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 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, 2017, Dominion Energy’s portfolio of assets includes approximately 26,000 MW of generating capacity, 6,600 miles of electric transmission lines, 57,900 miles of electric distribution lines, 14,800 miles of natural gas transmission, gathering and storage pipelines and 51,800 miles of gas distribution pipeline, exclusive of service lines. As of December 31, 2017, Dominion Energy serves nearly 6 million utility and retail energy customers and operates one of the nation’s largest underground natural gas storage systems, with approximately 1 trillion cubic feet of storage capacity.
In September 2016, Dominion Energy completed the Dominion Energy Questar Combination for total consideration of $4.4 billion and Dominion Energy Questar, a Rockies-based integrated natural gas company, became a wholly-owned subsidiary of Dominion Energy. Questar Gas, a wholly-owned subsidiary of Dominion Energy Questar, is consolidated by Dominion Energy, and is a voluntary SEC filer. However, its Form 10-K is filed separately and is not combined herein.
In March 2014, Dominion Energy formed Dominion Energy Midstream, an MLP designed to grow a portfolio of natural gas terminaling, processing, storage, transportation and related assets. In October 2014, Dominion Energy Midstream launched its initial public offering and issued 20,125,000 common units representing limited partner interests. Dominion Energy has and may continue to investigate opportunities to acquire assets that meet its strategic objective for Dominion Energy Midstream. At December 31, 2017, Dominion Energy owns the general partner, 50.6% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owns 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. Dominion Energy Midstream is consolidated by Dominion Energy, and is an SEC registrant. However, its Form 10-K is filed separately and is not combined herein.
Dominion Energy is focused on expanding its investment in regulated electric generation, transmission and distribution and regulated natural gas transmission and distribution infrastructure. Dominion Energy expects approximately 90% of earnings from its primary operating segments to come from regulated and long-term contracted businesses.
Dominion Energy continues to expand and improve its regulated and long-term contracted electric and natural gas businesses, in accordance with its existing five-year capital investment program. A major impetus for this program is to meet the anticipated increase in demand in its electric utility service territory. 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, to upgrade Dominion Energy’s gas and electric transmission and distribution networks, and to meet environmental requirements
and standards set by various regulatory bodies. Investments in utility-scale solar generation are expected to be a focus in meeting such environmental requirements, particularly in Virginia. In September 2014, Dominion Energy 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, to increase natural gas supplies in the region.
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 Dominion Energy Questar Combination, and in infrastructure whose output is sold under long-term purchase agreements as well as the sale of the electric retail energy marketing business in March 2014. 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 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. In May 2016,
Dominion Energy Gas sold 0.65% of the noncontrolling partnership interest in Iroquois, a FERC-regulated interstate natural gas pipeline in New York and Connecticut, to TransCanada. At December 31, 2017, Dominion Energy Gas holds a 24.07% noncontrolling partnership interest in Iroquois. 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
At December 31, 2017, Dominion Energy had approximately 16,200 full-time employees, of which approximately 5,200 are subject to collective bargaining agreements. At December 31, 2017, Virginia Power had approximately 6,900 full-time employees, of which approximately 3,100 are subject to collective bargaining agreements. At December 31, 2017, Dominion Energy Gas had approximately 3,000 full-time employees, 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. You may also read and copy any document they file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.
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 internet 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 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.
PROPOSED ACQUISITION OF SCANA
Under the terms of the SCANA Merger Agreement announced in January 2018, Dominion Energy has agreed to issue 0.6690 shares of Dominion Energy common stock for each share of SCANA common stock upon closing. In addition, Dominion Energy will provide the financial support for SCE&G to make a $1.3 billion up-front, one-time rate credit to all current electric service customers of SCE&G to be paid within 90 days of closing and a $575 million refund along with the benefit of the 2017 Tax Reform Act resulting in at least a 5% reduction to SCE&G
electric service customers’ bills over an estimated eight-year period as well as the exclusions from rate recovery of approximately $1.7 billion of costs related to the V.C. Summer Units 2 and 3 new nuclear development project and approximately $180 million to purchase the Columbia Energy Center power station. Subject to receipt of SCANA shareholder and any required regulatory approvals and meeting closing conditions, Dominion Energy targets closing by the end of 2018. See Note 3 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. In December 2016, Dominion Energy contributed Dominion Energy Questar Pipeline to Dominion Energy Midstream. 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 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The projects are expected to close in 2018 and 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. Pursuant to the agreement, upon the first closing in December 2017,
Dominion Energy entered into a commission agreement 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. 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. See Note 3 to the Consolidated Financial Statements for additional information.
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. In April 2015, Dominion Energy contributed DECG to Dominion Energy Midstream. See Note 3 to the Consolidated Financial Statements for additional information.
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 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 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 the natural gas producer closed on 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 will receive total consideration of $130 million, with $65 million received in November 2017 and $65 million to be received by the end of the third quarter of 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 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. The sale of the electric retail energy marketing business did not qualify for discontinued operations classification.
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.
In September 2013, DETI sold Line TL-388 to Blue Racer for $75 million in cash proceeds.
SALE OF BRAYTON POINT, KINCAID AND EQUITY METHOD INVESTMENT IN ELWOOD
In August 2013, Dominion Energy completed the sale of Brayton Point, Kincaid and its equity method investment in Elwood to Energy Capital Partners and received proceeds of $465 million, net of transaction costs. The historical results of Brayton Point’s and Kincaid’s operations are presented in discontinued operations.
OPERATING SEGMENTS
Dominion Energy manages 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 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.
For additional financial information on operating segments, including revenues from external customers, see Note 25 to the Consolidated Financial Statements. For additional information on operating revenue related to the Companies’ principal products and services, see Notes 2 and 4 to the Consolidated Financial Statements, which information is incorporated herein by reference.
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 existing five-year investment plan includes spending approximately $8.5 billion from 2018 through 2022 to upgrade or add new transmission 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. In addition, data centers continue to contribute to anticipated demand growth.
Revenue provided by 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. 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 117 minutes at the end of 2017, down from the three-year average of 123 minutes. Virginia Power’s overall customer satisfaction improved year over year when compared to 2016 J.D.
Power and Associates’ scoring. In the future, safety, electric service reliability, outage durations and customer service will remain key focus areas for electric distribution. Modernizing the electric grid will become a key focus area to support the enhancement of the customer service experience, build upon improvements in resiliency and security and support enhanced innovation and renewable generation.
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, a 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
Power Delivery Operating Segment- Dominion Energy and Virginia Power
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 now 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
Power Delivery Operating Segment-Dominion Energy and Virginia Power
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
Power Delivery Operating Segment-Dominion Energy and Virginia Power
Virginia Power has approximately 6,600 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.
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 ($325 million);
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Mt. Storm-to-Dooms ($240 million);
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Idylwood substation ($110 million);
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Dooms-to-Lexington ($130 million);
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Cunningham-to-Elmont ($110 million);
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Landstown voltage regulation ($70 million);
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Warrenton (including Remington CT-to-Warrenton, Vint Hill-to-Wheeler-to-Gainesville, and Vint Hill and Wheeler switching stations) ($110 million);
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Remington/Gordonsville/Pratts Area Improvement (including Remington-to-Gordonsville, and new Gordonsville substation transformer) ($110 million);
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Gainesville-to-Haymarket ($55 million);
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Kings Dominion-to-Fredericksburg ($50 million);
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Loudoun-Brambleton line-to-Poland Road Substation ($60 million);
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Cunningham-to-Dooms ($60 million);
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Carson-to-Rogers Road ($55 million);
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Dooms-Valley rebuild ($65 million);
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Mt. Storm-Valley rebuild ($225 million);
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Glebe-to-Station ($320 million);
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Idylwood-to-Tysons ($125 million);
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Chesterfield-to-Lakeside ($35 million); and
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Landstown-to-Thrasher ($25 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 $85 million.
Virginia Power plans to increase transmission substation physical security and expects to invest $250 million-$300 million through 2022 to strengthen its electrical system to better protect critical equipment, enhance its spare equipment process and create multiple levels of security.
In addition, Virginia Power’s electric distribution network includes approximately 57,900 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.
Virginia legislation in 2014 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 over the next decade. In August 2016, the Virginia Commission approved the first phase of the program encompassing approximately 400 miles of converted lines and $140 million in capital spending (with approximately $123 million recoverable through Rider U). In September 2017, the Virginia Commission approved recovery through Rider U of a total capital investment of $40 million for second phase conversions.
SOURCES OF ENERGY SUPPLY
Power Delivery Operating Segment-Dominion Energy and Virginia Power
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 Operating Segment-Dominion Energy and Virginia Power
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. 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. 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 existing five-year investment plan includes spending approximately $8.3 billion from 2018 through 2022 to construct new generation capacity and extend the life of nuclear generation facilities to meet growing electricity demand within its service territory and maintain reliability. The most significant project currently under construction is Greensville County, which is estimated to cost approximately $1.3 billion, excluding financing costs. See Properties and Environmental Strategy for additional information on this and other utility projects.
In addition, Dominion Energy’s merchant fleet includes numerous renewable generation facilities, which include a fuel cell generation facility in Connecticut and solar generation facilities in operation or development in nine 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 82% 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 fleet relates to changes in market-based prices received for electricity and capacity. Market-based prices for electricity are largely dependent on commodity prices, primarily natural gas, and the demand for electricity, which is primarily dependent upon weather. 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 fleet by hedging a substantial portion of its expected near-term energy sales with derivative instruments. Variability also results from changes in the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages. Variability in earnings provided by Dominion Energy’s renewable merchant fleet is primarily driven by weather.
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.
Power Generation Operating Segment-Dominion Energy
Power Generation’s recently acquired and developed 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 nonrenewable 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 nonrenewable 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. They are expected to issue a request for proposals by May 1, 2018. Millstone will participate in the state sponsored procurement. If successful in the competitive bid process, Millstone would receive a long-term power purchase agreement for between three and ten years.
REGULATION
Power Generation Operating Segment-Dominion Energy and Virginia Power
Virginia Power’s utility generation fleet and Dominion Energy’s merchant 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’s and Virginia Power’s existing generation facilities, see Item 2. Properties.
Power Generation Operating Segment-Dominion Energy and Virginia Power
The generation capacity of Virginia Power’s electric utility fleet totals approximately 20,800 MW. The generation mix is diversified and includes gas, coal, nuclear, oil, renewables, biomass and power purchase agreements. Virginia Power’s generation facilities are located in Virginia, West Virginia and North Carolina and serve load in Virginia and northeastern North Carolina.
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 Note 13 to the Consolidated Financial Statements for more information on this project.
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Virginia Power is considering the construction of a hydroelectric pumped storage facility in Southwest Virginia.
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In March 2016, the Virginia Commission authorized the construction of Greensville County and related transmission interconnection facilities. Commercial operations are expected to commence in late 2018, at an estimated cost of approximately $1.3 billion, excluding financing costs.
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In June 2017, Virginia Power signed an agreement 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 installed by the end of 2020.
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In October 2017, Virginia Power received a permit by rule from the VDEQ to construct and operate the Hollyfield solar facility, a 17 MW solar facility in King William County, Virginia and related distribution interconnection facilities. The total estimated cost of the Hollyfield solar facility is approximately $33 million, excluding financing costs. The facility is the subject of a public-private partnership whereby the University of Virginia, an agency of the Commonwealth of Virginia and a non-jurisdictional customer, will compensate Virginia Power for the facility’s net electrical energy output.
Power Generation Operating Segment-Dominion Energy
The generation capacity of Dominion Energy’s merchant fleet totals approximately 5,100 MW. The generation mix is diversified and includes nuclear, natural gas and renewables. Merchant nonrenewable generation facilities are located in Connecticut, Pennsylvania and Rhode Island, with a majority of that capacity concentrated in New England. Dominion Energy’s merchant renewable generation facilities include a fuel cell generation facility in Connecticut, solar generation facilities in California, Connecticut, Georgia, Indiana, North Carolina, South Carolina, Tennessee, Utah and Virginia, and wind generation facilities in Indiana and West Virginia.
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 agreements with other suppliers to provide for utility system load requirements.
Power Generation also occasionally purchases electricity from the PJM and ISO-NE spot markets 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 announced its intention to apply for operating life extensions for Surry and North Anna.
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 2013.
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’s and Virginia Power’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Dominion Energy’s 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, 2017, the minority owners held $42 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 LNG operations, Dominion Energy Questar operations, Hope’s gas distribution operations in West Virginia, and nonregulated retail natural gas marketing, as well as Dominion Energy’s investments in the Blue Racer joint venture, Atlantic Coast Pipeline and Dominion Energy Midstream. See Properties and Investments below for additional information regarding the Blue Racer and Atlantic Coast Pipeline investments. Dominion Energy’s LNG operations involve the import and storage of LNG at Cove Point and the transportation of regasified LNG to the interstate pipeline grid and mid-Atlantic and Northeast markets. Dominion Energy has received DOE and FERC approval to export LNG from Cove Point and, once the Liquefaction Project commences commercial operations, will be able to import LNG and regasify it as natural gas and liquefy natural gas and export it as LNG. See Note 22 to the Consolidated Financial Statements for more information.
In September 2016, Dominion Energy completed the Dominion Energy Questar Combination and Dominion Energy Questar, a Rockies-based integrated natural gas company, became a wholly-owned subsidiary of Dominion Energy. Dominion Energy Questar included Questar Gas, Wexpro and Dominion Energy Questar Pipeline at closing. Questar Gas’ regulated gas distribution operations in Utah, southwestern Wyoming and southeastern Idaho includes 29,600 miles of gas distribution pipeline. 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 through 2,200 miles of gas transmission pipeline and 56 bcf of working gas storage. See Acquisitions and Dispositions above and Note 3 to the Consolidated Financial Statements for a description of the Dominion Energy Questar Combination.
In 2014, Dominion Energy formed Dominion Energy Midstream, an MLP initially consisting of a preferred equity interest in Cove Point. See General above for more information. Also see Acquisitions and Dispositions above and Note 3 to the Consolidated Financial Statements for a description of Dominion Energy’s contribution of Dominion Energy Questar Pipeline to
Dominion Energy Midstream in December 2016 as well as Dominion Energy’s acquisition of DECG, which Dominion Energy contributed to Dominion Energy Midstream in April 2015, and Dominion Energy Midstream’s acquisition of a 25.93% noncontrolling partnership interest in Iroquois in September 2015. DECG provides FERC-regulated interstate natural gas transportation services in South Carolina and southeastern Georgia through 1,500 miles of gas transmission pipeline.
Gas Infrastructure’s existing five-year investment plan includes spending approximately $8.3 billion from 2018 through 2022 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 91% of DETI’s transmission capacity is subscribed including 86% under long-term contracts (two years or greater) and 5% 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 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. Dominion Energy Questar Pipeline’s 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, 2017, approximately 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.
Dominion Energy Questar Pipeline’s 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. In March 2014, Dominion Energy completed the sale of its electric retail energy marketing business. In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations. The sale is expected to be completed by the end of 2018. The remaining retail natural gas business consists of approximately 350,000 customer accounts in five states. The heaviest concentration of customers in these markets are 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, Dominion Energy Questar Pipeline’s, 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 AND INVESTMENTS
For a description of Dominion Energy’s 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 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 Tennessee Gas Pipeline Company, L.L.C. 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 September 2014, DETI announced its intent to construct and operate the Supply Header project which is estimated to cost between $550 million and $600 million to construct, excluding financing costs, and provide 1,500,000 Dths per day of firm transportation service to various customers. In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header project. In October 2017, DETI received FERC authorization to construct and operate the project facilities, with the facilities expected to be in service in late 2019.
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 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 permitted 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 2017, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2016 costs. The filing reflects gross plan investment for 2016 of $188 million, cumulative gross plant investment of $1.2 billion and a revenue requirement of $157 million.
Gas Infrastructure Operating Segment-Dominion Energy
Dominion Energy has the following significant projects under construction or development.
Cove Point-Dominion Energy expects the Liquefaction Project to commence commercial operations in March 2018, which will enable the Cove Point facility to liquefy domestically-produced natural gas and export it as LNG. The DOE previously authorized Dominion Energy to export LNG to countries with free trade agreements. In September 2013, the DOE authorized
Dominion Energy to export LNG from Cove Point to non-free trade agreement countries.
In September 2014, Cove Point received the FERC order authorizing the Liquefaction Project with certain conditions. The conditions regarding the Liquefaction Project set forth in the FERC order largely incorporate the mitigation measures proposed in the environmental assessment. In October 2014, Cove Point commenced construction of the Liquefaction Project, with an in-service date anticipated in March 2018 at a total estimated cost of approximately $4.1 billion, excluding financing costs. The Cove Point facility is authorized to export at a rate of 770 million cubic feet of natural gas per day for a period of 20 years.
In April 2013, Dominion Energy announced it had fully subscribed the capacity of the project with 20-year terminal service agreements. ST Cove Point, LLC, a joint venture of Sumitomo Corporation, a Japanese corporation that is one of the world’s leading trading companies, and Tokyo Gas Co., Ltd., a Japanese corporation that is the largest natural gas utility in Japan, and GAIL Global (USA) LNG LLC, a wholly-owned indirect U.S. subsidiary of GAIL (India) Ltd., have each contracted for half of the capacity. Following completion of the front-end engineering and design work, Dominion Energy also announced it had awarded its engineering, procurement and construction contract for new liquefaction facilities to IHI/Kiewit Cove Point, a joint venture between IHI E&C International Corporation and Kiewit Energy Company.
Cove Point has historically operated as an LNG import facility under various long-term import contracts. Since 2010, Dominion Energy has renegotiated certain existing LNG import contracts in a manner that will result in a significant reduction in pipeline and storage capacity utilization and associated anticipated revenues during the period from 2017 through 2028. Such amendments created the opportunity for Dominion Energy to explore the Liquefaction Project, which, will extend the economic life of Cove Point and contribute to Dominion Energy’s overall growth plan. In total, these renegotiations reduced Cove Point’s expected annual revenues from the import-related contracts by approximately $150 million from 2017 through 2028, partially offset by approximately $50 million of additional revenues in the years 2013 through 2017.
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 early 2019.
DECG-In 2014, DECG executed binding precedent agreements with three customers for the Charleston project. The project is expected to cost approximately $125 million, and provide 80,000 Dths per day of firm transportation service from an existing interconnect with Transcontinental Gas Pipe, LLC in Spartanburg County, South Carolina to customers in Dillon, Marlboro, Sumter, Charleston, Lexington and Remington counties, South Carolina. In February 2017, DECG received FERC approval to construct and operate the project facilities, which are expected to be placed into service in March 2018.
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 2017 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.
Gas Infrastructure Equity Method Investments-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.
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. 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, with development and construction costs estimated between $6.0 billion and $6.5 billion, excluding financing costs. In October 2014, Atlantic Coast Pipeline requested approval from FERC to utilize the pre-filing process under which environmental review for the natural gas pipeline project will commence. Atlantic Coast Pipeline filed its FERC application in September 2015 and expects to be in service in late 2019. In October 2017, Atlantic Coast Pipeline received the FERC order authorizing the construction and operation of the project. The FERC order has been appealed to the U.S. Court of Appeals for the Fourth Circuit and the project remains subject to other pending federal and state approvals. See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Atlantic Coast Pipeline.
In December 2012, Dominion Energy formed Blue Racer with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions
of Pennsylvania. Blue Racer is an equal partnership between Dominion Energy and Caiman, with Dominion Energy contributing midstream assets and Caiman contributing private equity capital. Midstream services offered by Blue Racer include gathering, processing, fractionation, and natural gas liquids transportation and marketing. Blue Racer is expected to develop additional new capacity designed to meet producer needs as the development of the Utica Shale formation increases. See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Blue Racer.
SOURCES OF ENERGY SUPPLY
Gas Infrastructure Operating Segment-Dominion Energy and Dominion Energy Gas
Dominion Energy’s 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’s 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’s 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’s 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 Operating Segment-Dominion Energy and Dominion Energy Gas
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, 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.
