Item 1. Business
GENERAL
Dominion, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion’s strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. As of December 31, 2015, Dominion’s portfolio of assets includes approximately 24,300 MW of generating capacity, 6,500 miles of electric transmission lines, 57,300 miles of electric distribution lines, 12,200 miles of natural gas transmission, gathering and storage pipeline and 22,000 miles of gas distribution pipeline, exclusive of service lines. As of December 31, 2015, Dominion serves over 5 million utility and retail energy customers in 14 states and operates one of the nation’s largest underground natural gas storage systems, with approximately 933 bcf of storage capacity.
In March 2014, Dominion formed Dominion Midstream, an MLP designed to grow a portfolio of natural gas terminaling, processing, storage, transportation and related assets. In October 2014, Dominion Midstream launched its initial public offering and issued 20,125,000 common units (including 2,625,000 common units issued pursuant to the exercise of the underwriters’ over-allotment option) representing limited partner interests. Dominion has recently and may continue to investigate opportunities to acquire assets that meet its strategic objective for Dominion Midstream. At December 31, 2015, Dominion owns the general partner and 64.1% of the limited partner interests in Dominion Midstream, which owns a preferred equity interest and the general partner interest in Cove Point, DCG and a 25.93% noncontrolling partnership interest in Iroquois. Dominion Midstream is consolidated by Dominion, and is an SEC registrant. However, its Form 10-K is filed separately and is not combined herein.
Dominion is focused on expanding its investment in regulated electric generation, transmission and distribution and regulated natural gas transmission and distribution infrastructure. Dominion expects 80% to 90% of earnings from its primary operating segments to come from regulated and long-term contracted businesses.
Dominion 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’s gas and electric transmission and distribution networks, and to meet environmental requirements and standards set by various regulatory bodies. Investments in utility solar generation are expected to be a focus in meeting such environmental requirements, particularly in Virginia. Blue Racer is investing in natural gas gathering and processing assets in Ohio and West Virginia, targeting primarily the Utica Shale formation. In September 2014, Dominion 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 has transitioned to a more regulated, less volatile earnings mix as evidenced by its capital investments in regulated infrastructure and infrastructure whose output is sold under long-term purchase agreements, as well as dispositions of certain merchant generation facilities during 2013 and the sale of the electric retail energy marketing business in March 2014. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and natural gas retail energy marketing operations. Dominion’s operations are conducted through various subsidiaries, including Virginia Power and Dominion 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 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 Virginia Power” and primarily serves retail customers. In North Carolina, it conducts business under the name “Dominion North Carolina Power” 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.
Dominion Gas, a limited liability company formed in September 2013, is a wholly-owned subsidiary of Dominion and a holding company. It serves as the intermediate parent company for the majority of Dominion’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 Gas’ principal wholly-owned subsidiaries are DTI, East Ohio and Dominion Iroquois. DTI 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 DTI system links to other major pipelines and markets in the mid-Atlantic, Northeast, and Midwest including Dominion’s Cove Point pipeline. DTI also operates one of the largest underground natural gas storage systems in the U.S. and is a producer and supplier of NGLs. 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. Dominion Iroquois holds a 24.72% noncontrolling partnership interest in Iroquois, a FERC-regulated interstate natural gas pipeline in New York and Connecticut. All of Dominion Gas’ membership interests are owned by Dominion.
Amounts and information disclosed for Dominion are inclusive of Virginia Power and/or Dominion Gas, where applicable.
EMPLOYEES
At December 31, 2015, Dominion had approximately 14,700 full-time employees, of which approximately 5,300 employees are subject to collective bargaining agreements. At December 31, 2015, Virginia Power had approximately 6,800 full-time employees, of which approximately 3,100 employees are subject to collective bargaining agreements. At December 31, 2015, Dominion Gas had approximately 2,800 full-time employees, of which approximately 2,000 employees 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’s internet website, http://www.dom.com, as soon as reasonably practicable after filing or furnishing the material to the SEC. Information contained on Dominion’s website is not incorporated by reference in this report.
ACQUISITIONS AND DISPOSITIONS
Following are significant acquisitions and divestitures by the Companies during the last five years.
PROPOSED ACQUISITION OF QUESTAR
Under the terms of the Questar Combination announced in February 2016, upon closing, Dominion has agreed to pay Questar’s shareholders approximately $4.4 billion in cash as well as assume Questar’s outstanding debt. Subject to receipt of Questar shareholder and any required regulatory approvals and meeting closing conditions, Dominion targets closing by the end of 2016. See Note 3 to the Consolidated Financial Statements and Liquidity and Capital Resources in Item 7. MD&A for additional information.
ACQUISITION OF WHOLLY-OWNED MERCHANT SOLAR PROJECTS
Throughout 2015, Dominion completed the acquisition of various wholly-owned merchant solar projects in California and Virginia for $381 million. The projects are expected to cost approximately $588 million to construct, including the initial acquisition cost, and are expected to generate approximately 182 MW.
Throughout 2014, Dominion 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 approximately 179 MW.
See Note 3 to the Consolidated Financial Statements for additional information.
ACQUISITION OF NON-WHOLLY-OWNED MERCHANT SOLAR PROJECTS
In 2015, Dominion acquired 50% of the units in Four Brothers and Three Cedars from SunEdison for $107 million. The projects are expected to cost approximately $1.2 billion to construct, including the initial acquisition cost. The facilities are expected to begin commercial operations in the third quarter of 2016, generating approximately 530 MW. See Note 3 to the Consolidated Financial Statements for additional information.
SALE OF INTEREST IN MERCHANT SOLAR PROJECTS
In September 2015, Dominion 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 approximately 425 MW, to SunEdison for approximately $300 million. 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. See Note 3 to the Consolidated Financial Statements for additional information.
DOMINION MIDSTREAM ACQUISITION OF INTEREST IN IROQUOIS
In September 2015, Dominion 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 Midstream’s common units at closing. The common units issued to NG and NJNR are reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. See Note 3 to the Consolidated Financial Statements for additional information.
ACQUISITION OF DCG
In January 2015, Dominion completed the acquisition of 100% of the equity interests of DCG from SCANA Corporation for $497 million in cash, as adjusted for working capital. In April 2015, Dominion contributed DCG to Dominion Midstream. See Note 3 to the Consolidated Financial Statements for additional information.
SALE OF ELECTRIC RETAIL ENERGY MARKETING BUSINESS
In March 2014, Dominion 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. See Note 3 to the Consolidated Financial Statements for additional information.
SALE OF PIPELINES AND PIPELINE SYSTEMS
In March 2014, Dominion Gas sold the Northern System to an affiliate that subsequently sold the Northern System to Blue Racer for consideration of $84 million. Dominion Gas’ consideration consisted of $17 million in cash proceeds and the extinguishment of affiliated current borrowings of $67 million and Dominion’s consideration consisted of cash proceeds of $84 million.
In September 2013, DTI sold Line TL-388 to Blue Racer for $75 million in cash proceeds.
In December 2012, East Ohio sold two pipeline systems to an affiliate for consideration of $248 million. East Ohio’s consideration consisted of $61 million in cash proceeds and the extinguishment of affiliated long-term debt of $187 million and Dominion’s consideration consisted of a 50% interest in Blue Racer and cash proceeds of $115 million.
See Note 9 to the Consolidated Financial Statements for additional information on sales of pipelines and pipeline systems.
ASSIGNMENTS OF SHALE DEVELOPMENT RIGHTS
In March 2015, Dominion 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. Also in March 2015, Dominion 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 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 Gas, subject to customary adjustments, of $52 million and an overriding royalty interest in gas produced from the acreage.
In November 2014, Dominion 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 provides for payments to Dominion 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 December 2013, Dominion 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 provide for payments to Dominion Gas, subject to customary adjustments, of approximately $200 million over a period of nine years, and overriding royalty interest in gas produced from that acreage.
See Note 10 to the Consolidated Financial Statements for additional information on these sales of Marcellus acreage.
SALE OF BRAYTON POINT, KINCAID AND EQUITY METHOD INVESTMENT IN ELWOOD
In August 2013, Dominion 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 included in the Corporate and Other segment and presented in discontinued operations. See Note 3 to the Consolidated Financial Statements for additional information.
OPERATING SEGMENTS
Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued, which is discussed in Note 3 to the Consolidated Financial Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s other operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion 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 allocating resources among the segments.
Dominion Gas manages its daily operations through its primary operating segment: Dominion Energy. 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.
While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by the Companies and their respective legal subsidiaries.
A description of the operations included in the Companies’ primary operating segments is as follows:
(1) Includes remaining producer services activities.
(2) As a result of Dominion’s decision to realign its business units effective for 2015 year-end reporting, nonregulated retail energy marketing operations were moved from the Dominion Generation segment to the Dominion Energy segment. See Note 25 to the Consolidated Financial Statements for additional information.
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.
DVP
The DVP Operating Segment of Dominion and Virginia Power includes Virginia Power’s regulated electric transmission and distribution (including customer service) operations, which serve approximately 2.5 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.
DVP’s existing five-year investment plan includes spending approximately $7.7 billion from 2016 through 2020 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. The proposed electric delivery infrastructure projects are intended to address both continued customer growth and increases in electricity consumption by the typical consumer. 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 120 minutes at the end of 2015, up from the three-year average of 113 minutes, due to increased weather related outages. Virginia Power’s overall customer satisfaction, however, improved year over year when compared to its 2014 score in the South Large segment of J.D. Power and Associates’ rankings. In the future, safety, electric service reliability and customer service will remain key focus areas for electric distribution.
Revenue provided by Virginia Power’s electric transmission operations is based primarily on rates approved by FERC. The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings primarily results from changes in rates and the timing of property additions, retirements and depreciation.
Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to NERC by EPACT, Virginia Power’s electric transmission operations are committed to meeting NERC standards, modernizing its infrastructure and maintaining superior system reliability. Virginia Power’s electric transmission operations will continue to focus on safety, operational performance, NERC compliance and execution of PJM’s RTEP.
COMPETITION
DVP Operating Segment-Dominion 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 FERC Order 1000, subject to state and local siting and permitting approvals. This could result in additional competition to build transmission lines in Virginia Power’s service area in the future and could allow Dominion to seek opportunities to build facilities in other service territories.
REGULATION
DVP Operating Segment-Dominion and Virginia Power
Virginia Power’s electric retail 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, including a discussion of the February 2015 amendment to the Regulation Act and the 2015 Biennial Review Order.
PROPERTIES
DVP Operating Segment-Dominion and Virginia Power
Virginia Power has approximately 6,500 miles of electric transmission lines of 69 kV or more located in the states of 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 ($150 million);
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Dooms-to-Lexington ($112 million);
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Cunningham-to-Elmont ($106 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) ($105 million);
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Carolina-to-Kerr Dam ($58 million);
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Remington/Gordonsville/Pratts Area Improvement (including Remington-to-Gordonsville, and new Gordonsville substation transformer) ($104 million);
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Kings Dominion-to-Fredericksburg ($51 million); and
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Cunningham-to-Dooms ($110 million).
Over the next 5 years, Virginia Power plans to increase transmission substation physical security and to invest in a new system operations center. Virginia Power expects to invest $300 million-$400 million during that time 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 57,300 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.
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, designed to reduce restoration outage time, has an annual investment cap of approximately $175 million and is expected to be implemented over the next decade. In December 2015, Virginia Power re-filed its application with the Virginia Commission seeking approval to place its most outage-prone overhead distribution lines underground as part of the initial phase of this program.
SOURCES OF ENERGY SUPPLY
DVP Operating Segment-Dominion and Virginia Power
DVP’s supply of electricity to serve Virginia Power customers is produced or procured by Dominion Generation. See Dominion Generation for additional information.
SEASONALITY
DVP Operating Segment-Dominion and Virginia Power
DVP’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 DVP’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.
Dominion Generation
The Dominion 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 the DVP segment’s utility customers. The Dominion Generation Operating Segment of Dominion includes Virginia Power’s generation facilities and its related energy supply operations as well as the generation operations of Dominion’s merchant fleet and energy marketing and price risk management activities for these assets.
Dominion Generation’s existing five-year electric utility investment plan includes spending approximately $8.0 billion from 2016 through 2020 to construct new generation capacity to meet growing electricity demand within its utility service territory and to continue to replace coal-fired generating capacity with less carbon-intensive natural gas and solar. The most significant project currently under construction is Brunswick County, which is estimated to cost approximately $1.2 billion, excluding financing costs. See Properties and Environmental Strategy for additional information on this and other utility projects.
In addition, Dominion’s merchant fleet has acquired and developed numerous renewable generation projects, which include a fuel cell generation facility in Connecticut and solar generation facilities in California, Indiana, Georgia, Tennessee, Utah and Connecticut. The output of these facilities is sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. See Note 3 to the Consolidated Financial Statements for additional information regarding certain solar projects.
Earnings for the Dominion 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 80% 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 Electric Regulation in Virginia under Regulation and Note 13 to the Consolidated Financial Statements for additional information.
The Dominion Generation Operating Segment of Dominion derives its earnings primarily from the sale of electricity generated by Virginia Power’s utility and Dominion’s merchant generation assets, as well as from associated capacity and ancillary services. Variability in earnings provided by Dominion’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 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.
COMPETITION
Dominion Generation Operating Segment-Dominion 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 Regulation-State Regulations-Electric for more information. Currently, North Carolina does not offer retail choice to electric customers.
Dominion Generation Operating Segment-Dominion
Dominion Generation’s recently acquired and developed renewable generation projects are not subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally lasting between 15 and 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 Dominion 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. Dominion 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. These RTOs have clearly identified market rules that ensure the competitive wholesale market is functioning properly. Dominion 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 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.
REGULATION
Dominion Generation Operating Segment-Dominion and Virginia Power
Virginia Power’s utility generation fleet and Dominion’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 Commission and the North Carolina Commission. 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.
The Clean Power Plan and related proposed rules discussed represent a significant regulatory development affecting this segment. See Future Issues and Other Matters in Item 7. MD&A.
PROPERTIES
For a listing of Dominion’s and Virginia Power’s existing generation facilities, see Item 2. Properties.
Dominion Generation Operating Segment-Dominion and Virginia Power
The generation capacity of Virginia Power’s electric utility fleet totals approximately 20,000 MW. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro, renewables 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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In August 2013, the Virginia Commission authorized the construction of Brunswick County, which is estimated to cost approximately $1.2 billion, excluding financing costs. Construction of the facility commenced in the third quarter of 2013 with commercial operations expected to begin in mid-2016. Brunswick County is expected to offset the expected reduction in capacity caused by the retirement of coal-fired units at Chesapeake in December 2014 and at Yorktown as early as 2017, primarily due to the cost of compliance with MATS.
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Virginia Power has filed for approval to construct certain solar facilities in Virginia. See Note 13 to the Consolidated Financial Statements for more information.
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Virginia Power is considering 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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The BOEM auctioned approximately 113,000 acres of federal land off the Virginia coast as a single lease for construction of offshore wind turbines. Virginia Power was awarded the lease, effective November 1, 2013. The BOEM has several lease milestones with which Virginia Power must comply as conditions to being awarded the lease.
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Virginia Power is also considering the development of a commercial offshore wind generation project through a federal land lease off the Virginia coast. Virginia Power and several partners are collaborating to develop a 12 MW offshore wind demonstration project, which is proposed to be located approximately 24 miles off the coast of Virginia. In May 2014, the DOE selected the Virginia Offshore Wind Technology Advancement project as one of three projects to receive up to $47 million of follow-on funding. This project may be operational as early as the end of 2018, pending regulatory approvals.
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Subject to the receipt of certain regulatory approvals, Virginia Power plans to construct and operate Greensville County and related transmission interconnection facilities. If the project is approved, commercial operations are expected to commence in late 2018, at an estimated cost of approximately $1.3 billion, excluding financing costs.
Dominion Generation Operating Segment-Dominion
The generation capacity of Dominion’s merchant fleet totals approximately 4,300 MW. The generation mix is diversified and includes nuclear, natural gas and renewables. Merchant non-renewable generation facilities are located in Connecticut, Pennsylvania and Rhode Island, with a majority of that capacity concentrated in New England. Dominion’s merchant renewable generation facilities include a fuel cell generation facility in Connecticut, solar generation facilities in Indiana, Georgia, California, Tennessee, Utah and Connecticut, and wind generation facilities in Indiana and West Virginia. Additional solar projects under construction are as set forth below:
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In June 2015, Dominion acquired 50% of the units in Four Brothers from SunEdison for $64 million of consideration. Four Brothers’ purpose is to develop and operate four solar projects located in Utah, which will produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $730 million to construct, including the initial acquisition cost. The facilities are expected to begin commercial operations in the third quarter of 2016, generating approximately 320 MW.
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In September 2015, Dominion acquired 50% of the units in Three Cedars from SunEdison for $43 million of consideration. Three Cedars’ purpose is to develop and operate three solar projects located in Utah, which will produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $425 million to construct. The facilities are expected to begin commercial operations in the third quarter of 2016, generating approximately 210 MW.
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In November 2015, Dominion acquired 100% of the equity interests of the Eastern Shore Solar project in Virginia from Community Energy, Inc. for $34 million. The project is expected to cost approximately $212 million once constructed, including the initial acquisition cost. The facility is expected to begin commercial operations in October 2016 and generate approximately 80 MW.
SOURCES OF ENERGY SUPPLY
Dominion Generation Operating Segment-Dominion and Virginia Power
Dominion 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-Dominion 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-Dominion Generation primarily utilizes natural gas and coal in its fossil fuel plants. All recent fossil fuel plant construction for Dominion Generation, with the exception of the Virginia City Hybrid Energy Center, involves natural gas generation.
Dominion 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 or third parties. Dominion 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.
Dominion Generation’s coal supply is obtained through long-term contracts and short-term spot agreements from domestic suppliers.
Biomass-Dominion Generation’s biomass supply is obtained through long-term contracts and short-term spot agreements from local suppliers.
Purchased Power-Dominion Generation purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for utility system load requirements.
Dominion 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.
Dominion 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. The average cost of coal for 2015 Virginia in-system generation was $31.29 per MWh.
(3) Includes oil, hydro, biomass and solar.
SEASONALITY
Dominion Generation Operating Segment-Dominion and Virginia Power
Sales of electricity for Dominion 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 DVP-Seasonality above for additional considerations that also apply to Dominion Generation.
