certain states in which the Companies operate may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities and could be material. The changes in deferred taxes resulting from the 2017 Tax Reform Act, and the Companies’ interpretations of proposed regulations issued in 2018, were recorded as either an increase to a regulatory liability or as an adjustment to the deferred tax provision.
Continuing Operations
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
The 2017 Tax Reform Act reduced the statutory federal income tax rate to 21% beginning in January 2018. Accordingly, current income taxes, and deferred income taxes that originate in 2018, are recorded at the new 21% rate. Dominion Energy had less than $1 million of state deferred income tax expense as a result of the reversal of deferred taxes upon the sale of its interest in Blue Racer and Fairless and Manchester. Dominion Energy’s current federal income taxes primarily include the recognition of a $47 million benefit related to a carryback claim for specified liability losses involving prior tax years.
The accounting for the reduction in the corporate income tax rate decreased deferred income tax expense by $851 million at Dominion Energy, $93 million at Virginia Power, and $197 million for Dominion Energy Gas for the year ending December 31, 2017. The decrease in deferred income taxes at Dominion Energy primarily relates to the remeasurement of deferred taxes on merchant operations and includes the effects at Virginia Power and Dominion Energy Gas. Virginia Power and Dominion Energy Gas have certain regulatory assets and liabilities that have not yet been charged or returned to customers through rates, or on which they do not earn a return, including unrecognized pension and other postretirement benefits. The remeasurement of the deferred taxes on these regulatory balances was charged to continuing operations in 2017. For ratemaking purposes, Dominion Energy Gas’ subsidiary DETI follows the cash method on pension contributions. Deferred taxes recorded on pension balances as required by GAAP are not included as a component of rates and therefore the remeasurement of these deferred taxes were charged to continuing operations in 2017.
In 2016, Dominion Energy realized a taxable gain resulting from the contribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream. The contribution and related transactions resulted in increases in the tax basis of Dominion Energy Questar Pipeline’s assets and the number of Dominion Energy Midstream’s common and convertible preferred units held by noncontrolling interests. The direct tax effects of the transactions included a provision for current income taxes ($212 million) and an offsetting benefit for deferred income taxes ($96 million) and were charged to common shareholders’ equity. The federal tax liability was reduced by $129 million of tax
credits generated in 2016 that otherwise would have resulted in additional credit carryforwards and a $17 million benefit provided by the domestic production activities deduction. These benefits, as indirect effects of the contribution transaction, were reflected in Dominion Energy’s 2016 current federal income tax expense.
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows:
For the Companies’ rate-regulated entities, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. The Companies have recorded an estimate of the portion of excess deferred income tax amortization in 2018, and changes in estimates of amounts probable of collection from or return to customers. The reversal of these excess deferred income taxes will impact the effective tax rate, and may ultimately impact rates charged to customers. As described in Note 13 to the Consolidated Financial Statements, the Companies decreased revenue and increased regulatory liabilities to offset these deferred tax impacts in accordance with applicable regulatory commission orders or formula rate mechanisms.
In 2018, the Companies applied the provisions of recently proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017 through December 31, 2017. The application of these changes increased Dominion Energy’s 2017 net operating loss carryforward, the benefit of which will be recognized at the 21% rate. As a result, Dominion Energy’s effective tax rate reflects a $23 million increase to deferred income tax expense associated with the remeasurement of this deferred tax asset. The application of these proposed regulations at Dominion Energy Gas had no impact on income tax expense as the changes in, and remeasurement of, deferred tax liabilities increased regulatory liabilities by $35 million. The effects of these changes at Virginia Power were immaterial. These amounts and adjustments represent the Companies’ best estimate based on available information, and could be subject to change based on additional guidance in yet to be finalized regulations. In addition, changes in estimates of amounts probable of return to or collection from customers increased deferred income tax expense at Virginia Power by $23 million and increased regulatory liabilities by $31 million. At Dominion Energy Gas similar changes in estimates decreased income tax expense by $11 million and regulatory liabilities by $16 million. These changes also impacted Dominion Energy. In addition, Dominion Energy and Dominion Energy Gas’ effective tax rates reflect the impacts of a state legislative change enacted in the second quarter of 2018 that was retroactive to January 1, 2018.
In 2017, the Companies’ effective tax rates reflect the net benefit of remeasurement of deferred taxes resulting from the lower corporate income tax rate promulgated by the 2017 Tax Reform Act, and the completion of audits by state tax authorities that resulted in the recognition of previously unrecognized tax benefits. At December 31, 2016, Virginia Power’s unrecognized tax benefits included state refund claims for open tax years through 2011. Management believed settlement of the claims, including interest thereon, within the next twelve months was remote. In June 2017, Virginia Power received and accepted a cash offer to settle the refund claims. As a result of the settlement, Virginia Power decreased its unrecognized tax benefits by $8 million, and recognized a $2 million tax benefit, which impacted its effective tax rate. Also in connection with this settlement, Virginia Power realized interest income of $11 million, which is reflected in other income in the Consolidated Statements of Income.
In 2016, Dominion Energy’s effective tax rate reflects a valuation allowance on a state credit not expected to be utilized by a Dominion Energy subsidiary which files a separate state return.
Combined Notes to Consolidated Financial Statements, Continued
The Companies’ deferred income taxes consist of the following:
The most significant impact reflected for the 2017 Tax Reform Act is the adjustment of the net accumulated deferred income tax liability for the reduction in the corporate income tax rate to 21%. In addition to amounts recognized in deferred income tax expense, the impacts of the 2017 Tax Reform Act decreased the accumulated deferred income tax liability by $3.1 billion at Dominion Energy, $1.9 billion at Virginia Power and $0.8 billion at Dominion Energy Gas at December 31, 2017. At Dominion Energy, the December 31, 2017 balance sheet reflected the impact of the 2017 Tax Reform Act on our regulatory liabilities which increased our regulatory liabilities by $4.2 billion, and created a corresponding deferred tax asset of $1.1 billion. At Virginia Power, our regulatory liabilities increased $2.6 billion, and created a deferred tax asset of $0.7 billion. At Dominion Energy Gas, our regulatory liabilities increased $1.0 billion, and created a deferred tax asset of $0.2 billion. These adjustments had no impact on 2017 cash flows.
At December 31, 2018, Dominion Energy had the following deductible loss and credit carryforwards:
At December 31, 2018, Virginia Power had the following deductible loss and credit carryforwards:
At December 31, 2018, Dominion Energy Gas had the following deductible loss and credit carryforwards:
A reconciliation of changes in the Companies’ unrecognized tax benefits follows:
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities
and expiration of statutes of limitations. For Dominion Energy and its subsidiaries, these unrecognized tax benefits were $37 million, $31 million and $45 million at December 31, 2018, 2017 and 2016, respectively. For Dominion Energy, the change in these unrecognized tax benefits increased income tax expense by $5 million in 2018 and decreased income tax expense by $9 million and $18 million in 2017 and 2016 respectively. For Virginia Power, these unrecognized tax benefits were $2 million, $3 million, and $9 million at December 31, 2018, 2017 and 2016, respectively. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $2 million and $6 million in 2018 and 2017, respectively, and increased income tax expense by $1 million in 2016. For Dominion Energy Gas, these unrecognized tax benefits were less than $1 million, at December 31, 2018 and 2017, and $5 million at December 31, 2016. For Dominion Energy Gas, the change in these unrecognized tax benefits decreased income tax expense by less than $1 million, $5 million, and $11 million in 2018, 2017, and 2016, respectively.
Dominion Energy participates in the IRS Compliance Assurance Process which provides the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions agreed to by the IRS. In 2018, Dominion Energy submitted carryback claims for specified liability losses involving prior tax years. These claims will be subject to IRS examination. With the exception of these claims, the IRS has completed its audit of tax years through 2017. The statute of limitations has not yet expired for tax years after 2012. Although Dominion Energy has not received a final letter indicating no changes to its taxable income for tax year 2017, no material adjustments are expected. The IRS examination of tax year 2018 is ongoing.
It is reasonably possible that settlement negotiations and expiration of statutes of limitations could result in a decrease in unrecognized tax benefits in 2019 by up to $18 million for Dominion Energy and less than $1 million for Virginia Power and Dominion Energy Gas. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by up to $17 million for Dominion Energy and less than $1 million for Virginia Power and Dominion Energy Gas.
Otherwise, with regard to 2018 and prior years, Dominion Energy, Virginia Power and Dominion Energy Gas cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2019.
For each of the major states in which Dominion Energy operates, the earliest tax year remaining open for examination is as follows:
(1) Considered a major state for Dominion Energy Gas’ operations.
(2) Considered a major state for Virginia Power’s operations.
The Companies are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion Energy utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination.
NOTE 6. FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion Energy applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments, and other investments including those held in nuclear decommissioning, Dominion Energy’s rabbi, and pension and other postretirement benefit plan trusts, in accordance with the requirements discussed above. Virginia Power applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments and other investments including those held in the nuclear decommissioning trust, in accordance with the requirements discussed above. Dominion Energy Gas applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments and other investments including those held in pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above.
Inputs and Assumptions
Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services, or brokers, the Companies consider the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the unobservable inputs are developed and substantiated using historical information, avail-
Combined Notes to Consolidated Financial Statements, Continued
able market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party sources.
For options and contracts with option-like characteristics where observable pricing information is not available from external sources, Dominion Energy and Virginia Power generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. Dominion Energy and Virginia Power use other option models under special circumstances, including but not limited to Spread Approximation Model and a Swing Option Model. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.
The inputs and assumptions used in measuring fair value include the following:
For commodity derivative contracts:
•
Forward commodity prices
•
Transaction prices
•
Price volatility
•
Price correlation
•
Volumes
•
Commodity location
•
Interest rates
•
Credit quality of counterparties and the Companies
•
Credit enhancements
•
Time value
For interest rate derivative contracts:
•
Interest rate curves
•
Credit quality of counterparties and the Companies
•
Notional value
•
Credit enhancements
•
Time value
For foreign currency derivative contracts:
•
Foreign currency forward exchange rates
•
Interest rates
•
Credit quality of counterparties and the Companies
•
Notional value
•
Credit enhancements
•
Time value
For investments:
•
Quoted securities prices and indices
•
Securities trading information including volume and restrictions
•
Maturity
•
Interest rates
•
Credit quality
Levels
The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:
•
Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as certain exchange-traded derivatives, and exchange-listed equities, U.S. and international equity securities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas, and rabbi trust funds for Dominion Energy.
•
Level 2-Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include commodity forwards and swaps, interest rate swaps, foreign currency swaps and cash and cash equivalents, corporate debt instruments, government securities and other fixed income investments held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas and rabbi trust funds for Dominion Energy.
•
Level 3-Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, certain natural gas and power options and other modeled commodity derivatives.
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. Alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments held in nuclear decommissioning and benefit plan trust funds, are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date. Alternative investments recorded at NAV are not classified in the fair value hierarchy.
Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became
observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.
Level 3 Valuations
The Companies enter into certain physical and financial forwards, futures, options and swaps, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards and futures
contracts. An option model is used to value Level 3 physical and financial options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices, and volumes. For Level 3 fair value measurements, certain forward market prices and implied price volatilities are considered unobservable.
The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at December 31, 2018. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.
(1) Averages weighted by volume.
(2) Includes basis.
(3) Represents market prices beyond defined terms for Levels 1 and 2.
(4) Represents volatilities unrepresented in published markets.
Combined Notes to Consolidated Financial Statements, Continued
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Nonrecurring Fair Value Measurements
DOMINION ENERGY
See Note 9 for information regarding an impairment charge recognized associated with Dominion Energy’s equity method investment in Fowler Ridge.
ATLANTIC COAST PIPELINE GUARANTEE AGREEMENT
In October 2017, Dominion Energy entered into a guarantee agreement in connection with Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility. See Note 22 for more information about the guarantee agreement associated with Atlantic Coast Pipeline’s revolving credit facility. Dominion Energy recorded a liability of $30 million, the fair value of the guarantee at inception, associated with the guarantee agreement. The fair value was estimated using a discounted cash flow method and is considered a Level 3 fair value measurement due to the use of a significant unobservable input related to the interest rate differential between the interest rate charged on the guaranteed revolving credit facility and the estimated interest rate that would have been charged had the loan not been guaranteed.
DOMINION ENERGY GAS
In the fourth quarter of 2018, subsequent to the announcement of the sale of Dominion Energy’s interest in Blue Racer, Dominion Energy Gas conducted a review of strategic alternatives of its remaining gathering and processing assets at DGP. Based on an evaluation of DGP’s long-lived assets for recoverability under a probability weighted approach, Dominion Energy Gas determined the assets were impaired. As a result of this evaluation, Dominion Energy Gas recorded a charge of $219 million ($165 million after-tax) in impairment of assets and related charges in its Consolidated Statements of Income to write down DGP’s property, plant and equipment to its estimated fair value of $190 million. The fair value of the property, plant and equipment was estimated using an income approach and market approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risks inherent in the future cash flows and market prices.
Recurring Fair Value Measurements
Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans are presented in Note 21.
DOMINION ENERGY
The following table presents Dominion Energy’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
(1) Includes investments held in the nuclear decommissioning and rabbi trusts. Excludes $220 million and $88 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.
The following table presents the net change in Dominion Energy’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
Combined Notes to Consolidated Financial Statements, Continued
VIRGINIA POWER
The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2018. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.
(1) Averages weighted by volume.
(2) Includes basis.
(3) Represents market prices beyond defined terms for Levels 1 and 2.
(4) Represents volatilities unrepresented in published markets.
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
(1) Includes investments held in the nuclear decommissioning trusts. Excludes $160 million and $27 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.
The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2018, 2017 and 2016.
DOMINION ENERGY GAS
The following table presents Dominion Energy Gas’ assets and liabilities for derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
The following table presents the net change in Dominion Energy Gas’ derivative assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
Combined Notes to Consolidated Financial Statements, Continued
There were no gains and losses included in earnings in the Level 3 fair value category for the years ended December 31, 2018, 2017 and 2016. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2018, 2017 and 2016.
Fair Value of Financial Instruments
Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash, restricted cash and equivalents, customer and other receivables, affiliated receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies’ financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:
(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.
(2) Carrying amount includes amounts which represent, the unamortized debt issuance costs, discount or premium, and foreign currency remeasurement adjustments. At December 31, 2018, and 2017, includes the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt of $(20) million and $(22) million, respectively.
(3) Carrying amount includes amounts which represent the unamortized debt issuance costs, discount or premium.
(4) Carrying amount includes amounts which represent the unamortized debt issuance costs, discount or premium, and foreign currency remeasurement adjustments.
NOTE 7. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES
See Note 2 for the Companies’ accounting policies, objectives, and strategies for using derivative instruments. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives.
Derivative assets and liabilities are presented gross on the Companies’ Consolidated Balance Sheets. Dominion Energy’s derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Virginia Power and Dominion Energy Gas’ derivative contracts include over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions.
In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and, in some cases, other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on the Companies’ Consolidated Balance Sheets, as well as letters of credit and other forms of security, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure. See Note 23 for further information regarding credit-related contingent features for the Companies derivative instruments.
DOMINION ENERGY
Balance Sheet Presentation
The tables below present Dominion Energy’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:
(1) Excludes $7 million and $4 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.
(1) Excludes $1 million of derivative liabilities at December 31, 2018 and 2017, which are not subject to master netting or similar arrangements.
Combined Notes to Consolidated Financial Statements, Continued
Volumes
The following table presents the volume of Dominion Energy’s derivative activity as of December 31, 2018. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.
(1) Includes options.
(2) Includes NGLs and oil.
(3) Maturity is determined based on final settlement period.
(4) Euro equivalent volumes are  250,000,000.
Ineffectiveness and AOCI
For the years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were immaterial. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.
The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy’s Consolidated Balance Sheet at December 31, 2018:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign currency exchange rates.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Dominion Energy’s derivatives and where they are presented in its Consolidated Balance Sheets:
(1) Current derivative assets are presented in other current assets in Dominion Energy’s Consolidated Balance Sheets.
(2) Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Energy’s Consolidated Balance Sheets.
(3) Current derivative liabilities are presented in other current liabilities in Dominion Energy’s Consolidated Balance Sheets.
(4) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Energy’s Consolidated Balance Sheets.