Corporate and Other
Corporate and Other Segment-Virginia Power and Dominion Energy Gas
Virginia Power’s 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, Ohio, West Virginia, Utah, Wyoming and Idaho, SEC, FERC, EPA, DOE, NRC, Army Corps of Engineers, and the Department of Transportation.
State Regulations
ELECTRIC
Virginia Power’s electric utility retail service is subject to regulation by the Virginia Commission and the North Carolina Commission.
Virginia Power holds CPCNs which authorize it to maintain and operate its electric facilities now in operation and to sell electricity to customers. However, Virginia Power 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 transactions with affiliates and transfers of certain facilities. The Virginia Commission also regulates 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, 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 February 2015, the Virginia Governor signed legislation into law which will keep Virginia Power’s base rates unchanged until at least December 1, 2022. In addition, no biennial reviews will be conducted by the Virginia Commission for the five successive 12-month test periods beginning January 1, 2015, and ending December 31, 2019. The legislation states that Virginia Power’s 2015 biennial review, filed in March 2015, would proceed for the sole purpose of reviewing and determining whether any refunds are due to customers based on earnings performance for generation and distribution services during the 2013 and 2014 test periods. In addition the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility’s ROE for use in connection with rate adjustment clauses and requires utilities to file integrated resource plans annually rather than biennially. In November 2017, the Virginia Commission approved an ROE of 9.2% for rate adjustment clauses.
In February 2017, the Governor of Virginia signed legislation into law that allows utilities to file a rate adjustment clause to recover costs of pumped hydroelectricity generation and storage facilities that are located in the coalfield region of Virginia. In March 2017, the Governor of Virginia signed legislation into law that allows utilities to file a rate adjustment clause to recover, beginning in 2020, reasonably appropriate costs for extending the operating licenses, or the operating lives, of nuclear power generation facilities.
In March 2017, the Governor of Virginia signed legislation into law stating that it is in the public interest for utilities to replace existing overhead tap lines having nine or more total unplanned outage events-per-mile with new underground facilities, and that utilities can seek cost recovery for such new underground facilities through a rate adjustment clause.
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.
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.
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.
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 Note 3 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 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.
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.
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, 2017, approximately 1.0 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 Dominion Energy’s merchant generators sell electricity in the PJM, MISO, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. 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.
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 Virginia Power and Dominion Energy’s merchant plants without first receiving FERC authorization, (2) require the merchant plants and Virginia Power to conduct their wholesale power sales operations separately, and (3) prohibit Virginia Power from sharing market information with merchant plant operating personnel. The rules are designed to prohibit Virginia Power 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 of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
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’s 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 Department of Transportation regulations under these Acts, and has 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 monitor 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 national and international attention to GHG emissions and their relationship to climate change has resulted in federal, regional and state legislative and regulatory action in this area. See, for example, the discussion of the Clean Power Plan and the United Nation’s Paris Agreement in Environmental Matters in Future Issues and Other Matters in Item 7. MD&A.
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 pro-
duction 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 the 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 to allow 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 populations. These can result in compliance and mitigation costs, and 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’s 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’s 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 above and Note 9 to the Consolidated Financial Statements. See Note 22 to the Consolidated Financial Statements for information on spent nuclear fuel.
ENVIRONMENTAL STRATEGY
As part of the Companies’ overall long term strategic planning overseen by the Board of Directors, we have a well formed environmental strategy. 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, we seek to build partnerships and engage with local communities, stakeholders and customers on environmental issues important to them. 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 significantly reduced both its carbon emissions and its carbon intensity while generating electricity with an increasingly clean portfolio. From 2000 through 2016, our carbon intensity decreased by 43%. This strategy has also resulted in significant 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, which include initiatives that address electric energy production and delivery, natural gas storage, transmission and delivery and energy management, are as follows:
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Expand Dominion Energy’s and Virginia Power’s renewable energy portfolio, including solar, wind power, and biomass, to further diversify Dominion Energy’s and Virginia Power’s fleet, meet state renewable energy targets and lower the carbon footprint;
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Pursue the extension of operating licenses of existing nuclear units which provide carbon-free generation;
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Evaluate effective battery solutions, such as hydroelectric pumped storage, which help support a grid with increased renewables;
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Enhance conservation and energy efficiency programs on both the electric and gas side of our businesses to help customers use energy wisely and reduce environmental impacts;
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Sell, close, place in cold reserve or convert to cleaner fuels a number of coal-fired generation units owned by Dominion Energy and Virginia Power;
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Evaluate behind-the-meter and rate design solutions and other business opportunities;
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Construct new electric and gas transmission infrastructure to modernize the grid, to expand availability of cleaner fuel, to reduce emissions, to promote energy and economic security and help deliver more green energy to population centers where it is needed most;
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Replace older distribution pipeline mains and services; and
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Implement and enhance voluntary methane mitigation measures through participation in the EPA’s Natural Gas Star and Methane Challenge programs; and continue to evaluate business opportunities presented by a lower carbon economy and innovative technologies.
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. Nationally, Dominion Energy has nearly 2,400 MW of renewable generating capacity in operation or under development in nine states, including offtake agreements for Virginia Power’s utility customers. Both Virginia and North Carolina have passed legislation setting targets for renewable power. Dominion Energy 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, and North Carolina’s Renewable Portfolio Standard of 12.5% by 2021 and continues to add utility-scale solar capacity. Backed by a $1 billion investment, Dominion Energy has grown its solar fleet in Virginia and North Carolina over the past two years from near zero to about 1,350 megawatts 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 2016 to annual year 2000, the entire electric generating fleet (based on ownership percentage) reduced its average CO2 emissions rate per MWh of energy produced from electric generation by approximately 43%. Comparing annual year 2016 to annual year 2000, the regulated electric generating fleet (based on ownership percentage) reduced its average CO 2 emissions rate per MWh of energy produced from electric generation by approximately 26%.
Dominion Energy also develops a comprehensive GHG inventory annually. For Power Generation, Dominion Energy and Virginia Power’s direct CO 2 equivalent emissions, based on ownership percentage, were 37.2 million metric tons and 33.1 million metric tons, respectively, in 2016, compared to 34.3 million metric tons and 30.9 million metric tons, respectively, in 2015. The corresponding carbon intensity rates for Dominion Energy were 0.339 metric tons CO2 equivalent
emissions per net MWh in 2016 and 0.348 metric tons CO2 equivalent emissions per net MWh in 2015.
For Power Delivery’s regulated electric transmission and distribution operations, direct CO 2 equivalent emissions for 2016 were 42,856 metric tons, compared to 53,819 metric tons in 2015.
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 EPA on March 31, 2017.
Hope and East Ohio direct CO2 equivalent emissions together decreased from 0.90 million metric tons in 2015 to 0.86 million metric tons in 2016. DETI’s and Cove Point’s direct CO2 equivalent emissions together were 1.3 million metric tons in 2016, increasing from 1.1 million metric tons in 2015 attributable to new EPA reporting of transmission pipeline blowdowns.
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 2.3 million metric tons in 2016. 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 2016 corporate GHG inventory emission estimate includes Dominion Energy Questar Pipeline, Questar Gas and Wexpro for the entire calendar year.
Energy Infrastructure Modernization
Dominion Energy’s existing five-year investment plan includes significant capital expenditures to upgrade or add new electric transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory, maintain reliability, implement a strategic underground program to minimize outage duration and address environmental requirements. These enhancements are primarily aimed at meeting Dominion Energy’s continued goal of providing reliable service, and are intended to address both continued population growth and 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 their existing five-year investment plans, 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 Regulation Act provides incentives for energy conservation through the implementation of conservation programs. Additional legislation in 2009 added definitions of peak-shaving and energy efficiency programs, and allowed for a margin on operating expenses and recovery of revenue reductions related to energy efficiency programs.
Virginia Power’s DSM programs, implemented with Virginia Commission and North Carolina Commission approval, provide important incremental steps in assisting customers to reduce energy consumption through programs that include energy audits and incentives for customers to upgrade or install certain energy efficient measures and/or systems. The DSM programs began in Virginia in 2010 and in North Carolina in 2011. Currently, there are residential and non-residential DSM programs active in the two states. Virginia Power continues to evaluate opportunities to redesign current DSM programs and develop new DSM initiatives in Virginia and North Carolina.
Virginia Power continues to upgrade meters throughout Virginia to AMI, also referred to as smart meters. The AMI meter upgrades are part of an ongoing demonstration effort to help Virginia Power further evaluate the effectiveness of AMI meters to monitor voltage stability, remotely turn off and on electric service, increase detection and reporting capabilities with respect to power outages and restorations, obtain remote daily meter readings and offer dynamic rates.
East Ohio offers two DSM programs, approved by the Ohio Commission, designed to help customers reduce their energy consumption. One program provides weatherization assistance to help income-eligible customers reduce their energy usage. Another program has been designed to help East Ohio’s residential customers improve their homes’ energy efficiency, starting with a home energy assessment. Following the assessment, customers receive a report with recommendations on how to save energy and improve their home’s comfort. This program includes rebates and free installation of several energy-efficient products such as, high-efficiency showerheads, kitchen and bathroom faucet aerators, programmable thermostat or carbon monoxide detector and water heater pipe wrap.
Questar Gas offers an energy-efficiency program, approved by the Utah and Wyoming Commissions, designed to help customers reduce their energy consumption. This program promotes the use of energy-efficient appliances and practices to reduce natural gas usage. The program provides home energy planning, which provides homeowners with a step-by-step roadmap to efficiency improvements to reduce gas usage. In addition to the recommendations, the program provides home owners with energy-saving devices such as pipe insulation and low-flow shower heads as well as rebates on appliances and weatherization items. The program also offers new construction builders with rebates for installing high-efficiency equipment and offers commercial businesses with rebates on energy efficient equipment and retrofits.
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 addition, the Companies are subject to mandatory cybersecurity regulatory requirements, 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 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’s and Dominion Energy Gas’ gas transmission and distribution operations and Virginia Power’s electric transmission, distribution and generation operations are subject to regulatory review. Revenue provided by Virginia Power’s electric transmission, distribution and generation operations and Dominion Energy’s 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.
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, 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 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’s and Dominion Energy Gas’ gas transmission businesses are subject to review by FERC. In addition, the rates of Dominion Energy’s 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’s 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 on a biennial basis in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a combined two-year 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.
Legislation signed by the Virginia Governor in February 2015 suspends biennial reviews for the five successive 12-month test periods beginning January 1, 2015 and ending December 31, 2019, and no changes will be made to Virginia Power’s existing base rates until at least December 1, 2022. During this period, Virginia Power bears the risk of any severe weather events and natural disasters, the risk of asset impairments related to the early retirement of any generation facilities due to the implementation of environmental regulations, as well as an increase in general operating and financing costs, and Virginia Power may not recover its associated costs through increases to base rates. If Virginia Power incurs any such significant additional expenses during this period, Virginia Power may not be able to recover its costs and/or earn a reasonable return on capital investment, which could negatively affect Virginia Power’s future earnings.
Virginia Power’s retail electric base rates for bundled generation, transmission, and distribution services to customers 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. If retail electric earnings exceed the returns 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 through
base rates, on a timely basis, of costs incurred in providing service, 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 could result in amounts currently collected from utility customers to be refundable to such customers, generally through reductions in rates. 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. 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 refunds of other deferred taxes may be determined by our federal and state 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 are subject to an increased risk of FERC initiating industry-wide proceedings under Section 5 of the Natural Gas Act to have interstate pipelines substantiate 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 tax reform 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’ regulated subsidiaries; however, states as well as customers have petitioned FERC to request changes in rates as a result of tax reform.
The interpretation of provisions of the 2017 Tax Reform Act that take effect in 2018 may significantly impact our operations. The 2017 Tax Reform Act contains provisions that limit the deductibility of interest expense. The new provision generally limits 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. Regulated public utilities are not subject to this interest limitation; however Dominion Energy is a consolidated group with both regulated and merchant lines of businesses. The U.S. Department of Treasury has been tasked with providing guidance on applying the interest limitation to consolidated groups, such as Dominion Energy, but it is unclear when that guidance may be issued, 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 July 2015, FERC approved changes to PJM’s Reliability Pricing Model capacity market establishing a new Capacity Performance Resource product. This product offers the potential for higher capacity prices but can also impose significant economic penalties on generator owners such as Virginia Power for failure to perform during periods when electricity is in high demand. 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 before construction can commence. 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. 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, including but not limited to commencement of commercial operations at our power generation facilities following expansions and the Liquefaction Project. 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 Liquefaction Project, the Atlantic Coast Pipeline Project, the Supply Header project, Greensville County and multiple DETI projects, which together help contribute to the over $25 billion in capital expenditures planned by the Companies through 2022. 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. For example, while Dominion Energy has received the required approvals to commence construction of the Liquefaction Project from the DOE, all DOE export licenses are subject to review and possible withdrawal should the DOE conclude that such export authorization is no longer in the public interest. 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 Clean Power Plan, targeted at reducing CO2 emissions from existing fossil fuel-fired power generation facilities, has been stayed and is being reviewed by the EPA. Compliance with a replacement rule for the Clean Power Plan, or similar regulations, are 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. In the absence of federal legislation, states are also contemplating regulations regarding GHG emissions. For example, the Virginia General Assembly has considered legislation which would authorize the state to directly join the RGGI program as a full participant. 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’s and Virginia Power’s generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion Energy’s or Virginia Power’s results of operations, financial performance or liquidity.
There are also potential impacts on Dominion Energy’s 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.
Virginia Power is subject to risks associated with the disposal and storage of coal ash. Virginia Power historically produced and continues to produce coal ash, or CCRs, as a by-product of its coal-fired generation operations. The ash is stored and managed in impoundments (ash ponds) and landfills located at eight different facilities.
Virginia Power is facing litigation regarding alleged CWA violations at Chesapeake power station, and may face litigation concerning its coal ash facilities at other stations. Depending on the final outcome of any such litigation, Virginia Power could incur expenses and other costs, including costs associated with
closing, corrective action and ongoing monitoring of certain ash ponds. In addition, the EPA has issued regulations concerning the management and storage of CCRs, which Virginia has adopted. These CCR regulations require Virginia Power to make additional capital expenditures and increase its operating and maintenance expenses.
Further, while Virginia Power operates its 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 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, 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 environmental 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’s 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’s and Virginia Power’s decommissioning trust funds are insufficient, and they are not allowed to recover the additional costs incurred through insurance, or in the case of Virginia Power through regulatory mechanisms, their results of operations could be negatively impacted.
Dominion Energy’s 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’s and Dominion Energy Gas’ facilities. A number of other factors could reduce the volumes of natural gas and NGLs available to Dominion Energy’s 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’s 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’s 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 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 fuel under a variety of terms, including long-term and short-term contracts and spot market purchases. Dominion Energy is exposed to fuel cost volatility for the portion of its fuel obtained through short-term contracts or on the spot market, including as a result of market supply shortages. Fuel prices can be volatile and the price that can be obtained for power produced from such fuel may not change at the same rate as 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’s 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 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.
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. In such arrangements, Dominion Energy is dependent on third parties to fund their required share of capital expenditures. 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 will also be 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’s and Virginia Power’s decommissioning trust funds and Dominion Energy’s and Dominion Energy Gas’ benefit plan assets or increase Dominion Energy’s 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’s and Virginia Power’s nuclear plants and under Dominion Energy’s 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’s 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’s 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’s 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 Dodd-Frank Act includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can choose to exempt their hedging transactions from these clearing and exchange trading requirements. Final rules for the over-the-counter derivative-related provisions of the Dodd-Frank Act will continue to be established through the ongoing rulemaking process of the applicable regulators, including rules regarding margin requirements for non-cleared swaps. 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, including from higher margin requirements, for their derivative activities. In addition, changes to or the elimination of rulemaking that implements Title VII of the Dodd-Frank Act by the Companies’ counterparties could result in increased costs related to the Companies’ derivative activities.
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, a physical attack on a critical substation in California resulted in serious impacts to the power grid. 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 finan-
cial 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 could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. The Companies maintain property and casualty insurance that may cover certain damage caused by potential cyber incidents; however, other 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 complement to future needs, 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 transmission, generation and distribution operations. The Companies’ inability to attract and retain these employees could adversely affect their business and future operating results.
The completion of the merger with SCANA is subject to the receipt of consents, approvals and/or findings from governmental entities, which may impose conditions that could have an adverse effect on Dominion Energy or SCANA or could cause either Dominion Energy or SCANA to abandon the merger. The completion of the merger is also subject to there not having been substantive changes in certain South Carolina laws that have or would reasonably be expected to have an adverse effect on SCANA or its subsidiaries or orders of governmental entities or changes in law that impose any condition that would reasonably be expected to result in specified changes to the South Carolina Commission petition. Dominion Energy and SCANA are not required to complete the merger until after the applicable waiting period under the Hart-Scott-Rodino Act expires or terminates and the requisite authorizations, approvals, consents and/or permits are received from the FERC, NRC, South Carolina Commission, North Carolina Commission and Georgia Public Service Commission. Any of the relevant governmental entities may oppose the merger, fail to approve the
merger, fail to make required findings in favor of the merger, or impose certain requirements or obligations as conditions for their consent, approval or findings or in connection with their review. Regulatory approvals of the merger or findings with respect to the merger may not be obtained on a timely basis or at all, and such approvals or findings may include conditions that could have an adverse effect on Dominion Energy and/or SCANA, or result in the abandonment of the merger. Dominion Energy cannot provide any assurance that Dominion Energy and SCANA will obtain the necessary approvals or findings or that any required conditions will not have an adverse effect on Dominion Energy following the merger.
Subject to the terms and conditions set forth in the merger agreement, the merger agreement may require Dominion Energy to accept conditions from regulators that could adversely impact Dominion Energy after the merger without either of Dominion Energy or SCANA having the right to refuse to close the merger on the basis of those regulatory conditions, except that Dominion Energy is generally not required, and SCANA is generally not permitted without Dominion Energy’s prior approval, to take any action or accept any condition that results in a burdensome condition for Dominion Energy or SCANA as more fully described in the SCANA Merger Agreement.
In addition, the SCANA Merger Agreement provides that Dominion Energy (but not SCANA) will have the right to refuse to complete the merger if, since the date of the SCANA Merger Agreement, any governmental entity shall have enacted any order, or there shall have been any change in law (including the Base Load Review Act and the other laws governing South Carolina public utilities), which imposes any material change to the terms, conditions or undertakings set forth in the South Carolina Commission petition, or any significant changes to the economic value of the proposed terms set forth in the South Carolina Commission petition, in each case as determined by Dominion Energy in good faith.
The SCANA Merger Agreement further provides that Dominion Energy will have the right to refuse to close the merger if there shall have occurred any substantive change in the Base Load Review Act or other laws governing South Carolina public utilities which has or would reasonably be expected to have an adverse effect on SCANA or any of its subsidiaries. There is currently pending before the South Carolina Senate a bill that would make substantive changes to the Base Load Review Act. This bill has passed the South Carolina House of Representatives. If this bill becomes law, Dominion Energy would not be obligated to complete the merger if it is determined that the bill has or would reasonably be expected to have an adverse effect on SCANA or any of its subsidiaries.
Certain lawsuits and regulatory actions have been filed against SCANA and SCE&G in connection with the abandonment of the V.C. Summer Units 2 and 3 new nuclear development project. If the relief requested in these matters (including a request for declaratory judgment that the Base Load Review Act is unconstitutional) is granted, Dominion Energy might not be obligated to complete the merger.
Dominion Energy and SCANA can provide no assurance that these risks will not materialize and either adversely impact Dominion Energy after the completion of the merger or, if such conditions rise to the thresholds discussed above, some of which,
as described above, are in the subjective determination of Dominion Energy acting in good faith, or if the required authorizations, approvals, consents and/or permits are not obtained or received, result in the abandonment of the merger.
Dominion Energy expects to incur substantial expenses related to the merger with SCANA. Dominion Energy expects to incur relatively significant expenses in connection with completing the merger. While Dominion Energy has assumed that a certain level of transaction and integration expenses would be incurred, there are a number of factors beyond its control that could affect the total amount or the timing of its integration expenses. Many of the expenses that will be incurred, by their nature, are difficult to estimate accurately at the present time.