NUCLEAR DECOMMISSIONING
Dominion Generation Operating Segment-Dominion 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. Virginia Power expects to decommission the Surry and North Anna units during the period 2032 to 2078.
Dominion Generation Operating Segment-Dominion
In addition to the four nuclear units discussed above, Dominion has two licensed, operating nuclear reactors at Millstone in Connecticut. A third Millstone unit ceased operations before Dominion acquired the power station. In May 2013, Dominion ceased operations at its single unit Kewaunee 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’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 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 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’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 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’s and Virginia Power’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Dominion’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’s acquisition of Millstone.
(4) Millstone Unit 3 is jointly owned by Dominion Nuclear Connecticut, with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. Decommissioning cost is shown at Dominion’s ownership percentage. At December 31, 2015, the minority owners held $35 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 Note 14 and Note 22 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively, and Note 9 for information about nuclear decommissioning trust investments.
Dominion Energy
The Dominion Energy Operating Segment of Dominion Gas includes the majority of Dominion’s regulated natural gas operations. DTI, the gas transmission pipeline and storage business, serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in the transmission pipeline and storage business is gas gathering and processing activity, which includes the sale of extracted products at market rates. As discussed further under Properties and Investments, Dominion Gas has requested approval from FERC to transfer these gathering and processing assets from DTI to another wholly-owned subsidiary of Dominion Gas. East Ohio, the primary gas distribution business of Dominion, serves residential, commercial and industrial gas sales, transportation and gathering service customers. Dominion Iroquois holds a 24.72% 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.
Earnings for the Dominion Energy Operating Segment of Dominion Gas primarily result from rates established by FERC and the Ohio Commission. The profitability of this business is dependent on Dominion 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 96% of the transmission capacity under contract on DTI’s pipeline is subscribed with long-term contracts (two years or greater). The remaining 4% is contracted on a year-to-year basis. Less than 1% of firm transportation capacity is currently unsubscribed. Less than 1% of storage services are unsubscribed. All contracted storage is subscribed with long-term contracts.
Revenue from processing and fractionation operations largely results from the sale of commodities at market prices. For DTI’s processing plants, Dominion Gas receives the wet gas product from producers and may retain the extracted NGLs as compensation for its services. This exposes Dominion Gas to commodity price risk for the value of the spread between the NGL products and natural gas. In addition, Dominion Gas has volumetric risk as 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.
In addition to the operations of Dominion Gas, the Dominion Energy Operating Segment of Dominion also includes LNG operations, Hope’s gas distribution operations in West Virginia, and nonregulated retail natural gas marketing, as well as Dominion’s investments in the Blue Racer joint venture, Atlantic Coast Pipeline and Dominion Midstream. See Properties and Investments below for additional information regarding the Atlantic Coast Pipeline investment. Dominion’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 has received DOE and FERC approval to export LNG from Cove Point and has begun construction on a bi-directional facility, which will be able to import LNG and vaporize 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 2014, Dominion formed Dominion 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’s acquisition of DCG, which Dominion contributed to Dominion Midstream in April 2015, as well as Dominion Midstream’s acquisition of an additional partnership interest in Iroquois in September 2015.
Blue Racer concentrates on building and operating new gathering, processing, fractionation and NGL transportation assets as the development of the Utica Shale formation increases. Dominion has contributed or sold various assets to the joint venture. See Note 9 to the Consolidated Financial Statements for more information.
Dominion Energy’s existing five-year investment plan includes spending approximately $7.3 billion from 2016 through 2020 to upgrade existing infrastructure or add new pipelines to meet growing energy needs within its service territory and maintain reliability. Demand for natural gas is expected to continue to grow as the Clean Power Plan and other initiatives to transition to gas from more carbon-intensive fuels are implemented. This plan includes spending for the Atlantic Coast Pipeline Project and approximately $1.4 billion, exclusive of financing costs, for the Liquefaction Project.
In addition to the earnings drivers noted above for Dominion Gas, earnings for the Dominion Energy Operating Segment of Dominion primarily include the results of rates established by FERC and the West Virginia Commission. Additionally, Dominion Energy receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain LNG storage and regasification services. Hope’s gas distribution operations in West Virginia serve residential, commercial 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. DCG’s revenues are primarily derived from reservation charges for firm transportation services as provided for in its FERC approved tariff. 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. The processing and fractionation operations within Dominion Energy’s Blue Racer joint venture are primarily managed under long-term fee-based contracts, which minimizes direct commodity price risk. However, commodity prices do impact customer demand for Blue Racer’s services.
Dominion’s retail energy marketing operations compete in nonregulated energy markets. In March 2014, Dominion completed the sale of its electric retail energy marketing business; however, it still participates in the retail natural gas and energy-related products and services businesses. The remaining customer base includes approximately 1.3 million customer accounts. Dominion has a heavy concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice, primarily in the states of Ohio and Pennsylvania.
COMPETITION
Dominion Energy Operating Segment-Dominion and Dominion Gas
Dominion Gas’ natural gas transmission operations compete with domestic and Canadian pipeline companies. Dominion Gas also competes with gas marketers seeking to provide or arrange transportation, storage and other services. Alternative energy 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 to tailor its services to meet the needs of individual customers.
DTI’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, 2015, approximately 1 million of East Ohio’s 1.2 million Ohio customers were participating in the Energy Choice program.
Dominion Energy Operating Segment-Dominion
For Hope, West Virginia does not allow customers to choose their provider in its retail natural gas markets at this time. See Regulation-State Regulations-Gas 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.
DCG’s pipeline system generates a substantial portion of its revenue from long-term firm contracts for transportation services and is therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, DCG’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’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas. Customers in these markets have the right to select a retail marketer and typically do so based upon price savings or price stability; however, incumbent utilities have the advantage of long-standing relationships with their customers and greater name recognition in their markets.
REGULATION
Dominion Energy Operating Segment-Dominion and Dominion Gas
Dominion Gas’ natural gas transmission, storage, processing and gathering 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.
Dominion Energy Operating Segment-Dominion
Cove Point’s and DCG’s operations are regulated primarily by FERC. 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’s and Dominion Gas’ existing facilities see Item 2. Properties.
Dominion Energy Operating Segment-Dominion and Dominion Gas
Dominion Gas has the following significant projects under construction or development to better serve customers or expand its service offerings within its service territory.
In July 2013, East Ohio signed long-term precedent agreements with two customers to move 320,000 Dths per day of processed gas from the outlet of new gas processing facilities in Ohio to interconnections with multiple interstate pipelines. The first phase of the Western Access project provides system enhancements to facilitate the movement of processed gas over East Ohio’s system. The initial phase of the project was completed in the fourth quarter of 2014 and cost approximately $85 million. During the second and third quarters of 2014, East Ohio executed long-term precedent agreements with customers for 450,000 Dths per day of service to new interconnects with interstate pipelines. This second phase of the Western Access project will expand the number of interstate pipelines to which East Ohio will deliver processed gas to four. East Ohio commenced service to the Western Access II project customers in January 2016 at a cost of approximately $130 million.
In September 2014, DTI announced its intent to construct and operate the Supply Header project which is expected to cost approximately $500 million and provide 1,500,000 Dths per day of firm transportation service to various customers. In October 2014, DTI requested authorization to use FERC’s pre-filing process. The application to request FERC authorization to construct and operate the project facilities was filed in September 2015, with the facilities expected to be in service in the fourth quarter of 2018. In December 2014, DTI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header project.
In June 2014, DTI executed binding precedent agreements with two power generators for the Leidy South project. In November 2014, one of the power generators assigned a portion of its capacity to an affiliate, bringing the total number of project customers to three. The project is expected to cost approximately
$210 million and provide 155,000 Dths per day of firm transportation service from Clinton County, Pennsylvania to Loudoun County, Virginia. The application to request FERC authorization to construct and operate the project facilities was filed in May 2015. Service under the 20-year contracts is expected to commence in the fourth quarter of 2017.
During the second quarter of 2014, DTI executed a binding precedent agreement with a customer for the Monroe-to-Cornwell project. The project is expected to cost approximately $70 million and provide 205,000 Dths per day of firm transportation service from Monroe County, Ohio to an interconnect near Cornwell, West Virginia. In December 2015, DTI received FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service in the fourth quarter of 2016. Construction is expected to commence in March 2016.
In the first quarter of 2014, DTI executed a binding precedent agreement for the Lebanon West II project. The project is expected to cost approximately $112 million and provide 130,000 Dths per day of firm transportation service from Butler County, Pennsylvania to an interconnect with Texas Gas Pipeline in Lebanon, Ohio. In November 2015, DTI received FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service in the fourth quarter of 2016. Construction commenced in January 2016.
In September 2013, DTI executed binding precedent agreements with several local distribution company customers for the New Market project. The project is expected to cost approximately $159 million and provide 112,000 Dths per day of firm transportation service from Leidy, Pennsylvania to interconnects with Iroquois and Niagara Mohawk Power Corporation’s distribution system in the Albany, New York market. In June 2014, DTI filed an application to request FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service in the fourth quarter of 2016.
In October 2013, DTI executed a binding precedent agreement with CNX Gas Company LLC for the Clarington project. The project is expected to cost approximately $78 million and provide 250,000 Dths per day of firm transportation service from central West Virginia to Clarington, Ohio. In August 2015, DTI received FERC authorization to construct, operate and maintain the project facilities. Construction commenced in December 2015. The project is expected to be placed into service in the fourth quarter of 2016.
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 October 2015, DTI filed an application with FERC seeking authority to abandon by sale its gathering and processing facilities to Dominion Gathering and Processing, Inc., a newly-formed wholly-owned subsidiary of Dominion Gas. Pending approval by FERC, these gathering and processing facilities with a carrying value of approximately $430 million are expected to be transferred in 2016.
Dominion Energy Operating Segment-Dominion
Dominion has the following significant projects under construction or development.
Cove Point-Dominion is pursuing the Liquefaction Project, which would enable Cove Point to liquefy domestically-produced natural gas for export as LNG. The DOE previously authorized Dominion to export LNG to countries with free trade agreements. In September 2013, the DOE authorized Dominion to export LNG from Cove Point to non-free trade agreement countries.
In May 2014, the FERC staff issued its EA for the Liquefaction Project. In the EA, the FERC staff addressed a variety of topics related to the proposed construction and development of the Liquefaction Project and its potential impact to the environment, and determined that with the implementation of appropriate mitigation measures, the Liquefaction Project can be built and operated safely with no significant impact to the environment. 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 EA. In October 2014, Cove Point commenced construction of the Liquefaction Project, with an in-service date anticipated in late 2017. 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 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 also announced it had awarded its EPC 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 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 to explore the Liquefaction Project, which, assuming it becomes operational, will extend the economic life of Cove Point and contribute to Dominion’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 2014, DCG executed binding precedent agreements with three customers for the Transco-to-Charleston project. The project is expected to cost approximately $120 million, and provide 80,000 Dths per day of firm transportation service from an existing interconnect with Transcontinental Gas Pipe Line Company, LLC in Spartanburg County, South Carolina to customers in Dillon, Marlboro, Sumter, Charleston, Lexington and Richland
counties, South Carolina. In July 2015, DCG requested authorization to utilize FERC’s pre-filing process. DCG expects to file the application to request FERC authorization to construct and operate the project facilities in the first quarter of 2016. The project is expected to be placed into service in the fourth quarter of 2017.
Dominion Energy Equity Method Investments-In September 2015, Dominion, through Dominion Midstream, acquired an additional 25.93% interest in Iroquois. Dominion Gas holds a 24.72% interest with TransCanada holding a 44.48% interest and TEN Transmission Company holding a 4.87% 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’s equity method investment in Iroquois.
In September 2014, Dominion, along with Duke Energy, Piedmont and AGL, announced the formation of Atlantic Coast Pipeline. The members, which are subsidiaries of the above-referenced parent companies, hold the following membership interests: Dominion, 45%; Duke Energy, 40%; Piedmont, 10%; and AGL, 5%. In October 2015, Duke Energy entered into a merger agreement with Piedmont. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, which has a total expected cost of $4.5 billion to $5.0 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. It filed its FERC application in September 2015 and expects to be in service in late 2018. The project is subject to FERC, state and other federal approvals. See Note 9 to the Consolidated Financial Statements for further information about Dominion’s equity method investment in Atlantic Coast Pipeline.
In December 2012, Dominion 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 and Caiman, with Dominion 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 leverage Dominion’s existing presence in the Utica region with significant 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’s equity method investment in Blue Racer.
SOURCES OF ENERGY SUPPLY
Dominion’s and Dominion 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 and gas marketers. Dominion’s and Dominion 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 and mid-Atlantic regions. Dominion’s and Dominion 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’s and Dominion Gas’ underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Northeast, mid-Atlantic and Midwest 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’s retail energy marketing customers is procured through market wholesalers or by Dominion Energy.
SEASONALITY
Dominion Energy’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 the straight-fixed-variable rate design at East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipeline 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’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 Gas
Virginia Power’s and Dominion 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 allocating resources among the segments.
Corporate and Other Segment-Dominion
Dominion’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued, which is discussed in Note 3 and Note 25 to the Consolidated Financial Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
REGULATION
The Companies are subject to regulation by various federal, state and local authorities, including the Virginia Commission, North Carolina Commission, Ohio Commission, West Virginia Commission, Maryland Commission, 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, transfers of certain facilities and the issuance of certain securities.
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, 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. However, in November 2015, the Virginia Commission ordered testimony, briefs and separate bifurcated
hearing in Virginia Power’s currently pending Rider B, Rider R, Rider S and Rider W cases on whether the Virginia Commission can adjust the ROE applicable to these rate adjustment clauses prior to 2017. The legislation also required Virginia Power to write-off $85 million of prior-period deferred fuel costs during the first quarter of 2015. In addition, the legislation required the Virginia Commission to implement a fuel rate reduction for Virginia Power as soon as practicable based on this non-recovery as well as any over-recovery for the 2014-2015 fuel year and projected fuel expense for the 2015-2016 fuel year. The legislation also deems the construction or purchase of one or more utility-scale solar facilities located in Virginia up to 500 MW in total to be in the public interest.
2015 Biennial Review
Pursuant to the Regulation Act, in March 2015, Virginia Power filed its base rate case and schedules for the Virginia Commission’s 2015 biennial review of Virginia Power’s rates, terms and conditions. Per legislation enacted in February 2015, this biennial review was limited to reviewing Virginia Power’s earnings on rates for generation and distribution services for the combined 2013 and 2014 test period, and determining whether credits are due to customers in the event Virginia Power’s earnings exceeded the earnings band determined in the 2013 Biennial Review Order. 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. Based upon 2015 legislation keeping Virginia Power’s base rates unchanged until at least December 1, 2022, the Virginia Commission did not order certain existing rate adjustment clauses to be combined with Virginia Power’s base rates. The Virginia Commission did not determine whether Virginia Power had a revenue deficiency or sufficiency when projecting the annual revenues generated by base rates to the revenues required to recover costs of service and earn a fair return. In December 2015, a group of large industrial customers filed notices of appeal with the Supreme Court of Virginia from both the 2015 Biennial Review Order and the Virginia Commission’s order denying their petition for rehearing or reconsideration. This appeal is pending.
See Note 13 to the Consolidated Financial Statements for additional information.
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. In March 2012, Virginia Power filed an application with the North Carolina Commission to increase base non-fuel revenues with January 1, 2013 as the proposed effective date for the permanent rate revision. In December 2012, the North Carolina Commission approved a $36 million increase in Virginia Power’s annual non-fuel base revenues based on an authorized ROE of 10.2%, and a $14 million decrease in annual base fuel revenues for a combined total base revenue increase of $22 million. These rate changes became effective on January 1, 2013. Following an appeal to the Supreme Court of North Carolina, the North Carolina Commission issued an opinion reaffirming its 10.2% ROE determination in July 2015.
In August 2015, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed an $11 million decrease to the fuel component of its electric rates for the rate year beginning January 1, 2016. This decrease includes the North Carolina Commission’s previous approval to defer recovering 50% of Virginia Power’s estimated $17 million jurisdictional deferred fuel balance to the 2016 fuel year, without interest. In December 2015, the North Carolina Commission approved Virginia Power’s proposed fuel charge adjustment.
See Note 13 to the Consolidated Financial Statements for additional information.
GAS
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 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 which included an authorized ROE of 10.38%.
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
Dominion’s gas distribution subsidiary 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.
Status of Competitive Retail Gas Services
Both of the states in which Dominion and Dominion 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, 2015,
approximately 1.0 million of Dominion 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’s merchant generators sell electricity in the PJM, MISO, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Tennessee, Georgia, California and Utah, under Dominion’s market-based sales tariffs authorized by FERC. 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 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 and Virginia Power are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between Virginia Power and Dominion’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 million per day, per violation and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
Dominion and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion 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 and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cybersecurity programs as well as efforts to ensure appropriate facility ratings for Virginia Power’s transmission lines. In October 2010, NERC issued an industry alert identifying possible discrepancies between the design and actual field conditions of transmission facilities as a potential reliability issue. The alert recommends that entities review their current facilities rating methodology to verify that the methodology is based on actual field conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power has evaluated its transmission facilities for any discrepancies between design and actual field conditions and has taken necessary corrective actions. In addition, NERC has redefined critical assets which expanded the number of assets subject to NERC reliability standards, including cybersecurity assets. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above 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 DTI, DCG, Iroquois and certain services performed by Cove Point. Pursuant to FERC’s February 2014 approval of DTI’s uncontested settlement offer, DTI’s base rates for storage and transportation services are subject to a moratorium through the end of 2016. 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 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 Gas operates 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 Gas also makes certain informational postings available on Dominion’s website.
See Note 13 to the Consolidated Financial Statements for additional information.
Safety Regulations
Dominion Gas is 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 Gas has evaluated its 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. Nothwithstanding 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. There are significant new regulations affecting Dominion’s electric generation and gas businesses in the Clean Power Plan and NSPS regulating methane and VOC emissions, respectively. If expenditures for GHG emissions reductions and pollution control technologies 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 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.
GLOBAL CLIMATE CHANGE
The national and international attention in recent years on 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 address climate change while meeting the growing needs of their service territory. The Companies are actively developing plans to comply with new Clean Power Plan and NSPS regulations for new and existing electric generating sources and its natural gas business. Dominion’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including climate change, and Dominion’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. Dominion must comply with applicable aspects of the CWA programs at its operating facilities.