The following tables present the gains and losses on Dominion Energy’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
(1) Amounts deferred into AOCI have no associated effect in Dominion Energy’s Consolidated Statements of Income.
(2) Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’s Consolidated Statements of Income.
(3) Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in interest and related charges.
(4) Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in other income.
Combined Notes to Consolidated Financial Statements, Continued
(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’s Consolidated Statements of Income.
VIRGINIA POWER
Balance Sheet Presentation
The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:
(1) Excludes $26 million and $11 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.
(1) Excludes $9 million and $5 million of derivative liabilities at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.
Volumes
The following table presents the volume of Virginia Power’s derivative activity at December 31, 2018. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.
(1) Includes options.
(2) Maturity is determined based on final settlement period.
Ineffectiveness and AOCI
For the years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were immaterial.
The following table presents selected information related to losses on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at December 31, 2018:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of interest rates contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates.
Combined Notes to Consolidated Financial Statements, Continued
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:
(1) Current derivative assets are presented in other current assets in Virginia Power’s Consolidated Balance Sheets.
(2) Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Power’s Consolidated Balance Sheets.
(3) Current derivative liabilities are presented in other current liabilities in Virginia Power’s Consolidated Balance Sheets.
(4) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheets.
The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
(1) Amounts deferred into AOCI have no associated effect in Virginia Power’s Consolidated Statements of Income.
(2) Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.
(3) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges.
(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.
(2) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.
DOMINION ENERGY GAS
Balance Sheet Presentation
The tables below present Dominion Energy Gas’ derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:
Combined Notes to Consolidated Financial Statements, Continued
Volumes
The following table presents the volume of Dominion Energy Gas’ derivative activity at December 31, 2018. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.
(1) Maturity is determined based on final settlement period.
(2) Euro equivalent volumes are 250,000,000.
Ineffectiveness and AOCI
For the years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were immaterial.
The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices, interest rates, and foreign currency exchange rates.
Fair Value and Gains and Losses on Derivative Instruments
The following table presents the fair values of Dominion Energy Gas’ derivatives and where they are presented in its Consolidated Balance Sheets:
(1) Current derivative assets are presented in other current assets in Dominion Energy Gas’ Consolidated Balance Sheets.
(2) Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Energy Gas’ Consolidated Balance Sheets.
(3) Current derivative liabilities are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.
(4) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.
The following tables present the gains and losses on Dominion Energy Gas’ derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
(1) Amounts deferred into AOCI have no associated effect in Dominion Energy Gas’ Consolidated Statements of Income.
(2) Amounts recorded in Dominion Energy Gas’ Consolidated Statements of Income are classified in interest and related charges.
(3) Amounts recorded in Dominion Energy Gas’ Consolidated Statements of Income are classified in other income.
NOTE 8. EARNINGS PER SHARE
The following table presents the calculation of Dominion Energy’s basic and diluted EPS:
(1) Dilutive securities for 2018 consist primarily of forward sale agreements, effective April 2018 to December 2018. Dilutive securities for 2016 consist primarily of the 2013 Equity Units. See Notes 17 and 19 for more information.
The 2014 Equity Units were excluded from the calculation of diluted EPS for the year ended December 31, 2016 as the dilutive stock price threshold was not met. The 2016 Equity Units were excluded from the calculation of diluted EPS for the years ended December 31, 2018, 2017 and 2016, as the dilutive stock price threshold was not met. See Note 17 for more information. The Dominion Energy Midstream convertible preferred units were potentially dilutive securities but had no effect on the calculation of diluted EPS for the years ended December 31, 2018, 2017 and 2016. See Note 19 for more information.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 9. INVESTMENTS
DOMINION ENERGY
Equity and Debt Securities
RABBI TRUST SECURITIES
Equity and debt securities and cash equivalents in Dominion Energy’s rabbi trusts and classified as trading totaled $111 million and $112 million at December 31, 2018 and 2017, respectively.
DECOMMISSIONING TRUST SECURITIES
Dominion Energy holds equity and debt securities, cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion Energy’s decommissioning trust funds are summarized below:
(1) Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
(2) Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
(3) Includes pending sales of securities of $5 million at December 31, 2017.
(4) The fair value of securities in an unrealized loss position was $833 million and $565 million at December 31, 2018 and 2017, respectively.
The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy’s nuclear decommissioning trusts is summarized below:
(1) Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
The fair value of Dominion Energy’s debt securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2018 by contractual maturity is as follows:
Presented below is selected information regarding Dominion Energy’s equity and debt securities with readily determinable fair values held in nuclear decommissioning trust funds.
(1) Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.
Dominion Energy recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:
(1) Amounts include other-than-temporary impairment losses for debt securities of $5 million and $13 million at December 31, 2017 and 2016, respectively.
VIRGINIA POWER
Virginia Power holds equity and debt securities, cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below:
(1) Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
(2) Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
(3) Includes pending sales of securities of $6 million at both December 31, 2018 and 2017.
(4) The fair value of securities in an unrealized loss position was $404 million and $234 million at December 31, 2018 and 2017, respectively.
The portion of unrealized gains and losses that relates to equity securities held within Virginia Power’s nuclear decommissioning trusts is summarized below:
(1) Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
The fair value of Virginia Power’s debt securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2018, by contractual maturity is as follows:
Presented below is selected information regarding Virginia Power’s equity and debt securities with readily determinable fair values held in nuclear decommissioning trust funds.
(1) Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.
Combined Notes to Consolidated Financial Statements, Continued
Virginia Power recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:
(1) Amounts include other-than-temporary impairment losses for debt securities of $2 million and $8 million at December 31, 2017 and 2016 , respectively.
Equity Method Investments
DOMINION ENERGY AND DOMINION ENERGY GAS
Investments that Dominion Energy and Dominion Energy Gas account for under the equity method of accounting are as follows:
(1) Comprised of Dominion Energy Midstream’s interest of 25.93% and Dominion Energy Gas’ interest of 24.07%. See Note 15 for more information.
(2) Liability of less than $1 million and $17 million associated with NedPower recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets as of December 31, 2018 and 2017, respectively. See additional discussion of NedPower below.
Dominion Energy’s equity earnings on its investments totaled $197 million, $14 million and $111 million in 2018, 2017 and 2016, respectively, included in other income in Dominion Energy’s Consolidated Statements of Income. Dominion Energy received distributions from these investments of $209 million, $419 million and $104 million in 2018, 2017 and 2016, respectively. As of December 31, 2018 and 2017, the carrying amount of Dominion Energy’s investments exceeded its share of underlying equity in net assets by $161 million and $249 million, respectively. At December 31, 2018 these differences are comprised of $146 million of equity method goodwill that is not being amortized and $15 million related to basis differences from Dominion Energy’s investments in wind projects, which are being amortized over the useful lives of the underlying assets, and in Atlantic Coast Pipeline, which is being amortized over the term of its credit facility. At December 31, 2017 these differences are
comprised of $176 million of equity method goodwill and $73 million related to basis differences from Dominion Energy’s investments in Blue Racer and wind projects, and in Atlantic Coast Pipeline.
Dominion Energy Gas’ equity earnings on its investment totaled $24 million in 2018 and $21 million in 2017 and 2016. Dominion Energy Gas received distributions from its investment of $28 million, $24 million and $22 million in 2018, 2017 and 2016, respectively. As of December 31, 2018 and 2017, the carrying amount of Dominion Energy Gas’ investment exceeded its share of underlying equity in net assets by $8 million. The difference reflects equity method goodwill and is not being amortized. In May 2016, Dominion Energy Gas sold 0.65% of the noncontrolling partnership interest in Iroquois to TransCanada for approximately $7 million, which resulted in a $5 million ($3 million after-tax) gain, included in other income in Dominion Energy Gas’ Consolidated Statements of Income.
DOMINION ENERGY
ATLANTIC COAST PIPELINE
In September 2014, Dominion Energy, along with Duke and Southern Company Gas, announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion Energy an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. In October 2016, Dominion Energy purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million. As of December 31, 2018, the members hold the following membership interests: Dominion Energy, 48%; Duke, 47%; and Southern Company Gas, 5%.
Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Subsidiaries and affiliates of all three members plan to be customers of the pipeline under 20-year contracts. Atlantic Coast Pipeline is considered an equity method investment as Dominion Energy has the ability to exercise significant influence, but not control, over the investee. See Note 15 for more information.
DETI provides services to Atlantic Coast Pipeline which totaled $203 million, $129 million and $95 million in 2018, 2017 and 2016, respectively, included in operating revenue in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income. Amounts receivable related to these services were $13 million and $12 million at December 31, 2018 and 2017, respectively, composed entirely of accrued unbilled revenue, included in other receivables in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.
In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under its credit facility. See Note 22 for more information.
Dominion Energy contributed $414 million, $310 million and $184 million during 2018, 2017 and 2016, respectively, to Atlantic Coast Pipeline.
Dominion Energy received distributions of $36 million and $270 million during 2018 and 2017, respectively, from Atlantic Coast Pipeline. No distributions were received in 2016.
During the third and fourth quarters of 2018, a FERC stop work order together with delays in obtaining permits necessary for construction along with construction delays due to judicial actions impacted the cost and schedule for the project. As a result project cost estimates have increased from between $6.0 billion to $6.5 billion to between $7.0 billion to $7.5 billion, excluding financing costs. Atlantic Coast Pipeline expects to achieve a late 2020 in-service date for at least key segments of the project, while the remainder may extend into early 2021. Alternatively, if it takes longer to resolve the judicial issues, such as through appeal to the Supreme Court of the U.S., full in-service could extend to the end of 2021 with total project cost estimated to increase an additional $250 million, resulting in total project cost estimates of $7.25 billion to $7.75 billion excluding financing costs. Abnormal weather, work delays (including due to judicial or regulatory action) and other conditions may result in further cost or schedule modifications in the future, which could result in a material impact to Dominion Energy’s cash flows, financial position and/or results of operations.
BLUE RACER
In December 2012, Dominion Energy formed a joint venture with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. Blue Racer was an equal partnership between Dominion Energy and Caiman, with Dominion Energy contributing midstream assets and Caiman contributing private equity capital.
In December 2016, Dominion Energy Gas repurchased a portion of the Western System from Blue Racer for $10 million.
In December 2018, Dominion Energy sold its 50% limited partnership interest in Blue Racer for up-front cash consideration of $1.05 billion and additional consideration of $150 million, subject to increase for interest costs effective March 2019, payable upon the purchaser’s availability of cash. The additional consideration was recorded at a fair value of $150 million on the date of sale following a discounted cash flow model and is included within other receivables in the Consolidated Balance Sheets at December 31, 2018. The valuation is considered a Level 3 fair value measurement due to the use of judgment and unobservable inputs, including projected timing and amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows. As a result of the sale, Dominion Energy recognized a gain of $546 million ($390 million after-tax), included in other income in its Consolidated Statements of Income. Also, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. Pursuant to the purchase agreement, the aggregate will not exceed $300 million, which represents a gain contingency, and, as a result, Dominion Energy will not recognize any additional gain unless such consideration is realizable.
FOWLER RIDGE & NEDPOWER
In the fourth quarter of 2017, Dominion Energy recorded a charge of $126 million ($76 million after-tax) in other income in
its Consolidated Statements of Income reflecting its share of a long-lived asset impairment of property, plant and equipment recorded by NedPower, which resulted in losses in excess of Dominion Energy’s investment balance. Dominion Energy recorded the excess losses due to its commitment to provide further financial support for NedPower, resulting in a liability of $17 million at December 31, 2017, recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets.
As a result of the impairment recorded by NedPower, Dominion Energy evaluated its equity method investment in Fowler Ridge, a similar wind-powered merchant generation facility, determined its fair value was other than-temporarily impaired and recorded an impairment charge of $32 million ($20 million after-tax) in other income in its Consolidated Statements of Income. The fair value of $81 million was estimated using a discounted cash flow method and is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future equity distributions based on the investee’s future wind generation and operating costs.
OTHER - CATALYST OLD RIVER HYDROELECTRIC LIMITED PARTNERSHIP
In September 2018, Dominion Energy completed the sale of its 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership and received proceeds of $91 million. The sale resulted in a gain of $87 million ($63 million after-tax), which is included in other income in Dominion Energy’s Consolidated Statement of Income.
NOTE 10. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment and their respective balances for the Companies are as follows:
Combined Notes to Consolidated Financial Statements, Continued
Jointly-Owned Power Stations
Dominion Energy and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2018 is as follows:
(1) Units jointly owned by Virginia Power.
(2) Unit jointly owned by Dominion Energy.
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion Energy and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.
Sale of Certain Retail Energy Marketing Assets
In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy
marketing operations for total consideration of $143 million, subject to customary approvals and certain adjustments. In December 2017, the first phase of the agreement closed for $79 million, which resulted in the recognition of a $78 million ($48 million after-tax) benefit, included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. In October 2018, the second phase of the agreement closed for $63 million, which resulted in the recognition of a $65 million ($49 million after-tax) benefit included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. Pursuant to the agreement, Dominion Energy entered into a commission agreement with the buyer upon the first closing in December 2017 under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a ten-year term.
Sale of Certain Merchant Generation Facilities
In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. Dominion Energy recognized a gain of $210 million ($198 million after-tax) included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. The after-tax gain reflects Dominion Energy’s assessment and more-likely-than-not conclusion that the utilization of state tax incentives will reduce the income tax expense associated with the sale of these facilities.
Acquisition of Solar Projects
In September 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The first acquisition closed in October 2018. The facility commenced commercial operations in December 2018 at a cost of $140 million, including the initial acquisition cost. The second acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2019, and cost approximately $140 million once constructed, including the initial acquisition cost. The projects are expected to generate approximately 155 MW combined. Virginia Power anticipates claiming federal investment tax credits on these solar projects.
In February 2019, Virginia Power completed the acquisition of a solar development project in Virginia. The project is expected to commence commercial operations in the first quarter 2019, and cost approximately $37 million once constructed, including the initial acquisition cost. The project is expected to generate approximately 20 MW. Virginia Power anticipates claiming federal investment tax credits on this solar project.
In August 2018, Virginia Power entered into agreements to acquire two solar development projects in North Carolina and Virginia. The first acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2019, and cost approximately $120 million once constructed, including the initial acquisition cost. The second acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2020, and cost approximately $130 million, including the initial acquisition cost. The projects are expected to generate approximately 155 MW combined. Virginia Power anticipates claiming federal investment tax credits on these solar projects.
Assignment of Tower Rental Portfolio
Virginia Power rents space on certain of its electric transmission towers to various wireless carriers for communications antennas and other equipment. In March 2017, Virginia Power sold its rental portfolio to Vertical Bridge Towers II, LLC for $91 million in cash. The proceeds are subject to Virginia Power’s FERC-regulated tariff, under which it is required to return half of the proceeds to customers. Virginia Power recorded $6 million in operating revenue and $11 million in other income during 2018 and 2017, respectively, with $29 million remaining to be recognized ratably through 2023.
Assignments of Shale Development Rights
In December 2013, Dominion Energy Gas closed on agreements with two natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. The agreements provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013, Dominion Energy Gas received approximately $100 million in cash proceeds. In 2014, Dominion Energy Gas received $16 million in additional cash proceeds resulting from post-closing adjustments. In March 2015, Dominion Energy Gas and one of the natural gas producers closed on an amendment to the agreement, which included the immediate conveyance of approximately 9,000 acres of Marcellus Shale development rights and a two-year extension of the term of the original agreement. The conveyance of development rights resulted in the recognition of $43 million ($27 million after-tax) of previously deferred revenue to operations and maintenance expense in Dominion Energy Gas’ Consolidated Statements of Income. In April 2016, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of a 32% partial interest in the remaining approximately 70,000 acres. This conveyance resulted in the recognition of the remaining $35 million ($21 million after-tax) of previously deferred revenue to gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income. In August 2017, Dominion Energy Gas and the natural gas producer signed an amendment to the agreement, which included the finalization of contractual matters on previous conveyances, the conveyance of Dominion Energy Gas’ remaining 68% interest in approximately 70,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. Dominion Energy Gas received total consideration of $130 million, with $65 million received in 2017 and $65 million received in September 2018 in connection with the final conveyance. As a result of this amendment, in 2017, Dominion Energy Gas recognized a $56 million ($33 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the finalization of the contractual matters on previous conveyances, a $9 million ($5 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the elimination of its overriding royalty interest and in 2018, a
$65 million ($47 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the final conveyance of acreage.