Following the merger with SCANA, Dominion Energy may be unable to successfully integrate SCANA’s businesses. Dominion Energy and SCANA currently operate as independent public companies. After the merger, Dominion Energy will be required to devote significant management attention and resources to integrating SCANA’s business. Potential difficulties Dominion Energy may encounter in the integration process include the following:
•
The complexities associated with integrating SCANA and its utility businesses, while at the same time continuing to provide consistent, high quality services;
•
The complexities of integrating a company with different core services, markets and customers;
•
The inability to attract and retain key employees;
•
Potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the merger;
•
Difficulties in managing political and regulatory conditions related to SCANA’s utility businesses after the merger;
•
The cost recovery plan includes a moratorium on filing requests for adjustments in SCE&G’s base electric rates until 2021 if the merger is approved by the South Carolina Commission, which would limit Dominion Energy’s ability to recover increases in non-fuel related costs of electric operations for SCE&G’s customers; and
•
Performance shortfalls as a result of the diversion of Dominion Energy management’s attention caused by completing the merger and integrating SCANA’s utility businesses.
For these reasons, it is possible that the integration process following the merger 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 and SCANA may be materially adversely affected by negative publicity related to the merger and in connection with other related matters, including the abandonment of the V.C. Summer Units 2 and 3 new nuclear development 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 V.C. Summer Units 2 and 3 new nuclear development project may result in a significant
amount of adverse press coverage and other adverse public statements affecting Dominion Energy and SCANA. 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 and SCANA’s respective businesses.
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 and SCANA, 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 and SCANA’s respective business, financial condition, results of operations and prospects.
The market value of Dominion Energy common stock could decline if large amounts of its common stock are sold following the merger with SCANA. Following the merger, shareholders of Dominion Energy and former SCANA shareholders will own interests in a combined company operating an expanded business with more assets and a different mix of liabilities. Current shareholders of Dominion Energy and SCANA may not wish to continue to invest in the combined company, or may wish to reduce their investment in the combined company, in order to comply with institutional investing guidelines, to increase diversification or to track any rebalancing of stock indices in which Dominion Energy common stock or SCANA common stock is or was included. If, following the merger, large amounts of Dominion Energy common stock are sold, the price of its common stock could decline.
The merger with SCANA 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 merger 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 merger on its GAAP earnings will be a decrease in such earnings due to the anticipated charges for refunds to SCE&G customers, write-offs of regulatory assets and transaction costs.
Litigation against SCANA and Dominion Energy could result in an injunction preventing the completion of the merger with SCANA or may adversely affect the combined company’s business, financial condition or results of operations following the merger with SCANA. Following the announcement of the SCANA Merger Agreement, lawsuits have been filed asserting claims relating to the merger. Among other things, the lawsuits allege breaches of various fiduciary duties by the members of the SCANA board in connection with the merger and allegations that Dominion Energy and/or SCANA aided and abetted such alleged breaches. Among other remedies, the plaintiffs seek to enjoin the merger, rescind the merger agreement or be awarded monetary damages should the merger be completed. While Dominion Energy believes that dismissal of these lawsuits is warranted, the outcome of any such litigation is inherently uncertain. The defense or settlement of any lawsuit or any claim that remains unresolved at the time the merger closes may adversely affect the combined company’s business, financial condition or results of operation. Additionally, other lawsuits may be filed in the future making similar or new claims and seeking similar or new remedies.
Dominion Energy has goodwill and other intangible assets on its balance sheet, and these amounts will increase as a result of the merger with SCANA. 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. Upon the completion of the merger, 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. 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 merger, 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, 2017, Dominion Energy owned its principal executive office and three other corporate offices, all located in Richmond, Virginia. 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. See Item 1. Business for additional information about each segment’s principal properties, which information is incorporated herein by reference.
Dominion Energy’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described here and in Item 1. Business.
Certain of Virginia Power’s property is 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, 2017; 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.
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 10,400 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 1,226,500 Gals of propane, 109,000 Gals of isobutane, 442,000 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 Cove Point pipeline is a 36-inch diameter underground, interstate natural gas pipeline that extends approximately 88 miles from Cove Point to interconnections with Transcontinental Gas Pipe Line Company, LLC 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.
Questar Gas distributes gas to customers in Utah, Wyoming and Idaho. Questar Gas owns and operates distribution systems and has a total of 29,600 miles of street mains, service lines and interconnecting pipelines. Questar Gas has a major operations center in Salt Lake City, and has operations centers, field offices and service-center facilities in other parts of its service area.
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.
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 171 compressor stations with approximately 1,190,000 installed compressor horsepower.
POWER DELIVERY
See Item 1. Business, General for details regarding Power Delivery’s principal properties, which primarily include transmission and distribution lines.
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, 2017, Power Generation’s total utility and merchant generating capacity was approximately 26,000 MW. The following tables list Power Generation’s utility and merchant generating units and capability, as of December 31, 2017.
VIRGINIA POWER UTILITY GENERATION(1)
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) The table excludes Virginia Power’s Morgans Corner solar facility located in Pasquotank County, NC, Remington solar facility located in Remington, VA and Oceana solar facility located in Virginia Beach, VA which have a net summer capacity of 20 MW, 20 MW and 18 MW, respectively as these facilities are dedicated to serving non-jurisdictional customers.
(2) Excludes 50% undivided interest owned by ODEC.
(3) Coal-fired units are expected to be retired at Yorktown power station as early as 2018 as a result of the issuance of MATS.
(4) Excludes 11.6% undivided interest owned by ODEC.
(5) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of FirstEnergy Corp.
(6) In January 2018, Virginia Power announced it would place certain units at this facility in cold storage.
DOMINION MERCHANT GENERATION
Note: (CC) denotes combined cycle.
(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 NRG. 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) Subject to a lien securing the facility’s debt.
(6) Excludes 50% membership interest owned by BP.
(7) Excludes 50% membership interest owned by Shell.
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.
In January 2016, Virginia Power self-reported a release of mineral oil from the Crystal City substation and began extensive cleanup. Virginia Power assumed the role of responsible party and has continued to cooperate with ongoing requirements for investigative and corrective action. In December 2016, the Virginia State Water Control Board approved a consent order between the VDEQ and Virginia Power related to this matter, which included a penalty in excess of $100,000. In May 2017, the VDEQ formally terminated the consent order, finding that all requirements had been completed. Also in May 2017, the U.S. Department of the Interior, on behalf of several federal and state agencies, proposed a settlement to resolve the agencies’ claims for natural resource damages related to the mineral oil release. In January 2018, Virginia Power and the natural resource trustee agencies executed a settlement agreement that would require Virginia Power to pay approximately $400,000 to fund wetland restoration and related projects in the location of the release. Final approval of the settlement is pending completion of a 30-day public comment period which is expected during the first quarter of 2018.
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 environmental and other regulatory proceedings to which the Companies are a party.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
Information concerning the executive officers of Dominion Energy, each of whom is elected annually, is as follows:
(1) Any service listed for Virginia Power, Dominion Energy Midstream GP, LLC, Dominion Energy Gas, DETI, East Ohio, Dominion Cove Point, Inc., Questar Gas and DES reflects service at a subsidiary of Dominion Energy.
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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. At February 15, 2018, there were approximately 123,000 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 and restrictions on Dominion Energy’s payment of dividends required by this Item are contained in Liquidity and Capital Resources in Item 7. MD&A and Notes 17 and 20 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 2017 and 2016. Quarterly information concerning stock prices and dividends is disclosed in Note 26 to the Consolidated Financial Statements, which information is incorporated herein by reference.
The following table presents certain information with respect to Dominion Energy’s common stock repurchases during the fourth quarter of 2017:
(1) 29,305, 8 and 4 shares were tendered by employees to satisfy tax withholding obligations on vested restricted stock in October, November and December 2017, 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. Potential restrictions on Virginia Power’s payment of dividends are discussed in Note 20 to the Consolidated Financial Statements. In 2016, no dividends were declared or paid given the sufficiency of operating and other cash flows at Dominion Energy. In 2017, Virginia Power declared and paid quarterly cash dividends of $445 million, $409 million and $345 million during the first three quarters of 2017, respectively. Virginia Power intends to pay quarterly cash dividends in 2018 but is neither required to nor restricted, except as described above, from making such payments.
Dominion Energy Gas
All of Dominion Energy Gas’ membership interests are owned by Dominion Energy. Potential restrictions on Dominion Energy Gas’ payment of distributions are discussed in Note 20 to the Consolidated Financial Statements. Dominion Energy Gas declared and paid cash distributions of $150 million in the second quarter of 2016. Dominion Energy Gas declared and paid cash distributions of $7 million and $8 million in the first and second quarters of 2017, respectively. Dominion Energy Gas intends to pay quarterly cash dividends in 2018 but is neither required to nor restricted, except as described above, 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.
DOMINION ENERGY
(1) 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.
(2) Includes a $122 million after-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities.
(3) 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.
(4) Includes a $109 million after-tax charge related to Dominion Energy’s restructuring of its producer services business ($76 million) and an impairment of certain natural gas infrastructure assets ($33 million). Also in 2013, Dominion Energy recorded a $92 million after-tax net loss from the discontinued operations of Brayton Point and Kincaid.
(5) Amounts attributable to Dominion Energy’s common shareholders.
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’s 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, including provisions of the 2017 Tax Reform Act that take effect beginning in 2018;
•
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’s and Dominion Energy Gas’ earnings and the Companies’ liquidity position and the underlying value of their assets;
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Counterparty credit and performance risk;
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Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;
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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;
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Fluctuations in interest rates or foreign currency exchange rates;
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Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;
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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;
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Risks of operating businesses in regulated industries that are subject to changing regulatory structures;
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Impacts of acquisitions, divestitures, transfers of assets to joint ventures or Dominion Energy Midstream, and retirements of assets based on asset portfolio reviews;
•
The expected timing and likelihood of completion of the proposed acquisition of SCANA, including the ability to obtain the requisite approvals of SCANA’s shareholders and the terms and condition of any regulatory approvals;
•
Receipt of approvals for, and timing of, closing dates for other acquisitions and divestitures;
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The timing and execution of Dominion Energy Midstream’s growth strategy;
•
Changes in rules for regional transmission organizations and independent system operators 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;
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Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
•
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 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 Virginia Power’s service territory in connection with FERC Order 1000;
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Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;
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Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas;
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Changes in operating, maintenance and construction costs;
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Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals;
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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;
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Adverse outcomes in litigation matters or regulatory proceedings; and
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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 2017, 2016 and 2015, Dominion Energy recognized $117 million, $104 million and $93 million, respectively, of accretion, and expects to recognize $117 million in 2018. 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. At December 31, 2017, Dominion Energy’s nuclear decommissioning AROs totaled $1.5 billion, representing approximately 62% 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 we 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, 2017, Dominion Energy had $38 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, 2017, Dominion Energy had established $146 million of valuation allowances.
The 2017 Tax Reform Act includes 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 includes significant changes to the Internal Revenue Code of 1986, including amendments which significantly change the taxation of individuals and business entities and includes specific provisions related to regulated public utilities including Dominion Energy subsidiaries Questar Gas, Wexpro, Hope, 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) limiting the deductibility of interest expense to 30% of adjusted taxable income for certain businesses; (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 continues 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 represent amounts probable of collection from or refund to customers, and are recorded as either an increase to a regulatory asset or liability. 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 refunds of other deferred taxes may be determined by our state and federal regulators. For nonregulated operations, the changes in deferred taxes are recorded as an adjustment to deferred tax expense.
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
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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, 2017, 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.
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 2017, 2016 and 2015 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, particularly 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 Note 9 to the Consolidated Financial Statements for a discussion of impairments related to certain equity method investments.
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 volatilities and correlations;
•
Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; 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 target. 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 2017, 2016 and 2015. For 2018, the expected long-term rate of return for pension cost assumption is 8.75%. Dominion Energy calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2017, 2016 and 2015. For 2018, 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 3.31% to 4.50% for pension plans and 3.92% to
4.47% for other postretirement benefit plans in 2017, ranged from 2.87% to 4.99% for pension plans and 3.56% to 4.94% for other postretirement benefit plans in 2016 and were 4.40% in 2015. Dominion Energy selected a discount rate ranging from 3.80% to 3.81% for pension plans and 3.76% for other postretirement benefit plans for determining its December 31, 2017 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, 2017 was 7.00% and is expected to gradually decrease to 5.00% by 2022 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, while holding all other assumptions constant:
In addition to the effects on cost, at December 31, 2017, a 0.25% decrease in the discount rate would increase Dominion Energy’s projected pension benefit obligation by $338 million and its accumulated postretirement benefit obligation by $44 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $158 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.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion Energy
RESULTS OF OPERATIONS
Presented below is a summary of Dominion Energy’s consolidated results:
Overview
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.
2016 VS. 2015
Net income attributable to Dominion Energy increased 12%, primarily due to higher renewable energy investment tax credits and the new PJM capacity performance market effective June 2016. These increases were partially offset by a decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields and charges related to future ash pond and landfill closure costs at certain utility 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:
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 6%, 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;
•
A $78 million benefit from the sale of certain assets associated with nonregulated retail energy marketing operations;
•
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
•
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).
Other income decreased 34%, 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) and an increase in AFUDC associated with rate-regulated projects ($23 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).
2016 VS. 2015
Net revenue increased 10%, primarily reflecting:
•
A $544 million increase from electric utility operations, primarily reflecting:
•
A $225 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($155 million) and the expiration of non-utility generator contracts in 2015 ($58 million);
•
An increase from rate adjustment clauses ($183 million); and
•
The absence of an $85 million write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015; and
•
A $305 million increase due to the Dominion Energy Questar Combination.
These increases were partially offset by:
•
A $47 million decrease from merchant generation operations, primarily due to lower realized prices at certain merchant generation facilities ($64 million) and an increase in planned and unplanned outage days in 2016 ($26 million), partially offset by additional solar generating facilities placed into service ($37 million);
•
A $19 million decrease from regulated natural gas transmission operations, primarily due to:
•
A $14 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by expansion projects placed in service ($18 million) and increased regulated gas sales ($20 million); and
•
A $17 million decrease in NGL activities, due to decreased prices ($15 million) and volumes ($2 million); partially offset by
•
A $12 million increase in other revenues, primarily due to an increase in services performed for Atlantic Coast Pipeline ($21 million), partially offset by decreased amor-
tization of deferred revenue associated with conveyed shale development rights ($4 million); and
•
A $12 million decrease from regulated natural gas distribution operations, primarily due to a decrease in rate adjustment clause revenue related to low income assistance programs ($26 million) and a decrease in sales to customers due to a reduction in heating degree days ($6 million), partially offset by an increase in AMR and PIR program revenues ($18 million).
Other operations and maintenance increased 18%, primarily reflecting:
•
A $148 million increase due to the Dominion Energy Questar Combination, including $58 million of transaction and transition costs;
•
A $98 million increase in charges related to future ash pond and landfill closure costs at certain utility generation facilities;
•
A $78 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields;
•
Organizational design initiative costs ($64 million);
•
A $50 million increase in storm damage and service restoration costs, including $23 million for Hurricane Matthew;
•
A $20 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 $16 million increase due to labor contract renegotiations as well as costs resulting from a union workforce temporary work stoppage; partially offset by
•
A $26 million decrease 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.
Depreciation, depletion and amortization increased 12%, primarily due to various expansion projects being placed into service.
Other income increased 28%, primarily due to an increase in earnings from equity method investments ($55 million) and an increase in AFUDC associated with rate-regulated projects ($12 million), partially offset by lower realized gains (net of investment income) on nuclear decommissioning trust funds ($19 million).
Interest and related charges increased 12%, primarily due to higher long-term debt interest expense resulting from debt issuances in 2016 ($134 million), partially offset by an increase in capitalized interest associated with the Cove Point Liquefaction Project ($45 million).
Income tax expense decreased 28%, primarily due to higher renewable energy investment tax credits ($189 million) and the impact of a state legislative change ($14 million), partially offset by higher pre-tax income ($15 million).
Outlook
Dominion Energy’s strategy is to continue focusing on its regulated and long-term contracted businesses while maintaining upside potential in well-positioned nonregulated businesses. The goals of this strategy are to provide EPS growth, a growing dividend and to maintain a stable credit profile. Dominion Energy expects approximately 90% of earnings from its primary operating segments to come from regulated and long-term contracted businesses.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion Energy’s 2018 net income is expected to decrease on a per share basis as compared to 2017 primarily from the following:
•
Absence of a benefit from remeasurement of deferred income taxes from the 2017 Tax Reform Act;
•
Reduction of solar investment tax credits;
•
Increases in interest and related charges;
•
An increase in depreciation, depletion, and amortization; and
•
Share dilution.
These decreases are expected to be partially offset by the following:
•
Revenues from the Liquefaction Project;
•
A return to normal weather in its electric utility operations;
•
Growth in weather-normalized electric utility sales of approximately 1.5%;
•
Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue;
•
Construction and operation of growth projects in gas transmission and distribution;
•
Absence of additional refueling outages at Millstone; and
•
A lower effective tax rate, driven by the tax reform.
In addition, if the merger with SCANA is completed in 2018, it would result in a decrease to net income as the result of charges to be incurred for refunds to SCE&G electric customers, write-offs of regulatory assets and transaction costs.
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:
2017 VS. 2016
2016 VS. 2015
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:
2017 VS. 2016
2016 VS. 2015
(1) Represents noncontrolling interest related to merchant solar partnerships.
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:
2017 VS. 2016
(1) Represents the portion of earnings attributable to Dominion Energy Midstream’s public unitholders.
2016 VS. 2015
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 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.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
VIRGINIA POWER
RESULTS OF OPERATIONS
Presented below is a summary of Virginia Power’s consolidated results:
Overview
2017 VS. 2016
Net income increased 26%, primarily due to the absence of charges related to future ash pond and landfill closures costs, a benefit from the remeasurement of deferred income taxes to the new corporate income tax rate and an electric capacity benefit.
2016 VS. 2015
Net income increased 12%, primarily due to the new PJM capacity performance market effective June 2016, an increase in rate adjustment clause revenue and the absence of a write-off of deferred fuel costs associated with the Virginia legislation enacted in February 2015. These increases were partially offset by charges related to future ash pond and landfill closure costs at certain utility generation facilities.
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:
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 pre-tax income ($139 million), partially offset by benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($93 million).
2016 VS. 2015
Net revenue increased 11%, primarily reflecting:
•
A $225 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($155 million) and the expiration of non-utility generator contracts in 2015 ($58 million);
•
An increase from rate adjustment clauses ($183 million); and
•
The absence of an $85 million write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015.
Other operations and maintenance increased 14%, primarily reflecting:
•
A $98 million increase in charges related to future ash pond and landfill closure costs at certain utility generation facilities;
•
A $50 million increase in storm damage and service restoration costs, including $23 million for Hurricane Matthew;
•
A $37 million increase in salaries, wages and benefits and general administrative expenses; and
•
Organizational design initiative costs ($32 million).
Income tax expense increased 10%, primarily reflecting higher pre-tax income.
DOMINION ENERGY GAS
RESULTS OF OPERATIONS
Presented below is a summary of Dominion Energy Gas’ consolidated results:
Overview
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.
2016 VS. 2015
Net income decreased 14%, primarily due a decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields.
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:
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 11%, 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;
•
A $15 million increase due to a charge to write-off the balance of a regulatory asset no longer considered probable of recovery; and
•
A $13 million increase in salaries, wages and benefits and general administrative expenses; partially offset by
•
A $25 million increase in gains from agreements to convey shale development rights underneath several natural gas storage fields.
Depreciation and amortization increased 11%, primarily due to growth projects being placed into service.
Other income increased 82%, primarily due to a $12 million increase in AFUDC associated with rate-regulated projects, 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).