THREATENED AND ENDANGERED SPECIES
The Endangered Species Act establishes prohibitions on activities that can result in harm of specific species of plants and animals. In some cases those prohibitions could result in impacts to the viability of projects or requirements for capital expenditures to reduce a facility’s impacts on a species.
Nuclear Regulatory Commission
All aspects of the operation and maintenance of Dominion’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’s and Virginia Power’s nuclear generating units. See Note 22 to the Consolidated Financial Statements for further information.
The NRC also requires Dominion and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and Dominion and Virginia Power are required by the NRC to be financially prepared. For information on decommissioning trusts, see Dominion 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
Environmental stewardship is embedded in the Companies’ culture and core values and is the responsibility of all employees. They are committed to working with their stakeholders to find sustainable solutions to the energy and environmental challenges that confront our company and our nation. It is the Companies’ belief that sustainable solutions must balance the interdependent goals of environmental stewardship and economic prosperity. Their integrated strategy to meet this objective consists of four major elements:
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Compliance with applicable environmental laws, regulations and rules;
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Conservation and load management;
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Renewable generation development; and
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Improvements in other energy infrastructure, including natural gas operations.
This strategy incorporates the Companies’ efforts to voluntarily reduce GHG emissions, which are described below. See Dominion Generation-Properties and Dominion Energy-Properties for more information on certain of the projects described below.
Environmental Compliance
The Companies remain committed to compliance with applicable environmental laws, regulations and rules related to their operations. As part of their commitment to compliance with such laws, Dominion and Virginia Power have sold or closed a number of coal-fired generation units over the past several years, and have plans to close additional units in the future. A significant recent development in environmental regulation was the EPA’s issuance in August 2015 of final carbon standards for existing fossil fuel power plants known as the Clean Power Plan, which involves coordination with the states on specific plans to reduce carbon emissions to specified levels. In February 2016, the U.S. Supreme Court stayed the Clean Power Plan pending resolution of litigation challenging the regulations. Additional information related to these and other of the Companies’ environmental compliance matters can be found in Operating Segments and Future Issues and Other Matters in Item 7. MD&A and in Notes 3, 6 and 22 to the Consolidated Financial Statements.
Conservation and Load Management
Conservation and load management play a significant role in meeting the growing demand for electricity. 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 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.
In Ohio, East Ohio offers three DSM programs, approved by the Ohio Commission, designed to help customers reduce their energy consumption.
Virginia Power continues to upgrade meters to AMI, also referred to as smart meters, in areas throughout Virginia. The AMI meter upgrades are part of an ongoing project that will help Virginia Power further evaluate the effectiveness of AMI meters in monitoring voltage stability, remotely turning off and on electric service, power outage and restoration detection and reporting, remote daily meter readings and offering dynamic rates.
Renewable Generation
Renewable energy is also an important component of a diverse and reliable energy mix. Both Virginia and North Carolina have passed legislation setting targets for renewable power. Virginia Power 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 plans to add utility solar capacity in Virginia.
See Operating Segments and Item 2. Properties for additional information, including Dominion’s merchant solar properties.
Improvements in Other Energy Infrastructure
Virginia Power’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 and address environmental requirements. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service, and are intended to address both continued population growth and increases in electricity consumption by the typical consumer. 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. See Properties in Item 1., Operating Segments, DVP for additional information.
Dominion and Dominion 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. See Properties and Investments in Item 1., Operating Segments, Dominion Energy for additional information, including natural gas infrastructure projects.
The Companies’ Strategy for Voluntarily Reducing GHG Emissions
The Companies have not established a standalone GHG emissions reduction target or timetable, but they are actively engaged in voluntary reduction efforts. The Companies have an integrated voluntary strategy for reducing GHG emission intensity with diversification as its cornerstone. The six principal components of the strategy include initiatives that address electric energy management, electric energy production, electric energy delivery and natural gas storage, transmission and delivery, as follows:
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Enhance conservation and energy efficiency programs to help customers use energy wisely and reduce environmental impacts;
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Expand the Companies’ renewable energy portfolio, principally wind power, solar, fuel cells and biomass, to help diversify the Companies’ fleet, meet state renewable energy targets and lower the carbon footprint;
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Evaluate other new generating capacity, including low emissions natural-gas fired and emissions-free nuclear units to meet customers’ future electricity needs;
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Construct new electric transmission infrastructure to modernize the grid, promote economic security and help deliver more green energy to population centers where it is needed most;
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Construct new natural gas infrastructure to expand availability of this cleaner fuel, to reduce emissions, and to promote energy and economic security both in the U.S. and abroad; and
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Implement and enhance voluntary methane mitigation measures through the EPA’s Natural Gas Star Program.
Since 2000, Dominion 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 2000 to annual year 2014, 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 39%. Comparing annual year 2000 to annual year 2014, the regulated electric generating fleet (based on ownership percentage) reduced its average CO2 emissions rate per MWh of energy produced from electric generation by approximately 20%. Dominion and Virginia Power do not yet have final 2015 emissions data.
Dominion also developed a comprehensive GHG inventory for calendar year 2014. For Dominion Generation, Dominion’s and Virginia Power’s direct CO2 equivalent emissions, based on equity share (ownership), were 33.6 million metric tons and 30.1 million metric tons, respectively, in 2014, compared to 33.9 million metric tons and 30.2 million metric tons, respectively, in 2013. For the DVP operating segment’s electric transmission and distribution operations, direct CO2 equivalent emissions for 2014 were 75,671 metric tons, compared to 46,446 metric tons in 2013. The increase was due to new containing equipment purchased and installed to handle growth in the electric transmission and distribution system. Although emissions from the equipment increased, the leak rate has remained relatively consistent at 1.1%. For 2014, DTI’s and Cove Point’s direct CO2 equivalent emissions together were 1.3 million metric tons, and Hope’s and East Ohio’s direct CO2 equivalent emissions together were 0.9 million metric tons, similar to 2013. Dominion’s GHG inventory follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98 for calculating emissions.
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’s and Dominion 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’s and Dominion Gas’ gas transmission and distribution operations is based primarily on rates approved by state and federal regulatory agencies. 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’s and Dominion Gas’ gas transmission businesses are subject to review by FERC. Pursuant to FERC’s February 2014 approval of DTI’s uncontested settlement offer, DTI’s base rates for storage and transportation services are subject to a moratorium through
the end of 2016. In addition, the rates of Dominion’s and Dominion Gas’ gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate. A failure by us to support these rates could result in rate decreases from current rate levels, which could adversely affect our 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 the Clean Power Plan 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.
Dominion’s 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’s 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’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’s 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’s 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 fuel type conversions to natural gas and biomass. 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 and construction of several large-scale infrastructure projects simultaneously involves significant execution risk. The Companies are currently simultaneously developing or constructing several major projects, including the Liquefaction Project, the Atlantic Coast Pipeline Project, the Supply Header project, Greensville County, Brunswick County, and multiple DTI producer outlet projects, which together help contribute to the over $23 billion in capital expenditures planned by the Companies through 2020. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas (for example, the Liquefaction Project) 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, which could impede 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 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 its 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.
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 is targeted at reducing CO2 emissions from existing fossil fuel-fired power generation facilities.
Compliance with the Clean Power Plan may 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. The Clean Power Plan 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. Compliance with the Clean Power Plan’s anticipated implementing regulations may require Virginia Power to prematurely retire certain generating facilities, with the potential lack or delay of cost recovery and higher electric rates, which could affect consumer demand. The cost of compliance with the Clean Power Plan is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon controls and/or reduction programs, and the selected compliance alternatives. Dominion 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’s and Virginia Power’s generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.
There are also potential impacts on Dominion’s and Dominion Gas’ natural gas businesses as federal or state GHG regulations may require GHG emission reductions from the natural gas sector and 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.
The Companies’ operations are subject to a number of environmental laws and regulations which impose significant compliance costs to the Companies. The Companies’ operations 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.
Existing environmental laws and regulations may be revised and/or new laws may be adopted or become applicable to the Companies. Risks relating to expected regulation of GHG emissions from existing fossil fuel-fired electric generating units are discussed above. In addition, further regulation of air quality and GHG emissions under the CAA will be imposed on the natural gas sector, including rules to limit methane leakage. The Companies are also subject to recently finalized 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 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 liability 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.
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 may face litigation regarding alleged CWA violations at Possum Point, and is facing litigation regarding alleged CWA violations at Chesapeake and could incur settlement expenses and other costs, depending on the outcome of any such litigation, including costs associated with closing, corrective action and ongoing monitoring of certain ash ponds. In addition, the EPA and Virginia recently issued regulations concerning the management and storage of CCRs and West Virginia may impose additional regulations that will apply to the facilities noted above. These regulations will 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 and Virginia Power have substantial ownership interests in and operate nuclear generating units; as a result, each may incur substantial costs and liabilities. Dominion’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 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’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’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 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 and Dominion Gas gather, process, and transport and reducing the value of NGLs retained by Dominion Gas, which may adversely affect Dominion and Dominion Gas’ revenues and earnings. Dominion and Dominion 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’s and Dominion Gas’ facilities. A number of other factors could reduce the volumes of natural gas and NGLs available to Dominion’s and Dominion 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
and Dominion Gas. Producers with direct commodity price exposure face liquidity constraints, which could present a credit risk to Dominion and Dominion Gas. Producers could shift their production activities to regions outside Dominion’s and Dominion 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’s and Dominion Gas’ systems and facilities for any reason, Dominion and Dominion Gas could experience lower revenues to the extent they are unable to replace the lost volumes on similar terms. In addition, Dominion Gas’ revenue from processing and fractionation operations largely results from the sale of commodities at market prices. Dominion Gas receives the wet gas product from producers and may retain the extracted NGLs as compensation for its services. This exposes Dominion 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 Gas’ results.
Dominion’s merchant power business operates in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion’s merchant power business depends upon favorable market conditions including the ability to sell power at prices sufficient to cover its operating costs. Dominion operates in active wholesale markets that expose it to price volatility for electricity and fuel as well as the credit risk of counterparties. Dominion 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 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 purchases fuel under a variety of terms, including long-term and short-term contracts and spot market purchases. Dominion 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’s financial results.
In addition, in the event that any of the merchant generation facilities experience a forced outage, Dominion may not receive the level of revenue it anticipated.
The Companies’ financial results can be adversely affected by various factors driving 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.
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 Gas has experienced a decline in demand for certain of its processing services due to competing facilities operating in nearby areas.
Dominion Gas may not be able to maintain, renew or replace its existing portfolio of customer contracts successfully, or on favorable terms. Upon contract expiration, customers may not elect to re-contract with Dominion 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 Gas’ services, the extent to which Dominion Gas is able to successfully execute its 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 Gas.
Certain of Dominion and Dominion 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 result of these “negotiated rate” contracts could decrease Dominion and Dominion 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. For example, some of Dominion’s operations are conducted through less than wholly-owned subsidiaries, such as Four Brothers and Three Cedars. In such arrangements, Dominion 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, joint venture partners or other third parties may adversely affect the Companies’ financial results.
Dominion 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’s favor, Dominion 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’s decommissioning trust funds and Dominion’s and Dominion Gas’ benefit plan assets or increase Dominion’s and Dominion 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’s nuclear plants and under Dominion’s and Dominion Gas’ pension and other postretirement benefit plans. Dominion and Dominion Gas have significant obligations in these areas and holds 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’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’s and Dominion 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’s and Dominion 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, Dominion’s and Dominion Gas’ 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 and financial market risks. In addition, Dominion and Dominion 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 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, implementation of, and compliance with, the swaps provisions 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 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 financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data 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 other appropriately qualified employees 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. 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. An aging workforce in the energy industry also necessitates recruiting, retaining and developing the next generation of leadership.
Dominion may be unable to complete the Questar Combination or, in order to do so, the combined company may be required to comply with material restrictions or conditions. On February 1, 2016, Dominion announced the execution of a merger agreement with Questar. Before the Questar Combination may be completed, approval by the shareholders of Questar will have to be obtained. In addition, various filings must be made with various state utility, regulatory, antitrust and other authorities in the U.S. These governmental authorities may impose conditions on the completion, or require changes to the terms, of the transaction, including restrictions or conditions on the business, operations, or financial performance of the combined company following completion of the transaction. Several parties have filed a complaint in court seeking to enjoin the merger. Additional parties may also seek to enjoin the merger in court or challenge regulatory filings. These conditions, changes or challenges could have the effect of delaying completion of the acquisition or imposing additional costs on or limiting the revenues of the combined company following the transaction, which could have a material adverse effect on the financial position, results of operations or cash flows of the combined company and/or cause either Dominion or Questar to abandon the transaction.
If completed, the Questar Combination may not achieve its intended results. Dominion and Questar entered into the merger agreement with the expectation that the transaction would result in various benefits, including, among other things, being accretive to earnings and adding to Dominion’s inventory of regulated energy infrastructure assets. Achieving the anticipated benefits of the transaction is subject to a number of uncertainties, including whether the business of Questar is integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy, all of which could have an adverse effect on the combined company’s financial position, results of operations or cash flows.
Failure to complete the transaction with Questar could negatively impact Dominion’s stock price and Dominion’s future business and financial results. If the Questar Combination is not completed, Dominion’s ongoing business and financial results may be adversely affected and Dominion will be subject to a number of risks, including (i) Dominion may be required, under specified circumstances set forth in the Merger Agreement, to pay Questar a termination fee of $154 million; (ii) Dominion will be required to pay costs relating to the transaction, including legal, accounting, financial advisory, filing and printing costs, whether or not the transaction is completed; and (iii) execution of the Questar Combination (including integration planning) may require substantial commitments of time and resources by our management, which could otherwise have been devoted to other opportunities that may have been beneficial to Dominion.
Dominion could also be subject to litigation related to any failure to complete the transaction with Questar. If the transaction is not completed, these risks may materialize and may adversely affect Dominion’s financial position, results of operations or cash flows.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
As of December 31, 2015, Dominion owned its principal executive office and three other corporate offices, all located in Richmond, Virginia. Dominion also leases corporate offices in other cities in which its subsidiaries operate. Virginia Power and Dominion Gas share Dominion’s principal office in Richmond, Virginia, which is owned by Dominion. In addition, Virginia Power’s DVP and 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’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described here and in Item 1. Business.
Substantially all 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, 2015; however, by leaving the indenture open, Virginia Power expects to retain the flexibility to issue mortgage bonds in the future. Certain of Dominion’s merchant generation facilities are also subject to liens.
DOMINION ENERGY
Dominion and Dominion 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 rights-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 Gas has approximately 10,500 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion 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 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 Gas is approximately 933 bcf. Certain storage fields are jointly-owned and operated by Dominion Gas. The capacity of those fields owned by Dominion Gas’ partners totals approximately 224 bcf.
Dominion
Cove Point’s LNG facility has an operational peak regasification daily send-out capacity of approximately 1.8 million Dths/day 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 DTI 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.
DCG’s interstate natural gas pipeline system in South Carolina and southeastern Georgia is comprised of approximately 1,500 miles of transmission pipeline. DCG’s pipeline system is substantially fully subscribed with a contracted pipeline capacity of 765,773 Dths/day. Dominion has 148 compressor stations with approximately 904,000 installed compressor horsepower.
DVP
See Item 1. Business, General for details regarding DVP’s principal properties, which primarily include transmission and distribution lines.
DOMINION GENERATION
Dominion and Virginia Power generate electricity for sale on a wholesale and a retail level. Dominion and Virginia Power supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2015, Dominion Generation’s total utility and merchant generating capacity was approximately 24,300 MW.
The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2015:
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 which has a net summer capacity of 20 MW, as the facility is dedicated to serving a non-jurisdictional customer.
(2) Converted from coal to gas in 2014.
(3) Excludes 50% undivided interest owned by ODEC.
(4) Coal-fired units are expected to be retired at Yorktown as early as 2017 as a result of the issuance of the MATS rule.
(5) Excludes 11.6% undivided interest owned by ODEC.
(6) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.
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) Subject to a lien securing the facility’s debt.
(3) Excludes 50% membership interest owned by BP.
(4) Excludes 50% membership interest owned by Shell.
(5) All solar facilities are alternating current.
(6) Excludes 33% noncontrolling interest owned by Terra Nova Renewable Partners.
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 February 2016, Virginia Power received a notice of violation from the Virginia Department of Environmental Quality relating to a release of mineral oil from the Crystal City substation. In January 2016, Virginia Power self-reported the discharge and began an extensive cleanup. Virginia Power has assumed the role of responsible party and is continuing to cooperate with ongoing requirements for investigative and corrective action. Virginia Power may enter into a consent order with the Virginia Department of Environmental Quality that includes a penalty. The amount of that penalty cannot be reasonably estimated at this time.
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.
Executive Officers of Dominion
Information concerning the executive officers of Dominion, each of whom is elected annually, is as follows:
(1) Any service listed for Virginia Power, Dominion Midstream GP, LLC, Dominion Gas, DTI, East Ohio, Dominion Cove Point, Inc. and DRS reflects service at a subsidiary of Dominion.
Part II
Item 5.
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Dominion
Dominion’s common stock is listed on the NYSE. At January 31, 2016, there were approximately 129,000 record holders of Dominion’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion’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 Direct®. Discussions of expected dividend payments and restrictions on Dominion’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 2015 and 2014. 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’s common stock repurchases during the fourth quarter of 2015:
(1) 21,185 and 114,784 shares were tendered by employees to satisfy tax withholding obligations on vested restricted stock in October and December 2015, respectively.
(2) Represents the weighted-average price paid per share.
(3) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion 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. Restrictions on Virginia Power’s payment of dividends are discussed in Note 20 to the Consolidated Financial Statements. Virginia Power paid quarterly cash dividends on its common stock as follows:
As discussed in Note 18 to the Consolidated Financial Statements in this report, during 2014, Virginia Power redeemed all shares of each outstanding series of its preferred stock. Effective October 30, 2014, the Virginia Power Board of Directors approved amendments to Virginia Power’s Articles of Incorporation to delete references to the redeemed series of preferred stock.
Dominion Gas
All of Dominion Gas’ membership interests are owned by Dominion. Restrictions on Dominion Gas’ payment of distributions are discussed in Note 20 to the Consolidated Financial Statements. Dominion Gas paid quarterly distributions as follows:
Item 6.