In November 2014, Dominion Energy Gas closed an agreement with a natural gas producer to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas produced from the acreage. In November 2014, Dominion Energy Gas closed on the agreement and received proceeds of $60 million associated with an initial conveyance of approximately 12,000 acres. In connection with that agreement, in 2016, Dominion Energy Gas conveyed a 50% interest in approximately 4,000 acres of Marcellus Shale development rights and received proceeds of $10 million and an overriding royalty interest in gas produced from the acreage. These transactions resulted in a $10 million ($6 million after-tax) gain. In July 2017, in connection with the existing agreement, Dominion Energy Gas conveyed an additional 50% interest in approximately 2,000 acres of Marcellus Shale development rights and received proceeds of $5 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in a $5 million ($3 million after-tax) gain. The gains are included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income. In January 2018, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the conveyance of Dominion Energy Gas’ remaining 50% interest in approximately 18,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. Dominion Energy Gas received proceeds of $28 million, resulting in an approximately $28 million ($20 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.
In March 2018, Dominion Energy Gas closed an agreement with a natural gas producer to convey approximately 11,000 acres of Utica and Point Pleasant Shale development rights underneath one of its natural gas storage fields. The agreement provided for a payment to Dominion Energy Gas, subject to customary adjustments, of $16 million. In March 2018, Dominion Energy Gas received cash proceeds of $16 million associated with the conveyance of the acreage, resulting in a $16 million ($12 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.
In June 2018, Dominion Energy Gas closed an amendment to an agreement with a natural gas producer for the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from approximately 9,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields previously conveyed in December 2013. In June 2018, Dominion Energy Gas received proceeds of $6 million associated with the transaction, resulting in a $6 million ($4 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 11. GOODWILL AND INTANGIBLE ASSETS
Goodwill
The changes in Dominion Energy and Dominion Energy Gas’ carrying amount and segment allocation of goodwill are presented below:
(1) Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.
(2) Goodwill amounts do not contain any accumulated impairment losses.
(3) See Note 3.
Other Intangible Assets
The Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion Energy’s amortization expense for intangible assets was $82 million, $80 million and $73 million for 2018, 2017 and 2016, respectively. In 2018, Dominion Energy acquired $127 million of intangible assets, primarily representing software and right-of-use assets, with an estimated weighted-average amortization period of approximately 15 years. Amortization expense for Virginia Power’s intangible assets was $31 million for both 2018 and 2017 and $29 million for 2016. In 2018, Virginia Power acquired $49 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 11 years. Dominion Energy Gas’ amortization expense for intangible assets was $14 million for both 2018 and 2017 and $6 million for 2016. In 2018, Dominion Energy Gas acquired $14 million of intangible assets, primarily representing software and right-of-use
assets, with an estimated weighted-average amortization period of approximately 10 years. The components of intangible assets are as follows:
Annual amortization expense for these intangible assets is estimated to be as follows:
NOTE 12. REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities include the following:
(1) Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Dominion Energy and Virginia Power’s generation operations. See Note 13 for more information.
(2) Primarily reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power and deferrals of costs associated with certain current and prospective rider projects for Dominion Energy Gas. See Note 13 for more information.
(3) Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months.
(4) Reflects unrecovered or overrecovered gas costs at regulated gas operations, which are recovered or refunded through filings with the applicable regulatory authority.
(5) Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain of Dominion Energy and Dominion Energy Gas’ rate-regulated subsidiaries.
(6) Ohio legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future.
(7) Reflects amounts related to the PJM transmission cost allocation matter. See Note 13 for more information.
(8) As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.
(9) Rates charged to customers by the Companies’ regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.
(10) Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at the Companies’ regulated electric generation and electric and natural gas distribution operations. See Note 13 for more information.
Combined Notes to Consolidated Financial Statements, Continued
(11) Charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers. See Note 13 for more information.
(12) Current regulatory liabilities are presented in other current liabilities in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.
(13) Amounts recorded to pass the effect of reduced income tax rates from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity.
(14) Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related AROs.
(15) Under PIPP, eligible customers can make reduced payments based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rider according to East Ohio tariff provisions. See Note 13 for more information.
(16) Current regulatory assets are presented in other current assets in Dominion Energy Gas’ Consolidated Balance Sheets.
At December 31, 2018, $396 million of Dominion Energy’s, $300 million of Virginia Power’s and $12 million of Dominion Energy Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. With the exception of the PJM transmission cost allocation matter, the majority of these expenditures are expected to be recovered within the next two years.
NOTE 13. REGULATORY MATTERS
Regulatory Matters Involving Potential Loss Contingencies
As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For regulatory matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.
FERC-ELECTRIC
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public util-
ities. Virginia Power purchases and sells electricity in the PJM wholesale market and sells electricity to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s merchant generators sell electricity in the PJM, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.
Rates
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its investment in electric transmission infrastructure.
In March 2010, ODEC and North Carolina Electric Membership Corporation filed a complaint with FERC against Virginia Power claiming, among other issues, that the incremental costs of undergrounding certain transmission line projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. A settlement of the other issues raised in the complaint was approved by FERC in May 2012.
In March 2014, FERC issued an order excluding from Virginia Power’s transmission rates for wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable for non-Virginia wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities because the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to benefit the citizens of Virginia. The order is retroactively effective as of March 2010 and will cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC determined that there was not sufficient evidence on the record to determine the magnitude of the underground increment and held a hearing to determine the appropriate amount of undergrounding cost to be allocated to each wholesale transmission customer in Virginia.
In October 2017, FERC issued an order determining the calculation of the incremental costs of undergrounding the transmission projects and affirming that the costs are to be recovered from the wholesale transmission customers with loads located in Virginia. FERC directed Virginia Power to rebill all wholesale transmission customers retroactively to March 2010 within 30 days of when the proceeding becomes final and no longer subject to rehearing. In November 2017, Virginia Power, North Carolina Electric Membership Corporation and the wholesale transmission customers filed petitions for rehearing. In July
2018, FERC denied the rehearing requests related to the October 2017 order determining the calculation of the undergrounding costs. Several parties have appealed FERC’s decision to the U.S. Court of Appeals for the D.C. Circuit. This matter is pending. While Virginia Power cannot predict the outcome of the matter, it is not expected to have a material effect on results of operations.
In January 2019, FERC issued an order denying PJM’s request to waive certain provisions of the PJM Tariff regarding the liquidation of a portfolio of FTRs owned by GreenHat who had defaulted on its financial obligations. As a result of FERC’s order, PJM is required to use the existing tariff provisions to liquidate GreenHat’s FTR portfolio and allocate the resulting costs to PJM members. In February 2019, PJM filed a request for clarification and rehearing with FERC. While the impacts of this order could be material to Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts.
PJM Transmission Rates
In April 2007, FERC issued an order regarding its transmission rate design for the allocation of costs among PJM transmission customers, including Virginia Power, for transmission service provided by PJM. For new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a PJM regional rate design where customers pay according to each customer’s share of the region’s load. For recovery of costs of existing facilities, FERC approved the existing methodology whereby a customer pays the cost of facilities located in the same zone as the customer. A number of parties appealed the order to the U.S. Court of Appeals for the Seventh Circuit.
In August 2009, the court issued its decision affirming the FERC order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above for further consideration by FERC. On remand, FERC reaffirmed its earlier decision to allocate the costs of new facilities 500 kV and above according to the customer’s share of the region’s load. A number of parties filed appeals of the order to the U.S. Court of Appeals for the Seventh Circuit. In June 2014, the court again remanded the cost allocation issue to FERC. In December 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the cost allocation issue. The hearing only concerns the costs of new facilities approved by PJM prior to February 1, 2013. Transmission facilities approved after February 1, 2013 are allocated on a hybrid cost allocation method approved by FERC and not subject to any court review.
In June 2016, PJM, the PJM transmission owners and state commissions representing substantially all of the load in the PJM market submitted a settlement to FERC to resolve the outstanding issues regarding this matter. In May 2018, FERC issued an order accepting the settlement agreement and directed PJM to make a compliance filing with revised tariff records. As a result, in August 2018, Virginia Power began to make payments to PJM, to continue for the next 10 years totaling $276 million, under the terms of revised tariff records, which was partially offset by a $265 million regulatory asset for the amount that will be recovered through retail rates in Virginia. At December 31, 2018, Virginia Power’s Consolidated Balance Sheet includes $126 million in other current liabilities and $50 million included in other
deferred credits and other liabilities for amounts owed to PJM.
FERC-GAS
In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report which could have the potential to result in adjustments which could be material to Dominion Energy and Dominion Energy Gas’ results of operations. In December 2017, DETI provided its response to the audit report. DETI requested FERC review of contested findings and submitted its plan for compliance with the uncontested portions of the report. In connection with one uncontested issue, DETI recognized a charge of $15 million ($9 million after-tax) recorded within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income during 2017 to write-off the balance of a regulatory asset, originally established in 2008, that is no longer considered probable of recovery. DETI recognized a charge of $129 million ($94 million after-tax) recorded primarily within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income during 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with FERC. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the remaining finding and no amounts have been recognized.
TAX REFORM ACT
Subsequent to the enactment of the 2017 Tax Reform Act, the Companies’ state regulators issued orders requesting that public utilities evaluate the total tax impact on the entity’s cost of service and accrue a regulatory liability attributable to the benefits of the reduction in the corporate income tax rate. Certain of the orders requested that the public utilities submit a response to the state regulatory commissions detailing the total tax impact on the utility’s cost of service.
The Companies began to reserve the impacts of the cost-of-service reduction as regulatory liabilities in January 2018 and will continue until rates are reset pursuant to state regulators’ approvals. The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate and are currently assessing these actions and decisions, which could have a material impact on the Companies’ results of operations, financial condition and/or cash flows.
In September 2018, the Virginia Commission issued an order directing Virginia Power to submit a filing quantifying the impacts of the 2017 Tax Reform Act in advance of the April 1, 2019 implementation as required by legislation. In October 2018, Virginia Power filed testimony with the Virginia Commission to implement adjustments in its base rates reflecting actual annual reductions in corporate income taxes resulting from the 2017 Tax Reform Act, which included a proposed annual revenue reduction of approximately $151 million effective April 2019. In December 2018, the Staff of the Virginia Commission proposed an annual revenue reduction of approximately $190 million. In January 2019, Virginia Power filed updated testimony with a proposed
Combined Notes to Consolidated Financial Statements, Continued
annual revenue reduction of approximately $171 million. Additionally, Virginia Power proposed to issue a one-time bill credit to customers within 90 days of this effective date, to true-up the difference between the final revenue reduction for the period January 1, 2018 through March 31, 2019 and the $125 million interim rate reduction implemented on July 1, 2018. Based on Virginia Power’s current proposed annual revenue reduction, this one-time bill credit is expected to total approximately $120 million. The actual credit will be based on actual billing data and customer usage during that 15-month period. This matter is pending.
In August 2018, Virginia Power filed with FERC to waive protocols and begin reflecting projected tax reform benefits of approximately $100 million through the transmission formula rate prior to the normal formula rate process. FERC granted the waiver and the amounts began being reflected in customer billings in November 2018 reflecting the adjustment effective January 1, 2018.
In October 2018, the North Carolina Commission issued an order requesting companies file to reduce base rates expeditiously. Virginia Power made its compliance filing in October 2018 and submitted an annual base rate revenue decrease of approximately $14 million effective in early 2019. Virginia Power also proposed to issue a one-time bill credit in early 2019 for its 2018 tax savings collected provisionally from customers, which is estimated to be approximately $13 million. The order allowed for the disposition of excess deferred income taxes to be deferred for consideration until the utilities’ next base rate case, but no longer than 3 years, and initiated a quarterly reporting requirement for such deferred amounts. This matter is pending.
In May 2018, the Utah Commission approved a stipulation submitted by Questar Gas proposing the cost-of-service component of customer rates be reduced by $15 million annually beginning in June 2018. In July 2018, the Utah Commission approved Questar Gas’ request to return an additional $9 million to Utah customers representing the amounts related to the corporate income tax reduction that had been deferred from January 1, 2018 to May 31, 2018. This additional reduction began amortizing on August 1, 2018 and will be amortized over a one-year period. In October 2018, the Wyoming Commission approved Questar Gas’ request to return deferred amounts through a surcredit beginning November 1, 2018. The surcredit will remain in effect until rates become effective in the next Wyoming general rate case. The impact of excess deferred income taxes resulting from the 2017 Tax Reform Act on rates charged to customers will be reported to the Utah and Wyoming Commissions by the first quarter of 2019.
In October 2018, the Ohio Commission issued an order requiring rate-regulated utilities to file an application reflecting the impact of the 2017 Tax Reform Act on current rates by January 1, 2019. In December 2018, East Ohio filed its application proposing an approach to establishing rates and charges by and through which to return tax reform benefits to its customers. This case is pending.
As directed by the West Virginia Commission, Hope is utilizing regulatory accounting to track the effects of the 2017 Tax Reform Act beginning in January 2018 and submitted testimony in July 2018 detailing such effects. In August 2018, the West Virginia Commission approved a settlement implementing base
rate reductions effective September 1, 2018. In November 2018, the West Virginia Commission issued an order requiring Hope to file a calculation of prospective tax reform savings based on 2017 financial statements, using federal income tax rates reduced for consolidated tax savings, and to record as a regulatory liability the difference between the amount calculated based on 2017 financial statements and the amount included in the voluntary base rate reduction effective September 1, 2018. In December 2018, Hope filed the required calculation setting forth an annual regulatory liability deferral amount of $0.4 million. The disposition of the additional regulatory liability will be determined in a future rate proceeding. These reductions are not expected to have a material impact on Hope’s financial condition.
In March 2018, FERC announced actions to address the income tax allowance component of regulated entities’ cost-of-service rates as a result of the 2017 Tax Reform Act. FERC required all interstate natural gas pipelines to make a one-time informational filing with FERC to provide financial information to allow FERC and other interested parties to analyze the impacts of the changes in tax law. The actions also included the reversal of FERC’s policy allowing master limited partnerships to recover an income tax allowance in cost-of-service rates and requiring other pass-through entities to justify the inclusion of an income tax allowance.
In July 2018, FERC issued a final rule adopting and modifying the procedures for determining whether jurisdictional natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate. Specifically, this final rule does not require master limited partnerships to eliminate their income tax allowances when completing the informational filing and allows entities that are wholly-owned by corporations to include an income tax allowance.
During 2018, Dominion Energy’s FERC-regulated pipelines, including those accounted for as equity method investments, filed the required informational reports with FERC. Dominion Energy Overthrust Pipeline, LLC, White River Hub, Dominion Energy Questar Pipeline and Cove Point have reached resolution through settlement, which did not result in a material impact to results of operations, financial condition and/or cash flows of Dominion Energy, waiver or FERC terminating the 501-G proceeding. In January 2019, Iroquois reached a settlement in principle with its customers, which if approved would not have a material impact to Dominion Energy or Dominion Energy Gas, and expects to file a settlement agreement with FERC in the first quarter of 2019. The FERC dockets for DETI and DECG remain open. While the informational filings for these two pipelines indicated that no changes to current rates charged to customers were necessary, given the associated uncertainty, Dominion Energy and Dominion Energy Gas are currently unable to predict the outcome of these matters; however, any change in rates permitted to be charged to customers could have a material impact on results of operations, financial condition and/or cash flows.
Other Regulatory Matters
VIRGINIA REGULATION
The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers.
The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs, renewable energy programs and nuclear license renewals, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.
If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.
Grid Transformation and Security Act of 2018
In March 2018, the GTSA reinstated base rate reviews on a triennial basis, other than the first review which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020. This review for Virginia Power will occur one year earlier than under the Regulation Act legislation enacted in February 2015.
In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized return on equity that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include in a customer credit reinvestment offset. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a customer credit reinvestment offset. Any costs that are the subject of a customer credit reinvestment offset may not be recovered in base rates for the service life of the projects and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized return on equity, base rates are subject to reduction prospectively and customer refunds would be due unless the total customer credit reinvestment offset elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. In the 2021 review, any such rate reduction is limited to $50 million.