VS. 2015
Net revenue decreased 3%, primarily reflecting:
•
A $34 million decrease from regulated natural gas transmission operations, primarily reflecting:
•
A $36 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by increased regulated gas sales ($16 million) and expansion projects placed in service ($9 million); and
•
An $18 million decrease from NGL activities, due to decreased prices ($16 million) and volumes ($2 million); partially offset by
•
A $21 million increase in services performed for Atlantic Coast Pipeline; and
•
A $12 million decrease from regulated natural gas distribution operations, primarily reflecting:
•
A decrease in rate adjustment clause revenue related to low income assistance programs ($26 million); and
•
A $9 million decrease in other revenue primarily due to a decrease in pooling and metering activities ($3 million), a decrease in Blue Racer management fees ($3 million) and a decrease in gathering activities ($2 million); partially offset by
•
An $18 million increase in AMR and PIR program revenues; and
•
An $8 million increase in off-system sales.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Other operations and maintenance increased 22%, primarily reflecting:
•
A $78 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields; and
•
A $20 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income; partially offset by
•
A $26 million decrease 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.
Other income increased $10 million, primarily due to a gain on the sale of 0.65% of the noncontrolling partnership interest in Iroquois ($5 million) and an increase in AFUDC associated with rate-regulated projects ($5 million).
Interest and related charges increased 29%, primarily due to higher interest expense resulting from the issuances of senior notes in November 2015 and the second quarter of 2016 ($28 million), partially offset by an increase in deferred rate adjustment clause interest expense ($7 million).
Income tax expense decreased 24% primarily reflecting lower pre-tax income.
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, 2017, Dominion Energy had $2.1 billion of unused capacity under its credit facilities. 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 $422 million, primarily due to the operations acquired in the Dominion Energy Questar combination being included for all of 2017, derivative activities, and lower income tax payments, partially offset by lower deferred fuel cost recoveries in the Virginia jurisdiction, higher interest expense, lower revenue from Cove Point’s import contracts and higher pension and postretirement benefit payments and funding.
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 2017, Dominion Energy’s Board of Directors established an annual dividend rate for 2018 of $3.34 per share of common stock, a 10.0% increase over the 2017 rate. Dividends are subject to declaration by the Board of Directors. In January 2018, Dominion Energy’s Board of Directors declared dividends payable in March 2018 of 83.5 cents per share of common stock.
Beginning in 2018, the 2017 Tax Reform Act is expected to reduce customer rates due to lower income tax expense recoveries and the settlement of income taxes refundable through future rates. The Companies’ regulated utilities continue to work with their respective regulatory commissions to determine the amount and timing of the 2017 Tax Reform Act benefits to customers. FERC has not yet issued guidance on the 2017 Tax Reform Act. The ultimate resolution of the amount and timing of these rate reductions with the Companies’ regulators could be material to the Companies’ operating cash flows.
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, 2017 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 14% of the total net credit exposure.
(2) The five largest counterparty exposures, combined, for this category represented approximately 7% of the total net credit exposure.
(3) The five largest counterparty exposures, combined, for this category represented approximately 5% of the total net credit exposure.
(4) The five largest counterparty exposures, combined, for this category represented approximately 38% of the total net credit exposure.
Investing Cash Flows
Net cash used in Dominion Energy’s investing activities decreased $4.7 billion, primarily due to the absence of the acquisition of Dominion Energy Questar and decreases in plant construction and other property additions, partially offset by an increase in acquisitions of solar development projects and increased contributions to Atlantic Coast Pipeline.
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 provided by Dominion Energy’s financing activities decreased $4.9 billion, primarily due to the absence of issuances of debt, common stock, and Dominion Energy Midstream common and convertible preferred units utilized to finance the Dominion Energy Questar Combination in 2016.
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 credit facilities, were as follows:
(1) These credit facilities mature in April 2020 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.
(2) The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facilities was 1.61% at December 31, 2017.
Dominion Energy has indicated its intention to replace the existing two joint revolving credit facilities with a $6.0 billion joint revolving credit facility in the first quarter of 2018. Terms and covenants of the new credit facility are expected to be similar to the existing credit facilities, including that Virginia Power, Dominion Energy Gas and Questar Gas will remain as co-borrowers, except that the maturity will be in five years and the maximum allowed total debt to total capital ratio, with respect to Dominion Energy only, will be increased from 65% to 67.5%. In February 2018, Virginia Power, as co-borrower, filed with the Virginia Commission for approval.
In February 2018, Dominion Energy borrowed $950 million under a 364-Day Term Loan Agreement that bears interest at a variable rate. In addition, the agreement contains a maximum allowed total debt to total capital ratio of 67.5%. The proceeds were used for general corporate purposes and to repay debt.
In July 2017, Dominion Energy Questar repaid a $250 million variable rate term loan due in August 2017 at the amount of principal then outstanding plus accrued interest.
In November 2017, Dominion Energy filed an SEC shelf registration 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, 2017 was less than $0.1 million. The notes are short-term debt obligations of Dominion Energy and are reflected as short-term debt on Dominion Energy’s Consolidated Balance Sheets. The proceeds will be used for general corporate purposes and to repay debt.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
LONG-TERM DEBT
During 2017, Dominion Energy issued the following long-term public debt:
During 2017, Dominion Energy also issued the following long-term private debt:
•
In March 2017, Dominion Energy issued through private placement $300 million of 3.496% senior notes that mature in 2024. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper.
•
In June 2017, Dominion Energy issued through private placement $500 million of variable rate senior notes that mature in 2019. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper.
•
In November 2017, Questar Gas issued through private placement $100 million of 3.38% senior notes that mature in 2032. The proceeds were used for general corporate purposes and to repay short-term debt.
•
In December 2017, Dominion Energy issued through private placement $300 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.
During 2017, Dominion Energy also remarketed the following long-term debt:
•
In May 2017, Dominion Energy successfully remarketed the $1.0 billion 2014 Series A 1.50% RSNs due in 2020 pursuant to the terms of the 2014 Equity Units. In connection with the remarketing, the interest rate on the junior subordinated notes was reset to 2.579%. Dominion Energy did not receive any proceeds from the remarketing. See Note 17 to the Consolidated Financial Statements for more information.
During 2017, Dominion Energy also borrowed the following under a term loan agreement:
•
In May 2017, Dominion Solar Projects III, Inc. borrowed $280 million under a term loan agreement that bears interest at a variable rate. The term loan amortizes over an 18-year period and matures in May 2024. The debt is nonrecourse to Dominion Energy and is secured by Dominion Solar Projects III, Inc.’s interest in certain solar facilities. The proceeds were used for general corporate purposes.
During 2017, Dominion Energy repaid the following long-term debt:
•
In August 2017, Dominion Energy retired its $75 million variable rate Massachusetts Development Finance Agency
Solid Waste Disposal Revenue Bonds, Series 2010B, due in 2041 at the amount of principal then outstanding plus accrued interest.
During 2017, Dominion Energy repaid and repurchased $1.6 billion of long-term debt.
In October 2017, Questar Gas entered into an agreement with certain investors to issue through private placements in April 2018, $50 million of 3.30% 12-year senior notes and $100 million of 3.97% 30-year senior notes. The proceeds will be used for general corporate purposes and to repay short-term 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 for general corporate purposes and to pay maturing long-term debt.
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. In January 2014, Dominion Energy began purchasing its common stock on the open market for these plans. In April 2014, Dominion Energy began issuing new common shares for these direct stock purchase plans.
During 2017, Dominion Energy issued 4.3 million shares of common stock totaling $335 million through employee savings plans, direct stock purchase and dividend reinvestment plans and other employee and director benefit plans. Dominion Energy received cash proceeds of $302 million from the issuance of 3.8 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 January 2018, Dominion Energy issued 6.6 million shares and received cash proceeds of $495 million, net of fees and commissions paid of $5 million through its at-the-market program. See Note 19 to the Consolidated Financial Statements for a description of the at-the-market program.
During 2018, Dominion Energy plans to issue shares for employee savings plans and direct stock purchase and dividend reinvestment plans. In addition, if the merger with SCANA is realized, Dominion Energy would issue 0.6690 shares of Dominion Energy common stock for each share of SCANA common stock outstanding at closing.
REPURCHASE OF COMMON STOCK
Dominion Energy did not repurchase any shares in 2017 and does not plan to repurchase shares during 2018, 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 January 2018, Moody’s affirmed Dominion Energy’s senior unsecured debt and commercial paper ratings of Baa2 and P-2, respectively, and Standard & Poor’s affirmed Dominion Energy’s senior unsecured debt and commercial paper ratings of BBB and A-2, respectively. Moody’s and Standard & Poor’s each changed Dominion Energy’s rating outlook to negative from stable. Dominion Energy cannot predict the potential impact the negative outlook at Moody’s and Standard & Poor’s could have on its cost of borrowing.
In January 2018, Fitch affirmed Dominion Energy’s senior unsecured debt and commercial paper ratings of BBB+ and, respectively, and maintained its stable outlook for both ratings.
Credit ratings as of February 23, 2018 follow:
(1) Securities do not have an interest deferral feature.
(2) Securities have an interest deferral feature.
As of February 23, 2018, Fitch maintained a stable outlook for its respective ratings of Dominion Energy and Moody’s and Standard & Poor’s maintained a negative outlook for their respective ratings of Dominion Energy.
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 filed with the SEC 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 facilities. In addition, Dominion Energy’s credit agreements contain various terms and conditions that could affect its ability to borrow under these facilities. They include maximum debt to total capital ratios and cross-default provisions.
As of December 31, 2017, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:
(1) The $950 million 364-Day Term Loan Credit Agreement, borrowed in February 2018, has a maximum allowed total debt to total capital ratio of 67.5%. In addition, the $6.0 billion replacement joint revolving credit facility, expected to be executed in the first quarter of 2018, is expected to increase the maximum allowed total debt to total capital ratio from 65% to 67.5%.
(2) 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.
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 facilities, 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 facilities. In addition, if the defaulting company is Virginia Power, Dominion Energy’s obligations to repay any outstanding borrowing under the credit facilities could also be accelerated and the lenders’ commitments to Dominion Energy could terminate.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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, 2017, 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, 2017, there have been no events of default under Dominion Energy’s debt covenants.
Dividend Restrictions
Certain agreements associated with Dominion Energy’s credit facilities 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, 2017.
See Note 17 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion Energy 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, 2017. 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 2018.
(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders. In February 2018, $250 million of Dominion Energy Questar Pipeline’s senior notes were repaid 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. As a result, at December 31, 2017, $250 million of senior notes with a 2018 maturity were included in long-term debt in the Consolidated Balance Sheets.
(2) 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, 2017 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.
(3) Primarily consists of operating leases.
(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, $27 million of income taxes payable associated with unrecognized tax 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 $5.5 billion, $5.2 billion and $4.8 billion in 2018, 2019 and 2020, 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 Dominion Energy’s portion of the 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 and Gas Infrastructure -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 2017 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 $139 million as of December 31, 2017. 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. The financial accounting treatment of the lease agreement will be impacted by the new accounting standard issued in February 2016. See Note 2 to the Consolidated Financial Statements for additional information. 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, tribal 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 $200 million, $394 million and $298 million of expenses (including accretion and depreciation) during, 2017, 2016 and 2015 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $190 million and $185 million in 2018 and 2019, respectively. In addition, capital expenditures related to environmental controls were $201 million, $191 million, and $94 million for 2017, 2016 and 2015, respectively. These expenditures are expected to be approximately $205 million and $135 million for 2018 and 2019, respectively.
FUTURE ENVIRONMENTAL REGULATIONS
Air
The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. 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.
In August 2015, the EPA issued final carbon standards for existing fossil fuel power plants. Known as the Clean Power Plan, the rule uses a set of measures for reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units and expanding renewable resources. The final rule has been challenged in the U.S. Court of Appeals for the D.C. Circuit. In February 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan until the disposition of the petitions challenging the rule now before the Court of Appeals, and, if such petitions are filed in the future, before the U.S. Supreme Court. Pursuant to an Executive Order directing the EPA to undertake a review of the Clean Power Plan, the EPA issued a proposed rule in October 2017 to repeal the Clean Power Plan on the basis that the rule promulgated in 2015 exceeds the
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
EPA’s authority under the CAA. In December 2017, the EPA issued an Advanced Notice of Proposed Rulemaking to solicit input on whether it should proceed with a rule to replace the Clean Power Plan, and if so, what the scope of such a rule should be. Given these developments and 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.
In March 2016, the EPA began development of regulations for reducing methane emissions from existing sources in the oil and natural gas sectors. In November 2016, the EPA issued an Information Collection Request to collect information on existing sources upstream of local distribution companies in this sector. In March 2017, the EPA withdrew the information collection request and it remains unclear whether the EPA may propose new regulations on existing sources. Dominion Energy cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.
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. Several states in which Dominion Energy operates, including Pennsylvania, New York and Maryland, are developing state-specific regulations to control GHG emissions, including methane. In January 2018, the VDEQ published for comment a proposed state carbon regulation program linked to RGGI. Dominion Energy cannot currently estimate the potential financial statements impacts on results of operations, financial condition and/or cash flows related to these matters.
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
PROPOSED GRID TRANSFORMATION AND SECURITY ACT OF 2018
In January 2018, legislation was introduced in the Virginia General Assembly to reinstate base rate reviews on a triennial basis other than the first review, which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020. This review for Virginia Power will occur one year earlier than under the Regulation Act legislation enacted in February 2015.
In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized return on equity that might have been refunded to customers may be reduced by any prior investment amounts for new solar or wind generation facilities or up to 5,000 MW of new solar or wind generation facilities and electric distribution grid transformation projects that Virginia Power elects to include in a customer credit reinvestment offset. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a customer credit reinvestment offset. Any costs that are the subject of a customer credit reinvestment offset may not be recovered in base rates for the service life of the projects and may not be included in base rates in future triennial review proceedings.
The legislation also includes provisions requiring Virginia Power to provide current customers a one-time bill credit of
$200 million and to reduce base rates to reflect reductions in federal tax liability resulting from the enactment of the 2017 Tax Reform Act. The legislation is pending.
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’s and Virginia Power’s electric operations and Dominion Energy’s 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 purchases and sales of natural gas and other energy-related products.
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 financial 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 $5 million and $27 million of Dominion Energy’s commodity-based derivative instruments as of December 31, 2017 and December 31, 2016, respectively. The decrease in sensitivity is largely due to a decrease in commodity derivative activity and changes in commodity prices.
A hypothetical 10% decrease in commodity prices would have resulted in a decrease in the fair value of $51 million and $62 million of Virginia Power’s commodity-based derivative instruments as of December 31, 2017 and December 31, 2016, respectively. The decrease in sensitivity is largely due to a decrease in commodity derivative activity and lower commodity prices.
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 $4 million as of both December 31, 2017 and 2016.
The impact of a change in energy commodity prices on the Companies’ commodity-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 losses from commodity 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 the Companies, a hypothetical 10% increase in market interest rates would not have resulted in a material change in annual earnings at December 31, 2017 or 2016.
The Companies also use interest rate derivatives, including forward-starting swaps, as cash flow hedges of forecasted interest payments. 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’s and Virginia Power’s interest rate derivatives at December 31, 2017. As of December 31, 2016, Dominion Energy and Virginia Power had
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
$2.9 billion and $1.7 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 $58 million and $45 million, respectively, in the fair value of Dominion Energy’s and Virginia Power’s interest rate derivatives at December 31, 2016.
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, 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% increase in market interest rates would have resulted in a $6 million decrease in the fair value of Dominion Energy’s and Dominion Energy Gas’ foreign currency swaps at December 31, 2017. As of December 31, 2016, Dominion Energy and Dominion Energy Gas had $280 million ( 250 million) in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% increase in market interest rates would have resulted in a $5 million decrease in the fair value of Dominion Energy’s and Dominion Energy Gas’s foreign currency swaps at December 31, 2016.
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 realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $167 million and $144 million in 2017 and 2016, respectively. 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 increase in unrealized gains of $462 million and $183 million in 2017 and 2016, respectively.
Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $76 million and $67 million in 2017 and 2016, respectively. 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 increase in unrealized gains of $216 million and $93 million in 2017 and 2016, respectively.
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 of $1.6 billion and $534 million in 2017
and 2016, respectively, versus expected returns of $767 million and $691 million, respectively. Dominion Energy Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns of $335 million and $130 million in 2017 and 2016, respectively, versus expected returns of $165 million and $157 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 and $18 million as of December 31, 2017 and 2016, respectively, for pension benefits and $4 million as of both December 31, 2017 and 2016, 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, 2017 and 2016, for pension benefits and $1 million as of both December 31, 2017 and 2016, for other postretirement benefits.
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, 2017 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, 2017 and 2016, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2017, 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 27, 2018, 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 27, 2018
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 Notes 3 and 9 for amounts attributable to related parties.
(2) 1 billion shares authorized; 645 million shares and 628 million shares outstanding at December 31, 2017 and 2016, 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 3 for noncash activities related to the acquisition of Four Brothers and Three Cedars.
(2) See Note 17 for noncash activities related to the remarketing of RSNs in 2017 and 2016.
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, 2017 and 2016, 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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 27, 2018
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, 2017 and 2016.
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, 2017 and 2016, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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 27, 2018
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 Dominion Energy Questar Combination was completed in September 2016. See Note 3 for a description of operations acquired in the Dominion Energy Questar Combination.
Dominion Energy’s operations also include the Cove Point LNG import, transport and storage facility in Maryland, an equity investment in Atlantic Coast Pipeline and regulated gas transportation and distribution operations in West Virginia. Dominion Energy’s nonregulated operations include merchant generation, energy marketing and price risk management activities, retail energy marketing operations and an equity investment in Blue Racer.
In October 2014, Dominion Energy Midstream launched its initial public offering of 20,125,000 common units representing limited partner interests. At December 31, 2017, Dominion Energy owns the general partner, 50.6% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owns 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. The public’s ownership interest in Dominion Energy Midstream is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements.
Dominion Energy manages 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.
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, the accounts 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. NRG’s ownership interest in Four Brothers and Three Cedars, as well as Terra Nova Renewable Partners’ 33% interest in certain of Dominion Energy’s merchant solar projects, is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. See Note 3 for further information on these transactions.
The Companies report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.
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 2016 and 2015 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2017 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows, except for the reclassification of debt issuance costs.
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, 2017 and 2016 included $661 million and $631 million, respectively, of accrued unbilled
Combined Notes to Consolidated Financial Statements, Continued
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, 2017 and 2016 included $400 million and $349 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, 2017 and 2016 included $121 million and $134 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its customers. See Note 9 for amounts attributable to related parties.
The primary types of sales and service activities reported as operating revenue for Dominion Energy are as follows:
•
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 derivative activity;
•
Regulated gas sales consist primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity;
•
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, gas trading and marketing revenue and associated derivative activity;
•
Gas transportation and storage consists primarily of FERC-regulated sales of transmission and storage services. Also included are state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; and
•
Other revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes 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 are as follows:
•
Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and
•
Other revenue consists 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 are as follows:
•
Regulated gas sales consist primarily of state- and FERC-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 and sales of gas purchased from third parties. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties;
•
Gas transportation and storage consists primarily of FERC-regulated sales of transmission and storage services. Also
included are state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;
•
NGL revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity; and
•
Other revenue consists primarily of miscellaneous service revenue, gas processing and handling revenue.
Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs
Where permitted by regulatory authorities, the differences between Dominion Energy’s and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion Energy’s and Dominion Energy Gas’ purchased gas expenses and the related 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, approximately 84% is currently 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’s, Questar Gas’ and Hope’s 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 includes 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 is 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 are 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.
Dominion Energy and Virginia Power both recognized interest income of $11 million in 2017. Dominion Energy Gas’ interest was immaterial in 2017. Interest for the Companies was immaterial in 2016 and 2015. Dominion Energy’s, Virginia
Power’s and Dominion Energy Gas’ penalties were immaterial in 2017, 2016 and 2015.
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 are expected to be 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.