Item 6. Selected Financial Data
DOMINION
(1) 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’s restructuring of its producer services business and a $174 million after-tax charge associated with the Liability Management Exercise.
(2) Includes a $109 million after-tax charge related to Dominion’s restructuring of its producer services business ($76 million) and an impairment of certain natural gas infrastructure assets ($33 million). Also in 2013, Dominion recorded a $92 million after-tax net loss from the discontinued operations of Brayton Point and Kincaid.
(3) Includes a $1.1 billion after-tax loss from discontinued operations, including impairment charges, of Brayton Point and Kincaid and a $303 million after-tax charge primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013.
(4) Includes a $139 million after-tax charge reflecting generation plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units and a $59 million after-tax charge reflecting restoration costs associated with damage caused by Hurricane Irene.
(5) Amounts attributable to Dominion’s common shareholders.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
MD&A discusses Dominion’s results of operations and general financial condition and Virginia Power’s and Dominion 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 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:
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Forward-Looking Statements
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Accounting Matters-Dominion
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Dominion
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Results of Operations
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Segment Results of Operations
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Virginia Power
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Results of Operations
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Dominion Gas
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Results of Operations
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Liquidity and Capital Resources-Dominion
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Future Issues and Other Matters-Dominion
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:
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Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;
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Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities;
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Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;
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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 emissions, more extensive permitting requirements and the regulation of additional substances;
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Cost of environmental compliance, including those costs related to climate change;
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Changes in enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;
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Changes in regulator implementation of environmental standards and litigation exposure for remedial activities;
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Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals;
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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;
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Unplanned outages at facilities in which the Companies have an ownership interest;
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Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s and Dominion 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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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;
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Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion and Dominion Gas;
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Fluctuations in interest 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;
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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 Midstream, and retirements of assets based on asset portfolio reviews;
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The expected timing and likelihood of completion of the proposed acquisition of Questar, including the ability to obtain the requisite approvals of Questar’s shareholders and the terms and conditions of any required regulatory approvals;
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Receipt of approvals for, and timing of, closing dates for other acquisitions and divestitures;
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The timing and execution of Dominion Midstream’s growth strategy;
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Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;
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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;
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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 and Dominion 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;
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Additional competition in industries in which the Companies operate, including in electric markets in which Dominion’s merchant generation facilities operate, and 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 and Dominion 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 expansion projects and compliance with conditions associated with such regulatory approvals;
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The inability to complete planned construction, conversion or expansion projects at all, or with the outcomes or within the terms and time frames initially anticipated;
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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 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 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’s regulated electric and gas operations differs from the accounting for nonregulated operations in that Dominion 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 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 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 and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Dominion 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 rates in the future, may be significant. When Dominion 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 adjusts the carrying amount of the ARO liability with such changes recognized in income. Dominion accretes the ARO liability to reflect the passage of time. In 2015, Dominion recorded an increase in AROs of $403 million primarily related to future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 to the Consolidated Financial Statements for additional information.
In 2015, 2014 and 2013, Dominion recognized $93 million, $81 million and $86 million, respectively, of accretion, and expects to recognize $99 million in 2016. Dominion records accretion and depreciation associated with utility nuclear decommissioning AROs as an adjustment to the regulatory liability related to its nuclear decommissioning trust.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
A significant portion of Dominion’s AROs relates to the future decommissioning of its merchant and utility nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2015, Dominion’s nuclear decommissioning AROs totaled $1.5 billion, representing approximately 70% 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’s nuclear decommissioning obligations.
Dominion 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’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion 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.
Primarily as a result of a shift of the delayed planned date on which the DOE was expected to begin accepting spent nuclear fuel, in 2014, Dominion recorded an increase of $95 million to the nuclear decommissioning AROs.
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. 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.
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, 2015, Dominion had $103 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 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 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, 2015, Dominion had established $73 million of valuation allowances.
ACCOUNTING FOR DERIVATIVE CONTRACTS AND OTHER INSTRUMENTS AT FAIR VALUE
Dominion uses derivative contracts such as futures, swaps, forwards, options and FTRs to manage commodity and financial market risks of its business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies. The majority of investments held in Dominion’s nuclear decommissioning and rabbi and benefit plan trust 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 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 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 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 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, 2015, Dominion reported $3.3 billion of goodwill in its Consolidated Balance Sheet. A significant portion resulted from the acquisition of the former CNG in 2000.
In April of each year, Dominion 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 2015, 2014 and 2013 annual tests and any interim tests did not result in the recognition of any goodwill impairment.
In general, Dominion 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’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’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion 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 IMPAIRMENT TESTING
Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an 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. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of 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 operating the long-lived assets and the selection of an appropriate discount rate. When determining whether an 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, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. See Note 6 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets.
EMPLOYEE BENEFIT PLANS
Dominion 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’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 determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:
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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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Forecasts of an independent investment advisor;
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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
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Investment allocation of plan assets. The strategic target asset allocation for Dominion’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’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’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 develops assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions. Dominion calculated its pension cost using an expected long-term rate of return on plan assets assumption of 8.75% for 2015 and 2014 and 8.50% for 2013. For 2016, the expected long-term rate of return for pension cost assumption is 8.75%. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2015 and 2014 and 7.75% for 2013. For 2016, 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 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 were 4.40% in 2015, ranged from 5.20% to 5.30% for pension plans and 5.00% to 5.10% for other postretirement benefit plans in 2014, and ranged from 4.40% to 4.80% in 2013. Dominion selected a discount rate ranging from 4.96% to 4.99% for pension plans and ranging from 4.93% to 4.94% for other postretirement benefit plans for determining its December 31, 2015 projected benefit obligations.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion 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’s healthcare cost trend rate assumption as of December 31, 2015 was 7.00% and is expected to gradually decrease to 5.00% by 2019 and continue at that rate for years thereafter.
Dominion develops its mortality assumption using plan-specific studies and projects mortality improvement using scales developed by the Society of Actuaries.
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, 2015, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $212 million and its accumulated postretirement benefit obligation by $40 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $157 million.
See Note 21 to the Consolidated Financial Statements for additional information on Dominion’s employee benefit plans.
New Accounting Standards
See Note 2 to the Consolidated Financial Statements for a discussion of new accounting standards.
DOMINION
RESULTS OF OPERATIONS
Presented below is a summary of Dominion’s consolidated results:
Overview
VS. 2014
Net income attributable to Dominion increased by 45% primarily due to the absence of 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, the absence of losses related to the repositioning of Dominion’s producer services business in the first quarter of 2014, and the absence of charges related to Dominion’s Liability Manage-
ment Exercise. See Note 13 to the Consolidated Financial Statements for more information on legislation related to North Anna and offshore wind facilities. See Liquidity and Capital Resources for more information on the Liability Management Exercise.
2014 VS. 2013
Net income attributable to Dominion decreased by 23% primarily due to 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, charges associated with Dominion’s Liability Management Exercise, and the repositioning of Dominion’s producer services business, which was completed in the first quarter of 2014. See Note 13 to the Consolidated Financial Statements for more information on legislation related to North Anna and offshore wind facilities. See Liquidity and Capital Resources for more information on the Liability Management Exercise. These decreases were partially offset by an increase in investment tax credits received, primarily from new solar projects.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion’s results of operations:
An analysis of Dominion’s results of operations follows:
2015 VS. 2014
Net revenue increased 10%, primarily reflecting:
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The absence of losses related to the repositioning of Dominion’s producer services business in the first quarter of 2014, reflecting the termination of natural gas trading and certain energy marketing activities ($313 million);
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A $159 million increase from electric utility operations, primarily reflecting:
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An increase from rate adjustment clauses ($225 million);
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An increase in sales to retail customers, primarily due to a net increase in cooling degree days ($38 million); and
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A decrease in capacity related expenses ($33 million); partially offset by
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An $85 million write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015;
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A decrease in sales to customers due to the effect of changes in customer usage and other factors ($24 million); and
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A decrease due to a charge based on the 2015 Biennial Review Order to refund revenues to customers ($20 million).
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The absence of losses related to the retail electric energy marketing business which was sold in the first quarter of 2014 ($129 million);
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A $77 million increase from merchant generation operations, primarily due to increased generation output reflecting the absence of planned outages at certain merchant generation facilities ($83 million) and additional solar generating facilities placed into service ($53 million), partially offset by lower realized prices ($58 million);
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A $38 million increase from regulated natural gas distribution operations, primarily due to an increase in rate adjustment clause revenue related to low income assistance programs ($12 million), an increase in AMR and PIR program revenues ($24 million) and various expansion projects placed into service ($22 million); partially offset by a decrease in gathering revenues ($9 million); and
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A $30 million increase from regulated natural gas transmission operations, primarily reflecting:
•
A $61 million increase in gas transportation and storage activities, primarily due to the addition of DCG ($62 million), decreased fuel costs ($24 million) and various expansion projects placed into service ($24 million), partially offset by decreased regulated gas sales ($46 million); and
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A $46 million net increase primarily due to services performed for Atlantic Coast Pipeline and Blue Racer; partially offset by
•
A $61 million decrease from NGL activities, primarily due to decreased prices.
Other operations and maintenance decreased 6%, primarily reflecting:
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The absence of 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 ($370 million);
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An increase in gains from agreements to convey shale development rights underneath several natural gas storage fields ($63 million);
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A $97 million decrease in planned outage costs primarily due to a decrease in scheduled outage days at certain merchant generation facilities ($59 million) and non-nuclear utility generation facilities ($38 million); and
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A $22 million decrease in charges related to future ash pond and landfill closure costs at certain utility generation facilities.
These decreases were partially offset by:
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The absence of a gain on the sale of Dominion’s electric retail energy marketing business in March 2014 ($100 million), net of a $31 million write-off of goodwill;
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An $80 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;
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The absence of gains on the sale of assets to Blue Racer ($59 million);
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A $53 million increase in utility nuclear refueling outage costs primarily due to the amortization of outage costs that were previously deferred pursuant to Virginia legislation enacted in April 2014;
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A $46 million net increase due to services performed for Atlantic Coast Pipeline and Blue Racer. These expenses are billed to these entities and do not significantly impact net income; and
•
A $22 million increase due to the acquisition of DCG.
Other income decreased 22%, primarily reflecting lower tax recoveries associated with contributions in aid of construction ($17 million), a decrease in interest income related to income taxes ($12 million), and lower net realized gains on nuclear decommissioning trust funds ($11 million).
Interest and related charges decreased 24%, primarily as a result of the absence of charges associated with Dominion’s Liability Management Exercise in 2014.
Income tax expense increased 100%, primarily reflecting higher pre-tax income.
2014 VS. 2013
Net revenue decreased 3%, primarily reflecting:
•
A $263 million decrease from retail energy marketing operations, primarily due to the sale of the retail electric business in March 2014; and
•
A $195 million decrease primarily related to the repositioning of Dominion’s producer services business which was completed in the first quarter of 2014, reflecting the termination of natural gas trading and certain energy marketing activities.
These decreases were partially offset by:
•
A $171 million increase from electric utility operations, primarily reflecting:
•
An increase from rate adjustment clauses at electric utility operations ($132 million); and
•
An increase in sales from electric utility operations primarily due to an increase in heating degree days ($34 million);
•
A $46 million increase in gas transportation and storage activities and other revenues, largely due to various expansion projects being placed into service; and
•
A $35 million increase in merchant generation margins, primarily due to higher realized prices ($120 million), partially offset by lower generation output due to the decommissioning of Kewaunee beginning in May 2013 ($95 million).
Other operations and maintenance increased 12%, primarily reflecting:
•
$370 million in 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 $135 million increase in planned outage costs at certain merchant generation facilities and at certain non-nuclear utility facilities; and
•
A $121 million charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
These increases were partially offset by:
•
A gain on the sale of Dominion’s electric retail energy marketing business in March 2014 ($100 million), net of a $31 million write-off of goodwill;
•
A $67 million decrease primarily due to the deferral of utility nuclear outage costs beginning in the second quarter of 2014, pursuant to the Virginia legislation enacted in April 2014;
•
The absence of a $65 million charge primarily reflecting impairment charges recorded in 2013 for certain natural gas infrastructure assets; and
•
A decrease in bad debt expense at regulated natural gas distribution operations primarily related to low-income assistance programs ($53 million). These bad debt expenses are recovered through rates and do not impact net income.
Interest and related charges increased 36%, primarily due to charges associated with Dominion’s Liability Management Exercise in 2014 ($284 million) and higher long-term debt interest expense resulting from debt issuances in 2014 ($44 million).
Income tax expense decreased 49%, primarily reflecting lower pre-tax income ($350 million) and the impact of federal renewable energy investment tax credits ($105 million).
Loss from discontinued operations reflects the sale of Brayton Point and Kincaid in 2013.
Outlook
Dominion’s strategy is to continue focusing on its regulated 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 expects 80% to 90% of earnings from its primary operating segments to come from regulated and long-term contracted businesses.
In 2016, Dominion is expected to experience an increase in net income on a per share basis as compared to 2015. Dominion’s anticipated 2016 results reflect the following significant factors:
•
A return to normal weather in its electric utility operations;
•
Growth in weather-normalized electric utility sales of approximately 1%;
•
Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue;
•
The absence of a write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015 and decreased charges related to future ash pond and landfill closure costs at certain utility generation facilities;
•
A lower effective tax rate, driven primarily by additional investment tax credits;
•
Construction and operation of growth projects in gas transmission and distribution; partially offset by
•
An increase in depreciation, depletion, and amortization;
•
Higher operating and maintenance expenses; and
•
Share dilution.
Additionally, in 2016, Dominion expects to focus on meeting new and developing environmental requirements, including by making investments in utility solar generation, particularly in Virginia.
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’s operating segments to net income attributable to Dominion:
(1) Amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Energy segment.
DVP
Presented below are operating statistics related to DVP’s operations:
(1) Period average.
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
2015 VS. 2014
2014 VS. 2013
Dominion Generation
Presented below are operating statistics related to Dominion Generation’s operations:
(1) Excludes 7.6 million MWh for 2013 related to Kewaunee, Brayton Point, Kincaid, State Line power station, Salem Harbor power station and Dominion’s equity method investment in Elwood. There are no exclusions related to these stations in 2014 or 2015.
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
2015 VS. 2014
2014 VS. 2013
Dominion Energy
Presented below are selected operating statistics related to Dominion Energy’s operations.
(1) Period average.
(2) Excludes 511 thousand average retail electric energy marketing customer accounts due to the sale of this business in March 2014.
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:
2015 VS. 2014
(1) Primarily represents absence of a gain from the sale of the Northern System.
(2) Represents the portion of earnings attributable to Dominion Midstream’s public unitholders.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
2014 VS. 2013
(1) Includes a $24 million decrease in gains from the sale of assets.
(2) Excludes earnings from Retail electric energy marketing, which was sold in March 2014.
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’s primary operating segments that are not included in profit measures evaluated by executive management in assessing those segments’ performance or allocating resources among the segments. 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 2014, this primarily included $174 million in after-tax charges associated with Dominion’s Liability Management Exercise.
VIRGINIA POWER
RESULTS OF OPERATIONS
Presented below is a summary of Virginia Power’s consolidated results:
Overview
VS. 2014
Net income increased by 27% primarily due to the absence of 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.
2014 VS. 2013
Net income decreased by 25% primarily due to 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.
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:
2015 VS. 2014
Net revenue increased 3%, primarily reflecting:
•
An increase from rate adjustment clauses ($225 million);
•
An increase in sales to retail customers, primarily due to a net increase in cooling degree days ($38 million); and
•
A decrease in capacity related expenses ($33 million); partially offset by
•
An $85 million write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015;
•
A decrease in sales to customers due to the effect of changes in customer usage and other factors ($24 million); and
•
A decrease due to a charge based on the 2015 Biennial Review Order to refund revenues to customers ($20 million).
Other operations and maintenance decreased 15%, primarily reflecting:
•
The absence of $370 million in 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; and
•
A $38 million decrease in planned outage costs primarily due to a decrease in scheduled outage days at certain non-nuclear utility generation facilities.
These decreases were partially offset by:
•
An $80 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income; and
•
A $53 million increase in utility nuclear refueling outage costs primarily due to the amortization of outage costs that were previously deferred pursuant to Virginia legislation enacted in April 2014.
Other income decreased 27%, primarily reflecting lower tax recoveries associated with contributions in aid of construction.
Income tax expense increased 20%, primarily reflecting higher pre-tax income.
2014 VS. 2013
Net revenue increased 4%, primarily reflecting increases from rate adjustment clauses ($132 million) and sales to customers due to an increase in heating degree days ($34 million).
Other operations and maintenance increased 32%, primarily reflecting:
•
$370 million in 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; and
•
A $121 million charge related to a settlement offer to incur future ash pond closure costs at certain generation facilities.
Interest and related charges increased 11%, primarily due to higher long-term debt interest expense resulting from debt issuances in August 2013 and February 2014.
Income tax expense decreased 17%, primarily reflecting lower pre-tax income.
DOMINION GAS
RESULTS OF OPERATIONS
Presented below is a summary of Dominion Gas’ consolidated results:
Overview
VS. 2014
Net income decreased by 11% primarily due to the absence of gains on the indirect sale of assets to Blue Racer, a decrease in income from NGL activities and higher interest expense, partially offset by increased gains from agreements to convey shale development rights underneath several natural gas storage fields.
2014 VS. 2013
Net income increased by 11% primarily due to the absence of impairment charges for certain natural gas infrastructure assets and increased gains due to assignments of Marcellus acreage, partially offset by decreased gains on sales of assets to related parties.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion Gas’ results of operations:
An analysis of Dominion Gas’ results of operations follows:
2015 VS. 2014
Net revenue increased 1%, primarily reflecting:
•
A $43 million increase from regulated natural gas distribution operations, primarily due to an increase in AMR and PIR program revenues ($24 million) and various expansion projects placed into service ($22 million); partially offset by
•
A $27 million decrease from regulated natural gas transmission operations, primarily reflecting:
•
A $62 million decrease from NGL activities, primarily due to decreased prices; partially offset by
•
A $2 million increase in gas transportation and storage activities, primarily due to decreased fuel costs ($24 million) and various expansion projects placed into service ($24 million), partially offset by decreased regulated gas sales ($46 million); and
•
A $33 million net increase in other revenue primarily due to services performed for Atlantic Coast Pipeline and Blue Racer ($47 million), partially offset by a decrease in non-regulated gas sales ($8 million) and decreased farmout revenues ($6 million).