The legislation also includes provisions requiring Virginia Power to provide current customers one-time rate credits totaling $200 million and to reduce base rates to reflect reductions in income tax expense resulting from the 2017 Tax Reform Act. As a result, Virginia Power incurred a $215 million ($160 million after-tax) charge in connection with this legislation, including the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology. In July 2018 and January 2019, Virginia Power credited $138 million and $77 million, respectively, to current customers’ bills.
In addition, Virginia Power reduced base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act, which is subject to adjustment
effective April 2019. In May and June 2018, Virginia Power submitted filings detailing the implementation plan for interim reductions in rates for generation and distribution services pursuant to the GTSA.
In July 2018, Virginia Power filed a petition with the Virginia Commission for approval of the first three years of its ten-year plan for electric distribution grid transformation projects as authorized by the GTSA. During the first three years of the plan, Virginia Power proposes to focus on the following seven foundational components of the overall grid transformation plan: (i) smart meters; (ii) customer information platform; (iii) reliability and resilience; (iv) telecommunications infrastructure; (v) cyber and physical security; (vi) predictive analytics; and (vii) emerging technology. The total estimated capital investment during 2019-2021 is $816 million and the proposed operations and maintenance expenses are $102 million. In January 2019, the Virginia Commission issued its final order approving capital spending for the first three years of the plan-totaling $68 million on cyber and physical security and related telecommunications infrastructure. The Virginia Commission declined to approve the remainder of the proposed components for the first three years of the plan, the proposed spending for which was not found reasonable and prudent based on the record in the proceeding. Virginia Power intends to file a revised plan in mid-2019 that will address the elements needed for a comprehensive plan, as outlined by the Virginia Commission in its order.
Virginia Fuel Expenses
In May 2018, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.5 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2018. Virginia Power’s proposed fuel rate represented a fuel revenue increase of $222 million when applied to projected kilowatt-hour sales for the period July 1, 2018 to June 30, 2019. In August 2018, the Virginia Commission approved Virginia Power’s fuel rate with an increase of $209 million.
Solar Facility Projects
In July 2018, Virginia Power filed an application with the Virginia Commission for CPCNs to construct two solar facilities. Colonial Trail West and Spring Grove 1 are estimated to cost approximately $410 million, excluding financing costs. Colonial Trail West and Spring Grove 1 are expected to commence commercial operations, subject to regulatory approvals associated with the projects, in the fourth quarter of 2019 and the fourth quarter of 2020, respectively. Virginia Power also applied for approval of Rider US-3 associated with these projects with a proposed $10 million total revenue requirement for the rate year beginning March 1, 2019. In January 2019, the Virginia Commission issued a final order granting CPCNs to construct the solar facilities, subject to a 20-year performance guarantee of the facilities at a 25% solar capacity factor when normalized for force majeure events. The matter regarding Rider US-3 is pending.
Rate Adjustment Clauses
Below is a discussion of significant riders associated with various Virginia Power projects:
•
The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2018, Virginia Power proposed a $755 million total revenue requirement consisting of $468 million for the transmission component of Virginia
Combined Notes to Consolidated Financial Statements, Continued
Power’s base rates and $287 million for Rider T1. This total revenue requirement represents a $146 million increase versus the revenues to be produced during the rate year under current rates. In August 2018, the Virginia Commission approved a total revenue requirement of $630 million, including Rider T1, subject to true-up, for the rate year beginning September 1, 2018. The Virginia Commission’s order required an adjustment to Rider T1 to begin providing projected benefits associated with the 2017 Tax Reform Act to customers in rates effective September 1, 2018. Such projected benefits were not included in the underlying transmission formula rates approved by FERC. Also in August 2018, Virginia Power filed a petition with the Virginia Commission seeking limited reconsideration and rehearing of this approval to adjust the total revenue requirement to $636 million. In November 2018, the Virginia Commission denied the petition for limited reconsideration and rehearing and adjusted the total revenue requirement to $628 million.
•
The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by Virginia legislation. In March 2018, Virginia Power requested approval of its third phase of conversions totaling $179 million and a balance of $65 million in second phase conversions not previously approved for recovery through Rider U. Virginia Power also proposed a total $73 million revenue requirement for the rate year beginning February 1, 2019 for continuing recovery of the previously approved first and second phase conversions and the proposed second and third phase conversions. In December 2018, the Virginia Commission approved a total $70 million annual revenue requirement effective February 1, 2019, a total capital investment of $179 million for third phase conversions and a balance of $64 million for second phase conversions not previously approved for recovery through Rider U.
•
The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2018, Virginia Power requested approval to implement ten new energy efficiency programs and one new demand-response DSM program for five years, subject to future extensions, with a $262 million cost cap, and proposed a total $49 million revenue requirement for the rate year beginning July 1, 2019, which represents an $18 million increase over the previous year. This matter is pending.
Additional significant riders associated with various Virginia Power projects are as follows:
Coastal Virginia Offshore Wind Project
In November 2018, Virginia Power received approval from the Virginia Commission for its petition seeking a prudency determination as provided in the GTSA with respect to the proposed Coastal Virginia Offshore Wind project consisting of two 6 MW wind turbine generators located approximately 27 miles off the coast of Virginia Beach, Virginia in federal waters, and for a CPCN, for the generation tie line connecting the generators to shore. This project is expected to cost approximately $300 million and to be placed into service by the end of 2020.
Electric Transmission Projects
In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry switching station in Surry County to a new Skiffes Creek switching station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek switching station to Virginia Power’s existing Whealton substation in the City of Hampton. As of July 2017, Virginia Power has received all major required permits and approvals and is proceeding with construction of the project. In connection with the receipt of the permit from the U.S. Army Corps of Engineers in July 2017, Virginia Power was required to make payments totaling approximately $90 million to fund improvements to historical and cultural resources near the project. Accordingly, in July 2017, Virginia Power recorded an increase to property, plant and equipment and a corresponding liability for these payment obligations. Through December 31, 2017, Virginia Power had made $90 million of such payments. Also in July 2017, the National Parks Conservation Association filed a lawsuit in U.S. District Court for the D.C. Circuit seeking to set aside the permit granted by the U.S. Army Corps of Engineers for the project and requested a preliminary injunction against the permit. In August 2017, the National Trust for Historic Preservation and Preservation Virginia filed a similar lawsuit in U.S. District Court for the D.C. Circuit. In October 2017, the preliminary injunction requests were denied. In May 2018, the District Court granted summary judgment in favor of the U.S. Army Corps of Engineers and Virginia Power and dismissed both lawsuits. In June 2018, the National Parks Conservation Association and the National Trust for Historic Preservation and Preservation Virginia appealed that decision to the U.S. Court of Appeals for the D.C. Circuit. The appeal is pending. Also in June 2018, the National Parks Conservation Association filed requests with the U.S. District Court for the District of Columbia and the U.S. Court of Appeals for the D.C. Circuit for an injunction against the permit pending appeal. The U.S. District Court for the District of Columbia denied the injunction request in June 2018 and the U.S. Court of Appeals for the D.C. Circuit similarly denied the request in July 2018.
In November 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to convert an existing transmission line to 230 kV in Prince William County, Virginia, and Loudoun County, Virginia, and to construct and operate a new approximately five mile overhead 230 kV double circuit transmission line between a tap point near the Gainesville substation and a new to-be-constructed Haymarket substation. The
total estimated cost of the project is approximately $180 million. In April 2017, the Virginia Commission issued an interim order instructing Virginia Power to construct and operate the project along an approved route if Virginia Power could obtain all necessary rights-of-way. Otherwise, the Virginia Commission ruled that Virginia Power can construct and operate the project along an approved alternative route. In June 2017, the Virginia Commission issued a final order approving the alternative route for the project, and granted the necessary CPCN. In July 2017, the Virginia Commission retained jurisdiction over the case to evaluate two requests to reconsider its decisions. Also in July 2017, Virginia Power requested that the Virginia Commission stay the proceeding while Virginia Power discusses the proposed route with leaders of Prince William County. In December 2017, the Virginia Commission granted in part the two motions for reconsideration, retained jurisdiction for further proceedings in the case and stayed the effectiveness of its final order. In March 2018, Virginia Power and the two parties seeking reconsideration entered into a stipulation settlement filed with the Virginia Commission agreeing that the project should be placed into an underground pilot program created by the GTSA. In July 2018, Virginia Power filed a request with the Virginia Commission to allow the project to participate in the underground pilot program. Subsequently, in July 2018, the Virginia Commission issued a final order granting the CPCN for the project and allowing the project to participate in the underground pilot program.
In June 2018, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in King and Queen, King William, and New Kent Counties, Virginia four separate segments of 230 kV transmission line between Lanexa and the Northern Neck in Virginia. In February 2019, Virginia Power withdrew two of the segments from the application. As a result, the total estimated cost of the project is approximately $30 million. This matter is pending.
Additional significant Virginia Power electric transmission projects approved and applied for in 2018 are as follows:
NORTH CAROLINA REGULATION
In August 2018, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $24 million increase to the fuel component of its electric rates for the rate year beginning February 1, 2019. As a mitigation alternative, Virginia Power proposed recovering 50% in the February 1, 2019 to the January 31, 2020 rate period and the remaining 50% in the following rate period. In January 2019, the North Carolina Commission approved Virginia Power’s full proposed fuel charge adjustment of $24 million.
OHIO REGULATION
PIR Program
In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In March 2015, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years and to increase the annual capital investment, with corresponding increases in the annual rate-increase caps. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to settle East Ohio’s pending application. As requested, the PIR program and associated cost recovery will continue for another five-year term, calendar years 2017 through 2021, and East Ohio will be permit-
ted to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio.
In April 2018, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2017 costs. The filing reflects gross plant investment for 2017 of $204 million, cumulative gross plant investment of $1.4 billion and a revenue requirement of $165 million.
AMR Program
In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. The AMR program approved by the Ohio Commission was completed in 2012. Although no further capital investment will be added, East Ohio is approved to recover depreciation, property taxes, carrying charges and a return until East Ohio has another rate case.
In April 2018, the Ohio Commission approved East Ohio’s application to adjust its AMR cost recovery rate for 2017 costs. The filing reflects a revenue requirement of approximately $5 million.
PIPP Plus Program
Under the Ohio PIPP Plus Program, eligible customers can make reduced payments based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP amount is deferred and collected under the PIPP rider in accordance with
Combined Notes to Consolidated Financial Statements, Continued
the rules of the Ohio Commission. In May 2018, East Ohio filed its annual update of the PIPP rider with the Ohio Commission. In July 2018, East Ohio’s annual update of the PIPP rider was automatically approved by the Ohio Commission after a 45-day waiting period from the date of the filing. The revised rider rate reflects recovery over the twelve-month period from July 2018 through June 2019 of projected deferred program costs of approximately $10 million from April 2018 through June 2019, net of a refund for over-recovery of accumulated arrearages of approximately $4 million as of March 31, 2018.
UEX Rider
East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In September 2018, the Ohio Commission approved East Ohio’s application requesting approval of its UEX Rider to reflect a refund of over-recovered accumulated bad debt expense of approximately $11 million as of March 31, 2018, and recovery of prospective net bad debt expense projected to total $16 million for the twelve-month period from April 2018 to March 2019.
DSM Rider
East Ohio has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In November 2018, East Ohio filed an application with the Ohio Commission seeking approval of an adjustment to the DSM rider to recover a total of $4 million, which includes an over-recovery of costs during the preceding 12-month period. This application was approved by the Ohio Commission in January 2019.
WEST VIRGINIA REGULATION
In May 2018, Hope filed a PREP application with the West Virginia Commission requesting approval to recover PREP costs related to $31 million and $36 million of projected capital investment for 2018 and 2019, respectively. The application also includes a true-up of PREP costs related to the 2017 actual capital investment of $28 million and sets forth $8 million of annual PREP costs to be recovered in proposed rates effective November 2018. In October 2018, the West Virginia Commission approved PREP rates effective November 2018. Approved rates recover $7 million of annual PREP costs related to actual cumulative PREP investment through December 31, 2017 of $48 million and projected PREP investment for calendar years 2018 and 2019 of $31 million and $29 million, respectively.
UTAH AND WYOMING REGULATION
Fuel Deferral
In May 2018, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $86 million gas cost decrease reflecting forecasted decreases in commodity costs. The Utah Commission and the Wyoming Commission both approved the filings in May 2018 with rates effective June 2018.
In October 2018, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $48 million gas cost decrease reflecting forecasted decreases in commodity costs. The Utah Commission and the
Wyoming Commission both approved the filings in October 2018 with rates effective November 2018.
In October 2018, the Utah Commission denied Questar Gas’ request for pre-approval to construct an LNG peaking storage facility with a liquefaction rate of 8.2 million cubic feet per day. Questar Gas is reviewing the order and assessing its options, which include filing supplemental information with the Utah Commission for reconsideration.
Infrastructure Replacement Tracker
During 2018, Questar Gas filed applications with the Utah Commission to increase its infrastructure replacement surcharge to collect an additional $11 million in revenue in 2019 related to $85 million in 2018 capital investment. The Utah Commission approved the applications in the fourth quarter of 2018.
FERC-GAS
Cove Point
In March 2018, Cove Point submitted its annual electric power cost adjustment to FERC requesting approval to recover $30 million. FERC approved the adjustment in March 2018.
In June 2015, Cove Point executed two binding precedent agreements for the approximately $150 million Eastern Market Access Project. In January 2018, Cove Point received FERC authorization to construct and operate the project facilities, which are expected to be placed in service in the second half of 2019. In October 2018, Cove Point announced it is evaluating alternatives to a proposed Charles County, Maryland compressor station that was initially part of this project and in December 2018, after working with project customers for alternative solutions, decided not to pursue further construction at this location resulting in a revised project estimate of approximately $45 million and a write-off of $37 million pre-tax ($28 million after-tax) recorded within impairment of assets and related charges in Dominion Energy’s Consolidated Statements of Income.
DETI
In September 2018, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $37 million. Also in September 2018, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $7 million. In October 2018, FERC approved these adjustments.
In August 2018, DETI executed a binding precedent agreement with a customer for the West Loop project. The project is expected to cost approximately $95 million and provide 150,000 Dth per day of firm transportation service from Pennsylvania to Ohio for delivery to a proposed combined-cycle, natural gas-fired electric power generation facility to be located in Columbiana County, Ohio. In December 2018, DETI filed an application to request FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service by the end of 2021.
NOTE 14. ASSET RETIREMENT OBLIGATIONS
AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of the Companies’ long-lived assets. Dominion Energy and Virginia Power’s AROs are primarily associated with the decom-
missioning of their nuclear generation facilities and ash pond and landfill closures. Dominion Energy Gas’ AROs primarily include plugging and abandonment of gas and oil wells and the interim retirement of natural gas gathering, transmission, distribution and storage pipeline components.
The Companies have also identified, but not recognized, AROs related to the retirement of Dominion Energy’s LNG facility, Dominion Energy and Dominion Energy Gas’ storage wells in their underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in Dominion Energy and Virginia Power’s generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 2017 and 2018 were as follows:
(1) Includes $263 million and $282 million reported in other current liabilities at December 31, 2017, and 2018, respectively.
(2) Reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 for further information.
(3) Includes $146 million and $153 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2017 and 2018, respectively.
Dominion Energy and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 2018 and 2017, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of equity and debt securities, totaled $4.9 billion and $5.1 billion, respectively. At December 31, 2018 and 2017, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $2.4 billion for both periods.
NOTE 15. VARIABLE INTEREST ENTITIES
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
DOMINION ENERGY
At December 31, 2018, Dominion Energy owned the general partner, 60.9% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owned a preferred equity interest and the general partner interest in Cove Point. In January 2019, Dominion Energy acquired all outstanding partnership interests not owned by Dominion Energy and Dominion Energy Midstream became a wholly-owned subsidiary of Dominion Energy. Dominion Energy previously concluded that Dominion Energy Midstream was a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy was the primary beneficiary of Dominion Energy Midstream and Dominion Energy Midstream was the primary beneficiary of Cove Point as they had the power to direct the activities that most significantly impact their economic performance as well as to absorb losses and benefits which could be significant to them.