At December 31, 2016, Virginia Power had an income tax-related affiliated receivable of $112 million, comprised of $122 million of federal income taxes due from Dominion Energy net of $10 million for state income taxes due to Dominion Energy. Dominion Energy Gas also had an affiliated receivable of $11 million due from Dominion Energy, representing $10 million of federal income taxes and $1 million of state income taxes. The net affiliated receivables were refunded by Dominion Energy.
In addition, Virginia Power’s Consolidated Balance Sheet at December 31, 2016 included $2 million of noncurrent federal income taxes payable, $6 million of state income taxes receivable and $13 million of noncurrent state income taxes receivable. Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2016 included $1 million of noncurrent federal income taxes payable, $1 million of state income taxes receivable and $7 million of noncurrent state income taxes payable.
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 and Cash Equivalents
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:
Combined Notes to Consolidated Financial Statements, Continued
The Companies hold restricted cash and cash equivalent balances that primarily consist of amounts held for customer deposits, future debt payments on Dominion Solar Projects III, Inc.’s term loan agreement and a distribution reserve at Cove Point. The amount of restricted cash held at each company is presented in the table below. These balances are presented in Other Current Assets and Other Investments in the Consolidated Balance Sheets.
For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.
Derivative Instruments
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 $92 million and $82 million associated with cash collateral at December 31, 2017 and 2016, respectively. Dominion Energy’s margin liabilities associated with cash collateral at December 31, 2017 or 2016 were immaterial. Virginia Power had margin assets of $23 million and $2 million associated with cash collateral at December 31, 2017 and 2016, respectively. Virginia Power’s margin liabilities associated with cash collateral were immaterial at December 31, 2017 and 2016. Dominion Energy Gas’ margin assets and liabilities associated with cash collateral were immaterial at December 31, 2017 and 2016. 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
The Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, the Companies formally document the relationship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using the hedging instrument. The Companies assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges. 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 also uses fair value hedges to mitigate the fixed price exposure inherent in commodity inventory. In addition, Dominion Energy has designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. 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 2017, 2016 and 2015, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $236 million, $159 million and $100 million, respectively. In 2017, 2016 and 2015, Virginia Power capitalized AFUDC to property, plant and equipment of $37 million, $21 million and $30 million, respectively. In 2017, 2016 and 2015, Dominion Energy Gas capitalized AFUDC to property, plant and equipment of $25 million, $8 million and $1 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 2017, 2016 and 2015, Virginia Power recorded $22 million, $31 million and $19 million of AFUDC related to these projects, respectively.
For property subject to cost-of-service rate regulation, including 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.
For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not asso-
ciated 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 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 $2.11 per mcfe in 2017.
Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:
Depreciation and amortization related to Virginia Power’s and Dominion Energy Gas’ nonutility property, plant and equipment and exploration and production properties was immaterial for the years ended December 31, 2017, 2016 and 2015, 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.
Combined Notes to Consolidated Financial Statements, Continued
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.
Regulatory Assets and Liabilities
The accounting for Dominion Energy’s and Dominion Energy Gas’ regulated gas 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. Virginia Power reports 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, Virginia Power reports 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 over the lives of the new issuances.
Investments
MARKETABLE EQUITY AND DEBT SECURITIES
Dominion Energy accounts for and classifies investments in marketable equity and debt securities as trading or available-for-sale securities. Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities.
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Trading securities include marketable equity and debt 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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Available-for-sale securities include all other marketable equity and 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 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 marketable equity and debt securities, the cost basis of the security is based on the specific identification method.
NON-MARKETABLE INVESTMENTS
The Companies account for illiquid and privately held securities for which market prices or quotations are not readily available under either the equity or cost method. Non-marketable investments 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 Virginia Power’s investments are included in other investments in their Consolidated Balance Sheets. The Companies record equity method adjustments in other income in the 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’s and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds.
OTHER-THAN-TEMPORARY IMPAIRMENT
The Companies periodically review their investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in 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
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The recognition provisions of the FASB’s other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities.
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Debt Securities-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.
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Equity securities and other investments-Dominion Energy’s and Virginia Power’s method of assessing other-than-temporary declines requires demonstrating the ability to hold individual securities for a period of time sufficient to allow for the anticipated recovery in their market value prior to the
consideration of the other criteria mentioned above. Since Dominion Energy and Virginia Power have limited ability to oversee the day-to-day management of nuclear decommissioning trust fund investments, they do not have the ability to ensure investments are held through an anticipated recovery period. Accordingly, they consider all equity and other securities as well as non-marketable investments held in nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired.
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 $9 million and $13 million at December 31, 2017 and December 31, 2016, respectively. Based on the average price of gas purchased during 2017 and 2016, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $79 million and $55 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 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 core principle of this revised accounting guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amendments in this update also require disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For the Companies, the revised accounting guidance is effective for interim and annual periods beginning January 1, 2018. The Companies have completed their evaluations of the impact of this guidance and expect no significant impact on their results of
Combined Notes to Consolidated Financial Statements, Continued
operations. However, the Companies will have offsetting increases in operating revenues and other energy-related purchases for noncash consideration related to NGLs received in consideration for performing processing and fractionation services and offsetting decreases in operating revenues and purchased gas for fuel retained to offset costs on certain transportation and storage arrangements. The Companies will apply the standard using the modified retrospective method as opposed to the full retrospective method.
FINANCIAL INSTRUMENTS
In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. In accordance with the guidance effective January 2018, Dominion Energy and Virginia Power will no longer classify equity securities as trading or available-for-sale securities. All equity securities with a readily determinable fair value, or for which it is permitted to estimate fair value using NAV (or its equivalent), including those held in Dominion Energy’s and Virginia Power’s nuclear decommissioning trusts and Dominion Energy’s rabbi trusts, will be reported at fair value in nuclear decommissioning trust funds and other investments, respectively, 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 will be 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. Net realized and unrealized gains and losses on equity securities held in Virginia Power’s nuclear decommissioning trusts will be 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 will be included in other income. Dominion Energy and Virginia Power will qualitatively assess equity securities reported using the measurement alternative to evaluate whether the investment is impaired on an ongoing basis.
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 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 $4 million was recorded to retained earnings and $32 million was recorded to regulatory liabilities for net unrealized gains subject to cost-based regulation. The potential impact to the Consolidated Statements of Income is subject to investment price risk and is therefore difficult to reasonably estimate. If this guidance had been effective January 1, 2017, Dominion Energy and Virginia Power would have
recorded net unrealized gains of approximately $275 million ($176 million after-tax) and $30 million ($19 million after-tax), respectively, to other income in the Consolidated Statements of Income.
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, although it can be early adopted, with a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented for leases that commenced prior to the date of adoption. The Companies plan to elect the proposed transition expedient which would allow the Companies to maintain historical presentation for periods before January 1, 2019. The Companies expect to elect the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases and no reassessment of lease classification for existing leases. The Companies have completed a preliminary assessment for evaluating the impact of this guidance and anticipate that its adoption will result in a significant amount of offsetting right-of-use assets and liabilities on their financial position for leases in effect at the adoption date. No material changes are expected on the Companies’ results of operations. The Companies are beginning implementation activities that primarily include accumulating contracts and lease data points in formats compatible with a new lease management system that will assist with the initial adoption and on-going compliance with the standard.
DEFINITION OF A BUSINESS
In January 2017, the FASB issued revised accounting guidance to clarify the definition of a business. The revised guidance affects the evaluation of whether a transaction should be accounted for as an acquisition or disposition of an asset or a business, which may impact goodwill and related financial statement disclosures. The Companies have adopted this guidance on a prospective basis effective October 1, 2017. The adoption of the pronouncement will result in additional transactions being accounted for as asset acquisitions or dispositions.
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 is effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, and the Companies have elected to apply the standard using the modified retrospective method. Upon adoption of the standard on January 1, 2018,
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. The update 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 benefit costs would be classified outside of income from operations. In addition, only the service cost component will be eligible for capitalization during construction. However, these changes will not impact the accounting by participants in a multi-employer plan. The standard also recognized 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. The guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, with a retrospective adoption for income statement presentation and a prospective adoption for capitalization. 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 provides for up to a one-year measurement period in which to complete the required analyses and accounting. The guidance describes 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. In addition, the guidance provides clarification related to disclosures for entities which are utilizing the measurement period. The Companies have recorded their best estimate of the impacts of the 2017 Tax Reform Act as discussed above and in Note 5. The amounts are considered to be provisional and may result in adjustments to be recognized during the measurement period.
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 guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2019, with early adoption permitted, and may be applied prospectively or retrospectively upon adoption. If the Companies had adopted this guidance for the period ended December 31, 2017, Dominion Energy would have reclassified a benefit of $165 million from AOCI to retained earnings, Dominion Energy Gas would have reclassified a benefit of $26 million from AOCI to membership interests and Virginia Power would have reclassified an expense of $13 million from AOCI to retained earnings.
NOTE 3. ACQUISITIONS AND DISPOSITIONS
DOMINION ENERGY
Proposed Acquisition of SCANA
Under the terms of the SCANA Merger Agreement announced in January 2018, Dominion Energy has agreed to issue 0.6690 shares of Dominion Energy common stock for each share of SCANA common stock upon closing. In addition, Dominion Energy will provide the financial support for SCE&G to make a $1.3 billion up-front, one-time rate credit to all current electric service customers of SCE&G to be paid within 90 days of closing and a $575 million refund along with the benefit of the 2017 Tax Reform Act resulting in at least a 5% reduction to SCE&G electric service customers’ bills over an eight-year period as well as the exclusions from rate recovery of approximately $1.7 billion of costs related to the V.C. Summer Units 2 and 3 new nuclear development project and approximately $180 million to purchase the Columbia Energy Center power station. In addition, SCANA’s debt, which currently totals approximately $7.0 billion, is expected to remain outstanding.
The transaction requires approval of SCANA’s shareholders, FERC and the NRC and clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. In February 2018, the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act. In January 2018, SCANA and Dominion Energy filed for review and approval, as required, from the South Carolina Commission, the North Carolina Commission, the Georgia Public Service Commission and the NRC. Dominion Energy is not required to accept an order by the South Carolina Commission approving Dominion Energy’s merger with SCANA if such order contains any material change to the terms, conditions or undertakings set forth in the cost recovery plan related to the V.C. Summer Units 2 and 3 new nuclear development project or any significant changes to the economic value of the cost recovery plan. In addition, the SCANA Merger Agreement provides that Dominion Energy will have the right to refuse to close the merger if there shall have occurred any substantive change in the Base Load Review Act or other laws governing South Carolina public utilities which has or would reasonably be expected to have an adverse effect on SCE&G. The SCANA Merger Agreement con-
Combined Notes to Consolidated Financial Statements, Continued
tains certain termination rights for both Dominion Energy and SCANA, and provides that, upon termination of the SCANA Combination under specified circumstances, Dominion Energy would be required to pay a termination fee of $280 million to SCANA and SCANA would be required to pay Dominion Energy a termination fee of $240 million. Subject to receipt of SCANA shareholder and any required regulatory approvals and meeting closing conditions, Dominion Energy targets closing by the end of 2018.
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, became a wholly-owned subsidiary of Dominion Energy. Dominion Energy Questar included Questar Gas, Wexpro and Dominion Energy Questar Pipeline at closing. 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. See Notes 17 and 19 for more information.
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 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, 2017, 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 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 2017 and 2016, of which $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, 2015. 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.
Combined Notes to Consolidated Financial Statements, Continued
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) One of the projects, Marin Carport, began commercial operations in 2016.
(4) 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 or will claim 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, including certain projects in the table above. 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. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion Energy’s remaining 67% ownership in the projects upon the occurrence of certain events, none of which are expected to occur in 2018.
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, consisting of $2 million in cash and a $62 million payable. Dominion Energy had no remaining obligation related to this payable at December 31, 2016. 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, consisting of $6 million in cash and a $37 million payable. There was a $2 million payable included in other current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2016. Dominion has no remaining obligation related to this payable at December 31, 2017. 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.
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. The allocation of the $64 million purchase price for Four Brothers resulted in $89 million of property, plant and equipment and $25 million of noncontrolling interest. The allocation of the $43 million purchase price for Three Cedars resulted in $65 million of property, plant and equipment and $22 million of noncontrolling interest. The noncontrolling interest for each entity was measured at fair value using the discounted cash flow method, with the primary components of the valuation being future cash flows (both incoming and outgoing) and the discount rate. Dominion Energy determined its discount rate based on the cost of capital a utility-scale investor would expect, as well as the cost of capital an individual project developer could achieve via a combination of nonrecourse project financing and outside equity partners. The acquired assets of Four Brothers and Three Cedars are included in the Power Generation operating segment.
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, 2017, 2016 and 2015.
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.
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, which owns and operates a 416-mile, FERC-regulated natural gas transmission pipeline in New York and Connecticut. In exchange for this partnership interest, Dominion Energy Midstream issued 8.6 million common units representing limited partnership interests in Dominion Energy Midstream (6.8 million common units to NG for its 20.4% interest and 1.8 million common units to NJNR for its 5.53% interest). The investment was recorded at $216 million based on the value of Dominion Energy Midstream’s common units at closing. These common units are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Dominion Energy Midstream’s noncontrolling partnership interest is reflected in the Gas Infrastructure operating segment. In addition to this acquisition, Dominion Energy Gas currently holds a 24.07% noncontrolling partnership interest in Iroquois. Dominion Energy Midstream and Dominion Energy Gas each account for their interest in Iroquois as an equity method investment. See Notes 9 and 15 for more information regarding Iroquois.
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. DECG owns and operates nearly 1,500 miles of FERC-regulated interstate natural gas pipeline in South Carolina and southeastern Georgia. This acquisition supports Dominion Energy’s natural gas expansion into the southeastern U.S. The allocation of the purchase price resulted in $277 million of net property, plant and equipment, $250 million of goodwill, of which approximately $225 million is expected to be deductible for income tax purposes, and $38 million of regulatory liabilities. The goodwill reflects the value associated with enhancing Dominion Energy’s regulated gas position, economic value attributable to future expansion projects as well as increased opportunities for synergies. The acquired assets of DECG are included in the Gas Infrastructure operating segment.
On March 24, 2015, DECG converted to a limited liability company under the laws of South Carolina and changed its name from Carolina Gas Transmission Corporation to DECG. On April 1, 2015, Dominion Energy contributed 100% of the issued and outstanding membership interests of DECG to Dominion Energy Midstream in exchange for total consideration of $501 million, as adjusted for working capital. Total consideration to Dominion Energy consisted of the issuance of a two-year, $301 million senior unsecured promissory note payable by Dominion Energy Midstream at an annual interest rate of 0.6%, and 5,112,139 common units, valued at $200 million, representing limited partner interests in Dominion Energy Midstream. The number of units was based on the volume weighted average trading price of Dominion Energy Midstream’s common units for the ten trading days prior to April 1, 2015, or $39.12 per unit. Since Dominion Energy consolidates Dominion Energy Midstream for financial reporting purposes, this transaction was
Combined Notes to Consolidated Financial Statements, Continued
eliminated upon consolidation and did not impact Dominion Energy’s financial position or cash flows.
VIRGINIA POWER
Acquisition of Solar Projects
In December 2015, Virginia Power completed the acquisition of 100% of a solar development project in North Carolina from Morgans Corner for $47 million, all of which was allocated to property, plant and equipment. The project was placed into service in December 2015 with a total cost of $49 million, including the initial acquisition cost. The project generates 20 MW. The output generated by the project is used to meet a ten-year non-jurisdictional supply agreement with the U.S. Navy, which has the unilateral option to extend for an additional ten years. In October 2015, the North Carolina Commission granted the transfer of the existing CPCN from Morgans Corner to Virginia Power. The acquired asset is included in the Power Generation operating segment.
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 consists 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 author-
ities. 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.
The 2017 Tax Reform Act includes a broad range of tax reform provisions affecting the Companies as discussed in Note 2. The 2017 Tax Reform Act reduces 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 allows for the continued deductibility of interest expense, changes the tax depreciation of certain property acquired after September 27, 2017, and continues certain rate normalization requirements for accelerated depreciation benefits.
In December 2015, U.S. federal legislation was enacted, providing an extension of the 50% bonus depreciation allowance for qualifying expenditures incurred in 2015, 2016 and 2017. In addition, the legislation extended the 30% investment tax credit for qualifying expenditures incurred through 2019 and provides a phase down of the credit to 26% in 2020, 22% in 2021 and 10% in 2022 and thereafter.
As indicated in Note 2, certain of the Companies’ operations, including accounting for income taxes, is 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 are recorded as either an increase to a regulatory asset or liability. 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 refunds of other deferred taxes may be determined by state and federal regulators. See Note 13 for more information.
The Companies have completed or have made a reasonable estimate for the measurement and accounting of certain effects of the 2017 Tax Reform Act which have been reflected in the Consolidated Financial Statements. The changes in deferred taxes were recorded as either an increase to a regulatory liability or as an adjustment to the deferred tax provision.
The items reflected as provisional amounts are related to accelerated depreciation for tax purposes of certain property acquired and placed into service after September 27, 2017 and the impact of accelerated depreciation on state income taxes to the extent there is uncertainty on conformity to the new federal tax system.
The determination of the income tax effects of the items reflected as provisional amounts represents a reasonable estimate, but will require additional analysis of historical records and further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Department of Treasury regulations, which will require more time, information and resources than currently available to the Companies.
Continuing Operations
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
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.
In 2015, Dominion Energy’s current federal income tax benefit includes the recognition of a $20 million benefit related to a carryback to be filed for nuclear decommissioning expenditures included in its 2014 net operating loss.
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows:
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 recog-
Combined Notes to Consolidated Financial Statements, Continued
nition 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.
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 reflects 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, 2017, Dominion Energy had the following deductible loss and credit carryforwards:
At December 31, 2017, Virginia Power had the following deductible loss and credit carryforwards:
At December 31, 2017, 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 $31 million, $45 million and $69 million at December 31, 2017, 2016 and 2015, respectively. For Dominion Energy, the change in these unrecognized tax benefits decreased income tax expense by $9 million, $18 million and $6 million in 2017, 2016 and 2015, respectively. For Virginia Power, these unrecognized tax benefits were $3 million, $9 million, and $8 million at December 31, 2017, 2016 and 2015, respectively. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $6 million in 2017 and increased income tax expense by $1 million and less than $1 million in 2016 and 2015, respectively. For Dominion Energy Gas, these unrecognized tax benefits were less than $1 million, $5 million and $19 million at December 31, 2017, 2016 and 2015, respectively. For Dominion Energy Gas, the change in these unrecognized tax benefits decreased income tax expense by $5 million, $11 million and less than $1 million in 2017, 2016 and 2015, 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 2016 and 2017, the Companies submitted research credit claims for tax years 2012-2016. These claims are currently under IRS examination. With the exception of these research credit claims, the IRS has completed its audit of tax years through 2015. 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 2016, no material adjustments are expected. The IRS examination of tax year 2017 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 2018 by up to $13 million for Dominion Energy, $2 million for Virginia Power and less than $1 million for 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 $12 million for Dominion Energy, $2 million for Virginia Power and less than $1 million for Dominion Energy Gas.
Otherwise, with regard to 2017 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 2018.
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 includ-
Combined Notes to Consolidated Financial Statements, Continued
ing 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
The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. 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 broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, the Companies consider 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 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 Companies must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect their market assumptions.
The Companies’ commodity derivative valuations are prepared by Dominion Energy’s ERM department. The ERM department creates daily mark-to-market valuations for the Companies’ derivative transactions using computer-based statistical models. The inputs that go into the market valuations are transactional information stored in the systems of record and market pricing information that resides in data warehouse databases. The majority of forward prices are automatically uploaded into the data warehouse databases from various third-party sources. Inputs obtained from third-party sources are evaluated for reliability considering the reputation, independence, market presence, and methodology used by the third-party. If forward prices are not available from third-party sources, then the ERM department models the forward prices based on other available market data. A team consisting of risk management and risk quantitative analysts meets each business day to assess the validity of market prices and mark-to-market valuations. During this meeting, the changes in mark-to-market valuations from period to period are examined and qualified against historical expectations. If any discrepancies are identified during this process, the mark-to-market valuations or the market pricing information is evaluated further and adjusted, if necessary.