Other operations and maintenance increased 15%, primarily reflecting:
•
A $47 million net increase due to services performed for Atlantic Coast Pipeline and Blue Racer. These expenses are billed to these entities and do not significantly impact net income; and
•
The absence of gains on the sale of assets to Blue Racer ($59 million); partially offset by
•
An increase in gains from agreements to convey shale development rights underneath several natural gas storage fields ($63 million).
Depreciation and amortization increased 10% primarily due to various expansion projects placed into service.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Interest and related charges increased $46 million, primarily due to higher long-term debt interest expense resulting from debt issuances in December 2014.
Income tax expense decreased 15% primarily reflecting lower pre-tax income.
2014 VS. 2013
Other operations and maintenance decreased 20%, primarily reflecting:
•
The absence of impairment charges related to certain natural gas infrastructure assets ($55 million);
•
A decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs ($53 million). These bad debt expenses are recovered through rates and do not impact net income; and
•
An increase in gains associated with assignments of Marcellus acreage ($42 million); partially offset by
•
Decreased gains on the sale of assets to related parties ($43 million).
Income tax expense increased 11% primarily reflecting higher pre-tax income.
LIQUIDITY AND CAPITAL RESOURCES
Dominion 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, 2015, Dominion had $932 million of unused capacity under its credit facilities. See additional discussion below under Credit Facilities and Short-Term Debt.
A summary of Dominion’s cash flows is presented below:
Operating Cash Flows
Net cash provided by Dominion’s operating activities increased $1.0 billion, primarily due to the absence of losses related to the repositioning of Dominion’s producer services business in 2014, higher deferred fuel cost recoveries in its Virginia jurisdiction, higher revenue from rate adjustment clauses, lower outage costs and the absence of losses related to the retail electric energy marketing business in 2014.
Dominion 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 2015, Dominion’s Board of Directors affirmed the dividend policy it set in February 2015 targeting a payout ratio of 70-75%, and established an annual dividend rate for 2016 of $2.80 per share of common stock, an 8.1% increase over the 2015 rate. Dividends are subject to declaration by the Board of Directors. In January 2016, Dominion’s Board of Directors declared dividends payable in March 2016 of 70 cents per share of common stock.
Dominion’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’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’s credit exposure as of December 31, 2015 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 45% of the total net credit exposure.
(2) The five largest counterparty exposures, combined, for this category represented approximately 2% of the total net credit exposure.
(3) The five largest counterparty exposures, combined, for this category represented approximately 14% of the total net credit exposure.
(4) The five largest counterparty exposures, combined, for this category represented approximately 20% of the total net credit exposure.
Investing Cash Flows
In 2015, net cash used in Dominion’s investing activities increased $1.3 billion, primarily due to Dominion’s acquisition of DCG in 2015, an increase in acquisitions of solar development projects in 2015, and the absence of proceeds from the sale of Dominion’s electric retail energy marketing business in 2014.
Financing Cash Flows and Liquidity
Dominion 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’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 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 to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.
In 2015, net cash provided by Dominion’s financing activities increased $573 million, primarily due to the issuance of common stock through an at-the-market program, proceeds from the sale of interest in merchant solar projects and the absence of subsidiary preferred stock redemption in 2014, partially offset by the absence of proceeds from the issuance of Dominion Midstream common units in 2014.
LIABILITY MANAGEMENT
During 2014, Dominion elected to redeem certain debt and preferred securities prior to their stated maturities. Proceeds from the issuance of lower-cost senior and enhanced junior subordinated notes were used to fund the redemption payments. See Note 17 to the Consolidated Financial Statements for descriptions of these redemptions.
From time to time, Dominion 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.
CREDIT FACILITIES AND SHORT-TERM DEBT
Dominion 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 January 2016, Dominion expanded its short-term funding resources through a $1.0 billion increase to one of its joint revolving credit facility limits. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.
In connection with commodity hedging activities, Dominion is required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, Dominion 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 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 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’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 2019, 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) In January 2016, this facility limit was increased from $4.0 billion to $5.0 billion.
(3) The weighted-average interest rate of the outstanding commercial paper supported by Dominion’s credit facilities was 0.62% at December 31, 2015.
SHORT-TERM NOTES
In November 2014, Dominion issued $400 million of private placement short-term notes that matured and were repaid in November 2015 and bore interest at a variable rate. The proceeds were used for general corporate purposes.
In November 2015, Dominion issued $400 million of private placement short-term notes that mature in May 2016 and bear interest at a variable rate. In December 2015, Dominion issued an additional $200 million of the variable rate short-term notes that mature in May 2016. The proceeds were used for general corporate purposes.
In February 2016, Dominion purchased and cancelled $100 million of the variable rate short-term notes that would have otherwise matured in May 2016 using the proceeds from the February 2016 issuance of senior notes that mature in 2018. As a result, at December 31, 2015, $100 million of the notes were included in long-term debt in the Consolidated Balance Sheets.
LONG-TERM DEBT
During 2015, Dominion issued the following long-term debt:
In August 2015, Virginia Power remarketed five series of tax-exempt bonds, with an aggregate outstanding principal of $412 million to new investors. Two of the bonds will bear interest at a coupon rate of 1.75% until May 2019 after which they will bear interest at a market rate to be determined at that time. Three of the bonds will bear interest at a coupon rate of 2.15% until September 2020 after which they will bear interest at a market rate to be determined at that time. Previously, interest on all of the remarketed bonds was variable and reset monthly. This remarketing was accounted for as a debt extinguishment with the previous investors.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
During 2015, Dominion repaid and repurchased $892 million of long-term debt.
ISSUANCE OF COMMON STOCK AND OTHER EQUITY SECURITIES
Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’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 began purchasing its common stock on the open market for these plans. In April 2014, Dominion began issuing new common shares for these direct stock purchase plans.
During 2015, Dominion issued 4.2 million shares of common stock totaling $295 million through employee savings plans, direct stock purchase and dividend reinvestment plans and other employee and director benefit plans. Dominion received cash proceeds of $284 million from the issuance of 4.1 million of such shares through Dominion Direct® and employee savings plans.
During 2015, Dominion issued 6.8 million shares of common stock and received cash proceeds of $499 million, net of fees and commissions paid of $3 million, through an at-the-market program and a registered underwritten public offering. See Note 19 to the Consolidated Financial Statements for a description of the at-the-market program and public offering.
During 2016, Dominion plans to issue shares for employee savings plans, direct stock purchase and dividend reinvestment plans, stock purchase contracts and to finance the Questar Combination. See Note 17 to the Consolidated Financial Statements for a description of common stock to be issued by Dominion for stock purchase contracts.
REPURCHASE OF COMMON STOCK
Dominion did not repurchase any shares in 2015 and does not plan to repurchase shares during 2016, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not count against its stock repurchase authorization.
PURCHASE OF DOMINION MIDSTREAM UNITS
In September 2015, Dominion initiated a program to purchase from the market up to $50 million of common units representing limited partner interests in Dominion Midstream. The common units may be acquired by Dominion over the 12 month period following commencement of the program at the discretion of management. Through December 31, 2015, Dominion purchased approximately 887,000 common units for $25 million. In the first quarter of 2016, Dominion purchased approximately 377,000 additional common units for approximately $10 million. At February 23, 2016, Dominion still has the ability to purchase up to $15 million of common units under the program.
PROPOSED ACQUISITION OF QUESTAR
Under the terms of the Questar Combination announced in February 2016, Dominion has agreed to pay Questar shareholders $25 per share, totaling approximately $4.4 billion as well as assume Questar’s outstanding debt, currently approximately $1.6 billion, which is expected to remain outstanding following the merger. Additionally, Dominion entered into agreements with several of its lending banks pursuant to which they have commit-
ted to provide temporary debt financing consisting of a $3.9 billion acquisition facility. Dominion intends to permanently finance the transaction in a manner that supports its existing credit ratings targets by issuing a combination of common stock, mandatory convertibles (including RSNs) and debt at Dominion and indirectly through an issuance of common units at Dominion Midstream, the proceeds of which will be applied to pay Dominion for certain assets of Questar, which are expected to be contributed to Dominion Midstream. Subject to receipt of Questar shareholder and any required regulatory approvals and meeting closing conditions, Dominion targets closing by the end of 2016.
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 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 may affect its ability to access these funding sources or cause an increase in the return required by investors. Dominion’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 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 November 2014, Standard & Poor’s changed Dominion’s rating outlook to negative from stable. In February 2016, Standard & Poor’s lowered the following ratings for Dominion: issuer to BBB+ from A-, senior unsecured debt securities to BBB from BBB+ and junior/remarketable subordinated debt securities to BBB- from BBB. In addition, Standard & Poor’s affirmed Dominion’s commercial paper rating of A-2 and revised its outlook to stable from negative.
Credit ratings as of February 23, 2016 follow:
As of February 23, 2016, Fitch, Moody’s and Standard & Poor’s maintained a stable outlook for their respective ratings of Dominion.
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 works closely with Fitch, Moody’s and Standard & Poor’s with the objective of achieving its targeted credit ratings. Dominion 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 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.
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’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 is required to pay annual commitment fees to maintain its credit facilities. In addition, Dominion’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, 2015, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:
(1) Indebtedness as defined by the bank agreements excludes 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 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’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’s obligations to repay any outstanding borrowing under the credit facilities could also be accelerated and the lenders’ commitments to Dominion could terminate.
Dominion executed RCCs in connection with its issuance of the following hybrid securities:
•
June 2006 hybrids;
•
September 2006 hybrids; and
•
June 2009 hybrids.
In October 2014, Dominion redeemed all of the June 2009 hybrids. The redemption was conducted in compliance with the RCC. See Note 17 to the Consolidated Financial Statements for additional information, including terms of the RCCs.
At December 31, 2015, the termination dates and covered debt under the RCCs associated with Dominion’s hybrids were as follows:
Dominion monitors these debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2015, there have been no events of default under or changes to Dominion’s debt covenants.
Dividend Restrictions
Certain agreements associated with Dominion’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s ability to pay dividends or receive dividends from its subsidiaries at December 31, 2015.
See Note 17 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes and equity units, initially in the form of corporate units, which information is incorporated herein by reference.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
CONTRACTUAL OBLIGATIONS
Dominion 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 is a party as of December 31, 2015. 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’s current liabilities will be paid in cash in 2016.
(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders. In February 2016, Dominion purchased and cancelled $100 million of variable rate short-term notes that would have otherwise matured in May 2016 using the proceeds from the February 2016 issuance of senior notes that mature in 2018. As a result, at December 31, 2015, $100 million of the notes 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, 2015 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’s ability to defer interest and stock purchase contract payments on 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, $67 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 swap agreements.
PLANNED CAPITAL EXPENDITURES
Dominion’s planned capital expenditures are expected to total approximately $6.9 billion, $4.9 billion and $4.3 billion in 2016, 2017 and 2018, respectively. Dominion’s planned expenditures 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, the construction of the Liquefaction Project and funding of Dominion’s portion of the Atlantic Coast Pipeline Project.
Dominion 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 DVP, Dominion Generation and Dominion Energy-Properties in Item 1. Business for a discussion of Dominion’s expansion plans.
These estimates are based on a capital expenditures plan reviewed and endorsed by Dominion’s Board of Directors in late 2015 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion 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
GUARANTEES
Dominion 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. 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 is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES
Dominion incurred $190 million, $192 million and $182 million of expenses (including depreciation) during 2015, 2014, and 2013 respectively, in connection with environmental protection and monitoring activities, excluding charges related to ash pond and landfill closure costs, and expects these expenses to be approximately $186 million and $187 million in 2016 and 2017,
respectively. In addition, capital expenditures related to environmental controls were $59 million, $101 million, and $64 million for 2015, 2014 and 2013, respectively. These expenditures are expected to be approximately $85 million and $113 million for 2016 and 2017, 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 new rule requires states to impose standards of performance limits for existing fossil fuel-fired electric generating units or equivalent statewide intensity-based or mass-based CO2 binding goals or limits. States are required to submit interim plans to the EPA by September 2016 identifying how they will comply with the rule, with final plans due by September 2018. The EPA also proposed a federal plan and model trading rules that, when finalized, states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. Virginia Power’s most recent integrated resources plan filed in July 2015 includes four alternative plans that represent plausible compliance strategies with the rule as proposed, and which include additional coal unit retirements and additional low or zero-carbon 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. Dominion does not know whether these legal challenges will impact the submittal deadlines for the state implementation plans. Subsequent to the stay, Virginia has announced that it will continue development of a state plan. Unless the rule survives the court challenges and until the state plans are developed and the EPA approves the plans, Dominion cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.
In December 2012, the EPA issued a final rule that set a more stringent annual air quality standard for fine particulate matter. The EPA issued final attainment/nonattainment designations in January 2015. Until states develop their implementation plans, Dominion cannot determine whether or how facilities located in areas designated nonattainment for the standard will be impacted, but does not expect such impacts to be material.
The EPA has finalized rules establishing a new 1-hour NAAQS for NO2 and a new 1-hour NAAQS for SO2, which could require additional NOX and SO2 controls in certain areas
where Dominion operates. Until the states have developed implementation plans for these standards, the impact on Dominion’s facilities that emit NOX and SO2 is uncertain. Additionally, the impact of permit limits for implementing NAAQS on Dominion’s facilities is uncertain at this time.
In June 2005, the EPA finalized amendments to the Regional Haze Rule, also known as the Clean Air Visibility Rule. The rule requires the states to implement best available retrofit technology requirements for sources to address impacts to visual air quality through regional haze state implementation plans, but allows other alternative options. Dominion anticipates that the emission reductions achieved through compliance with other CAA-required programs will generally address this rule.
In December 2015, the EPA published a proposed revision to CSAPR. The proposal substantially reduces the CSAPR Phase II ozone season NOX emission caps in 23 states including Virginia, West Virginia and North Carolina, relative to the Phase II caps under the current CSAPR rule, that would take effect beginning with the 2017 ozone season. The proposed reductions in state ozone season NOX caps would in turn reduce, by approximately 55% overall, the number of allowances Dominion electric generating units will receive under the CSAPR ozone season NOX program beginning with the 2017 May - September ozone season. In addition, the EPA is proposing to discount the use of banked Phase I allowances for compliance in Phase II by applying either a 2:1 or 4:1 surrender ratio. Until the proposal is finalized, Dominion is unable to predict with certainty the impact to future CSAPR ozone season allowance streams and to what extent the rule may require additional controls. The EPA expects to issue a final revision to CSAPR in August 2016.
In April 2014, the Pennsylvania Department of Environmental Protection issued proposed regulations to reduce NOX and VOC emissions from combustion sources. The regulations are expected to be finalized in the second quarter of 2016. To comply with the regulations, Dominion Gas anticipates installing emission control systems on existing engines at several compressor stations in Pennsylvania. Until the regulations are finalized, Dominion Gas cannot estimate the potential impacts on results of operations, financial condition, and/or cash flows related to this matter.
Climate Change
In December 2015, the Paris Agreement was formally adopted under the United Nations Framework Convention on Climate Change. The accord establishes a universal framework for addressing GHG emissions involving actions by all nations through the concept of nationally determined contributions in which each nation defines the GHG commitment it can make and sets in place a process for increasing those commitments every five years. It also contains a global goal of holding the increase in the global average temperature to well below 2 degrees Celsius above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5 degrees Celsius above pre-industrial levels and to aim to reach global peaking of GHG emissions as soon as possible.
A key element of the initial U.S. nationally determined contributions of achieving a 26% to 28% reduction below 2005 levels by 2025 is the implementation of the Clean Power Plan, which establishes interim emission reduction targets for fossil fuel-fired electric generating units over the period 2022 through
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
2029 with final targets to be achieved by 2030. The EPA estimates that the Clean Power Plan will result in a nationwide reduction in CO2 emissions from fossil fuel-fired electric generating units of 32% from 2005 levels by 2030.
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 has elected to exempt its swaps from the CEA’s clearing requirements. The CFTC may continue to adopt final rules and implement provisions of the Dodd-Frank Act through its ongoing rulemaking process, including rules regarding margin requirements for non-cleared swaps. If, as a result of the rulemaking process, Dominion’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’s swap dealer counterparties may attempt to pass-through additional trading costs in connection with the implementation of, and compliance with, Title VII of the Dodd-Frank Act. Due to the ongoing rulemaking process, Dominion 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.
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’s and Virginia Power’s electric operations and Dominion’s and Dominion 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 and Virginia Power primarily hold commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products and Dominion 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 repositioning of Dominion’s producer services business was completed in the first quarter of 2014. This, combined with Dominion’s sale of its electric retail energy marketing business, has reduced Dominion’s commodity price risk exposure.
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% increase in commodity prices of Dominion’s commodity-based financial derivative instruments would have resulted in a decrease in fair value of $62 million and $101 million as of December 31, 2015 and 2014, respectively. The decline in sensitivity is largely due to decreased commodity derivative activity and lower commodity prices.
A hypothetical 10% increase in commodity prices would not have resulted in a material change in the fair value of Virginia Power’s commodity-based financial derivatives as of December 31, 2015 or 2014.
A hypothetical 10% increase in commodity prices of Dominion Gas’ commodity-based financial derivative instruments would have resulted in a decrease in fair value of $5 million and $2 million as of December 31, 2015 and 2014, respectively. The increase in sensitivity is largely due to an increase in commodity derivative volume.
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, 2015 or 2014.
The Companies may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. As of December 31, 2015, Dominion, Virginia Power and Domin-
ion Gas had $4.6 billion, $2.0 billion and $250 million, 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 $71 million, $52 million and $2 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2015. As of December 31, 2014, Dominion, Virginia Power and Dominion Gas had $4.1 billion, $1.5 billion and $250 million, 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 $46 million, $25 million and $2 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2014.
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 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 recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $184 million and $176 million in 2015 and 2014, 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 recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains of $157 million in 2015, and a net increase in unrealized gains of $172 million in 2014.
Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $88 million and $77 million in 2015 and 2014, 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 decrease in unrealized gains of $76 million in 2015, and a net increase in unrealized gains of $87 million in 2014.