At December 31, 2018, Dominion Energy owns the manager and 67% of the membership interest in certain merchant solar facilities, as discussed in Note 2. Dominion Energy has concluded that these entities are VIEs due to the members lacking the characteristics of a controlling financial interest. In addition, in 2016 Dominion Energy created a wholly owned subsidiary, SBL Holdco, as a holding company of its interest in the VIE merchant solar facilities and accordingly SBL Holdco is a VIE. Dominion Energy is the primary beneficiary of SBL Holdco and the merchant solar facilities, as it has the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Dominion Energy’s securities due within one year and long-term debt include $31 million and $299 million, respectively, of debt issued by SBL Holdco net of issuance costs that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in certain merchant solar facilities.
Dominion Energy owns a 48% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the
Combined Notes to Consolidated Financial Statements, Continued
nature of this entity. Dominion Energy concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion Energy has concluded that it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. Dominion Energy is obligated to provide capital contributions based on its ownership percentage. Dominion Energy’s maximum exposure to loss is limited to its current and future investment as well as any obligations under a guarantee provided. See Note 22 for more information.
DOMINION ENERGY AND VIRGINIA POWER
Dominion Energy and Virginia Power’s nuclear decommissioning trust funds and Dominion Energy’s rabbi trusts hold investments in limited partnerships or similar type entities (see Note 9 for further details). Dominion Energy and Virginia Power concluded that these partnership investments are VIEs due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy and Virginia Power have concluded neither is the primary beneficiary as they do not have the power to direct the activities that most significantly impact these VIEs’ economic performance. Dominion Energy and Virginia Power are obligated to provide capital contributions to the partnerships as required by each partnership agreement based on their ownership percentages. Dominion Energy and Virginia Power’s maximum exposure to loss is limited to their current and future investments.
DOMINION ENERGY AND DOMINION ENERGY GAS
Dominion Energy previously concluded that Iroquois was a VIE because a non-affiliated Iroquois equity holder had the ability during a limited period of time to transfer its ownership interests to another Iroquois equity holder or its affiliate. At the end of the first quarter 2016, such right no longer existed and, as a result, Dominion Energy concluded that Iroquois is no longer a VIE.
VIRGINIA POWER
Virginia Power had long-term power and capacity contracts with three non-utility generators, which contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. Contracts with two of these non-utility generators expired during 2017, leaving a remaining aggregate summer generation capacity of approximately 218 MW. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the remaining entity during the remaining terms of Virginia Power’s contract and for the years the entity is expected to operate after its contractual relationship expires. The remaining contract expires in 2021. Virginia Power is not subject to any risk of loss from this potential VIE other than its remaining purchase commitments which totaled $150 million as of December 31, 2018. Virginia
Power paid $50 million, $86 million, and $144 million for electric capacity to non-utility generators and $18 million, $24 million, and $31 million for electric energy to non-utility generators for the years ended December 31, 2018, 2017 and 2016, respectively.
DOMINION ENERGY GAS
DETI has been engaged to oversee the construction of, and to subsequently operate and maintain, the projects undertaken by Atlantic Coast Pipeline based on the overall direction and oversight of Atlantic Coast Pipeline’s members. An affiliate of DETI holds a membership interest in Atlantic Coast Pipeline, therefore DETI is considered to have a variable interest in Atlantic Coast Pipeline. The members of Atlantic Coast Pipeline hold the power to direct the construction, operations and maintenance activities of the entity. DETI has concluded it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance. DETI has no obligation to absorb any losses of the VIE. See Note 24 for information about associated related party receivable balances.
VIRGINIA POWER AND DOMINION ENERGY GAS
Virginia Power and Dominion Energy Gas purchased shared services from DES, an affiliated VIE, of $335 million and $126 million, $340 million and $126 million, and $346 million and $123 million for the years ended December 31, 2018, 2017 and 2016, respectively. Virginia Power and Dominion Energy Gas’ Consolidated Balance Sheets included amounts due to DES of $107 million and $46 million, respectively, at December 31, 2018, and $36 million and $14 million, respectively, at December 31, 2017, recorded in payables to affiliates in the Consolidated Balance Sheets. Virginia Power and Dominion Energy Gas determined that neither is the primary beneficiary of DES as neither has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it. DES provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including Virginia Power and Dominion Energy Gas. Virginia Power and Dominion Energy Gas have no obligation to absorb more than their allocated shares of DES costs.
NOTE 16. SHORT-TERM DEBT AND CREDIT AGREEMENTS
The Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.
DOMINION ENERGY
In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities were as follows:
(1) The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s credit facilities were 2.93% and 1.61% at December 31, 2018 and 2017, respectively.
(2) This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.
(3) These credit facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The facilities were scheduled to mature in April 2020 and were used to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.
In connection with the SCANA Combination, Dominion Energy intends to terminate SCANA, SCE&G and PSNC’s existing credit facilities and add SCE&G as a co-borrower to its $6.0 billion joint revolving credit facility in the first quarter of 2019 once certain regulatory approvals are obtained. In January 2019, Virginia Power and SCE&G, as co-borrowers, filed with the Virginia Commission and the South Carolina Commission, respectively, for approval. In February 2019, the Virginia Commission approved the request.
Questar Gas’ short-term financing is supported through its access as co-borrower to the joint revolving credit facility discussed above with Dominion Energy, Virginia Power and Dominion Energy Gas. At December 31, 2018, the sub-limit for Questar Gas was $250 million.
In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which had an original stated maturity date of December 2017 with automatic one-year renewals through the maturity of the SBL Holdco term loan agreement in 2023. Dominion Solar Projects III, Inc. has $25 million of credit facilities which had an original stated maturity date of May 2018 with automatic one-year renewals through the maturity of the Dominion Solar Projects III, Inc. term loan agreement in 2024. At December 31, 2018, no amounts were outstanding under either of these facilities.
In February and June 2018, Dominion Energy borrowed $950 million and $500 million, respectively, under 364-Day
Term Loan Agreements that bore interest at a variable rate. In September 2018, the principal outstanding plus accrued interest for both borrowings was repaid.
In March 2018, Dominion Energy Midstream entered into a $500 million revolving credit facility. The credit facility was scheduled to mature in March 2021, bore interest at a variable rate, and was used to support bank borrowings and the issuance of commercial paper, as well as to support up to $250 million of letters of credit. At December 31, 2018, Dominion Energy Midstream had $73 million outstanding under this credit facility. In February 2019, Dominion Energy Midstream terminated the facility subsequent to repaying the outstanding balance, plus accrued interest.
In October 2018, Dominion Energy entered into a credit agreement, which allows Dominion Energy to issue up to approximately $21 million in letters of credit. The facility terminates in June 2020. At December 31, 2018, Dominion Energy had $21 million in letters of credit outstanding under this agreement.
VIRGINIA POWER
In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Virginia Power’s short-term financing is supported through its access as co-borrower to the joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.
Virginia Power’s share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion Energy, Dominion Energy Gas and Questar Gas were as follows:
(1) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.94% and 1.65% at December 31, 2018 and 2017, respectively.
(2) The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Virginia Power was $1.5 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.
(3) These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The full amount of the facilities was available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. These facilities were scheduled to mature in April 2020 and were used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.
Combined Notes to Consolidated Financial Statements, Continued
In addition to the credit facility commitments mentioned above, Virginia Power also had a $100 million credit facility with a maturity date of April 2020. In March 2018, Virginia Power redeemed its variable rate tax-exempt financings supported by this credit facility and terminated the facility.
DOMINION ENERGY GAS
In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Dominion Energy Gas’ short-term financing is supported by its access as co-borrower to the joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.
Dominion Energy Gas’ share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion Energy, Virginia Power and Questar Gas were as follows:
(1) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.58% and 1.57% at December 31, 2018 and 2017, respectively.
(2) A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy Gas has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.
(3) These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. A maximum of a combined $1.5 billion of the facilities was available to Dominion Energy Gas, assuming adequate capacity was available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. These credit facilities were scheduled to mature in April 2020 and were used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.
NOTE 17. LONG-TERM DEBT
(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2018.
Combined Notes to Consolidated Financial Statements, Continued
(2) Amount includes foreign currency remeasurement adjustments.
(3) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. In March 2018, Virginia Power redeemed certain variable rate tax-exempt financings supported by its $100 million credit facility and terminated the facility. In December 2018, Virginia Power redeemed its $14 million Economic Development Authority of the County of Chesterfield Solid Waste and Sewage Disposal Revenue Bonds due in 2031.
(4) In November and December 2018, Dominion Energy redeemed certain senior notes prior to their stated maturity. See below for a discussion of the senior note redemptions.
(5) Represents debt assumed by Dominion Energy from the merger of its former CNG subsidiary.
(6) Represents debt obligations of Questar Gas. See Note 3 for more information.
(7) Represents debt obligations of Eagle Solar. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar’s interest in certain merchant solar facilities.
(8) Represents debt associated with SBL Holdco and Dominion Solar Projects III, Inc. The debt is nonrecourse to Dominion Energy and is secured by SBL Holdco and Dominion Solar Projects III, Inc.’s interest in certain merchant solar facilities.
(9) Represents debt obligations of a DGI subsidiary.
(10) Includes debt obligations of Cove Point that are secured by Dominion Energy’s common equity interest in Cove Point.
(11) In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2018.
(12) Represents debt obligations of Dominion Energy Questar Pipeline. See Note 3 for more information.
(13) Represents the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt.
(14) 2017 excludes $250 million of Dominion Energy Questar Pipeline’s senior notes that matured in February 2018 using proceeds from the January 2018 issuance, through private placements, of $100 million and $150 million of senior notes that mature in 2028 and 2038, respectively.
(15) Includes $20 million of estimated mandatory prepayments due within one year based on estimated cash flows in excess of debt service at SBL Holdco and Dominion Solar Projects III, Inc.
Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2018, were as follows:
(1) Excludes mandatory prepayments associated with SBL Holdco and Dominion Solar Projects III, Inc. based on cash flows in excess of debt service. At December 31, 2018, $20 million of estimated mandatory prepayments due within one year were included in securities due within one year in Dominion Energy’s Consolidated Balance Sheets.
(2) In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2018.
The Companies’ short-term credit facility and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2018, there were no events of default under these covenants.
Senior Note Redemptions
In November 2018 and December 2018, Dominion Energy redeemed the following outstanding series of senior notes: 2011 Series A 4.45% Senior Notes due 2021, 2014 Series B 2.50%
Senior Notes due 2019, 2014 Series C 3.625% Senior Notes due 2024 and 2018 Series A Floating Rate Senior Notes due 2020 with an aggregate outstanding principal of $2.2 billion. The aggregate redemption price paid was $2.2 billion and represents the principal amount outstanding, accrued and unpaid interest and the applicable make-whole premium of $34 million. Total charges of $69 million, including the make-whole premium, were recognized and recorded in interest expense in Dominion Energy’s Consolidated Statements of Income.
Enhanced Junior Subordinated Notes
In June 2006 and September 2006, Dominion Energy issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids bear interest at three-month LIBOR plus 2.825%, reset quarterly. Previously, interest was fixed at 7.5% per year. The September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly.
In October 2014, Dominion Energy issued $685 million of October 2014 hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly.
Dominion Energy may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion Energy may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.
Dominion Energy executed RCCs in connection with its issuance of the June 2006 hybrids and the September 2006 hybrids. Under the terms of the RCCs, Dominion Energy covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion Energy shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion Energy has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. In September 2011, Dominion Energy amended the RCCs of the June 2006 hybrids and September 2006 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock issuances from 180 days to 365 days. The proceeds Dominion Energy receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.
In the first quarter of 2016, Dominion Energy purchased and cancelled $38 million and $4 million of the June 2006 hybrids and the September 2006 hybrids, respectively. In July 2016, Dominion Energy launched a tender offer to purchase up to $200 million in aggregate of additional June 2006 hybrids and September 2006 hybrids, which expired on August 1, 2016. In connection with the tender offer, Dominion Energy purchased and cancelled $125 million and $74 million of the June 2006 hybrids and the September 2006 hybrids, respectively. All purchases were conducted in compliance with the applicable RCC. Also in July 2016, Dominion Energy issued $800 million of 5.25% July 2016 hybrids. The proceeds were used for general corporate purposes, including to finance the tender offer. The July 2016 hybrids are listed on the NYSE under the symbol DRUA.
Remarketable Subordinated Notes
In June 2013, Dominion Energy issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B 6.0% Equity Units, initially in the form of Corporate Units. In July 2014, Dominion Energy issued $1.0 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. The Corporate Units were listed on the NYSE under the symbols DCUA, DCUB and DCUC respectively.
Each Corporate Unit consisted of a stock purchase contract and 1/20 interest in a RSN issued by Dominion Energy. The stock purchase contracts obligated the holders to purchase shares of Dominion Energy common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price paid under the stock purchase contracts was $50 per Corporate Unit and the number of shares purchased was determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The RSNs were pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.
In May 2017, Dominion Energy successfully remarketed the $1.0 billion 2014 Series A 1.50% RSNs due 2020 pursuant to the terms of the related 2014 Equity Units. In connection with the remarketing, the interest rate on the junior subordinated notes was reset to 2.579%, payable on a semi-annual basis and Dominion Energy ceased to have the ability to redeem the notes at its option or defer interest payments. In March 2016 and May 2016, Dominion Energy successfully remarketed the $550 million 2013 Series A 1.07% RSNs due 2021 and the $550 million 2013 Series B 1.18% RSNs due 2019, respectively, pursuant to the terms of the related 2013 Equity Units. In connection with the remarketings, the interest rate on the Series A and Series B junior subordinated notes was reset to 4.104% and 2.962%, respectively, payable on a semi-annual basis and Dominion Energy ceased to have the ability to redeem the notes at its option or defer interest payments. At December 31, 2018, the securities are included in junior subordinated notes in Dominion Energy’s Consolidated Balance Sheets. Dominion Energy did not receive any proceeds from the remarketings. Remarketing proceeds belonged to the investors holding the related equity units and were temporarily used to purchase a portfolio of treasury securities. Upon maturity of each portfolio, the proceeds were applied on behalf of investors on the related stock purchase contract settlement date to pay the purchase price to Dominion Energy for issuance of 12.5 million shares of its common stock in July 2017 and 8.5 million shares of its common stock in both April 2016 and July 2016. See Issuance of Common Stock below for a description of common stock issued by Dominion Energy under the stock purchase contracts.
In August 2016, Dominion Energy issued $1.4 billion of 2016 Series A 6.75% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbol DCUD. The net proceeds from the 2016 Equity Units were used to finance the Dominion Energy Questar Combination. See Note 3 for more information.
Each 2016 Series A Corporate Unit consists of a stock purchase contract, a 1/40 interest in a 2016 Series A-1 RSN issued by Dominion Energy and a 1/40 interest in a 2016 Series A-2 RSN issued by Dominion Energy. The stock purchase contracts obli-
Combined Notes to Consolidated Financial Statements, Continued
gate the holders to purchase shares of Dominion Energy common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is $50 per Corporate Unit and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The RSNs are pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.
Dominion Energy makes quarterly interest payments on the RSNs and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. Dominion Energy may defer payments on the stock purchase contracts and the RSNs for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, Dominion Energy may not make any cash distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the RSNs.
Dominion Energy has recorded the present value of the stock purchase contract payments as a liability offset by a charge to
equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, Dominion Energy applies the treasury stock method to the equity units.
Pursuant to the terms of the 2016 Equity Units, Dominion Energy expects to remarket both the 2016 Series A-1 and 2016 Series A-2 RSNs during the second or third quarter of 2019. Following a successful remarketing, the interest rate on the RSNs will be reset, interest will be payable on a semi-annual basis and Dominion Energy will cease to have the ability to redeem the RSNs at its option or defer interest payments. Proceeds of each remarketing will belong to the investors in the related equity units and will be held and applied on their behalf at the settlement date of the related stock purchase contracts to pay the purchase price to Dominion Energy for issuance of its common stock.
Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion Energy will issue between 15.1 million and 18.9 million shares in August 2019. A total of 23.1 million shares of Dominion Energy’s common stock has been reserved for issuance in connection with the stock purchase contracts.
Selected information about Dominion Energy’s equity units is presented below:
(1) Payments of $64 million and $101 million were made in 2018 and 2017, respectively, including payments for the remarketed 2014 Series A notes. The stock purchase contract liability was $47 million and $111 million at December 31, 2018 and 2017, respectively.
(2) The maturity dates of the $700 million Series A-1 RSNs and $700 million Series A-2 RSNs are August 15, 2021 and August 15, 2024, respectively.