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 a Spread Approximation Model when contracts include different commodities or commodity locations and a Swing Option Model when contracts allow either the buyer or seller the ability to exercise within a range of quantities. 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
The Companies regularly evaluate and validate the inputs used to estimate fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities and investments in which the Companies transact.
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.
For derivative contracts, the Companies recognize transfers among Level 1, Level 2 and Level 3 based on fair values as of the first day of the month in which the transfer occurs. 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
Fair value measurements are categorized as Level 3 when price or other inputs that are considered to be unobservable are significant to their valuations. Long-dated commodity derivatives are generally based on unobservable inputs due to the length of time to settlement and the absence of market activity and are therefore categorized as Level 3. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from ISO auctions, which are generally not considered to be liquid markets. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets.
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 unobservable inputs are developed and substantiated using historical information, available 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 pricing sources.
Combined Notes to Consolidated Financial Statements, Continued
The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at December 31, 2017. 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) Includes NGLs and oil.
(4) Represents market prices beyond defined terms for Levels 1 and 2.
(5) Represents volatilities unrepresented in published markets.
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.
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’s 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 $88 million and $89 million of assets at December 31, 2017 and 2016, 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:
The following table presents Dominion Energy’s gains and losses included in earnings 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, 2017. 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 $27 million and $26 million of assets at December 31, 2017 and 2016, 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:
The gains and losses included in earnings in the Level 3 fair value category were classified in electric fuel and other energy-related purchases expense in Virginia Power’s Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015. 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, 2017, 2016 and 2015.
DOMINION ENERGY GAS
The following table presents Dominion Energy Gas’ quantitative information about Level 3 fair value measurements at December 31, 2017. The range and weighted average are presented in dollars for market price inputs.
(1) Averages weighted by volume.
(2) Represents market prices beyond defined terms for Levels 1 and 2.
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Combined Notes to Consolidated Financial Statements, Continued
The following table presents Dominion Energy Gas’ assets and liabilities for commodity and foreign currency 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:
The gains and losses included in earnings in the Level 3 fair value category were classified in operating revenue in Dominion Energy Gas’ Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015. 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, 2017, 2016 and 2015.
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 and cash equivalents, restricted cash (which is recorded in other current assets), 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 issues 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, 2017, and 2016, includes the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt of $(22) million and $(1) 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
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. The Companies use derivative instruments to manage exposure to these risks, and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes. As discussed in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivatives are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings. 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’s 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.
Combined Notes to Consolidated Financial Statements, Continued
DOMINION ENERGY
Balance Sheet Presentation
The tables below present Dominion Energy’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:
Volumes
The following table presents the volume of Dominion Energy’s derivative activity as of December 31, 2017. 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, 2017, 2016 and 2015, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. 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, 2017:
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.
Combined Notes to Consolidated Financial Statements, Continued
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 table presents 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.
(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.
(2) Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in interest and related charges.
VIRGINIA POWER
Balance Sheet Presentation
The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:
Combined Notes to Consolidated Financial Statements, Continued
Volumes
The following table presents the volume of Virginia Power’s derivative activity at December 31, 2017. 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, 2017, 2016 and 2015, gains or losses on hedging instruments determined to be ineffective were not material.
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, 2017:
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.
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) Current derivative liabilities are presented in other current liabilities in Virginia Power’s Consolidated Balance Sheets.
(3) 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.
Combined Notes to Consolidated Financial Statements, Continued
DOMINION ENERGY GAS
Balance Sheet Presentation
The tables below present Dominion Energy Gas’ derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:
Volumes
The following table presents the volume of Dominion Energy Gas’ derivative activity at December 31, 2017. 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. Euro equivalent volumes are 250,000,000.
Ineffectiveness and AOCI
For the years ended December 31, 2017, 2016 and 2015, gains or losses on hedging instruments determined to be ineffective were not material.
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, 2017:
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 Gas’ derivatives and where they are presented in its Consolidated Balance Sheets:
(1) Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Energy Gas’ Consolidated Balance Sheets.
(2) Current derivative liabilities are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.
(3) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.
Combined Notes to Consolidated Financial Statements, Continued
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 consist primarily of the 2013 Equity Units for 2016 and 2015. See Note 17 for more information.
The 2014 Equity Units were excluded from the calculation of diluted EPS for the years ended December 31, 2016 and 2015, as the dilutive stock price threshold was not met. The 2016 Equity Units were excluded from the calculation of diluted EPS for the year ended December 31, 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 are potentially dilutive securities but had no effect on the calculation of diluted EPS for the years ended December 31, 2017 and 2016. See Note 19 for more information.
NOTE 9. INVESTMENTS
DOMINION ENERGY
Equity and Debt Securities
RABBI TRUST SECURITIES
Marketable equity and debt securities and cash equivalents held in Dominion Energy’s rabbi trusts and classified as trading totaled $112 million and $104 million at December 31, 2017 and 2016, respectively.
DECOMMISSIONING TRUST SECURITIES
Dominion Energy holds marketable equity and debt securities (classified as available-for-sale), 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) Included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
(2) Includes pending sales of securities of $5 million and $9 million at December 31, 2017 and 2016, respectively.
(3) The fair value of securities in an unrealized loss position was $565 million and $576 million at December 31, 2017 and 2016, respectively.
The fair value of Dominion Energy’s marketable debt securities held in nuclear decommissioning trust funds at December 31, 2017 by contractual maturity is as follows:
Presented below is selected information regarding Dominion Energy’s marketable equity and debt securities 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
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, $13 million and $9 million at December 31, 2017, 2016 and 2015, respectively.
VIRGINIA POWER
Virginia Power holds marketable equity and debt securities (classified as available-for-sale), 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) Included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
(2) Includes pending sales of securities of $6 million and $7 million at December 31, 2017 and 2016, respectively.
(3) The fair value of securities in an unrealized loss position was $234 million and $287 million at December 31, 2017 and 2016, respectively.
The fair value of Virginia Power’s marketable debt securities at December 31, 2017, by contractual maturity is as follows:
Presented below is selected information regarding Virginia Power’s marketable equity and debt securities 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.
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, $8 million and $6 million at December 31, 2017, 2016 and 2015, 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 $17 million associated with NedPower recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets as of December 31, 2017. See additional discussion of NedPower below.
Dominion Energy’s equity earnings on its investments totaled $14 million, $111 million and $56 million in 2017, 2016 and 2015, respectively, included in other income in Dominion Energy’s Consolidated Statements of Income. Dominion Energy received distributions from these investments of $419 million, $104 million and $83 million in 2017, 2016 and 2015, respectively. As of December 31, 2017 and 2016, the carrying amount of Dominion Energy’s investments exceeded its share of underlying equity in net assets by $249 million and $260 million, respectively. These differences are comprised at both December 31, 2017 and 2016 of $176 million, reflecting equity method goodwill that is not being amortized and at December 31, 2017 and 2016, of $73 million and $84 million related to basis differences from Dominion Energy’s investments in Blue Racer and 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 the credit facility.
Dominion Energy Gas’ equity earnings on its investment totaled $21 million in 2017 and 2016 and $23 million in 2015. Dominion Energy Gas received distributions from its investment of $24 million, $22 million and $28 million in 2017, 2016 and 2015, respectively. As of December 31, 2017 and 2016, 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
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 is 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, which is included in property, plant and equipment in Dominion Energy Gas’ Consolidated Balance Sheets.
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, 2017, 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. Public Service Company of North Carolina, Inc. also plans to be a customer of the pipeline under a 20-year contract. 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 $129 million, $95 million and $74 million in 2017, 2016 and 2015, respectively, included in operating revenue in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income. Amounts receivable related to these services were $12 million and $10 million at December 31, 2017 and 2016, 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 $310 million, $184 million and $38 million during 2017, 2016 and 2015, respectively, to Atlantic Coast Pipeline.
Dominion Energy received distributions of $270 million in 2017 from Atlantic Coast Pipeline. No distributions were received in 2016 or 2015.
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 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.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 10. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment and their respective balances for the Companies are as follows:
DOMINION ENERGY AND VIRGINIA POWER
Jointly-Owned Power Stations
Dominion Energy’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2017 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.
Acquisition of Solar Projects
In September 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The first acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2018, and cost approximately $140 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 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.
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 recognized $11 million during 2017, with the remaining $35 million to be recognized ratably through 2023.
DOMINION ENERGY AND DOMINION ENERGY GAS
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 provide 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 operations and maintenance expense 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 will receive total consideration of $130 million, with $65 million received in 2017 and $65 million to be received by the end of the third quarter of 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 other operations and maintenance expense 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 other operations and maintenance expense in Dominion Energy Gas’ Consolidated Statements of Income associated with the elimination of its overriding royalty interest and expects to recognize an approximately $65 million ($47 million after-tax) gain 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 addi-
tional 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 other operations and maintenance expense 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 the first quarter of 2018.
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. This transaction resulted in a $27 million ($16 million after-tax) gain, included in other operations and maintenance expense in Dominion Energy Gas’ Consolidated Statements of Income.
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 September 2015, Dominion Energy Gas received proceeds of $52 million associated with the conveyance of the acreage, resulting in a $52 million ($29 million after-tax) gain, included in other operations and maintenance expense in Dominion Energy Gas’ Consolidated Statements of Income.
DOMINION ENERGY
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 other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income. Dominion Energy is expected to recognize a benefit of approximately $65 million ($48 million after-tax) in other operations and maintenance expense upon closing of the second phase of the agreement in 2018. 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.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 11. GOODWILL AND INTANGIBLE ASSETS
Goodwill
The changes in Dominion Energy’s 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 $80 million, $73 million and $78 million for 2017, 2016 and 2015, respectively. In 2017, Dominion Energy acquired $147 million of intangible assets, primarily representing software and right-of-use assets, with an estimated weighted-average amortization period of approximately 14 years. Amortization expense for Virginia Power’s intangible assets was $31 million, $29 million and $25 million for 2017, 2016 and 2015, respectively. In 2017, Virginia Power acquired $39 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 7 years. Dominion Energy Gas’ amor-
tization expense for intangible assets was $14 million, $6 million and $18 million for 2017, 2016 and 2015, respectively. In 2017, Dominion Energy Gas acquired $25 million of intangible assets, primarily representing software and right-of-use assets, with an estimated weighted-average amortization period of approximately 14 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) Primarily reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects 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.
(2) 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.
(3) Reflects unrecovered gas costs at regulated gas operations, which are recovered through filings with the applicable regulatory authority.
(4) Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Dominion Energy’s and Virginia Power’s generation operations. See Note 13 for more information.
(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’s and Dominion Energy Gas’ rate-regulated subsidiaries.
(6) 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.
(7) Reflects amount related to the PJM transmission cost allocation matter. See Note 13 for more information.
(8) 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.
(9) Amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes. See below for discussion of the 2017 Tax Reform Act.
Combined Notes to Consolidated Financial Statements, Continued
(10) 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.
(11) 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 rate adjustment clause according to East Ohio tariff provisions. See Note 13 for more information.
(12) Current regulatory liabilities are presented in other current liabilities in the Consolidated Balance Sheets of the Companies.
(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) Current regulatory assets are presented in other current assets in the Consolidated Balance Sheets of Dominion Energy Gas.
At December 31, 2017, $390 million of Dominion Energy’s, $273 million of Virginia Power’s and $11 million of Dominion Energy Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. With the exception of the $222 million 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 matters for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.
FERC-ELECTRIC
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public util-
ities. Dominion Energy’s merchant generators sell electricity in the PJM, MISO, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in the wholesale market. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.
Rates
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
In March 2010, 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 whole-
sale transmission customers filed petitions for rehearing. While Virginia Power cannot predict the outcome of the matter, it is not expected to have a material effect on results of operations.
PJM Transmission Rates
In April 2007, FERC issued an order regarding its transmission rate design for the allocation of costs among PJM transmission customers, including Virginia Power, for transmission service provided by PJM. For new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a PJM regional rate design where customers pay according to each customer’s share of the region’s load. For recovery of costs of existing facilities, FERC approved the existing methodology whereby a customer pays the cost of facilities located in the same zone as the customer. A number of parties appealed the order to the U.S. Court of Appeals for the Seventh Circuit.
In August 2009, the court issued its decision affirming the FERC order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above for further consideration by FERC. On remand, FERC reaffirmed its earlier decision to allocate the costs of new facilities 500 kV and above according to the customer’s share of the region’s load. A number of parties filed appeals of the order to the U.S. Court of Appeals for the Seventh Circuit. In June 2014, the court again remanded the cost allocation issue to FERC. In December 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the cost allocation issue. The hearing only concerns the costs of new facilities approved by PJM prior to February 1, 2013. Transmission facilities approved after February 1, 2013 are allocated on a hybrid cost allocation method approved by FERC and not subject to any court review.
In June 2016, PJM, the PJM transmission owners and state commissions representing substantially all of the load in the PJM market submitted a settlement to FERC to resolve the outstanding issues regarding this matter. Under the terms of the settlement, Virginia Power would be required to pay approximately $200 million to PJM over the next 10 years. Although the settlement agreement has not been accepted by FERC, and the settlement is opposed by a small group of parties to the proceeding, Virginia Power believes it is probable it will be required to make payment as an outcome of the settlement. Accordingly, as of December 31, 2017, Virginia Power has a contingent liability of $231 million in other deferred credits and other liabilities, which is offset by a $222 million regulatory asset for the amount that will be recovered through retail rates in Virginia.
FERC-GAS
In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations. 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 other operations and maintenance expense in Dominion Energy’s 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. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the other findings and no amounts have been recognized.
2017 TAX REFORM ACT
Subsequent to the enactment of the 2017 Tax Reform Act, the Companies’ state regulators issued orders requesting that public utilities evaluate the total tax impact on the entity’s cost of service and accrue a regulatory liability attributable to the benefits of the reduction in the corporate income tax rate. Certain of the orders requested that the public utilities submit a response to the state regulatory commissions detailing the total tax impact on the utility’s cost of service.
Virginia Power submitted a response to the North Carolina Commission detailing the impact of the 2017 Tax Reform Act on base non-fuel cost of service and Virginia Power’s excess deferred income taxes clarifying that the amounts have been deferred to a regulatory liability. Questar Gas submitted a response to the Utah Commission detailing the impact of the 2017 Tax Reform Act on base rates and the infrastructure rider, and proposing that the benefits be passed back to customers. These filings are pending. Dominion Energy plans to respond to the remaining state regulatory commissions in accordance with the due dates on the issued orders. The Companies will begin to reserve the impacts of the cost of service reduction as a regulatory liability beginning in 2018 until the rates are reset.
To date, the FERC has not issued guidance on how and when to reflect the impacts of the 2017 Tax Reform Act in customer rates.
The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate. Through actions by FERC or state regulators the estimates may be subject to changes that could have a material impact on the Companies’ results of operations, financial condition and/or cash flows.
Other Regulatory Matters
ELECTRIC REGULATION IN VIRGINIA
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 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.
If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings,
Combined Notes to Consolidated Financial Statements, Continued
differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.
Regulation Act Legislation
In February 2015, the Virginia Governor signed legislation into law which will keep Virginia Power’s base rates unchanged until at least December 1, 2022. In addition, no biennial reviews will be conducted by the Virginia Commission for the five successive 12-month test periods beginning January 1, 2015, and ending December 31, 2019. The legislation states that Virginia Power’s 2015 biennial review, filed in March 2015, would proceed for the sole purpose of reviewing and determining whether any refunds are due to customers based on earnings performance for generation and distribution services during the 2013 and 2014 test periods. In addition, the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility’s ROE for use in connection with rate adjustment clauses and requires utilities to file integrated resource plans annually rather than biennially. In November 2015, the Virginia Commission ordered testimony, briefs and a separate bifurcated hearing in Virginia Power’s then-pending Rider B, R, S, and W cases on whether the Virginia Commission can adjust the ROE applicable to these rate adjustment clauses prior to 2017. In February 2016, the Virginia Commission issued final orders in these cases, stating that it could adjust the ROE for the projects. After separate, additional bifurcated hearings, the Virginia Commission issued final orders setting base ROEs for the Rider GV, C1A and C2A, BW, US-2 and U cases.
In February 2016, certain industrial customers of APCo petitioned the Virginia Commission to issue a declaratory judgment that Virginia legislation enacted in 2015 keeping APCo’s base rates unchanged until at least 2020 (and Virginia Power’s base rates unchanged until at least 2022) is unconstitutional, and to require APCo to make biennial review filings in 2016 and 2018. Virginia Power intervened to support the constitutionality of this legislation. In July 2016, the Virginia Commission held in a divided opinion that this legislation is constitutional, and the industrial customers appealed this order to the Supreme Court of Virginia. In November 2016, the Supreme Court of Virginia granted the appeal as a matter of right and consolidated it for oral argument with other similar appeals from the Virginia Commission’s order. In September 2017, the Supreme Court of Virginia affirmed that the legislation is constitutional.
In March 2017, as required by Regulation Act legislation enacted in February 2015, Virginia Power filed an application for the Virginia Commission to determine the general ROE for Virginia Power’s non-transmission rate adjustment clauses. The application supported a 10.5% ROE for these rate adjustment clauses. In November 2017, the Virginia Commission approved a general 9.2% ROE for these rate adjustment clauses.
2015 Biennial Review
In November 2015, the Virginia Commission issued the 2015 Biennial Review Order. After deciding several contested regulatory earnings adjustments, the Virginia Commission ruled that Virginia Power earned on average an ROE of approximately 10.89% on its generation and distribution services for the combined 2013 and 2014 test periods. Because this ROE was more than 70 basis points above Virginia Power’s authorized ROE of
10.0%, the Virginia Commission ordered that approximately $20 million in excess earnings be credited to customer bills based on usage in 2013 and 2014 over a six-month period beginning within 60 days of the 2015 Biennial Review Order.
Virginia Fuel Expenses
In May 2017, Virginia Power submitted its annual fuel factor to the Virginia Commission to recover an estimated $1.6 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2017. Virginia Power’s proposed fuel rate represented a fuel revenue increase of $279 million when applied to projected kilowatt-hour sales for the period July 1, 2017 to June 30, 2018. In June 2017, the Virginia Commission approved Virginia Power’s proposed fuel rate.
Solar Facility Projects
In February 2017, Virginia Power received approval from the Virginia Commission for a CPCN to construct and operate the Remington solar facility and related distribution interconnection facilities. The 20 MW facility began operations in October 2017 at a total cost of $45 million, excluding financing costs. The facility is the subject of a public-private partnership whereby the Commonwealth of Virginia, a non-jurisdictional customer, compensates Virginia Power for the facility’s net electrical energy output, and Microsoft Corporation purchases all environmental attributes (including renewable energy certificates) generated by the facility. There is no rate adjustment clause associated with this CPCN, nor will any costs of the project be recovered from jurisdictional customers.
In March 2017, Virginia Power received Virginia Commission approval for a CPCN to construct and operate the Oceana solar facility and related distribution interconnection facilities. The 18 MW facility began operations in December 2017 at a total cost of $40 million, excluding financing costs. The facility is the subject of a public-private partnership whereby the Commonwealth of Virginia, a non-jurisdictional customer, compensates Virginia Power for the facility’s net electrical energy output. Virginia Power will retire renewable energy certificates on the Commonwealth of Virginia’s behalf in an amount equal to those generated by the facility. There is no rate adjustment clause associated with the facility, nor will any of its costs be recovered from jurisdictional customers.
Rate Adjustment Clauses
Below is a discussion of significant riders associated with various Virginia Power projects:
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The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2017, Virginia Power proposed a $625 million total revenue requirement consisting of $490 million for the transmission component of Virginia Power’s base rates and $135 million for Rider T1. This total revenue requirement represents a $55 million decrease versus the revenues to be produced during the rate year under current rates. In July 2017, the Virginia Commission approved the proposed total revenue requirement, including Rider T1, subject to true-up, for the rate year beginning September 1, 2017.