Dominion sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power and Dominion Gas
employees participate in these plans. Dominion’s pension and other postretirement plan assets experienced aggregate actual losses of $72 million in 2015 and aggregate actual returns of $706 million in 2014, versus expected returns of $648 million and $610 million, respectively. Dominion Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual losses of $13 million in 2015 and aggregate actual returns of $157 million in 2014, versus expected returns of $150 million and $138 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’s plan assets would result in an increase in net periodic cost of $16 million and $15 million as of December 31, 2015 and 2014, respectively, for pension benefits and $3 million as of both December 31, 2015 and 2014, for other postretirement benefits. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion 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, 2015 and 2014 for pension benefits and $1 million as of both December 31, 2015 and 2014, 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 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 Gas. Dominion 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 also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and the Companies’ December 31, 2015 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
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of Dominion’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Resources, Inc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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), Dominion’s internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2016 expressed an unqualified opinion on Dominion’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 26, 2016
Dominion Resources, Inc.
Consolidated Statements of Income
(1) Includes income tax benefit of $43 million in 2013.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Balance Sheets
(1) See Note 3 for amounts attributable to related parties.
(2) 1 billion shares authorized; 596 million shares and 585 million shares outstanding at December 31, 2015 and 2014, respectively.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Statements of Equity
(1) Primarily includes $28 million in shares issued in excess of principal amounts related to converted securities, net of reclassification from other paid-in capital. See Note 17 for further information on convertible securities.
(2) See Note 17 for further information.
(3) Includes subsidiary preferred dividends related to noncontrolling interests of $13 million and $17 million in 2014 and 2013, respectively.
(4) Contains shares issued in excess of principal amounts related to converted securities. See Note 17 for further information on convertible securities.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements
Dominion Resources, Inc.
Consolidated Statements of Cash Flows
(1) See Note 3 for noncash activities related to the acquisition of Four Brothers and Three Cedars.
The accompanying notes are an integral part of Dominion’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
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (“Virginia Power”) as of December 31, 2015 and 2014, and 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, 2015. These financial statements are the responsibility of Virginia Power’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 26, 2016
Virginia Electric and Power Company
Consolidated Statements of Income
(1) See Note 24 for amounts attributable to affiliates.
(2) Includes $2 million associated with the write-off of issuance expenses related to the redemption of Virginia Power’s preferred stock in 2014. See Note 18 for additional information.
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, 2015 and 2014.
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 Gas Holdings, LLC
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Dominion Gas Holdings, LLC (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (“Dominion Gas”) as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of Dominion Gas’ management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Dominion Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Dominion Gas’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Gas Holdings, LLC and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 26, 2016
Dominion Gas Holdings, LLC
Consolidated Statements of Income
(1) See Note 24 for amounts attributable to related parties.
(2) Includes gains on the sales of assets to related parties of $59 million and $122 million in 2014 and 2013, respectively. See Note 9 for more information.
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
Dominion Gas Holdings, LLC
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
Dominion 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 Gas’ Consolidated Financial Statements.
Dominion Gas Holdings, LLC
Consolidated Statements of Equity
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
Dominion Gas Holdings, LLC
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
Combined Notes to Consolidated Financial Statements
NOTE 1. NATURE OF OPERATIONS
Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion’s operations are conducted through various subsidiaries, including Virginia Power and Dominion 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. Dominion 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 Gas’ membership interests are held by Dominion.
Dominion’s operations also include an LNG import, transport and storage facility in Maryland, a preferred equity interest in which was contributed to Dominion Midstream in 2014, an equity investment in Atlantic Coast Pipeline and regulated gas transportation and distribution operations in West Virginia. Dominion’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 Midstream launched its initial public offering of 20,125,000 common units representing limited partner interests at a price of $21 per unit, which included an over-allotment option to purchase an additional 2,625,000 common units at the initial offering price, which was exercised in full by the underwriters. Dominion received $392 million in net proceeds from the sale of the units, after deducting underwriting discounts, structuring fees and estimated offering expenses. At December 31, 2015, Dominion owns the general partner and 64.1% of the limited partner interests in Dominion Midstream, which owns a preferred equity interest and the general partner interest in Cove Point, DCG and a 25.93% noncontrolling partnership interest in Iroquois. The public’s ownership interest in Dominion Midstream is reflected as non-controlling interest in Dominion’s Consolidated Financial Statements.
Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued, which is discussed in Notes 3 and 25. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion 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 allocating resources among the segments.
Dominion Gas manages its daily operations through one primary operating segment: Dominion Energy. 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 and the effect of certain items recorded at Dominion Gas as a result of the recognition of Dominion’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. SunEdison’s ownership interest in Four Brothers and Three Cedars, as well as Terra Nova Renewable Partners’ 33% interest in certain of Dominion’s merchant solar projects, is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. See Note 3 for further information on transactions with SunEdison.
The Companies report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.
Dominion maintains pension and other postretirement benefit plans. Virginia Power and Dominion Gas participate in certain of these plans. See Note 21 for further information on these plans.
Certain amounts in the 2014 and 2013 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2015 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.
Amounts disclosed for Dominion are inclusive of Virginia Power and/or Dominion 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 and Virginia Power collect sales, consumption and consumer utility taxes and Dominion Gas collects sales taxes; however, these amounts are excluded from revenue. Dominion’s customer receivables at December 31, 2015 and 2014 included $462 million and $564 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility
customers. Virginia Power’s customer receivables at December 31, 2015 and 2014 included $333 million and $407 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. Dominion Gas’ customer receivables at December 31, 2015 and 2014 included $98 million and $127 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its customers.
The primary types of sales and service activities reported as operating revenue for Dominion 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;
•
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 gathering, transmission, distribution and storage services. Also included are state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; 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, 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 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 gathering, transmission and storage services. Also included are state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers;
•
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’s and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion’s and Dominion 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 Gas’, Cove Point’s 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 and its subsidiaries, including Virginia Power and Dominion Gas’ subsidiaries. In addition, where applicable, combined income tax returns for Dominion and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed.
Although Dominion 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. Virginia Power and Dominion Gas participate in intercompany tax sharing agreements with Dominion 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 consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.
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
Combined Notes to Consolidated Financial Statements, Continued
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’s, Virginia Power’s and Dominion Gas’ interest and penalties were immaterial in 2015, 2014 and 2013.
At December 31, 2015, Virginia Power’s Consolidated Balance Sheet included a $296 million affiliated receivable, representing current year excess federal income tax payments expected to be refunded, $9 million of federal income taxes payable for prior years, less than $1 million of state income taxes payable, $10 million of state income taxes receivable, $14 million of noncurrent state income taxes receivable and $2 million of noncurrent state income taxes payable.
At December 31, 2014, Virginia Power’s Consolidated Balance Sheet included $225 million of federal and state income taxes receivable, $13 million of noncurrent state income taxes receivable and $38 million of noncurrent federal and state income taxes payable. In March 2015, Virginia Power received a $229 million refund of its 2014 federal income tax payments.
At December 31, 2015, Dominion Gas’ Consolidated Balance Sheet included $91 million of affiliated receivables, representing current year excess federal income tax payments expected to be refunded and the benefit of utilizing a subsidiary’s tax loss to offset taxable income in Dominion’s consolidated tax return to be filed in 2016, less than $1 million of state income taxes payable, $4 million of state income taxes receivable and $22 million of noncurrent state income taxes payable.
At December 31, 2014, Dominion Gas’ Consolidated Balance Sheet included $96 million of federal and state income taxes receivable, $14 million of state income taxes payable, $7 million of noncurrent state income taxes payable and $20 million noncurrent state income taxes receivable. In March 2015, Dominion Gas received a $93 million refund of its 2014 federal income tax payments.
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:
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 and Virginia Power use derivative instruments such as futures, swaps, forwards, options and FTRs to manage the commodity and financial market risks of their business operations. Dominion Gas uses derivative instruments such as physical and financial forwards, futures and swaps to manage commodity price and interest 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 had margin assets of $16 million and $287 million associated with cash collateral at December 31, 2015 and 2014, respectively. Dominion’s margin liabilities associated with cash collateral at December 31, 2015 were immaterial. Dominion had margin liabilities of $34 million associated with cash collateral at December 31, 2014. Virginia Power did not have any margin assets associated with cash collateral at December 31, 2015. Virginia Power had margin assets of $6 million associated with cash collateral at December 31 2014. Virginia Power did not have any margin liabilities associated with cash collateral at December 31, 2015 or 2014. Dominion Gas did not have any margin assets or liabilities related to cash collateral at December 31, 2015 or 2014. See Note 7 for further information about derivatives.
To manage price risk, Dominion and Virginia Power hold certain derivative instruments that are not designated as hedges for accounting purposes. However, to the extent Dominion and Virginia Power do not hold offsetting positions for such derivatives, they believe these instruments represent economic
hedges that mitigate their exposure to fluctuations in commodity prices and interest rates. As part of Dominion’s strategy to market energy and manage related risks, it formerly managed a portfolio of commodity-based financial derivative instruments held for trading purposes. Dominion used established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and used various derivative instruments to reduce risk by creating offsetting market positions. In the second quarter of 2013, Dominion commenced a repositioning of its producer services business. The repositioning was completed in the first quarter of 2014 and resulted in the termination of natural gas trading and certain energy marketing activities.
Statement of Income Presentation:
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Derivatives Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis.
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Derivatives Not Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses or interest and related charges based on the nature of the underlying risk.
In Virginia Power’s generation operations, 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, NGLs and other energy-related products. The Companies also use interest rate swaps to hedge their exposure to variable interest rates on long-term debt. 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 entered into interest rate derivative instruments to hedge its forecasted interest payments related to planned debt issuances in 2013 and 2014. These interest rate derivatives were designated by Dominion as cash flow hedges in 2012 and 2013, prior to the formation of Dominion Gas. For the purposes of the Dominion Gas financial statements, the derivative balances, AOCI balance, and any income statement impact related to these interest rate derivative instruments entered into by Dominion have been, and will continue to be, included in the Dominion Gas’ Consolidated Financial Statements as the forecasted interest payments related to the debt issuances now occur at Dominion Gas.
Fair Value Hedges-Dominion also uses fair value hedges to mitigate the fixed price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, Dominion and Virginia Power have 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. Derivative gains and losses from the hedged item are reclassified to earnings when the hedged item is included in earnings, or earlier, if the hedged item no longer qualifies for hedge accounting. 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 2015, 2014 and 2013, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $100 million, $80 million and $66 million, respectively. In 2015, 2014 and 2013, Virginia Power capitalized AFUDC to property, plant and equipment of $30 million, $39 million and $33 million, respectively. In 2015, 2014 and 2013, Dominion Gas capitalized AFUDC to property, plant and equipment of $1 million, $1 million and $5 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 2015, 2014 and 2013, Virginia Power recorded $19 million, $8 million and $32 million of AFUDC related to these projects, respectively.
Combined Notes to Consolidated Financial Statements, Continued
For property subject to cost-of-service rate regulation, including Virginia Power electric distribution, electric transmission, and generation property, Dominion Gas natural gas distribution and transmission property, and for certain Dominion 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 associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.
Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows:
In 2013, Virginia Power revised its depreciation rates to reflect the results of a new depreciation study. This change resulted in an increase of $19 million ($12 million after-tax) in depreciation and amortization expense in Virginia Power’s Consolidated Statements of Income.
In 2014, Virginia Power also made a one-time adjustment to depreciation expense as ordered by the Virginia Commission. This adjustment resulted in an increase of $38 million ($23 million after-tax) in depreciation and amortization expense in Virginia Power’s Consolidated Statements of Income.
In 2013, Dominion Gas revised the depreciation rates for East Ohio to reflect the results of a new depreciation study. This change resulted in a decrease of $8 million ($5 million after-tax) in depreciation and amortization expense in Dominion Gas’ Consolidated Statements of Income.
Dominion’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 Gas’ nonutility property, plant and equipment and E&P properties was immaterial for the years ended December 31, 2015, 2014 and 2013.
Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.
Long-Lived and Intangible Assets
The Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for a discussion of impairments related to certain long-lived assets.
Regulatory Assets and Liabilities
The accounting for Dominion’s and Dominion 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. 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. At least annually, the Companies evaluate the key assumptions underlying their AROs including estimates of the amounts and timing of future cash flows associated with retirement activities. AROs are adjusted when significant changes in these assumptions are identified. Dominion and Dominion 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 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 an asset and classified in other current assets and other deferred charges and other assets 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. Effective January 2016, deferred debt issuance costs will be recorded as a reduction in long-term debt in the Consolidated Balance Sheets. 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 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 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’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’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 and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion’s and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds.
OTHER-THAN-TEMPORARY IMPAIRMENT
Dominion and Virginia Power 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 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 and Virginia Power record the credit loss in earnings and any remaining portion of the unrealized
Combined Notes to Consolidated Financial Statements, Continued
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’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 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 for Dominion Gas used in East Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at $24 million and $12 million at December 31, 2015 and December 31, 2014, respectively. Based on the average price of gas purchased during 2015 and 2014, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $109 million and $98 million, respectively. Stored gas inventory for Dominion held by Hope and certain nonregulated gas operations is valued using the weighted-average cost method.
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 and Dominion 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 and Dominion Gas from other parties are reported in other current assets and imbalances that Dominion and Dominion Gas owe to other parties are reported in other current liabilities in the Consolidated Balance Sheets.
Goodwill
Dominion and Dominion 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
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 are currently in the preliminary stages of evaluating the impact of this guidance on their results of operations and overall liquidity. The Companies plan to complete their preliminary assessment, which includes a subset of representative contracts, in 2016. Once their initial evaluation is complete, the Companies will expand the scope of their assessment to include all contracts with customers. Other than increased disclosures, the impacts of the revised accounting guidance to the results of operations and cash flows of the Companies cannot be determined until their assessment process is complete.
In November 2015, the FASB issued revised accounting guidance to simplify the presentation of deferred income taxes. This update requires that deferred tax liabilities and assets be classified as noncurrent in the Consolidated Balance Sheet. The Companies have adopted this guidance on a prospective basis for the period ended December 31, 2015. For prior periods, the Companies have presented deferred taxes in either the current or noncurrent sections of the Consolidated Balance Sheets based on the classification of the related financial accounting assets or liabilities, or, for items such as operating loss carryforwards, the period in which the deferred taxes were expected to reverse.
In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. Most notably the update revises the accounting for equity securities, except for those accounted for under the equity method of accounting or resulting in consolidation, by requiring equity securities to be measured at fair value with the changes in fair value recognized in net income. However, an entity may measure equity investments that do not have a readily determinable fair value at cost minus impairment, if any, plus changes from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. The guidance also simplifies the impairment assessment of equity investments without readily determinable fair values, revises the presentation of financial assets and liabilities and amends certain disclosure requirements associated with the fair value of financial instruments. The guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, with a cumulative-effect adjustment to the balance sheet. Amendments related to equity securities without readily determinable fair values are to be applied prospectively to such investments that exist as of the date of adoption. The Companies are currently evaluating the impact the adoption of the standard will have on their consolidated financial statements and disclosures.
In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires the recognition of lease assets and liabilities for 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. 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 for leases that commenced prior to the date of adoption. The Companies are currently evaluating the impact the adoption of the standard will have on their consolidated financial statements and disclosures.
NOTE 3. ACQUISITIONS AND DISPOSITIONS
DOMINION
PROPOSED ACQUISITION OF QUESTAR
Pursuant to the terms of the Questar Combination announced in February 2016, upon closing, each share of Questar common stock issued and outstanding immediately prior to the closing will be converted automatically into the right to receive $25 in cash per share, or approximately $4.4 billion in total. In addition, Questar’s debt, which currently totals approximately $1.6 billion is expected to remain outstanding. Additionally, Dominion entered into agreements with several of its lending banks pursuant to which they have committed to provide temporary debt financing consisting of a $3.9 billion acquisition facility. Dominion intends to permanently finance the transaction in a manner that supports its existing credit ratings targets by issuing a combination of common stock, mandatory convertibles (including RSNs) and debt at Dominion, and indirectly through an issuance of common units at Dominion Midstream, the proceeds of which will be applied to pay Dominion for certain assets of Questar, which are expected to be contributed to Dominion Midstream.
The transaction requires approval of Questar’s shareholders and clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. Questar and Dominion also will file for review and approval, as required, from the Utah Public Service Commission and the Wyoming Public Service Commission, and provide information regarding the transaction to the Idaho Public Utilities Commission. In February 2016, the Federal Trade Commission granted antitrust approval of the Questar Combination under the Hart-Scott-Rodino Act. The Questar Combination contains certain termination rights for both Dominion and Questar, and provides that, upon termination of the Questar Combination under specified circumstances, Dominion would be required to pay a termination fee of $154 million to Questar and Questar would be required to pay Dominion a termination fee of $99 million. Subject to receipt of Questar shareholder and any required regulatory approvals and meeting closing conditions, Dominion targets closing by the end of 2016.
WHOLLY-OWNED MERCHANT SOLAR PROJECTS
Acquisitions
The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion in 2014 and 2015. Long-term power purchase, interconnection and operation and maintenance agreements have been executed for all of the projects. Dominion has claimed and/or expects to claim federal investment tax credits on the projects. These projects are included in the Dominion Generation operating segment.
(1) The purchase price was primarily allocated to Property, Plant and Equipment.
(2) Includes acquisition cost.
(3) One of the projects, Marin Carport, is expected to begin commercial operations in 2016.
Sale of Interest in Merchant Solar Projects
In September 2015, Dominion 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 approximately 425 MW, to SunEdison for approximately $300 million. 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. SunEdison subsequently sold its interest in these projects to Terra Nova Renewable Partners. SunEdison has a future option to buy all or a portion of Dominion’s remaining 67% ownership in the projects upon the occurrence of certain events, none of which had occurred as of December 31, 2015 nor are expected to occur in 2016.
Combined Notes to Consolidated Financial Statements, Continued
NON-WHOLLY-OWNED MERCHANT SOLAR PROJECTS
Acquisitions of Four Brothers and Three Cedars
In June 2015, Dominion 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. As of December 31, 2015, a $43 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Four Brothers’ purpose is to develop and operate four solar projects located in Utah, which will produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $730 million to construct, including the initial acquisition cost. Dominion is obligated to contribute $445 million of capital to fund the construction of the projects and had contributed $138 million through December 31, 2015. The facilities are expected to begin commercial operations in the third quarter of 2016, generating approximately 320 MW.