(3) Annual interest rate applies to each of the Series A-1 RSNs and Series A-2 RSNs.
NOTE 18. PREFERRED STOCK
Dominion Energy is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2018 or 2017.
Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference; however, none were issued and outstanding at December 31, 2018 or 2017.
NOTE 19. EQUITY
Issuance of Common Stock
DOMINION ENERGY
Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. Currently, Dominion Energy is issuing new shares of common stock for these direct stock purchase plans.
During 2018, Dominion Energy received cash proceeds, net of fees and commissions, of $2.5 billion from the issuance of approximately 36 million shares of common stock through various programs including the forward sale agreements described below resulting in approximately 681 million shares of common stock outstanding at December 31, 2018. These proceeds include cash of $315 million received from the issuance of 4.5 million of such shares through Dominion Energy Direct® and employee savings plans.
In July 2017, Dominion Energy issued 12.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2014 Equity Units and received proceeds of $1.0 billion.
In both April 2016 and July 2016, Dominion Energy issued 8.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2013 Equity Units and received $1.1 billion of total proceeds. Additionally, Dominion Energy completed a market issuance of equity in April 2016 of 10.2 million shares and received proceeds of $756 million through a registered underwritten public offering. A portion of the net proceeds was used to finance the Dominion Energy Questar Combination. See Note 3 for more information.
In June 2017, Dominion Energy filed an SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at-the-market program. Also in June 2017, Dominion Energy entered into three separate sales agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion Energy and the sales agents in conformance with applicable securities laws. In January 2018, Dominion Energy provided sales instructions to one of the sales agents and issued 6.6 million shares through at-the-market issuances and received cash proceeds of $495 million, net of fees and commissions paid of $5 million. Following these issuances, Dominion Energy had no remaining ability to issue stock under
the 2017 sales agency agreements and completed the program. In February 2018, Dominion Energy entered into six separate sales agency agreements to effect sales under a new at-the-market program pursuant to which it may offer from time to time up to $1.0 billion aggregate amount of its common stock. These agreements replaced the sales agency agreements entered into by Dominion Energy in June 2017. Sales of common stock can be made by means of private negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion Energy and the sales agents in conformance with applicable securities laws. In the fourth quarter of 2018, Dominion Energy provided sales instructions to two of the sales agents and issued 2.7 million shares through at-the-market issuances and received cash proceeds of $197 million, net of fees and commissions paid of $2 million. Following these issuances, Dominion Energy has $801 million of remaining ability to issue stock under the sales agency agreements.
Dominion Energy entered in March 2018, and closed in April 2018, separate forward sale agreements with Goldman Sachs & Co. LLC and Credit Suisse Capital LLC, as forward purchasers, and an underwriting agreement with Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, as representatives of the several underwriters named therein, relating to an aggregate of 20 million shares of Dominion Energy common stock. The underwriting agreement granted the underwriters a 30-day option to purchase up to an additional three million shares of Dominion Energy common stock, which the underwriters exercised with respect to approximately 2.1 million shares in April 2018. Dominion Energy entered into separate forward sale agreements with the forward purchasers with respect to the additional shares. In December 2018, Dominion Energy received proceeds of $1.4 billion (after deducting underwriting discounts, but before deducting expenses, and subject to forward price adjustments under the forward sale agreements) upon the physical settlement of 22.1 million shares.
See Note 3 to the Consolidated Financial Statements for information on the issuance of Dominion Energy common stock in January 2019 in connection with the SCANA Combination. Also in January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of common stock as noted below.
VIRGINIA POWER
In 2018, 2017 and 2016, Virginia Power did not issue any shares of its common stock to Dominion Energy.
Shares Reserved for Issuance
Dominion Energy has approximately 76 million shares reserved and available for issuance for Dominion Energy Direct®, employee stock awards, employee savings plans, director stock compensation plans and issuances in connection with stock purchase contracts and the at-the-market program. See Note 17 for more information.
Repurchase of Common Stock
Dominion Energy did not repurchase any shares in 2018 or 2017 and does not plan to repurchase shares during 2019, except for shares tendered by employees to satisfy tax withholding obliga-
Combined Notes to Consolidated Financial Statements, Continued
tions on vested restricted stock, which do not count against its stock repurchase authorization.
Purchase of Dominion Energy Midstream Units
In September 2015, Dominion Energy initiated a program to purchase from the market up to $50 million of common units representing limited partner interests in Dominion Energy Midstream, which expired in September 2016. Dominion Energy purchased approximately 658,000 common units for $17 million for the year ended December 31, 2016.
In January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. The merger was accounted for by Dominion Energy following the guidance for a change in a parent company’s ownership interest in a consolidated subsidiary. Because Dominion Energy controls Dominion Energy Midstream both before and after the merger, the changes in Dominion Energy’s ownership interest in Dominion Energy Midstream were accounted for as an equity transaction and no gain or loss will be recognized. The tax effect of the merger will be presented in common stock.
Issuance of Dominion Energy Midstream Units
In 2017, Dominion Energy Midstream received $18 million of proceeds from the issuance of common units through its at-the-market program.
In 2016, Dominion Energy Midstream received $482 million of proceeds from the issuance of common units and $490 million of proceeds from the issuance of convertible preferred units. The net proceeds were primarily used to finance a portion of the acquisition of Dominion Energy Questar Pipeline from Dominion Energy. See Note 3 for more information.
The holders of the convertible preferred units were entitled to receive cumulative quarterly distributions payable in cash or additional convertible preferred units, subject to certain conditions. The units were convertible into Dominion Energy Midstream common units on a one-for-one basis, subject to certain adjustments, (i) in whole or in part at the option of the unitholders any time after December 1, 2018 or, (ii) in whole or in part at Dominion Energy Midstream’s option, subject to certain conditions, any time after December 1, 2019. Immediately prior to the closing of Dominion Energy’s acquisition of the outstanding interest in Dominion Energy Midstream noted above, each convertible preferred unit was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement.
In May 2018, all of the subordinated units of Dominion Energy Midstream held by Dominion Energy were converted into common units on a 1:1 ratio following the payment of Dominion Energy Midstream’s distribution for the first quarter of 2018. In June 2018, Dominion Energy, as general partner, exercised an incentive distribution right reset as defined in Dominion Energy Midstream’s partnership agreement and received 26.7 million common units representing limited partner interests in Dominion Energy Midstream. As a result of the increase in its ownership interest in Dominion Energy Midstream, Dominion Energy recorded a decrease in noncontrolling interest, and a correspond-
ing increase in shareholders’ equity, of $375 million reflecting the change in the carrying value of the interest in the net assets of Dominion Energy Midstream held by others.
Accumulated Other Comprehensive Income (Loss)
Presented in the table below is a summary of AOCI by component:
DOMINION ENERGY
The following table presents Dominion Energy’s changes in AOCI by component, net of tax:
(1) See table below for details about these reclassifications.
The following table presents Dominion Energy’s reclassifications out of AOCI by component:
Combined Notes to Consolidated Financial Statements, Continued
VIRGINIA POWER
The following table presents Virginia Power’s changes in AOCI by component, net of tax:
(1) See table below for details about these reclassifications.
The following table presents Virginia Power’s reclassifications out of AOCI by component:
DOMINION ENERGY GAS
The following table presents Dominion Energy Gas’ changes in AOCI by component, net of tax:
(1) See table below for details about these reclassifications.
The following table presents Dominion Energy Gas’ reclassifications out of AOCI by component:
Stock-Based Awards
The 2005 and 2014 Incentive Compensation Plans permit stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of these plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. No options are outstanding under either plan. At December 31, 2018, approximately 22 million shares were available for future grants under these plans.
Goal-based stock awards are granted in lieu of cash-based performance grants to certain officers who have not achieved a certain targeted level of share ownership. As of December 31, 2018, unrecognized compensation cost related to nonvested goal-based stock awards was immaterial.
Dominion Energy measures and recognizes compensation expense relating to share-based payment transactions over the
vesting period based on the fair value of the equity or liability instruments issued. Dominion Energy’s results for the years ended December 31, 2018, 2017 and 2016 include $48 million, $45 million, and $33 million, respectively, of compensation costs and $12 million, $16 million, and $11 million, respectively of income tax benefits related to Dominion Energy’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income. Excess Tax Benefits are classified as a financing cash flow.
RESTRICTED STOCK
Restricted stock grants are made to officers under Dominion Energy’s LTIP and may also be granted to certain key non-officer employees. The fair value of Dominion Energy’s restricted stock awards is equal to the closing price of Dominion Energy’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2018, 2017 and 2016:
As of December 31, 2018, unrecognized compensation cost related to nonvested restricted stock awards totaled $49 million and is expected to be recognized over a weighted-average period of 2.1 years. The fair value of restricted stock awards that vested was $23 million, $21 million, and $21 million in 2018, 2017 and 2016, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion Energy stock and the applicable federal, state and local tax withholding rates.
CASH-BASED PERFORMANCE GRANTS
Cash-based performance grants are made to Dominion Energy’s officers under Dominion Energy’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.
In February 2016, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 2018 based on the achievement of two performance metrics during 2016 and 2017: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total of the payout under the grant was $12 million.
Combined Notes to Consolidated Financial Statements, Continued
In February 2017, two cash-based performance grants were made to officers as Dominion Energy transitioned from a two-year performance period to a three-year performance period. Payout of the two-year grant occurred in January 2019 based on the achievement of two performance metrics during 2017 and 2018: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC with an additional partial payout based on Dominion Energy’s price-earnings ratio relative to that of the members of Dominion Energy’s compensation peer group. The total of the payout under the two-year grant was $13 million and a liability of $13 million had been accrued for this award. Payout of the three-year cash-based performance grant is expected to occur by March 15, 2020 based on the achievement of two performance metrics during 2017, 2018 and 2019: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the awards based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2018, the targeted amount of the three-year grant was $14 million and a liability of $10 million had been accrued for the award.
In February 2018, a cash-based performance grant was made to officers. Payout of the three-year cash-based performance grant is expected to occur by March 15, 2021 based on the achievement of two performance metrics during 2018, 2019 and 2020: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the awards based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2018, the targeted amount of the three-year grant was $16 million and a liability of $5 million had been accrued for this award.
NOTE 20. DIVIDEND RESTRICTIONS
The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Virginia Commission had not restricted the payment of dividends by Virginia Power.
The North Carolina Commission, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by Virginia Power and PSNC to (i) the amount of retained earnings at closing of the SCANA Combination plus (ii) any future earnings recorded by Virginia Power and PSNC after such date. In addition, notice to the North Carolina Commission is required if payment of dividends causes the equity component of Virginia Power and PSNC’s capital structure to fall below 45%.
The Ohio Commission may prohibit any public service company, including East Ohio, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Ohio Commission had not restricted the payment of dividends by East Ohio.
Pursuant to the SCANA Merger Approval Order, the amount of any SCE&G dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. There is no specific restriction on the payment of dividends by SCE&G.
The Utah Commission may prohibit any public service company, including Questar Gas, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Utah Commission had not restricted the payment of dividends by Questar Gas.
Certain agreements associated with the Companies’ credit facility contains restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Companies’ ability to pay dividends or receive dividends from their subsidiaries at December 31, 2018.
In connection with the SCANA Combination, under the terms of the merger agreement, Dominion Energy could not declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock or property) in respect of, any of its capital stock, other than regular quarterly cash dividends from January 2018 through January 2019.
As part of the merger agreement with Dominion Energy Midstream from November 2018 through January 2019, Dominion Energy could not declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock or property) in respect of, any of its capital stock, other than regular quarterly cash dividends.
See Note 17 for a description of potential restrictions on dividend payments by Dominion Energy in connection with the deferral of interest payments on certain junior subordinated notes and equity units, initially in the form of corporate units.
NOTE 21. EMPLOYEE BENEFIT PLANS
Dominion Energy and Dominion Energy Gas-Defined Benefit Plans
Dominion Energy provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Energy Gas participates in a number of the Dominion Energy-sponsored retirement plans. Under the terms of its benefit plans, Dominion Energy reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.
Dominion Energy maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion Energy’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension programs also provide benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. The nonqualified plans are funded through contributions to grantor trusts. Dominion Energy also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service.
Pension benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by Dominion Energy that provides benefits to multiple Dominion Energy subsidiaries. Pension benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by separate pension plans for East Ohio and, for DETI, a plan that provides benefits to employees of both DETI and Hope. Employee compensation is the basis for allocating
pension costs and obligations between DETI and Hope and determining East Ohio’s share of total pension costs.
Retiree healthcare and life insurance benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by Dominion Energy that provides certain retiree healthcare and life insurance benefits to multiple Dominion Energy subsidiaries. Retiree healthcare and life insurance benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by separate other postretirement benefit plans for East Ohio and, for DETI, a plan that provides benefits to both DETI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DETI and Hope and determining East Ohio’s share of total other postretirement benefit costs.
Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates, mortality rates and the rate of compensation increases.
Dominion Energy uses December 31 as the measurement date for all of its employee benefit plans, including those in which Dominion Energy Gas participates. Dominion Energy uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost, for all pension plans, including those in which Dominion Energy Gas participates. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.
Dominion Energy’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $(605) million and $1.6 billion in 2018 and 2017, respectively, versus expected returns of $806 million and $767 million, respectively. Dominion Energy Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns (losses) of $(129) million and $335 million in 2018 and 2017, respectively, versus expected returns of $178 million and $165 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.
During 2016, Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units) engaged their actuary to conduct an experience study of their employees demographics over a five-year period as compared to significant assumptions that were being used to determine pension and other
postretirement benefit obligations and periodic costs. These assumptions primarily included mortality, retirement rates, termination rates, and salary increase rates. The changes in assumptions implemented as a result of the experience study resulted in increases of $290 million and $38 million in the pension and other postretirement benefits obligations, respectively, at December 31, 2016 for Dominion Energy and $24 million and $9 million in the pension and other postretirement benefits obligations, respectively, at December 31, 2016 for Dominion Energy Gas. In addition, these changes increased net periodic benefit costs $42 million for Dominion Energy during 2017. The increase in net periodic benefit costs for Dominion Energy Gas during 2017 was immaterial.
PLAN AMENDMENTS AND REMEASUREMENTS
In the fourth quarter of 2017, Dominion Energy remeasured its pension and other postretirement benefit plans as a result of voluntary and involuntary separation programs at Dominion Energy Questar. The settlement and related remeasurement resulted in a reduction in the pension benefit obligation of approximately $75 million and an increase in the accumulated postretirement benefit obligation of approximately $2 million. The discount rates used for the 2017 pension cost and related settlement were 4.46% as of December 31, 2016, 4.51% as of January 31, 2017 and 4.05% as of June 30 and September 30, 2017. All other assumptions used were consistent with the measurement as of December 31, 2016.
In the first quarter of 2017, Dominion Energy and Dominion Energy Gas remeasured an other postretirement benefit plan as a result of an amendment that changed post-65 retiree medical coverage for certain current and future Local 69 retirees effective July 1, 2017. The remeasurement resulted in a decrease in Dominion Energy and Dominion Energy Gas’ accumulated postretirement benefit obligation of $73 million and $61 million, respectively. As a result of regulatory accounting, the remeasurement had an immaterial impact on net income for both Dominion Energy and Dominion Energy Gas. The discount rate used for the remeasurement was 4.30%. All other assumptions used were consistent with the measurement as of December 31, 2016.
Also during the first quarter of 2017, Dominion Energy recorded a $7 million ($4 million after-tax) charge, including $6 million ($4 million after-tax) at Dominion Energy Gas, as a result of additional payments associated with the new collective bargaining agreement, which is reflected in other operations and maintenance expense in their Consolidated Statements of Income.
In the third quarter of 2016, Dominion Energy remeasured an other postretirement benefit plan as a result of an amendment that changed post-65 retiree medical coverage for certain current and future Local 50 retirees effective April 1, 2017. The remeasurement resulted in a decrease in Dominion Energy’s accumulated postretirement benefit obligation of $37 million. The impact of the remeasurement on net periodic benefit credit was recognized prospectively from the remeasurement date and increased the net periodic benefit credit for 2016 by $9 million. The discount rate used for the remeasurement was 3.71% and the demographic and mortality assumptions were updated using plan-specific studies and mortality improvement scales. The expected long-term rate of return used was consistent with the measurement as of December 31, 2015.