•
The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In February 2017, the Virginia Commission approved a $243 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017. It also established a 10.4% ROE effective April 1, 2017. In February 2018, the Virginia Commission approved a $218 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2018. It also established a 10.2% base ROE effective April 1, 2018.
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The Virginia Commission previously approved Rider W in conjunction with Warren County. In February 2017, the Virginia Commission approved a $121 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017. It also established a 10.4% ROE effective April 1, 2017. In February 2018, the Virginia Commission approved a $109 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2018. It also established a 10.2% ROE for Rider W effective April 1, 2018.
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The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In February 2017, the Virginia Commission approved a $72 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017. It also established a 10.4% ROE effective April 1, 2017. In February 2018, the Virginia Commission approved a $66 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2018. It also established a 10.2% ROE for Rider R effective April 1, 2018.
•
The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In February 2017, the Virginia Commission approved a $27 million revenue requirement for the rate year beginning April 1, 2017. It also established an 11.4% ROE effective April 1, 2017. In June 2017, Virginia Power proposed a $42 million revenue requirement for the rate year beginning April 1, 2018, which represents a $15 million increase over the previous year. This case is pending.
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The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by prior Virginia legislation. In September 2017, the Virginia Commission approved a total $22 million annual revenue requirement effective October 1, 2017, using a 9.4% ROE, and a total capital investment of $40 million for second phase conversions.
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The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In June 2017, the Virginia Commission approved a $28 million revenue requirement, subject to true-up, for the rate year beginning July 1, 2017. It also established a 9.4% ROE for Riders C1A and C2A effective July 1, 2017. In October 2017, Virginia Power requested approval to extend one existing energy efficiency program for five years with a new $25 million cost cap, and proposed a total $31 million revenue requirement for the rate year beginning July 1, 2018, which represents a $3 million increase over the previous year. This case is pending.
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The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In April 2017, the Virginia Commission established a 10.4% ROE for Rider BW effective September 1, 2017. In June 2017, it approved a
$127 million revenue requirement, subject to true-up, for the rate year beginning September 1, 2017. In October 2017, Virginia Power proposed a $132 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. This case is pending.
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The Virginia Commission previously approved Rider US-2 in conjunction with the Scott Solar, Whitehouse, and Woodland solar facilities. In April 2017, the Virginia Commission established a 9.4% ROE for Rider US-2 effective September 1, 2017. In June 2017, the Virginia Commission approved a $10 million revenue requirement, subject to true-up, for the rate year beginning September 1, 2017. In October 2017, Virginia Power proposed a $15 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. This case is pending.
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The Virginia Commission previously approved Rider GV in conjunction with Greensville County. In February 2017, the Virginia Commission approved an $82 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017. It also established a 9.4% ROE effective April 1, 2017. In February 2018, the Virginia Commission approved an $82 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2018. It also established a 9.2% ROE effective April 1, 2018.
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. These lawsuits are pending.
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
Combined Notes to Consolidated Financial Statements, Continued
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 $55 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. This matter is pending.
In November 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate in multiple Virginia counties an approximately 38 mile overhead 230 kV transmission line between the Remington and Gordonsville substations, along with associated facilities. In August 2017, the Virginia Commission granted a CPCN for the project. The total estimated cost of the project is approximately $105 million.
In March 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 33 miles of the existing 500 kV transmission line between the Cunningham switching station and the Dooms substation, along with associated station work. In May 2017, the Virginia Commission granted a CPCN to construct and operate the project. The total estimated cost of the project is approximately $60 million.
In August 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 28 miles of the existing 500 kV transmission line between the Carson switching station and a terminus located near the Rogers Road switching station under construction in Greensville County, Virginia, along with associated work at the Carson switching station. In March 2017, the Virginia Commission granted a CPCN to construct and operate the project. The total estimated cost of the project is approximately $55 million.
In January 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and rearrange its Idylwood substation in Fairfax County, Virginia. In September 2017, the Virginia Commission granted a CPCN for the project. The total estimated cost of the project is approximately $110 million.
In June 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in Prince William County, Virginia, approximately 9 miles of existing 115 kV transmission lines between Possum Point Switching Station and NOVEC’s Smoketown delivery point, utilizing 230 kV design on the majority of the route, for total estimated cost of approximately $20 million. In February 2018, the Virginia Commission granted a CPCN for the project.
In September 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in Augusta County, Virginia approximately 18 miles of the existing 500 kV transmission line between the Dooms substation and the Valley substation, along with associated substation work, for a total estimated cost of approximately $65 million. This case is pending.
In November 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to build and operate in Fairfax County, Virginia approximately 4 miles of 230 kV transmission line between the Idylwood and Tysons substations, along with associated substation work. The total estimated cost of the project is approximately $125 million. This case is pending.
In February 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in Lancaster County, Virginia and Middlesex County, Virginia and across the Rappahannock River, approximately 2 miles of existing 115 kV transmission lines between Harmony Village Substation and White Stone Substation. In December 2017, the Virginia Commission granted a CPCN for the project to be constructed under the Rappahannock River. The total estimated cost of the project is approximately $85 million.
North Anna
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna nuclear power station. If Virginia Power decides to build a new unit, it would require a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In June 2017, the NRC issued the COL. Virginia Power has not yet committed to building a new nuclear unit at North Anna nuclear power station.
Requests by BREDL for a contested NRC hearing on Virginia Power’s COL application were dismissed, and in September 2016, the U.S. Court of Appeals for the D.C. Circuit dismissed with prejudice petitions for judicial review that BREDL and other organizations had filed challenging the NRC’s reliance on a rule generically assessing the environmental impacts of continued onsite storage of spent nuclear fuel in various licensing proceedings, including Virginia Power’s COL proceeding. This dismissal followed the Court’s June 2016 decision in New York v. NRC, upholding the NRC’s continued storage rule and August 2016 denial of requests for rehearing en banc. Therefore, the contested portion of the COL proceeding was closed. The NRC is required to conduct a hearing in all COL proceedings. This mandatory NRC hearing was held in March 2017, was uncontested and the resulting NRC decision authorized issuance of the COL.
In August 2016, Virginia Power received a 60-day notice of intent to sue from the Sierra Club alleging Endangered Species Act violations. The notice alleges that the U.S. Army Corps of Engineers failed to conduct adequate environmental and consultation reviews, related to a potential third nuclear unit located at North Anna, prior to issuing a CWA section 404 permit to Virginia Power in September 2011. No lawsuit was filed and in November 2016, the Army Corps of Engineers suspended the section 404 permit while it gathered additional information. The section 404 permit was reinstated in April 2017.
NORTH CAROLINA REGULATION
In August 2017, 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 $15 million increase to the fuel component of its electric rates for the rate year beginning January 1, 2018. In January 2018, the North Carolina Commission approved Virginia Power’s proposed fuel charge adjustment.
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 permitted 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 2017, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2016 costs. The filing reflects gross plant investment for 2016 of $188 million, cumulative gross plant investment of $1.2 billion and a revenue requirement of $157 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 2017, the Ohio Commission approved East Ohio’s application to adjust its AMR cost recovery rate for 2016 costs. The filing reflects a revenue requirement of approximately $6 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 the rules of the Ohio Commission. In July 2017, East Ohio’s annual update of the PIPP Rider was automatically approved by the Ohio Commission after a 45-day waiting period from the date of the filing. The revised rider rate reflects the recovery over the twelve-month period from July 2017 through June 2018 of projected deferred program costs of approximately $19 million from April 2017 through June 2018, net of a refund for over-recovery of accumulated arrearages of approximately $20 million as of March 31, 2017.
UEX Rider
East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In September 2017, 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 $12 million as of March 31, 2017, and recovery of prospective net bad debt expense projected to total approximately $22 million for the twelve-month period from April 2017 to March 2018.
Ohio Legislation
In March 2017, the Governor of Ohio signed legislation into law that allows utilities to file an application to recover infrastructure development costs associated with economic development projects. The new cost recovery provision allows for projects totaling up to $22 million for East Ohio subject to Ohio Commission approval.
DSM Rider
East Ohio has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In December 2017, East Ohio filed an application with the Ohio Commission seeking approval of an adjustment to the DSM rider to recover a total of $5 million, which includes an under-recovery of costs during the preceding 12-month period. This application is pending.
WEST VIRGINIA REGULATION
In October 2017, the West Virginia Commission approved Hope’s application for new PREP customer rates, for the year beginning November 1, 2017, that provide for projected revenue of $4 million related to capital investments of $21 million, $27 million and $31 million for 2016, 2017 and 2018, respectively.
UTAH AND WYOMING REGULATION
In October 2017, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $25 million gas cost increase reflecting forecasted increases in commodity and transportation costs. The Utah Commission and the Wyoming Commission both approved the filings in October 2017 with rates effective November 2017.
FERC-GAS
Cove Point
In November 2016, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with 23 proposed rates to be effective January 1, 2017. Cove Point proposed an annual cost-of-service of approximately $140 million. In December 2016, FERC accepted a January 1, 2017 effective date for all proposed rates but five which were suspended to be effective June 1, 2017. Under the terms of the settlement agreement filed by Cove Point in August 2017 and approved by FERC in November 2017, Cove Point’s rates effective October 2017 result in decreases to annual revenues and depreciation expense of approximately $18 million and $3 million, respectively, compared to the rates in effect through December 2016.
DETI
In September 2017, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $39 million. Also in September 2017, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $6 million. In October 2017, FERC approved these adjustments.
Combined Notes to Consolidated Financial Statements, Continued
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’s and Virginia Power’s AROs are primarily associated with the decommissioning 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’s 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’s 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 2016 and 2017 were as follows:
(1) Primarily reflects AROs assumed in the Dominion Energy Questar Combination. See Note 3 for further information.
(2) Primarily reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 for further information.
(3) Includes $249 million and $263 million reported in other current liabilities at December 31, 2016, and 2017, respectively.
(4) Includes $147 million and $146 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2016 and 2017, respectively.
Dominion Energy and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 2017 and 2016, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of equity and debt securities, totaled $5.1 billion and $4.5 billion, respectively. At December 31, 2017 and 2016, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $2.4 billion and $2.1 billion, respectively.
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, 2017, Dominion Energy owns the general partner, 50.6% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owns a preferred equity interest and the general partner interest in Cove Point. Additionally, 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 limited partners or 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 Dominion Energy Midstream, SBL Holdco and the merchant solar facilities, and Dominion Energy Midstream is the primary beneficiary of Cove Point, as they have 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 $30 million and $332 million, respectively, of debt issued in 2016 by SBL Holdco net of issuance costs that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in the merchant solar facilities.
Dominion Energy owns a 48% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the 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’s 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 five 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 2015 and two additional contracts 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 $200 million as of December 31, 2017. Virginia Power paid $86 million, $144 million, and $200 million for electric capacity and $24 million, $31 million, and $83 million for electric energy to these entities for the years ended December 31, 2017, 2016 and 2015, 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 $340 million and $126 million, $346 million and $123 million, and $318 million and $115 million for the years ended December 31, 2017, 2016 and 2015, respectively. 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
Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:
Combined Notes to Consolidated Financial Statements, Continued
(1) These credit facilities mature in April 2020 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.
(2) The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s credit facilities were 1.61% and 1.05% at December 31, 2017 and 2016, respectively.
Questar Gas’ short-term financing is supported through its access as co-borrower to the two joint revolving credit facilities discussed above with Dominion Energy, Virginia Power and Dominion Energy Gas. At December 31, 2017, the aggregate sub-limit for Questar Gas was $250 million. In December 2016, Questar Gas entered into a commercial paper program pursuant to which it began accessing the commercial paper markets.
Dominion Energy has indicated its intention to replace the existing two joint revolving credit facilities with a $6.0 billion joint revolving credit facility in the first quarter of 2018. Terms and covenants of the new credit facility are expected to be similar to the existing credit facilities, including that Virginia Power, Dominion Energy Gas and Questar Gas will remain as co-borrowers, except that the maturity will be in five years and the maximum allowed total debt to total capital ratio, with respect to Dominion Energy only, will be increased from 65% to 67.5%. In February 2018, Virginia Power, as co-borrower, filed with the Virginia Commission for approval.
In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which have 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 have 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, 2017, no amounts were outstanding under either of these facilities.
In February 2018, Dominion Energy borrowed $950 million under a 364-Day Term Loan Agreement that bears interest at a variable rate. In addition, the agreement contains a maximum allowed total debt to total capital ratio of 67.5%.
VIRGINIA POWER
Virginia Power’s short-term financing is supported through its access as co-borrower to the two joint revolving credit facilities. These credit facilities 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 full amount of the facilities is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. Sub-limits for Virginia Power are set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2017, the sub-limit for Virginia Power was an aggregate $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. These facilities mature in April 2020 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.
(2) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 1.65% and 0.97% at December 31, 2017 and 2016, respectively.
In addition to the credit facility commitments mentioned above, Virginia Power also has a $100 million credit facility with a maturity date of April 2020. As of December 31, 2017, this facility supports $100 million of certain variable rate tax-exempt financings of Virginia Power. In February 2018, Virginia Power provided notice to redeem all $100 million of outstanding variable rate tax-exempt financings supported by this credit facility.
DOMINION ENERGY GAS
Dominion Energy Gas’ short-term financing is supported by its access as co-borrower to the two joint revolving credit facilities. These credit facilities 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) A maximum of a combined $1.5 billion of the facilities 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. Sub-limits for Dominion Energy Gas are set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2017, the sub-limit for Dominion Energy Gas was an aggregate $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. These credit facilities mature in April 2020 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.
(2) The weighted-average interest rate of the outstanding commercial paper supported by these credit facilities was 1.57% and 1.00% at December 31, 2017 and 2016, respectively.
NOTE 17. LONG-TERM DEBT
(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2017.
(2) Amount includes foreign currency remeasurement adjustments.
(3) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. As of December 31, 2017, certain variable rate tax-exempt financings are supported by a $100 million credit facility that terminates in April 2020. In February 2018, Virginia Power provided notice to redeem three series of variable rate tax-exempt financings with an aggregate outstanding principal of $100 million. The financings would otherwise mature in 2024, 2026 and 2027.
(4) Represents variable rate Massachusetts Development Finance Agency Solid Waste Disposal Revenue Bonds due in 2041 repaid in August 2017.
Combined Notes to Consolidated Financial Statements, Continued
(5) Represents debt assumed by Dominion Energy from the merger of its former CNG subsidiary.
(6) Represents debt obligations of Dominion Energy Questar or Questar Gas. See Note 3 for more information.
(7) 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’s and Dominion Solar Projects III, Inc.’s interest in certain merchant solar facilities.
(8) Represents debt obligations of a DGI subsidiary.
(9) Represents debt obligations of Dominion Energy Questar Pipeline. See Note 3 for more information.
(10) Represents the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt.
(11) Excludes $250 million of Dominion Energy Questar Pipeline’s senior notes that matured in February 2018 which were repaid using proceeds from the January 2018 issuance, through private placement, of $100 million of 3.53% senior notes and $150 million of 3.91% senior notes that mature in 2028 and 2038, respectively.
(12) 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, 2017, 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, 2017, $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 2018, $250 million of Dominion Energy Questar Pipeline’s senior notes were repaid using proceeds from the January 2018 issuance, through private placements, of $100 million of 3.53% senior notes and $150 million of 3.91% senior notes that mature in 2028 and 2038, respectively. As a result, at December 31, 2017, $250 million was included in long-term debt in the Consolidated Balance Sheets.
The Companies short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2017, there were no events of default under these covenants.
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. Beginning June 30, 2016, 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 pro-
ceeds Dominion Energy receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.
In 2015, Dominion Energy purchased and cancelled $14 million and $3 million of the June 2006 hybrids and the September 2006 hybrids, respectively. 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, 2017, 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 obligate 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 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.
Combined Notes to Consolidated Financial Statements, Continued
Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion Energy will issue between 15.0 million and 18.8 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 $101 million and $94 million were made in 2017 and 2016, respectively, including payments for the remarketed 2013 Series A and B notes and the remarketed 2014 Series A notes. The stock purchase contract liability was $111 million and $212 million at December 31, 2017 and 2016, 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, 2017 or 2016.
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, 2017 or 2016.
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. In January 2014, Dominion Energy began purchasing its common stock on the open market for these plans. In April 2014, Dominion Energy began issuing new common shares for these direct stock purchase plans.
During 2017, Dominion Energy received cash proceeds, net of fees and commissions, of $1.3 billion from the issuance of approximately 17 million shares of common stock through various programs resulting in approximately 645 million shares of common stock outstanding at December 31, 2017. These proceeds include cash of $302 million received from the issuance of 3.8 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 has 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 has no remaining ability to issue stock under the 2017 sales agency agreements and has completed the program.
VIRGINIA POWER
In 2017, 2016 and 2015, Virginia Power did not issue any shares of its common stock to Dominion Energy.
Shares Reserved for Issuance
At December 31, 2017, Dominion Energy had approximately 67 million shares reserved and available for issuance for Dominion Energy Direct®, employee stock awards, employee savings plans, director stock compensation plans and issuance in connection with stock purchase contracts. See Note 17 for more information.
Repurchase of Common Stock
Dominion Energy did not repurchase any shares in 2017 or 2016 and does not plan to repurchase shares during 2018, except for shares tendered by employees to satisfy tax withholding obligations 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 and 887,000 common units for $25 million for the years ended December 31, 2016 and 2015, respectively.
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 are entitled to receive cumulative quarterly distributions payable in cash or additional convertible preferred units, subject to certain conditions. The units are 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. The conversion of such units would result in a potential increase to Dominion Energy’s net income attributable to noncontrolling interests.
Combined Notes to Consolidated Financial Statements, Continued
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:
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.
Combined Notes to Consolidated Financial Statements, Continued
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. At December 31, 2017, approximately 23 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,
2017, 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, 2017, 2016 and 2015 include $45 million, $33 million, and $39 million, respectively, of compensation costs and $16 million, $11 million, and $14 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 from time to time. 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, 2017, 2016 and 2015:
As of December 31, 2017, unrecognized compensation cost related to nonvested restricted stock awards totaled $42 million and is expected to be recognized over a weighted-average period of 2.0 years. The fair value of restricted stock awards that vested was $21 million, $21 million, and $37 million in 2017, 2016 and 2015, 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%
Combined Notes to Consolidated Financial Statements, Continued
of the targeted amount based on the level of performance metrics achieved.
In February 2015, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 2017 based on the achievement of two performance metrics during 2015 and 2016: 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 $10 million.
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.
In February 2017, two cash-based performance grants were made to officers as the Company transitioned from a two-year performance period to a three-year performance period. Payout of the two-year grant is expected to occur by March 15, 2019 based on the achievement of two performance metrics during 2017 and 2018: TSR relative to that of companies that are members of the Company’s compensation peer group and ROIC. At December 31, 2017, the targeted amount of the two-year grant was $15 million and a liability of $7 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 the Company’s compensation peer group and ROIC. At December 31, 2017, the targeted amount of the three-year grant was $15 million and a liability of $5 million had been accrued for the 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, 2017, the Virginia Commission had not restricted the payment of dividends by Virginia Power.
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, 2017, the Ohio Commission had not restricted the payment of dividends by East Ohio.
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, 2017, the Utah Commission had not restricted the payment of dividends by Questar Gas.
Certain agreements associated with the Companies’ credit facilities contain 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, 2017.
As part of the SCANA Merger Agreement, Dominion Energy shall 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 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 of $1.6 billion and $534 million in 2017 and 2016, respectively, versus expected returns of $767 million and $691 million, respectively. Dominion Energy Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns of $335 million and $130 million in 2017 and 2016, respectively, versus expected returns of $165 million and $157 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.
In October 2014, the Society of Actuaries published new mortality tables and mortality improvement scales. Such tables and scales are used to develop mortality assumptions for use in determining pension and other postretirement benefit liabilities and expense. Following evaluation of the new tables, Dominion Energy changed its assumption for mortality rates to reflect a generational improvement scale. This change in assumption increased net periodic benefit cost for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units) by $25 million and $3 million, respectively, for 2015.