In September 2015, Dominion 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. As of December 31, 2015, a $29 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Three Cedars’ purpose is to develop and operate three solar projects located in Utah, which will produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $425 million to construct. Dominion is obligated to contribute $276 million of capital to fund the construction of the projects and had contributed $60 million through December 31, 2015. The facilities are expected to begin commercial operations in the third quarter of 2016, generating approximately 210 MW.
Long-term power purchase, interconnection and operation and maintenance agreements have been executed for both Four Brothers and Three Cedars. Dominion expects to claim 99% of the federal investment tax credits on the projects.
Dominion 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 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 non-recourse project financing and outside equity partners. The acquired assets of Four Brothers and Three Cedars are included in the Dominion Generation operating segment.
Four Brothers and Three Cedars have entered into agreements with SunEdison to provide administrative and support services in connection with the construction of the projects, operation and maintenance of the facilities, and administrative and technical management services of the solar facilities. In addition, Dominion has entered into contracts with SunEdison to provide services
related to construction project management and oversight. Costs related to services to be provided under these agreements were immaterial for the year ended December 31, 2015. Subsequent to Dominion’s acquisition of Four Brothers and Three Cedars through December 31, 2015, SunEdison made contributions to Four Brothers and Three Cedars of $103 million in aggregate, which are reflected as noncontrolling interests in the Consolidated Balance Sheets.
In December 2015, SunEdison entered an agreement to sell its interest in Four Brothers and Three Cedars through the sale of Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC to DESRI.
DOMINION MIDSTREAM ACQUISITION OF INTEREST IN IROQUOIS
In September 2015, Dominion 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 Midstream issued 8.6 million common units representing limited partnership interests in Dominion 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 Midstream’s common units at closing. These common units are reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. Dominion Midstream’s noncontrolling partnership interest is reflected in the Dominion Energy operating segment. In addition to this acquisition, Dominion Gas currently holds a 24.72% noncontrolling partnership interest in Iroquois. Dominion Midstream and Dominion 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 DCG
In January 2015, Dominion completed the acquisition of 100% of the equity interests of DCG from SCANA Corporation for $497 million in cash, as adjusted for working capital. DCG owns and operates nearly 1,500 miles of FERC-regulated interstate natural gas pipeline in South Carolina and southeastern Georgia. This acquisition supports Dominion’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’s regulated gas position, economic value attributable to future expansion projects as well as increased opportunities for synergies. The acquired assets of DCG are included in the Dominion Energy operating segment.
On March 24, 2015, DCG converted to a limited liability company under the laws of South Carolina and changed its name from Carolina Gas Transmission Corporation to DCG. On April 1, 2015, Dominion contributed 100% of the issued and outstanding membership interests of DCG to Dominion Midstream in exchange for total consideration of $501 million, as adjusted for working capital. Total consideration to Dominion consisted of the issuance of a two-year, $301 million senior
unsecured promissory note payable by Dominion 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 Midstream. The number of units was based on the volume weighted average trading price of Dominion Midstream’s common units for the ten trading days prior to April 1, 2015, or $39.12 per unit. Since Dominion consolidates Dominion Midstream for financial reporting purposes, this transaction was eliminated upon consolidation and did not impact Dominion’s financial position or cash flows.
SALE OF ELECTRIC RETAIL ENERGY MARKETING BUSINESS
In March 2014, Dominion completed the sale of its electric retail energy marketing business. The proceeds were $187 million, net of transaction costs. The sale resulted in a gain, subject to post-closing adjustments, of $100 million ($57 million after-tax) net of a $31 million write-off of goodwill, and is included in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. The sale of the electric retail energy marketing business did not qualify for discontinued operations classification.
SALE OF ILLINOIS GAS CONTRACTS
In June 2013, Dominion completed the sale of Illinois Gas Contracts. The sales price was $32 million, subject to post-closing adjustments. The sale resulted in a gain of $29 million ($18 million after-tax) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in Dominion’s Consolidated Statement of Income. The sale of Illinois Gas Contracts did not qualify for discontinued operations classification as it is not considered a component under applicable accounting guidance.
SALE OF BRAYTON POINT, KINCAID AND EQUITY METHOD INVESTMENT IN ELWOOD
In March 2013, Dominion entered into an agreement with Energy Capital Partners to sell Brayton Point, Kincaid, and its equity method investment in Elwood.
In the first and second quarters of 2013, Brayton Point’s and Kincaid’s assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell, resulting in impairment charges totaling $48 million ($28 million after-tax), which are included in discontinued operations in Dominion’s Consolidated Statements of Income. In both periods, Dominion used the market approach to estimate the fair value of Brayton Point’s and Kincaid’s long-lived assets. These were considered Level 2 fair value measurements given that they were based on the agreed-upon sales price.
Dominion’s 50% interest in Elwood was an equity method investment and therefore, in accordance with applicable accounting guidance, the carrying amount of this investment was not classified as held for sale nor were the equity earnings from this investment reported as discontinued operations.
In August 2013, Dominion completed the sale and received proceeds of $465 million, net of transaction costs. The sale resulted in a $35 million ($25 million after-tax) gain attributable to its equity method investment in Elwood, which is included in other income in Dominion’s Consolidated Statement of Income, which was partially offset by a $17 million ($18 million after-tax) loss attributable to Brayton Point and Kincaid, which includes a $16 million write-off of goodwill and is reflected in loss from discontinued operations in Dominion’s Consolidated Statement of Income.
The following table presents selected information regarding the results of operations of Brayton Point and Kincaid, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income:
(1) Includes $64 million of charges related to the defeasance of Brayton Point debt and the early redemption of Kincaid debt in 2013.
Virginia Power
ACQUISITION OF SOLAR PROJECT
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 approximately 20 MW. The output generated by the project will be 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 Virginia Power Generation operating segment.
Dominion and Dominion Gas
BLUE RACER
See Note 9 for a discussion of transactions related to Blue Racer.
ASSIGNMENTS OF SHALE DEVELOPMENT RIGHTS
See Note 10 for a discussion of assignments of shale development rights.
Combined Notes to Consolidated Financial Statements, Continued
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 authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.
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, and a phasing down of the allowance to 40% in 2018 and 30% in 2019 and expiration thereafter. In addition, the legislation extends 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. U.S. federal legislation had also been enacted in December 2014 to delay the expiration of the bonus depreciation allowance, but only for one year, so that it was available for qualifying expenditures incurred during 2014.
Continuing Operations
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
In 2015, Dominion’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:
Dominion’s effective tax rate in 2014 reflects the recognition of state tax credits and previously unrecognized tax benefits due to the expiration of statutes of limitations. Dominion Gas’ effective tax rate in 2015 reflects a benefit resulting from the impact of changes in the allocation of income among states on existing deferred taxes.
The Companies’ deferred income taxes consist of the following:
At December 31, 2015, Dominion had the following deductible loss and credit carryforwards:
•
Federal loss carryforwards of $594 million that expire if unutilized during the period 2021 through 2034;
•
Federal investment tax credits of $407 million that expire if unutilized during the period 2033 through 2035;
•
Federal production and other tax credits of $89 million that expire if unutilized during the period 2031 through 2035;
•
State loss carryforwards of $1.6 billion that expire if unutilized during the period 2018 through 2034. A valuation allowance on $1.1 billion of these carryforwards has been established;
•
State minimum tax credits of $145 million that do not expire; and
•
State investment tax credits of $40 million that expire if unutilized during the period 2019 through 2024.
At December 31, 2015, Virginia Power had the following deductible loss and credit carryforwards:
•
Federal loss carryforwards of $7 million that expire if unutilized during the period 2031 through 2034;
•
Federal investment, production and other tax credits of $38 million that expire if unutilized during the period 2031 through 2035; and
•
State investment tax credits of $9 million that expire if unutilized by 2024.
At December 31, 2015, Dominion Gas had federal loss carryforwards of $10 million that expire if unutilized during the period 2031 through 2034 and no credit carryforwards.
Combined Notes to Consolidated Financial Statements, Continued
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 and its subsidiaries, these unrecognized tax benefits were $69 million, $77 million and $126 million at December 31, 2015, 2014 and 2013, respectively. For Dominion, the change in these unrecognized tax benefits decreased income tax expense by $6 million, $47 million and $29 million in 2015, 2014 and 2013, respectively. For Virginia Power, these unrecognized tax benefits were $8 million at December 31, 2015, 2014 and 2013. For Virginia Power, the change in these unrecognized tax benefits affected income tax expense by less than $1 million in both 2015 and 2014, and increased income tax expense by $4 million in 2013. For Dominion Gas, these unrecognized tax benefits were $19 million at December 31, 2015, 2014 and 2013. For Dominion Gas, the change in these unrecognized tax benefits affected income tax expense by less than $1 million in 2015, 2014 and 2013.
The IRS examination of tax years 2008, 2009, 2010 and 2011 concluded in late 2013, resulting in a payment of $46 million, and an adjustment to a refund previously received by Dominion for its carryback of 2008 losses to 2007. The loss carryback, as adjusted, was submitted to the U.S. Congressional Joint Committee on Taxation for review. Early in 2014, Dominion received notification that the matter had been resolved with no further adjustments.
Effective for its 2014 tax year, Dominion was accepted into the CAP. Through the CAP, Dominion has 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. Under a Pre-CAP plan, the IRS audit of tax years 2012 and 2013 began in early 2014 and
concluded in late 2015. The IRS audit of CAP tax year 2014 also began in 2014. The IRS issued a partial acceptance letter in late 2015 and completed its post-filing review of the 2014 tax year in early 2016. The IRS audit of CAP tax year 2015 began in 2015. Accordingly, Dominion’s earliest tax year remaining open for federal examination is 2015.
It is reasonably possible that settlement negotiations and expiration of statutes of limitations could result in a decrease in unrecognized tax benefits in 2016 by up to $30 million for Dominion and $22 million for Dominion 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 $15 million for Dominion and $10 million for Dominion Gas.
Otherwise, with regard to 2015 and prior years, Dominion and Dominion Gas cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2016.
After considering the possibility of potential changes in the status of its remaining unrecognized tax benefits, Virginia Power has concluded that no significant changes are reasonably possible to occur in 2016.
For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows:
(1) Considered a major state for Dominion 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 utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination.
Discontinued Operations
Details of income tax expense for Dominion’s discontinued operations were as follows:
Dominion’s effective tax rate for 2013 reflects the impact of goodwill written off in the sale of Kincaid and Brayton Point that is not deductible for tax purposes.
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 and Virginia Power apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, and nuclear decommissioning trust and other investments including those held in Dominion’s rabbi, pension and other postretirement benefit plan trusts, in accordance with the requirements described above. Dominion Gas applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments and investments 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. These credit adjustments are currently not material to the derivative fair values.
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’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 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 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
Combined Notes to Consolidated Financial Statements, Continued
For interest rate derivative contracts:
•
Interest rate curves
•
Credit quality of counterparties and the Companies
•
Volumes
•
Credit enhancements
•
Time value
For investments:
•
Quoted securities prices and indices
•
Securities trading information including volume and restrictions
•
Maturity
•
Interest rates
•
Credit quality
•
NAV (for alternative investments and common/collective trust funds)
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, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion and Virginia Power, benefit plan trust funds for Dominion and Dominion Gas, and rabbi trust funds for Dominion.
•
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, restricted cash equivalents, and certain Treasury securities, money market funds, common/collective trust funds, and corporate, state and municipal debt securities held in nuclear decommissioning trust funds for Dominion and Virginia Power, benefit plan trust funds for Dominion and Dominion Gas, and rabbi trust funds for Dominion.
•
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, natural gas peaking options and other modeled commodity derivatives. Additional instruments categorized in Level 3 for Dominion and Dominion Gas include alternative
investments, consisting of investments in partnerships, joint ventures and other alternative investments, held in benefit plan trust funds.
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.
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. Alternative investments are categorized as Level 3 due to the absence of quoted market prices, illiquidity and the long-term nature of these assets. These investments 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.
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, forward market prices, credit spreads 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.
The following table presents Dominion’s quantitative information about Level 3 fair value measurements at December 31, 2015. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility and credit spreads.
(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 credit spreads unrepresented in published markets.
(6) 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
See Note 3 for information regarding the sale of Brayton Point, Kincaid and Dominion’s equity method investment in Elwood.
DOMINION GAS
Natural Gas Assets
In the fourth quarter of 2014, Dominion Gas recorded an impairment charge of $9 million ($6 million after-tax) in other
operations and maintenance expense in its Consolidated Statements of Income, to write off previously capitalized costs following the cancellation of a development project.
In June 2013, Dominion Gas purchased certain natural gas infrastructure facilities that were previously leased from third parties. The purchase price was based on terms in the lease, which exceeded current market pricing. As a result of the purchase price and expected losses, Dominion Gas recorded an impairment charge of $49 million ($29 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write down the long-lived assets to their estimated fair values of less than $1 million. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion Gas used the income approach (discounted cash flows) to estimate the fair value of the assets in this impairment test. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs, including estimates of future production and other commodity prices.
Combined Notes to Consolidated Financial Statements, Continued
Also in June 2013, Dominion Gas recorded an impairment charge of $6 million ($4 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write off previously capitalized costs following the cancellation of two development projects.
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’s and Dominion Gas’ pension and other postretirement benefit plans are presented in Note 21.
DOMINION
The following table presents Dominion’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.
The following table presents the net change in Dominion’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
(1) In March 2015, Dominion changed the classification of certain short term NGL derivatives from Level 3 to Level 2 due to an increase in liquidity in financial forward markets. The transfers out of Level 3 that relate to NGLs for the year ended December 31, 2015 were $9 million.
The following table presents Dominion’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, 2015. The range and weighted average are presented in dollars for market price inputs and percentages for credit spreads.
(1) Averages weighted by volume.
(2) Includes basis.
(3) Represents market prices beyond defined terms for Levels 1 and 2.
(4) Represents credit spreads unrepresented in published markets.
(5) 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 and rabbi trusts.
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, 2015, 2014 and 2013. 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, 2015, 2014 and 2013.
DOMINION GAS
The following table presents Dominion Gas’ quantitative information about Level 3 fair value measurements at December 31, 2015. The range and weighted average are presented in dollars for market price inputs and percentages for credit spreads.
(1) Averages weighted by volume.
(2) Represents market prices beyond defined terms for Levels 1 and 2.
Combined Notes to Consolidated Financial Statements, Continued
The following table presents Dominion Gas’ assets and liabilities for commodity and interest rate 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 Gas’ derivative assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
(1) In March 2015, Dominion Gas changed the classification of certain short term NGL derivatives from Level 3 to Level 2 due to an increase in liquidity in financial forward markets. The transfers out of Level 3 that relate to NGLs for the year ended December 31, 2015 were $9 million.
The gains and losses included in earnings in the Level 3 fair value category were classified in operating revenue in Dominion Gas’ Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013. 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, 2015, 2014 and 2013.
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, 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 discount and/or premium. At December 31, 2015, and 2014, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt, of $7 million and $19 million, respectively.
(3) Carrying amount includes amounts which represent the unamortized discount and/or premium.
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 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’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 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 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.
Combined Notes to Consolidated Financial Statements, Continued
DOMINION
Balance Sheet Presentation
The tables below present Dominion’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’s derivative activity as of December 31, 2015. 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.
Ineffectiveness and AOCI
For the years ended December 31, 2015, 2014 and 2013, 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’s Consolidated Balance Sheet at December 31, 2015:
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 and interest rates.
Combined Notes to Consolidated Financial Statements, Continued
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Dominion’s 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’s Consolidated Balance Sheets.
(2) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheets.
The following tables present the gains and losses on Dominion’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’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’s Consolidated Statements of Income.
(3) Amounts recorded in Dominion’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 Dominion’s Consolidated Statements of Income.
(2) Amounts recorded in Dominion’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, 2015. 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.
Ineffectiveness
For the years ended December 31, 2015, 2014 and 2013, gains or losses on hedging instruments determined to be ineffective were not material.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:
(1) Current derivative assets are presented in other current assets in Virginia Power’s Consolidated Balance Sheets.
(2) Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Power’s Consolidated Balance Sheets.
(3) 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 GAS
Balance Sheet Presentation
The tables below present Dominion 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 Gas’ derivative activity at December 31, 2015. 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.
Ineffectiveness and AOCI
For the years ended December 31, 2015, 2014 and 2013, 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 Gas’ Consolidated Balance Sheet at December 31, 2015:
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 and interest rates.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Dominion Gas’ derivatives and where they are presented in its Consolidated Balance Sheets:
(1) Current derivative assets are presented in other current assets in Dominion Gas’ Consolidated Balance Sheets.
(2) Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Gas’ Consolidated Balance Sheets.
(3) Current derivative liabilities are presented in other current liabilities in Dominion Gas’ Consolidated Balance Sheets.
(4) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Gas’ Consolidated Balance Sheets.
Combined Notes to Consolidated Financial Statements, Continued
The following tables present the gains and losses on Dominion 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 Gas’ Consolidated Statements of Income.
(2) Amounts recorded in Dominion Gas’ Consolidated Statements of Income are classified in interest and related charges.
NOTE 8. EARNINGS PER SHARE
The following table presents the calculation of Dominion’s basic and diluted EPS:
(1) Dilutive securities consist primarily of the 2013 Equity Units for 2015, the 2013 Equity Units and contingently convertible senior notes for 2014, and contingently convertible senior notes for 2013. Dominion redeemed all of its contingently convertible senior notes in 2014. See Note 17 for more information.
The 2014 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the year ended December 31, 2015 as inclusion would have been antidilutive. The 2014 Equity Units were excluded from the calculation of diluted EPS for the year ended December 31, 2014, as the dilutive stock price threshold was not met. The 2013 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the year ended December 31, 2013. See Note 17 for more information.
NOTE 9. INVESTMENTS
DOMINION
Equity and Debt Securities
RABBI TRUST SECURITIES
Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled $100 million and $110 million at December 31, 2015 and 2014, respectively.
DECOMMISSIONING TRUST SECURITIES
Dominion 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’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 $12 million and $3 million at December 31, 2015 and 2014, respectively.
(3) The fair value of securities in an unrealized loss position was $592 million and $379 million at December 31, 2015 and 2014, respectively.