Combined Notes to Consolidated Financial Statements, Continued
FUNDED STATUS
The following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):
(1) 2017 amounts relate primarily to a plan amendment that changed post-65 retiree medical coverage for certain current and future Local 69 retirees effective July 1, 2017.
(2) 2017 amount relates primarily to settlement and curtailment as a result of the voluntary and involuntary separation programs at Dominion Energy Questar.
(3) Reflected in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.
The ABO for all of Dominion Energy’s defined benefit pension plans was $7.8 billion and $8.2 billion at December 31, 2018 and 2017, respectively. The ABO for the defined benefit pension plans covering Dominion Energy Gas employees represented by collective bargaining units was $689 million and $724 million at December 31, 2018 and 2017, respectively.
Under its funding policies, Dominion Energy evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion Energy determines the amount of contributions for the current year, if any, at that time. During 2018, Dominion Energy and Dominion Energy Gas made no contributions to the qualified defined benefit pension plans. Dominion Energy expects to make $21 million of the minimum required contributions in 2019, and no contributions are currently expected in 2019 for Dominion Energy Gas.
Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion Energy’s subsidiaries, including Dominion Energy Gas, fund other postretirement benefit costs through VEBAs. Dominion Energy’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion Energy’s contributions to VEBAs, all of which pertained to Dominion Energy Gas employees, totaled $12 million for both 2018 and 2017, and Dominion Energy expects to contribute approximately $12 million to the Dominion Energy VEBAs in 2019, all of which pertains to Dominion Energy Gas employees.
Dominion Energy and Dominion Energy Gas do not expect any pension or other postretirement plan assets to be returned during 2019.
The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):
The following table provides information on the ABO and fair value of plan assets for Dominion Energy’s pension plans with an ABO in excess of plan assets:
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans:
PLAN ASSETS
Dominion Energy’s overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. As a participating employer in various pension plans sponsored by Dominion Energy, Dominion Energy Gas is subject to Dominion Energy’s investment policies for such plans. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for Dominion Energy’s pension funds are 28% U.S. equity, 18% non-U.S. equity, 35% fixed income, 3% real estate and 16% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the U.S. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the U.S. including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity real estate investment trusts and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.
Dominion Energy also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.
Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from
Combined Notes to Consolidated Financial Statements, Continued
the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to fur-
ther reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.
For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.
The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) pension plan assets by asset category are as follows:
(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.
(2) Excludes net assets related to pending sales of securities of $12 million, net accrued income of $21 million, and includes net assets related to pending purchases of securities of $22 million at December 31, 2018. Excludes net assets related to pending sales of securities of $11 million, net accrued income of $19 million, and includes net assets related to pending purchases of securities of $15 million at December 31, 2017.
(3) Excludes net assets related to pending sales of securities of $3 million, net accrued income of $5 million, and includes net assets related to pending purchases of securities of $5 million at December 31, 2018. Excludes net assets related to pending sales of securities of $3 million, net accrued income of $4 million, and includes net assets related to pending purchases of securities of $3 million at December 31, 2017.
The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement plan assets by asset category are as follows:
(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.
(2) Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $2 million at December 31, 2018. Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $1 million at December 31, 2017.
Combined Notes to Consolidated Financial Statements, Continued
The Plan’s investments are determined based on the fair values of the investments and the underlying investments, which have been determined as follows:
•
Cash and Cash Equivalents-Investments are held primarily in short-term notes and treasury bills, which are valued at cost plus accrued interest.
•
Common and Preferred Stocks-Investments are valued at the closing price reported on the active market on which the individual securities are traded.
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Insurance Contracts-Investments in Group Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate debt instruments, state and municipal debt securities.
•
Corporate Debt Instruments-Investments are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar instruments, the instrument is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks or a broker quote, if available.
•
Government Securities-Investments are valued using pricing models maximizing the use of observable inputs for similar securities.
•
Common/Collective Trust Funds-Common/collective trust funds invest in debt and equity securities and other instruments with characteristics similar to those of the funds’ benchmarks. The primary objectives of the funds are to seek investment returns that approximate the overall performance of their benchmark indexes. These benchmarks are major equity indices, fixed income indices, and money market indices that focus on growth, income, and liquidity strategies, as applicable. Investments in common/collective trust funds are stated at the NAV as determined by the issuer of the common/collective trust funds and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. The common/collective trust funds do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the common/collective trust funds have limited withdrawal or redemption rights during the term of the investment.
•
Alternative Investments-Investments in real estate funds, private equity funds, debt funds and hedge funds are stated at fair value based on the NAV of the Plan’s proportionate share of the partnership, joint venture or other alternative investment’s fair value as determined by reference to audited financial statements or NAV statements provided by the investment manager. The NAV is used as a practical expedient to estimate fair value.
NET PERIODIC BENEFIT (CREDIT) COST
The service cost component and non-service cost components of net periodic benefit (credit) cost are reflected in other operations and maintenance expense and other income, respectively, in the Consolidated Statements of Income. The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans are as follows:
(1) Assumptions used to determine net periodic cost for the following year.
(2) The Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the ultimate trend rate much more quickly than previous models.
Combined Notes to Consolidated Financial Statements, Continued
The components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:
(1) As of December 31, 2018, of the $3.5 billion and $(43) million related to pension benefits and other postretirement benefits, $2.0 billion and $(41) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2017, of the $3.2 billion and $(157) million related to pension benefits and other postretirement benefits, $1.9 billion and $(87) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.
(2) As of December 31, 2018, of the $555 million related to pension benefits, $200 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $37 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2017, of the $367 million related to pension benefits, $134 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $24 million related to other postretirement benefits is included entirely in regulatory assets and liabilities.
The following table provides the components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans as of December 31, 2018 that are expected to be amortized as components of net periodic benefit (credit) cost in 2019:
The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions used for Dominion Energy’s pension and other postretirement plans, including those in which Dominion Energy Gas participates, including discount rates, expected long-term rates of return, healthcare cost trend rates and mortality rates.
Dominion Energy determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans, including those in which Dominion Energy Gas participates, by using a combination of:
•
Expected inflation and risk-free interest rate assumptions;
•
Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;
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Expected future risk premiums, asset classes’ volatilities and correlations;
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Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and
•
Investment allocation of plan assets.
Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans, including those in which Dominion Energy Gas participates.
Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion Energy’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion Energy considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate. During 2016, Dominion Energy conducted a new experience study as scheduled and, as a result, updated its mortality assumptions for all its plans, including those in which Dominion Energy Gas participates.
Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion Energy’s retiree healthcare plans, including those in which Dominion Energy Gas participates. A one percentage point change in assumed healthcare cost trend rates would have had the following effects for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement benefit plans:
Dominion Energy Gas (Employees Not Represented by Collective Bargaining Units) and Virginia Power-Participation in Defined Benefit Plans
Virginia Power employees and Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan described above. As participating employers, Virginia Power and Dominion Energy Gas are subject to Dominion Energy’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. During 2018, Virginia Power and Dominion Energy Gas made no con-
tributions to the Dominion Energy Pension Plan, and no contributions to this plan are currently expected in 2019. Virginia Power’s net periodic pension cost related to this plan was $126 million, $110 million and $79 million in 2018, 2017 and 2016, respectively. Dominion Energy Gas’ net periodic pension credit related to this plan was $(38) million, $(37) million and $(45) million in 2018, 2017 and 2016, respectively. Net periodic pension (credit) cost is reflected in other operations and maintenance expense in their respective Consolidated Statements of Income. The funded status of various Dominion Energy subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion Energy subsidiaries. See Note 24 for Virginia Power and Dominion Energy Gas amounts due to/from Dominion Energy related to this plan.
Retiree healthcare and life insurance benefits, for Virginia Power employees and for Dominion Energy Gas employees not represented by collective bargaining units, are covered by the Dominion Energy Retiree Health and Welfare Plan described above. Virginia Power’s net periodic benefit (credit) cost related to this plan was $(51) million, $(42) million and $(29) million in 2018, 2017 and 2016, respectively. Dominion Energy Gas’ net periodic benefit (credit) cost related to this plan was $(7) million, $(5) million and $(4) million for 2018, 2017 and 2016, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expenses in their respective Consolidated Statements of Income. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion Energy subsidiaries. See Note 24 for Virginia Power and Dominion Energy Gas amounts due to/from Dominion Energy related to this plan.
Dominion Energy holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power and Dominion Energy Gas’ employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power and Dominion Energy Gas will provide to Dominion Energy for their shares of employee benefit plan contributions.
Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power and Dominion Energy Gas fund other postretirement benefit costs through VEBAs. During 2018 and 2017, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2019. Dominion Energy Gas made no contributions to the VEBAs for employees not represented by collective bargaining units during 2018 and 2017 and does not expect to contribute in 2019.
Defined Contribution Plans
Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2018, 2017 and 2016, Dominion Energy recognized $51 million, $45 million and $44 million, respectively, as employer matching contributions to these plans. Dominion Energy Gas participates in these employee savings plans, both specific to Dominion
Energy Gas and that cover multiple Dominion Energy subsidiaries. During 2018, 2017 and 2016, Dominion Energy Gas recognized $8 million, $7 million and $7 million, respectively, as employer matching contributions to these plans. Virginia Power also participates in these employee savings plans. During 2018, 2017 and 2016, Virginia Power recognized $20 million, $19 million and $19 million, respectively, as employer matching contributions to these plans.
Organizational Design Initiative
In the first quarter of 2016, the Companies announced an organizational design initiative that reduced their total workforces during 2016. The goal of the organizational design initiative was to streamline leadership structure and push decision making lower while also improving efficiency. For the year ended December 31, 2016, Dominion Energy recorded a $65 million ($40 million after-tax) charge, including $33 million ($20 million after-tax) at Virginia Power and $8 million ($5 million after-tax) at Dominion Energy Gas, primarily reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other costs related to the organizational design initiative. The terms of the severance under the organizational design initiative were consistent with the Companies’ existing severance plans.
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.
Combined Notes to Consolidated Financial Statements, Continued
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
Combined Notes to Consolidated Financial Statements, Continued
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
Combined Notes to Consolidated Financial Statements, Continued
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:
(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.
Combined Notes to Consolidated Financial Statements, Continued
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:
(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:
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:
(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.
NOTE 23. CREDIT RISK
Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.
The Companies maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 2018 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
General
DOMINION ENERGY
As a diversified energy company, Dominion Energy transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic, Midwest and Rocky Mountain and Southeast regions of the U.S. Dominion Energy does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.
Dominion Energy’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion Energy transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of any collateral. At December 31, 2018, Dominion Energy’s credit exposure totaled $145 million. Of this amount, investment grade counterparties, including those internally rated, represented 69%, and no single counterparty, whether investment grade or non-investment grade, exceeded $47 million of exposure.
VIRGINIA POWER
Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2018, Virginia Power’s credit exposure totaled $10 million, of which no amounts were investment grade counterparties, and no single counterparty exceeded $9 million of exposure.
Combined Notes to Consolidated Financial Statements, Continued
DOMINION ENERGY GAS
Dominion Energy Gas transacts mainly with major companies in the energy industry and with residential and commercial energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion Energy Gas does not believe that this geographic concentration contributes to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy Gas is not exposed to a significant concentration of credit risk for receivables arising from gas utility operations. Dominion Energy Gas’ gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2018, Dominion Energy Gas’ credit exposure totaled $8 million. Of this amount, investment grade counterparties, including those internally rated, represented 93%, and no single counterparty, whether investment grade or non-investment grade, exceeded $5 million of exposure.
In 2018, DETI provided service to 307 customers with approximately 96% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 38% of the total storage and transportation revenue and the thirty largest provided approximately 71% of the total storage and transportation revenue.
East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates established by the Ohio Commission. Approximately 99% of East Ohio revenues are derived from its regulated gas distribution services. East Ohio’s bad debt risk is mitigated by the regulatory framework established by the Ohio Commission. See Note 13 for further information about Ohio’s PIPP and UEX Riders that mitigate East Ohio’s overall credit risk.
Credit-Related Contingent Provisions
The majority of Dominion Energy’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion Energy to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 2018 and 2017, Dominion Energy would have been required to post an additional $1 million and $62 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion Energy had posted no collateral at December 31, 2018 and 2017, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 2018 and 2017 was $1 million and $65 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and Dominion Energy Gas were not material
as of December 31, 2018 and 2017. See Note 7 for further information about derivative instruments.
NOTE 24. RELATED-PARTY TRANSACTIONS
Virginia Power and Dominion Energy Gas engage in related party transactions primarily with other Dominion Energy subsidiaries (affiliates). Virginia Power and Dominion Energy Gas’ receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power and Dominion Energy Gas are included in Dominion Energy’s consolidated federal income tax return and, where applicable, combined income tax returns for Dominion Energy are filed in various states. See Note 2 for further information. Dominion Energy’s transactions with equity method investments are described in Note 9. A discussion of significant related party transactions follows.
VIRGINIA POWER
Transactions with Affiliates
Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of forward commodity purchases, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 19 for more information. As of December 31, 2018, Virginia Power’s derivative assets and liabilities with affiliates were $26 million and $10 million, respectively. As of December 31, 2017, Virginia Power’s derivative assets and liabilities with affiliates were $11 million and $5 million, respectively.
Virginia Power participates in certain Dominion Energy benefit plans as described in Note 21. At December 31, 2018 and 2017, Virginia Power’s amounts due to Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $632 million and $505 million, respectively. At December 31, 2018 and 2017, Virginia Power’s amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $254 million and $199 million, respectively.
DES and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage.
The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Virginia Power on the basis of direct and allocated methods in accordance with Virginia Power’s services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES serv-
ice. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.
Presented below are significant transactions with DES and other affiliates:
(1) Includes capitalized expenditures of $145 million, $144 million and $144 million for the year ended December 31, 2018, 2017 and 2016, respectively.
Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $224 million and $33 million in short-term demand note borrowings from Dominion Energy as of December 31, 2018 and 2017, respectively. The weighted-average interest rate of these borrowings was 2.94% and 1.65% at December 31, 2018 and 2017, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 2018 and 2017. Interest charges related to Virginia Power’s borrowings from Dominion Energy were immaterial for the years ended December 31, 2018, 2017 and 2016.
There were no issuances of Virginia Power’s common stock to Dominion Energy in 2018, 2017 or 2016.
DOMINION ENERGY GAS
Transactions with Related Parties
Dominion Energy Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Energy Gas provides transportation and storage services to affiliates. Dominion Energy Gas also enters into certain other contracts with affiliates, and related parties, including construction services, which are presented separately from contracts involving commodities or services. As of December 31, 2018 and 2017, all of Dominion Energy Gas’ commodity derivatives were with affiliates. See Notes 7 and 19 for more information. See Note 9 for information regarding transactions with an affiliate.
Dominion Energy Gas participates in certain Dominion Energy benefit plans as described in Note 21. At December 31, 2018 and 2017, Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $772 million and $734 million, respectively. Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $14 million and $7 million at December 31, 2018 and 2017, respectively.
DES and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Energy Gas. Dominion Energy Gas provides certain services to related parties, including technical services.
The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Dominion Energy Gas on the basis of direct and allocated methods in accordance with Dominion Energy Gas’ services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. The costs of these services follow:
(1) Includes capitalized expenditures of $37 million, $45 million and $49 million for the year ended December 31, 2018, 2017 and 2016, respectively.
(2) Amounts primarily attributable to Atlantic Coast Pipeline, a related party VIE.
The following table presents affiliated and related party balances reflected in Dominion Energy Gas’ Consolidated Balance Sheets:
(1) Represents amounts due from Atlantic Coast Pipeline, a related party VIE.
(2) Amounts are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.
(3) Amounts are presented in other deferred charges and other assets in Dominion Energy Gas’ Consolidated Balance Sheets.
Dominion Energy Gas’ borrowings under the IRCA with Dominion Energy totaled $218 million and $18 million as of December 31, 2018 and 2017, respectively. The weighted-average interest rate of these borrowings was 2.78% and 1.60% at December 31, 2018 and 2017, respectively. Interest charges related to Dominion Energy Gas’ total borrowings from Dominion Energy were immaterial for 2018, 2017 and 2016.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 25. OPERATING SEGMENTS
The Companies are organized primarily on the basis of products and services sold in the U.S. A description of the operations included in the Companies’ primary operating segments is as follows:
(1) Includes remaining producer services activities.