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’s 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. 2016 amount relates primarily to a plan amendment that changed post-65 retiree medical coverage for certain current and future Local 50 retirees effective April 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. 2016 amount relates primarily to a settlement for certain executives.
(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 $8.2 billion and $7.3 billion at December 31, 2017 and 2016, respectively. The ABO for the defined benefit pension plans covering Dominion Energy Gas employees represented by collective bargaining units was $724 million and $640 million at December 31, 2017 and 2016, 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 2017, Dominion Energy and Dominion Energy Gas made no contributions to the qualified defined benefit pension plans other than a $75 million contribution to Dominion Energy’s qualified pension plan to satisfy a regulatory condition to closing of the Dominion Energy Questar Combination and no contributions are currently expected in 2018. In July 2012, the MAP 21 Act was signed into law. This Act includes an increase in the interest rates used to determine plan sponsors’ pension contributions for required funding purposes. In 2014, the HATFA of 2014 was signed into law. Similar to the MAP 21 Act, the HATFA of 2014 adjusts the rules for calculating interest rates used in determining funding obligations. It is estimated that the new interest rates will reduce required pension contributions through 2019. Dominion Energy believes that required pension contributions will rise subsequent to 2019, resulting in an estimated $200 million reduction in net cumulative required contributions over a 10-year period.
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 2017 and 2016, and Dominion Energy expects to contribute approximately $12 million to the Dominion Energy VEBAs in 2018, 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 2018.
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’s 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
Combined Notes to Consolidated Financial Statements, Continued
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 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 further 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’s 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 $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. Excludes net assets related to pending sales of securities of $46 million, net accrued income of $19 million, and includes net assets related to pending purchases of securities of $47 million at December 31, 2016.
(3) 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. Excludes net assets related to pending sales of securities of $10 million, net accrued income of $4 million, and includes net assets related to pending purchases of securities of $10 million at December 31, 2016.
Combined Notes to Consolidated Financial Statements, Continued
The fair values of Dominion Energy’s 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 $1 million at December 31, 2017. Excludes net assets related to pending sales of securities of $5 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $5 million at December 31, 2016.
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.
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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.
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Government Securities-Investments are valued using pricing models maximizing the use of observable inputs for similar securities.
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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.
Combined Notes to Consolidated Financial Statements, Continued
NET PERIODIC BENEFIT (CREDIT) COST
Net periodic benefit (credit) cost is reflected in other operations and maintenance expense 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’s 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.
The components of AOCI and regulatory assets and liabilities for Dominion Energy’s 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, 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. As of December 31, 2016, of the $3.2 billion and $(136) million related to pension benefits and other postretirement benefits, $1.9 billion and $(103) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.
(2) 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. As of December 31, 2016, of the $458 million related to pension benefits, $167 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $67 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’s and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans as of December 31, 2017 that are expected to be amortized as components of net periodic benefit (credit) cost in 2018:
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;
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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 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 stock market indices; 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’s 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 2017, Virginia Power and Dominion Energy Gas made no con-
Combined Notes to Consolidated Financial Statements, Continued
tributions to the Dominion Energy Pension Plan, and no contributions to this plan are currently expected in 2018. Virginia Power’s net periodic pension cost related to this plan was $110 million, $79 million and $97 million in 2017, 2016 and 2015, respectively. Dominion Energy Gas’ net periodic pension credit related to this plan was $(37) million, $(45) million and $(38) million in 2017, 2016 and 2015, 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 $(42) million, $(29) million and $(16) million in 2017, 2016 and 2015, respectively. Dominion Energy Gas’ net periodic benefit (credit) cost related to this plan was $(5) million, $(4) million and $(5) million for 2017, 2016 and 2015, 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 2017 and 2016, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2018. Dominion Energy Gas made no contributions to the VEBAs for employees not represented by collective bargaining units during 2017 and 2016 and does not expect to contribute in 2018.
Defined Contribution Plans
Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2017, 2016 and 2015, Dominion Energy recognized $45 million, $44 million and $43 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 sub-
sidiaries. During 2017, 2016 and 2015, Dominion Energy Gas recognized $7 million as employer matching contributions to these plans. Virginia Power also participates in these employee savings plans. During 2017, 2016 and 2015, Virginia Power recognized $19 million, $19 million and $18 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 for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial position, liquidity or results of operations of the Companies.
Environmental Matters
The Companies are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
AIR
CAA
The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements.
MATS
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. Following a one-year compliance extension granted by VDEQ and an additional one-year extension under an EPA Administrative Order, 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 approximately 23 months following the receipt in July 2017 of final permits and approvals for construction. 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 2018. The Sierra Club has challenged the DOE order and certain renewal requests, all of which have been denied by the DOE.
Although litigation of the MATS rule is 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.
The statutory deadline for the EPA to complete attainment designations for a new standard was October 2017. States will have three years after final designations, certain of which were issued by the EPA in November 2017, 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 is installing emission control systems on existing engines at several compressor stations in Pennsylvania. The compliance costs associated with engineering and installation of controls and compliance demonstration with the regulation are expected to be 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 April 2017, the EPA issued a notice that it is reviewing the rule and, if appropriate, will issue a rulemaking to suspend, revise or rescind the June 2016 final NSPS for certain oil and gas facilities. In June 2017, the EPA published notice of reconsideration and partial stay of the rule for 90 days and proposed extending the stay for two years. In July 2017, the U.S. Court of Appeals for the D.C. Circuit vacated the 90-day stay. In November 2017, the EPA solicited comments on the proposed two-year stay of the June 2016 NSPS rules. 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
Combined Notes to Consolidated Financial Statements, Continued
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’s 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. DECG joined the EPA’s voluntary Natural Gas STAR Program in July 2016 and submitted an implementation plan in September 2016. 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. 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’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.
In September 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule establishes updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. Virginia Power has eight facilities subject to the final rule. 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’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.
WASTE MANAGEMENT AND REMEDIATION
The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.
From time to time, Dominion Energy, Virginia Power, or Dominion Energy Gas may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion Energy, Virginia Power, or Dominion Energy Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. The Companies do not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.
Dominion Energy has determined that it is associated with 19 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. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.
See below for discussion on ash pond and landfill closure costs.
Other Legal Matters
The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.
APPALACHIAN GATEWAY
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. This case is pending. At December 31, 2017, DETI has accrued a liability of $2 million for this matter. Dominion Energy Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.
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. All other 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. This case is pending.
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. Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. This rule created a legal obligation for Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary.
In 2015, Virginia Power recorded a $386 million ARO related to future ash pond and landfill closure costs, which resulted in a $99 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $166 million increase in property, plant and equipment associated with asset retirement costs, and a $121 million reduction in other noncurrent liabilities from the reversal of a previously recorded contingent liability since the ARO obligation created by the final CCR rule represents similar
Combined Notes to Consolidated Financial Statements, Continued
activities. 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. Litigation concerning the CCR rule is pending and the EPA has submitted to the court a list of which CCR rule provisions the EPA intends to reevaluate. 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 April 2017, the Virginia Governor 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. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the obligation.
COVE POINT
Dominion Energy has constructed the Liquefaction Project at the Cove Point facility, which, once commercially operational, would enable the facility to liquefy domestically-produced natural gas and export it as LNG. In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project.
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. Separately, one party requested a stay of the FERC order until the judicial proceedings are complete, which the court denied in June 2015. In July 2016, the court denied one party’s petition for review of the FERC order authorizing the Liquefaction Project. The court also issued a decision remanding the other party’s petition for review of the FERC order to FERC for further explanation of FERC’s decision that a previous transaction with an existing import shipper was not unduly discriminatory. In September 2017, FERC issued its order on remand from the U.S. Court of Appeals for the D.C. Circuit, and reaffirmed its ruling in its prior orders that Cove Point did not violate the prohibition against undue discrimination by agreeing to a capacity reduction and early contract termination with the existing import shipper. In October 2017, the party filed a request for rehearing of the FERC order on remand. This case is pending.
In September 2013, the DOE granted Non-FTA Authorization approval for the export of up to 0.77 bcfe/day of natural gas to countries that do not have an FTA for trade in natural gas. In June 2016, a party filed a petition for review of this approval in the U.S. Court of Appeals for the D.C. Circuit. In November 2017, the U.S. Court of Appeals for the D.C. Circuit issued an order denying the petition for review.
In July 2017, Cove Point submitted an application for a temporary operating permit to the Maryland Department of the Environment, as required prior to the date of first production of LNG for commercial purposes of exporting LNG. The permit was received in December 2017. In February 2018, the Public Service Commission of Maryland issued an order approving Cove Point’s August 2017 application to amend the CPCN issued by the Public Service Commission of Maryland in May 2014 to make necessary updates.
FERC
FERC staff in the Office of Enforcement, Division of Investigations, is conducting 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 has provided its response to FERC staff’s preliminary findings letter explaining why Virginia Power’s conduct was lawful and refuting any allegation of wrongdoing. Virginia Power is cooperating fully with the investigation; however, it cannot currently predict whether or to what extent it may incur a material liability.
GREENSVILLE COUNTY
Virginia Power is constructing Greensville County and related transmission interconnection facilities. In August 2016, the Sierra Club filed an administrative appeal in the Circuit Court for the City of Richmond challenging certain provisions in Greensville County’s PSD air permit issued by VDEQ in June 2016. In August 2017, the Circuit Court upheld the air permit, and no appeals were filed.
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 appropria-
tions 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. Reevaluation of the seismic and external flooding hazards is expected to continue through 2018. 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 2017 calculation for the NRC minimum financial assurance amount, aggregated for Dominion Energy’s and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.7 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 2017 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2017 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 up to $13.44 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion Energy and Virginia Power have purchased $450 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. However, the NRC granted an exemption in March 2015 to remove Kewaunee from the Secondary Financial Protection program. The current levels of nuclear property insurance coverage for Dominion Energy’s and Virginia Power’s nuclear units are as follows:
(1) Surry and North Anna share a blanket property limit of $200 million.
Dominion Energy’s and Virginia Power’s nuclear property insurance coverage for Millstone, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. Kewaunee meets the NRC minimum requirement of $1.06 billion. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion Energy’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $86 million and $50 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
Combined Notes to Consolidated Financial Statements, Continued
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’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $22 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’s 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 plants have been extended to provide for periodic payments for damages incurred through December 31, 2016, and have been extended to provide for periodic payment of damages through December 31, 2019. Pursuit of or possible settlement of the Kewaunee claims for damages incurred after December 31, 2013 is being evaluated.
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.
In 2015, Virginia Power and Dominion Energy received payments of $8 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2013 through December 31, 2013, and $17 million for resolution of claims incurred at Millstone for the period of July 1, 2013 through June 30, 2014.
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 $46 million and $56 million at December 31, 2017 and 2016, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $30 million and $37 million at December 31, 2017 and 2016, respectively.
Dominion Energy and Virginia Power will continue to manage their spent fuel until it is accepted by the DOE.
Long-Term Purchase Agreements
At December 31, 2017, 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 a power purchase contract with a qualifying facility and an independent power producer, which ends in 2021. Capacity payments under the contract are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2017, the present value of Virginia Power’s total commitment for capacity payments is $221 million. Capacity payments totaled $114 million, $248 million, and $305 million, and energy payments totaled $72 million, $126 million, and $198 million for the years ended 2017, 2016 and 2015, 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 and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2017 are as follows:
(1) Amounts include a lease agreement for the Dominion Energy Questar corporate office, which is accounted for as a capital lease. At December 31, 2017 and 2016, the Consolidated Balance Sheets include $27 million and $30 million, respectively, in property, plant and equipment and $33 million and $35 million, respectively, in other deferred credits and other liabilities. The Consolidated Statements of Income include $3 million and less than $1 million recorded in depreciation, depletion and amortization for the years ended December 31, 2017 and 2016.
Rental expense for Dominion Energy totaled $113 million, $104 million, and $99 million for 2017, 2016 and 2015, respectively. Rental expense for Virginia Power totaled $57 million, $52 million, and $51 million for 2017, 2016 and 2015, respectively. Rental expense for Dominion Energy Gas totaled $34 million, $37 million, and $37 million for 2017, 2016 and 2015, 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 $139 million as of December 31, 2017. 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, 2017, Atlantic Coast Pipeline has borrowed $664 million against the revolving credit facility. Dominion Energy’s Consolidated Balance Sheet includes a liability of $28 million associated with this guarantee agreement at December 31, 2017.
In addition, at December 31, 2017, 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, 2017, 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, 2017, Dominion Energy’s maximum remaining cumulative exposure under these equity funding agreements is $17 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $14 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, 2017, Dominion Energy had purchased $153 million of surety bonds, including $63 million at Virginia Power and $24 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $76 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.
As of December 31, 2017, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. The related debt matures in 2031 and is included in long-term debt in Virginia Power’s Consolidated Balance Sheets. In the event of default by a conduit, Virginia Power would be obligated to repay such amounts, which are limited to the principal and interest then outstanding.
Indemnifications
As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount
Combined Notes to Consolidated Financial Statements, Continued
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, 2017, 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, 2017 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 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, 2017, Dominion Energy’s credit exposure totaled $95 million. Of this amount, investment grade counterparties, including those internally rated, represented 26%, and no single counterparty, whether investment grade or non-investment grade, exceeded $13 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, 2017, Virginia Power’s credit exposure totaled $60 million. Of this amount, investment grade counterparties, including those internally rated, represented 9%, and no single counterparty, whether investment grade or non-investment grade, exceeded $13 million of exposure.
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, 2017, Dominion Energy Gas’ credit exposure totaled $15 million. Of this amount, investment grade counterparties, including those internally rated, represented 22%, and no single counterparty, whether investment grade or non-investment grade, exceeded $4 million of exposure.
In 2017, DETI provided service to 289 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 68% 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 98% 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 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, 2017 and 2016, Dominion Energy would have been required to post an additional $62 million and $3 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, 2017 and 2016, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. 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, 2017 and 2016 was $65 million and $9 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, 2017 and 2016. 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’s 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 commodity swaps, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 19 for more information. As of December 31, 2017, Virginia Power’s derivative assets and liabilities with affiliates were $11 million and $5 million, respectively. As of December 31, 2016, Virginia Power’s derivative assets and liabilities with affiliates were $41 million and $8 million, respectively.
Virginia Power participates in certain Dominion Energy benefit plans as described in Note 21. At December 31, 2017 and 2016, Virginia Power’s amounts due to Dominion Energy asso-
ciated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $505 million and $396 million, respectively. At December 31, 2017 and 2016, 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 $199 million and $130 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 service. 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 $144 million, $144 million and $143 million for the year ended December 31, 2017, 2016 and 2015, respectively.
Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $33 million and $262 million in short-term demand note borrowings from Dominion Energy as of December 31, 2017 and 2016, respectively. The weighted-average interest rate of these borrowings was 1.65% and 0.97% at December 31, 2017 and 2016, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 2017 and 2016. Interest charges related to Virginia Power’s borrowings from Dominion Energy were immaterial for the years ended December 31, 2017, 2016 and 2015.
There were no issuances of Virginia Power’s common stock to Dominion Energy in 2017, 2016 or 2015.
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, which are presented separately from contracts involving
Combined Notes to Consolidated Financial Statements, Continued
commodities or services. As of December 31, 2017 and 2016, 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, 2017 and 2016, 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 $734 million and $697 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 $7 million and $2 million at December 31, 2017 and 2016, 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 $45 million, $49 million and $57 million for the year ended December 31, 2017, 2016 and 2015, respectively.
(2) Amounts primarily attributable to Atlantic Coast Pipeline.
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 $18 million and $118 million as of December 31, 2017 and 2016, respectively. The weighted-average interest rate of these borrowings was 1.60% and 1.08% at December 31, 2017 and 2016, respectively. Interest charges related to Dominion Energy Gas’ total borrowings from Dominion Energy were immaterial for 2017, 2016 and 2015.
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 2017, Dominion Energy reported an after-tax net benefit of $389 million in the Corporate and Other segment, with $861 million of the net benefit attributable to specific items related to its operating segments.
The net benefit 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).
In 2015, Dominion Energy reported after-tax net expenses of $391 million in the Corporate and Other segment, with $136 million of these net expenses attributable to specific items related to its operating segments.
The net expenses for specific items in 2015 primarily related to the impact of the following items:
•
A $99 million ($60 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation; and
•
An $85 million ($52 million after-tax) write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015, attributable to Power Generation.
Combined Notes to Consolidated Financial Statements, Continued
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 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.
In 2015, Virginia Power reported after-tax net expenses of $153 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2015 primarily related to the impact of the following items:
•
A $99 million ($60 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation; and
•
An $85 million ($52 million after-tax) write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015, 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 2017, Dominion Energy Gas reported after-tax net expenses 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.
In 2015, Dominion Energy Gas reported after-tax net expenses of $21 million in its Corporate and Other segment, with $13 million of these net expenses attributable to specific items related to its operating segment.
The net expenses for specific items in 2015 primarily related to the impact of the following item:
•
$16 million ($10 million after-tax) ceiling test impairment charge.
Combined Notes to Consolidated Financial Statements, Continued
The following table presents segment information pertaining to Dominion Energy Gas’ operations:
NOTE 26. QUARTERLY FINANCIAL AND COMMON STOCK DATA (UNAUDITED)
A summary of the Companies’ quarterly results of operations for the years ended December 31, 2017 and 2016 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 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
Dominion Energy’s 2016 results include the impact of the following significant item:
•
Fourth quarter results include a $122 million after-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities.
VIRGINIA POWER
Virginia Power’s quarterly results of operations were as follows:
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.
Virginia Power’s 2016 results include the impact of the following significant item:
•
Fourth quarter results include a $121 million after-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities.
DOMINION ENERGY GAS
Dominion Energy Gas’ quarterly results of operations were as follows:
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.
There were no significant items impacting Dominion Energy Gas’ 2016 quarterly results.
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 consolidated 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 2017 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, 2017, 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, 2017. 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, 2017.
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 27, 2018
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, 2017, 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, 2017, 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, 2017, of Dominion Energy and our report dated February 27, 2018, 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 27, 2018
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 consolidated 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 2017 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, 2017, 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, 2017. 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, 2017.
This annual report does not include an attestation report of Virginia Power’s independent 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 27, 2018
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’ consolidated 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’ 2017 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, 2017, 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, 2017. 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, 2017.
This annual report does not include an attestation report of Dominion Energy Gas’ independent 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 27, 2018
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 2018 Proxy Statement, which will be filed on or around March 23, 2018:
•
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 2018 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 2018 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 2018 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 2018 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 2018 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, 2017 and 2016.
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 January 2018 meeting, the Dominion Energy Audit Committee approved Virginia Power and Dominion Energy Gas’ schedules of services and fees for 2018. 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 65.
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)
* 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 27, 2018
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 27th day of February, 2018.
Signature
Title
/s/ Thomas F. Farrell, II
Thomas F. Farrell, II
Chairman of the Board of Directors, President and Chief
Executive Officer
/s/ William P. Barr
William P. Barr
Director
/s/ Helen E. Dragas
Helen E. Dragas
Director
/s/ James O. Ellis, Jr.
James O. Ellis, Jr.
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/ Mark F. McGettrick
Mark F. McGettrick
Executive Vice President and Chief Financial Officer
/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 27, 2018
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 27th day of February, 2018.
Signature
Title
/s/ Thomas F. Farrell, II
Thomas F. Farrell, II
Chairman of the Board of Directors and Chief Executive Officer
/s/ Mark F. McGettrick
Mark F. McGettrick
Director, Executive Vice President and Chief Financial Officer
/s/ Mark O. Webb
Mark O. Webb
Director
/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 27, 2018
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 27th day of February, 2018.
Signature
Title
/s/ Thomas F. Farrell, II
Thomas F. Farrell, II
Chairman of the Board of Directors and Chief Executive Officer
/s/ Mark F. McGettrick
Mark F. McGettrick
Director, Executive Vice President and Chief Financial Officer
/s/ Mark O. Webb
Mark O. Webb
Director
/s/ Michele L. Cardiff
Michele L. Cardiff
Vice President, Controller and Chief Accounting Officer