In addition to the operating segments above, the Companies also report a Corporate and Other segment.
DOMINION ENERGY
The Corporate and Other Segment of Dominion Energy includes its corporate, service company and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.
In 2018, Dominion Energy reported after-tax net expenses of $608 million in the Corporate and Other segment, with $88 million of the net expenses attributable to specific items related to its operating segments.
The net expenses for specific items in 2018 primarily related to the impact of the following items:
•
A $219 million ($164 million after-tax) charge related to the impairment of certain gathering and processing assets attributable to Gas Infrastructure;
•
A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers, attributable to:
•
Power Generation ($109 million after-tax); and
•
Power Delivery ($51 million after-tax);
•
A $170 million ($134 million after-tax) net loss related to our investments in nuclear decommissioning trust funds attributable to Power Generation;
•
A $124 million ($88 million after-tax) charge for disallowance of FERC-regulated plant attributable to Gas Infrastructure;
•
An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Power Generation; and
•
A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Power Delivery; partially offset by
•
An $828 million ($619 million after-tax) benefit associated with the sale of certain merchant generation facilities and equity method investments attributable to:
•
Power Generation ($229 million after-tax); and
•
Gas Infrastructure ($390 million after-tax).
In 2017, Dominion Energy reported after-tax net benefits of $389 million in the Corporate and Other segment, with $861 million of the net benefits attributable to specific items related to its operating segments.
The net benefits for specific items in 2017 primarily related to the impact of the following items:
•
A $979 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, primarily attributable to:
•
Gas Infrastructure ($324 million);
•
Power Generation ($655 million); partially offset by
•
$158 million ($96 million after-tax) of charges associated with equity method investments in wind-powered generation facilities, attributable to Power Generation.
In 2016, Dominion Energy reported after-tax net expenses of $484 million in the Corporate and Other segment, with $180 million of these net expenses attributable to specific items related to its operating segments.
The net expenses for specific items in 2016 primarily related to the impact of the following items:
•
A $197 million ($122 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation; and
•
A $59 million ($36 million after-tax) charge related to an organizational design initiative, attributable to:
•
Power Delivery ($5 million after-tax);
•
Gas Infrastructure ($12 million after-tax); and
•
Power Generation ($19 million after-tax).
The following table presents segment information pertaining to Dominion Energy’s operations:
Intersegment sales and transfers for Dominion Energy are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation.
VIRGINIA POWER
The majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s Power Delivery and Power Generation segments.
The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.
In 2018, Virginia Power reported an after-tax net expense of $312 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2018 primarily related to the impact of the following items:
•
A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers, attributable to:
•
Power Generation ($109 million after-tax); and
•
Power Delivery ($51 million after-tax).
•
An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Power Generation.
•
A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Power Delivery.
Combined Notes to Consolidated Financial Statements, Continued
In 2017, Virginia Power reported an after-tax net benefit of $74 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net benefit for specific items in 2017 primarily related to the impact of the following item:
•
A $93 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, attributable to Power Generation.
In 2016, Virginia Power reported after-tax net expenses of $173 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2016 primarily related to the impact of the following item:
•
A $197 million ($121 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation.
The following table presents segment information pertaining to Virginia Power’s operations:
DOMINION ENERGY GAS
The Corporate and Other Segment of Dominion Energy Gas primarily includes specific items attributable to Dominion Energy Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources and the effect of certain items recorded at Dominion Energy Gas as a result of Dominion Energy’s basis in the net assets contributed.
In 2018, Dominion Energy Gas reported after-tax net expenses of $251 million in its Corporate and Other segment, with $244 million of these net expenses attributable to its operating segment.
The net expenses for specific items in 2018 primarily related to the impact of the following items:
•
A $219 million ($165 million after-tax) charge related to the impairment of gathering and processing assets; and
•
A $124 million ($88 million after-tax) charge for disallowance of FERC-regulated plant.
In 2017, Dominion Energy Gas reported after-tax net benefit of $179 million in its Corporate and Other segment, with $174 million of these net expenses attributable to its operating segment.
The net benefit for specific items in 2017 primarily related to the impact of the following item:
•
A $185 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.
In 2016, Dominion Energy Gas reported after-tax net expenses of $3 million in its Corporate and Other segment, with $7 million of these net expenses attributable to its operating segment.
The net expense for specific items in 2016 primarily related to the impact of the following item:
•
An $8 million ($5 million after-tax) charge related to an organizational design initiative.
Combined Notes to Consolidated Financial Statements, Continued
The following table presents segment information pertaining to Dominion Energy Gas’ operations:
NOTE 26. QUARTERLY FINANCIAL DATA (UNAUDITED)
A summary of the Companies’ quarterly results of operations for the years ended December 31, 2018 and 2017 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.
DOMINION ENERGY
Dominion Energy’s 2018 results include the impact of the following significant items:
•
Fourth quarter results include $536 million of after-tax gains from the sale of certain merchant generation facilities and equity method investments partially offset by a $164 million after-tax impairment charge for certain gathering and processing assets.
•
Second quarter results include an $89 million after-tax charge for disallowance of FERC-regulated plant.
•
First quarter results include a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.
Dominion Energy’s 2017 results include the impact of the following significant item:
•
Fourth quarter results include $851 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, partially offset by $96 million of after-tax charges associated with our equity method investments in wind-powered generation facilities.
VIRGINIA POWER
Virginia Power’s quarterly results of operations were as follows:
Virginia Power’s 2018 results include the impact of the following significant item:
•
First quarter results include a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.
Virginia Power’s 2017 results include the impact of the following significant item:
•
Fourth quarter results include a $93 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.
DOMINION ENERGY GAS
Dominion Energy Gas’ quarterly results of operations were as follows:
Dominion Energy Gas’s 2018 results include the impact of the following significant items:
•
Fourth quarter results include a $165 million after-tax impairment charge for certain gathering and processing assets.
•
Second quarter results include an $89 million after-tax charge for disallowance of FERC-regulated plant.
Dominion Energy Gas’s 2017 results include the impact of the following significant item:
•
Fourth quarter results include a $197 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
DOMINION ENERGY
Senior management, including Dominion Energy’s CEO and CFO, evaluated the effectiveness of Dominion Energy’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion Energy’s CEO and CFO have concluded that Dominion Energy’s disclosure controls and procedures are effective. There were no changes in Dominion Energy’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion Energy’s internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Dominion Energy understands and accepts responsibility for Dominion Energy’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion Energy continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion Energy does throughout all aspects of its business.
Dominion Energy maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.
The Audit Committee of the Board of Directors of Dominion Energy, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion Energy and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Audit Committee at any time.
SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion Energy’s 2018 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion Energy tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2018, Dominion Energy makes the following assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion Energy.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Dominion Energy’s internal control over financial reporting as of December 31, 2018. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion Energy maintained effective internal control over financial reporting as of December 31, 2018.
Dominion Energy’s independent registered public accounting firm is engaged to express an opinion on Dominion Energy’s internal control over financial reporting, as stated in their report which is included herein.
February 28, 2019
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Dominion Energy, Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Dominion Energy, Inc. and subsidiaries (“Dominion Energy”) at December 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, Dominion Energy maintained, in all material respects, effective internal control over financial reporting at December 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements at and for the year ended December 31, 2018, of Dominion Energy and our report dated February 28, 2019, expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
Dominion Energy’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion Energy’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Dominion Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 28, 2019
VIRGINIA POWER
Senior management, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes in Virginia Power’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Power’s internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Virginia Power understands and accepts responsibility for Virginia Power’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Virginia Power continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.
Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.
The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.
SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s 2018 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2018, Virginia Power makes the following assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Virginia Power’s internal control over financial reporting as of December 31, 2018. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2018.
This annual report does not include an attestation report of Virginia Power’s registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.
February 28, 2019
DOMINION ENERGY GAS
Senior management, including Dominion Energy Gas’ CEO and CFO, evaluated the effectiveness of Dominion Energy Gas’ disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion Energy Gas’ CEO and CFO have concluded that Dominion Energy Gas’ disclosure controls and procedures are effective. There were no changes in Dominion Energy Gas’ internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion Energy Gas’ internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Dominion Energy Gas understands and accepts responsibility for Dominion Energy Gas’ financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion Energy Gas continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.
Dominion Energy Gas maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.
The Board of Directors also serves as Dominion Energy Gas’ Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Dominion Energy Gas’ auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.
SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Dominion Energy Gas’ 2018 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Dominion Energy Gas tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2018, Dominion Energy Gas makes the following assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion Energy Gas.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Dominion Energy Gas’ internal control over financial reporting as of December 31, 2018. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion Energy Gas maintained effective internal control over financial reporting as of December 31, 2018.
This annual report does not include an attestation report of Dominion Energy Gas’ registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Dominion Energy Gas’ independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.
February 28, 2019
Item 9B.
Item 9B. Other Information
None.
Part III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
DOMINION ENERGY
The following information for Dominion Energy is incorporated by reference from the Dominion Energy 2019 Proxy Statement, which will be filed on or around March 22, 2019:
•
Information regarding the directors required by this item is found under the heading Election of Directors.
•
Information regarding compliance with Section 16 of the Securities Exchange Act of 1934, as amended, required by this item is found under the heading Section 16(a) Beneficial Ownership Reporting Compliance.
•
Information regarding the Dominion Energy Audit Committee Financial expert(s) required by this item is found under the heading The Committees of the Board-Audit Committee.
•
Information regarding the Dominion Energy Audit Committee required by this item is found under the headings The Committees of the Board-Audit Committee and Audit Committee Report.
•
Information regarding Dominion Energy’s Code of Ethics and Business Conduct required by this item is found under the heading Other Information-Code of Ethics and Business Conduct.
The information concerning the executive officers of Dominion Energy required by this item is included in Part I of this Form 10-K under the caption Executive Officers of Dominion Energy. Each executive officer of Dominion Energy is elected annually.
Item 11.
Item 11. Executive Compensation
DOMINION ENERGY
The following information about Dominion Energy is contained in the 2019 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the headings Compensation Discussion and Analysis and Executive Compensation Tables; the information regarding Compensation Committee interlocks contained under the heading Compensation Committee Interlocks and Insider Participation; the information regarding the Compensation Committee review and discussions of Compensation Discussion and Analysis contained under the heading Compensation, Governance and Nominating Committee Report; and the information regarding director compensation contained under the heading Compensation of Non-Employee Directors.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
DOMINION ENERGY
The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the heading Securities Ownership in the 2019 Proxy Statement is incorporated by reference.
The information regarding equity securities of Dominion Energy that are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation Tables-Equity Compensation Plans in the 2019 Proxy Statement is incorporated by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
DOMINION ENERGY
The information regarding related party transactions required by this item found under the heading Other Information-Certain Relationships and Related Party Transactions, and information regarding director independence found under the heading Corporate Governance-Director Independence, in the 2019 Proxy Statement is incorporated by reference.
Item 14.
Item 14. Principal Accountant Fees and Services
DOMINION ENERGY
The information concerning principal accountant fees and services contained under the heading Auditor Fees and Pre-Approval Policy in the 2019 Proxy Statement is incorporated by reference.
VIRGINIA POWER AND DOMINION ENERGY GAS
The following table presents fees paid to Deloitte & Touche LLP for services related to Virginia Power and Dominion Energy Gas for the fiscal years ended December 31, 2018 and 2017.
Audit fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power and Dominion Energy Gas’ annual consolidated financial statements, the review of financial statements included in Virginia Power and Dominion Energy Gas’ quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC.
Audit-related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Virginia Power and Dominion Energy Gas’ consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and attest services not required by statute or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.
Virginia Power and Dominion Energy Gas’ Boards of Directors have adopted the Dominion Energy Audit Committee pre-approval policy for their independent auditor’s services and fees and have delegated the execution of this policy to the Dominion Energy Audit Committee. In accordance with this delegation, each year the Dominion Energy Audit Committee pre-approves a schedule that details the services to be provided for the following year and an estimated charge for such services. At its February 2019 meeting, the Dominion Energy Audit Committee approved schedules of services and fees for 2019 inclusive of Virginia Power and Dominion Energy Gas. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Energy Audit Committee or a delegated member of the Dominion Energy Audit Committee.
Part IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.
1. Financial Statements
See Index on page 69.
2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.
3. Exhibits (incorporated by reference unless otherwise noted)
Exhibit
Number
Description
Dominion
Energy
Virginia
Power
Dominion
Energy
Gas
Audited Consolidated Financial Statements and Schedule of SCANA Corporation at December 31, 2018 and 2017 and for the three years ended December 31, 2018, together with the related notes to the financial statements (incorporated by reference from Item 8. Financial Statements and Supplementary Data for SCANA Corporation, SCANA Corporation Annual Report on Form 10-K for the fiscal year ended December 31, 2018, filed February 28, 2019, File No. 1-8809). SCANA Corporation’s Annual Report is included in a combined filing with the Annual Report of South Carolina Electric & Gas Company; information related to such affiliated entity is not considered to be a component of the Audited Financial Statements of SCANA Corporation.
X
The following financial statements from Dominion Energy, Inc., Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC Annual Report on Form 10-K for the year ended December 31, 2018, filed on February 28, 2019, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.
X
X
X
* Indicates management contract or compensatory plan or arrangement.
Item 16. Form 10-K Summary
None.
Signatures
Dominion Energy
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DOMINION ENERGY, INC.
By:
/s/ Thomas F. Farrell, II
(Thomas F. Farrell, II, Chairman, President and
Chief Executive Officer)
Date: February 28, 2019
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2019.
Signature
Title
/s/ Thomas F. Farrell, II
Thomas F. Farrell, II
Chairman of the Board of Directors, President and Chief
Executive Officer
/s/ James A. Bennett
James A. Bennett
Director
/s/ Helen E. Dragas
Helen E. Dragas
Director
/s/ James O. Ellis, Jr.
James O. Ellis, Jr.
Director
/s/ D. Maybank Hagood
D. Maybank Hagood
Director
/s/ John W. Harris
John W. Harris
Director
/s/ Ronald W. Jibson
Ronald W. Jibson
Director
/s/ Mark J. Kington
Mark J. Kington
Director
/s/ Joseph M. Rigby
Joseph M. Rigby
Director
/s/ Pamela J. Royal
Pamela J. Royal
Director
/s/ Robert H. Spilman, Jr.
Robert H. Spilman, Jr.
Director
/s/ Susan N. Story
Susan N. Story
Director
/s/ Michael E. Szymanczyk
Michael E. Szymanczyk
Director
/s/ James R. Chapman
James R. Chapman
Executive Vice President, Chief Financial Officer and Treasurer
/s/ Michele L. Cardiff
Michele L. Cardiff
Vice President, Controller and Chief Accounting Officer
Virginia Power
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VIRGINIA ELECTRIC AND POWER COMPANY
By:
/s/ Thomas F. Farrell, II
(Thomas F. Farrell, II, Chairman of the Board
of Directors and Chief Executive Officer)
Date: February 28, 2019
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2019.
Signature
Title
/s/ Thomas F. Farrell, II
Thomas F. Farrell, II
Chairman of the Board of Directors and Chief Executive Officer
/s/ Robert M. Blue
Robert M. Blue
Director
/s/ Carlos M. Brown
Carlos M. Brown
Director
/s/ James R. Chapman
James R. Chapman
Executive Vice President, Chief Financial Officer and Treasurer
/s/ Michele L. Cardiff
Michele L. Cardiff
Vice President, Controller and Chief Accounting Officer
Dominion Energy Gas
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DOMINION ENERGY GAS HOLDINGS, LLC
By:
/s/ Thomas F. Farrell, II
(Thomas F. Farrell, II, Chairman of the Board
of Directors and Chief Executive Officer)
Date: February 28, 2019
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2019.
Signature
Title
/s/ Thomas F. Farrell, II
Thomas F. Farrell, II
Chairman of the Board of Directors and Chief Executive Officer
/s/ Carlos M. Brown
Carlos M. Brown
Director
/s/ James R. Chapman
James R. Chapman
Director, Executive Vice President, Chief Financial Officer and Treasurer
/s/ Michele L. Cardiff
Michele L. Cardiff
Vice President, Controller and Chief Accounting Officer