The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at December 31, 2015 by contractual maturity is as follows:
Presented below is selected information regarding Dominion’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 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 $9 million, $3 million and $18 million at December 31, 2015, 2014 and 2013, 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 $8 million and $6 million at December 31, 2015 and 2014, respectively.
(3) The fair value of securities in an unrealized loss position was $281 million and $170 million at December 31, 2015 and 2014, respectively.
The fair value of Virginia Power’s marketable debt securities at December 31, 2015, 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 $6 million, $2 million and $9 million at December 31, 2015, 2014 and 2013, respectively.
EQUITY METHOD INVESTMENTS
Dominion and Dominion Gas
Investments that Dominion and Dominion Gas account for under the equity method of accounting are as follows:
(1) Comprised of Dominion Midstream’s interest of 25.93% and Dominion Gas’ interest of 24.72%. See Note 15 for more information.
(2) Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018.
Dominion’s equity earnings on its investments totaled $56 million, $46 million and $14 million in 2015, 2014 and 2013, respectively. Dominion received distributions from these investments of $83 million, $60 million and $33 million in 2015, 2014, and 2013, respectively. As of December 31, 2015 and 2014, the carrying amount of Dominion’s investments exceeded its share of underlying equity in net assets by $234 million and $126 million, respectively. These differences are comprised at December 31, 2015 and 2014, of $72 million and $87 million, respectively, related to basis differences from Dominion’s investments in Blue Racer and wind projects, which are being amortized over the useful lives of the underlying assets, and $162 million and $39 million, respectively, reflecting equity method goodwill that is not being amortized.
Dominion Gas’ equity earnings on its investment totaled $23 million, $21 million and $22 million in 2015, 2014 and 2013, respectively. Dominion Gas received distributions from its investment of $28 million, $20 million and $19 million in 2015, 2014, and 2013, respectively. As of December 31, 2015 and 2014, the carrying amount of Dominion 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.
Equity earnings are recorded in other income in Dominion’s and Dominion Gas’ Consolidated Statements of Income.
BLUE RACER
In December 2012, Dominion 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 and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital.
In March 2013, Dominion Gas sold Line TL-404 to an affiliate, that subsequently sold line TL-404 to Blue Racer for cash proceeds of $47 million. The sale resulted in a gain of $25 million ($14 million after-tax) net of a $2 million write-off of goodwill, and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statement of Income.
Phase 1 of Natrium was completed in the second quarter of 2013 and was contributed by Dominion to Blue Racer in the third quarter of 2013, resulting in an increased equity method investment in Blue Racer of $473 million. Also in the third quarter of 2013, Dominion Gas sold Line TPL-2A to an affiliate, that subsequently sold Line TPL-2A to Blue Racer, and sold Line TL-388 to Blue Racer and received $78 million in cash proceeds. The sales resulted in a $74 million ($41 million after-tax) gain which is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statements of Income.
In the fourth quarter of 2013, Dominion Gas sold the Western System to an affiliate, that subsequently sold the Western System to Blue Racer for cash proceeds of $30 million. The sale resulted in a gain of $3 million ($2 million after-tax) for Dominion Gas and $4 million ($2 million after-tax) for Dominion and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statement of Income.
Dominion NGL Pipelines, LLC was contributed in January 2014 by Dominion to Blue Racer, prior to commencement of service, resulting in an increased equity method investment of $155 million, including $6 million of goodwill allocated from Dominion’s goodwill balance to its equity method investment in Blue Racer.
In March 2014, Dominion Gas sold the Northern System to an affiliate, that subsequently sold the Northern System to Blue Racer for consideration of $84 million. Dominion Gas’ consideration consisted of $17 million in cash proceeds and the extinguishment of affiliated current borrowings of $67 million and Dominion’s consideration consisted of cash proceeds of $84 million. The sale resulted in a gain of $59 million ($35 million after-tax for Dominion Gas and $34 million after-tax for Dominion) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statements of Income.
Dominion
ATLANTIC COAST PIPELINE
In September 2014, Dominion, along with Duke Energy, Piedmont and AGL, announced the formation of Atlantic Coast Pipeline. The members, which are subsidiaries of the above-referenced parent companies, hold the following membership interests: Dominion, 45%; Duke Energy, 40%; Piedmont, 10%; and AGL, 5%. In October 2015, Duke Energy entered into a merger agreement with Piedmont. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. 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 four 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 has the ability to exercise significant influence, but not control, over the investee. See Note 15 for more information.
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:
There were no significant E&P properties under development, as defined by the SEC, excluded from Dominion Gas’ amortization at December 31, 2015. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.
In 2015, Dominion Gas recorded a ceiling test impairment charge of $16 million ($10 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income. Dominion sold substantially all its Appalachian E&P
properties in April 2010, retaining only wells in and around DTI’s storage facilities. The net book basis of the remaining properties as of December 31, 2015 is $14 million.
Jointly-Owned Power Stations
Dominion’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2015 is as follows:
(1) Units jointly owned by Virginia Power.
(2) Unit jointly owned by Dominion.
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 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.
Assignments of Shale Development Rights
In December 2013, Dominion 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 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 Gas received approximately $100 million in cash proceeds, resulting in a $20 million ($12 million after-tax) gain, recorded to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. In 2014, Dominion Gas received $16 million in additional cash proceeds resulting from post-closing adjustments. At December 31, 2014, deferred revenue totaled $85 million. In March 2015, Dominion 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 Gas’ Consolidated Statements of Income. At December 31, 2015, deferred revenue totaled $37 million, which is expected to be recognized over the remaining term of the agreement.
In November 2014, Dominion 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 provides for payments to Dominion Gas, subject to customary adjustments, of approx-
imately $120 million over a period of four years, and an overriding royalty interest in gas produced from the acreage. In November 2014, Dominion Gas closed on the agreement and received proceeds of $60 million associated with an initial conveyance of approximately 12,000 acres, resulting in a $60 million ($36 million after-tax) gain, recorded to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.
In March 2015, Dominion 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 Gas’ Consolidated Statements of Income.
In September 2015, Dominion 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 Gas, subject to customary adjustments, of $52 million and an overriding royalty interest in gas produced from the acreage. In September 2015, Dominion 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 Gas’ Consolidated Statements of Income.
NOTE 11. GOODWILL AND INTANGIBLE ASSETS
Goodwill
The changes in Dominion’s and Dominion 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) Recast to reflect nonregulated retail energy marketing operations in the Dominion Energy segment.
(4) See Note 3 for a discussion of Dominion’s dispositions and related goodwill write-offs.
(5) Related to assets sold or contributed to an affiliate or Blue Racer.
Other Intangible Assets
The Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion’s amortization expense for intangible assets was $78 million, $71 million and $72 million for 2015, 2014 and 2013, respectively. In 2015, Dominion acquired $78 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 8 years. Amortization expense for Virginia Power’s intangible assets was $25 million, $24 million and $22 million for 2015, 2014 and 2013, respectively. In 2015, Virginia Power acquired $34 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 6 years. Dominion Gas’ amortization expense for intangible assets was $18 million, $17 million and $16 million for 2015, 2014 and 2013, respectively. In 2015, Dominion Gas acquired $24 million of intangible assets, primarily representing software, 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:
Combined Notes to Consolidated Financial Statements, Continued
NOTE 12. REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities include the following:
(1) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Dominion’s and Virginia Power’s generation operations. See Note 13 for more information.
(2) 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. Reflects deferrals of costs associated with certain current and prospective rider projects for Dominion Gas. See Note 13 for more information.
(3) Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months.
(4) Reflects unrecovered gas costs at regulated gas operations, which are recovered through filings with the applicable regulatory authority.
(5) Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain of Dominion’s and Dominion Gas’ rate-regulated subsidiaries.
(6) Reflects amount related to the PJM transmission cost allocation matter. See Note 13 for more information.
(7) 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.
(8) As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.
(9) 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.
(10) Current regulatory liabilities are presented in other current liabilities in Dominion’s Consolidated Balance Sheets.
(11) 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.
(12) 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.
At December 31, 2015, $131 million of Dominion’s, $100 million of Virginia Power’s and $29 million of Dominion Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. 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 utilities. Dominion’s merchant generators sell electricity in the PJM, MISO, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Tennessee, Georgia, California and Utah, under Dominion’s market-based sales tariffs authorized by FERC. 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 that $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. In February 2012, Virginia Power submitted to FERC a settlement agreement to resolve all issues set for hearing. The settlement was accepted by FERC in May 2012 and provides for payment by Virginia Power to the transmission customer parties collectively of $250,000 per year for ten years and resolves all matters other than allocation of the incremental cost of certain underground transmission facilities.
In March 2014, FERC issued an order excluding from Virginia Power’s transmission rates for wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable for non-Virginia wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities because the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to benefit the citizens of Virginia. The order is retroactively effective as of March 2010 and will cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC determined that there was not sufficient evidence on the record to determine the magnitude of the underground increment and held a hearing to determine the appropriate amount of undergrounding cost to be allocated to each wholesale transmission customer in Virginia. While Virginia Power cannot predict the outcome of the hearing, it is not expected to have a material effect on results of operations.
PJM Transmission Rates
In April 2007, FERC issued an order regarding its transmission rate design for the allocation of costs among PJM transmission customers, including Virginia Power, for transmission service provided by PJM. For new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a PJM regional rate design where customers pay according to each customer’s share of the region’s load. For recovery of costs of existing facilities, FERC approved the existing methodology whereby a customer pays the cost of facilities located in the same zone as the customer. A number of parties appealed the order to the U.S. Court of Appeals for the Seventh Circuit.
In August 2009, the court issued its decision affirming the FERC order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above for further consideration by FERC. On remand, FERC reaffirmed its earlier decision to allocate the costs of new facilities 500 kV and above according to the customer’s share of the region’s load. A number of parties filed appeals of the order to the U.S. Court of Appeals for the Seventh Circuit. In June 2014, the court again remanded the cost allocation issue to FERC. In December 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the cost
Combined Notes to Consolidated Financial Statements, Continued
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.
Virginia Power expects that a settlement agreement will be executed regarding this matter. Under the terms of the settlement, Virginia Power would be required to pay $200 million to PJM over the next 10 years. Although no FERC order has been issued and the expected settlement agreement has not been filed and accepted by FERC, Virginia Power believes it is probable it will be required to make payment as an outcome of the hearing and settlement proceedings. Accordingly, as of December 31, 2015, Virginia Power has recorded a contingent liability of $200 million in other deferred credits and other liabilities, which is offset by a $192 million regulatory asset for the amount that will be recovered through retail rates in Virginia. The remaining $8 million was recorded in other operations and maintenance expense in the Consolidated Statement of Income.
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, 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. However, in November 2015, the Virginia Commission ordered testimony, briefs and
separate bifurcated hearing in Virginia Power’s currently pending Rider B, Rider R, Rider S and Rider W cases on whether the Virginia Commission can adjust the ROE applicable to these rate adjustment clauses prior to 2017. The legislation also required Virginia Power to write-off $85 million of prior-period deferred fuel costs during the first quarter of 2015. In addition, the legislation required the Virginia Commission to implement a fuel rate reduction for Virginia Power as soon as practicable based on this non-recovery as well as any over-recovery for the 2014-2015 fuel year and projected fuel expense for the 2015-2016 fuel year. The legislation also deems the construction or purchase of one or more utility-scale solar facilities located in Virginia up to 500 MW in total to be in the public interest.
Biennial Review
Pursuant to the Regulation Act, in March 2015, Virginia Power filed its base rate case and schedules for the Virginia Commission’s 2015 biennial review of Virginia Power’s rates, terms and conditions. Per legislation enacted in February 2015, this biennial review was limited to reviewing Virginia Power’s earnings on rates for generation and distribution services for the combined 2013 and 2014 test period, and determining whether credits are due to customers in the event Virginia Power’s earnings exceeded the earnings band determined in the 2013 Biennial Review Order. 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. Based upon 2015 legislation keeping Virginia Power’s base rates unchanged until at least December 1, 2022, the Virginia Commission did not order certain existing rate adjustment clauses to be combined with Virginia Power’s base rates. The Virginia Commission did not determine whether Virginia Power had a revenue deficiency or sufficiency when projecting the annual revenues generated by base rates to the revenues required to recover costs of service and earn a fair return. In December 2015, a group of large industrial customers filed notices of appeal with the Supreme Court of Virginia from both the 2015 Biennial Review Order and the Virginia Commission’s order denying their petition for rehearing or reconsideration. This appeal is pending.
Virginia Fuel Expenses
In February 2015, Virginia Power submitted its annual fuel factor filing to the Virginia Commission. In August 2015, the Virginia Commission approved Virginia Power’s annual fuel factor filing to recover an estimated $1.6 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2015. Virginia Power’s new approved fuel rate, in effect on an interim basis since April 1, 2015, represents a fuel revenue decrease of $512 million when applied to projected kilowatt-hour sales for the period April 1, 2015 to June 30, 2016.
Solar Facility Projects
In January 2015, Virginia Power applied for a CPCN to construct and operate a 20 MW utility-scale solar facility near its existing Remington power station in Fauquier County, Virginia. The total estimated cost of the Remington solar facility was approximately $47 million, excluding financing costs. Virginia Power also applied for approval of Rider US-1 to recover the projected costs of the facility. In October 2015, the Virginia Commission denied approval of the CPCN and Rider US-1 based on the evidence in the record but stated that an application could be re-filed to address the concerns cited by the Virginia Commission. Virginia Power is assessing its options for re-filing.
In October 2015, Virginia Power filed a CPCN with the Virginia Commission to construct three solar facilities. Woodland, Scott Solar and Whitehouse would increase Dominion’s renewable generation by a combined 56 MW and are estimated to cost approximately $130 million, excluding financing costs. Virginia Power also applied for approval of Rider US-2. This case is pending. The facilities are expected to commence commercial operations, subject to regulatory approvals, in the fourth quarter of 2016.
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 2015, Virginia Power proposed a $668 million total revenue requirement for the rate year beginning September 1, 2015, which represents a $130 million increase over the previous year. Virginia Power also presented a mitigation proposal to defer $96 million of this revenue requirement to the rate year beginning September 1, 2016, which would reduce by 50% the one-year rate impact on residential customers. In August 2015, the Virginia Commission rejected the mitigation proposal and approved full recovery of the proposed revenue requirement.
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The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2015, Virginia Power proposed a $250 million revenue requirement for the rate year beginning April 1, 2016, which represents a $5 million increase over the previous year. This case is pending.
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The Virginia Commission previously approved Rider W in conjunction with Warren County. In June 2015, Virginia Power proposed a $118 million revenue requirement for the rate year beginning April 1, 2016, which represents a $17 million decrease versus the previous year. This case is pending.
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The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In June 2015, Virginia Power proposed a $74 million revenue requirement for the rate year beginning April 1, 2016, which represents a $10 million decrease versus the previous year. This case is pending.
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The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2015, Virginia Power proposed a $30 million revenue requirement for the rate year beginning April 1, 2016, which represents a $21 million increase over the previous year. This case is pending.
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Virginia legislation which provides for the recovery of costs to move certain electric distribution facilities underground became effective in July 2014. In October 2014, Virginia Power filed for approval of Rider U, which proposed a revenue requirement of $28 million during the initial rate year beginning September 1, 2015. In May 2015, Virginia Power revised the revenue requirement to $24 million. In July 2015, the Virginia Commission denied approval of Rider U based on the evidence in the record, but found that an alternative plan addressing certain concerns, such as the lack of a cost-benefit analysis, could reasonably satisfy the regulatory requirements for approval. In December 2015, Virginia Power filed for approval of a more limited undergrounding program, along with a revised Rider U proposing a revenue requirement of $24 million for the initial rate year beginning September 1, 2016. This case is pending.
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The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In August 2015, Virginia Power proposed a total revenue requirement of $50 million for the rate year beginning May 1, 2016. Virginia Power further proposed two new energy efficiency programs for Virginia Commission approval with a requested five-year cost cap of $51 million for those programs, and to extend an existing peak-shaving program for an additional five years under current funding. This case is pending.
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The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In October 2015, Virginia Power proposed a $156 million total revenue requirement for the rate year beginning September 1, 2016, which represents a $45 million increase versus the previous year. This case is pending.
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In July 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate Greensville County and related transmission interconnection facilities. Virginia Power also applied for approval of Rider GV to recover the costs of Greensville County, and proposed a total revenue requirement of $42 million for the rate year beginning April 1, 2016. This case is pending.
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. In February 2014, the Virginia Commission granted reconsideration requested by Virginia Power and issued an Order Amending Certificate. Several appeals were filed with the Supreme Court of Virginia. In April 2015, the Supreme Court of Virginia issued its opinion in the consolidated appeals of the Virginia Commission’s order granting a CPCN for the Skiffes Creek transmission line and related facilities. The Supreme Court of Virginia unanimously affirmed all but one of the alleged grounds for appeal. The court approved the proposed project including the proposed route for a
Combined Notes to Consolidated Financial Statements, Continued
500 kV overhead transmission line from Surry to the Skiffes Creek switching station site. The court reversed and remanded the Virginia Commission’s determination in one set of appeals that the Skiffes Creek switching station was a transmission line for purposes of statutory exemption from local zoning ordinances. In May 2015, the Supreme Court of Virginia denied separate petitions filed by Virginia Power and the Virginia Commission to rehear its ruling regarding the Skiffes Creek switching station. Pending receipt of remaining required permits and approvals, Virginia Power expects to construct the project.
In May 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate in Loudoun County, Virginia, a new approximately 230 kV Poland Road substation, and a new approximately four mile overhead 230 kV double circuit transmission line between the existing 230 kV Loudoun-Brambleton line and the Poland Road substation. The total estimated cost of the project is approximately $55 million. This case is 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 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 $51 million. This case 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. The total estimated cost of the project is approximately $104 million. This case is pending.
In February 2016, the Virginia Commission issued an order granting Virginia Power a CPCN to construct and operate the Remington CT-Warrenton 230 kV double circuit transmission line, the Vint Hill-Wheeler and Wheeler-Gainesville 230 kV lines and the 230 kV Vint Hill and Wheeler switching stations along Virginia Power’s proposed route. The total estimated cost of the project is approximately $105 million.
North Anna
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. The COL is expected in 2017. Virginia Power has not yet committed to building a new nuclear unit at North Anna.
The motions and petitions filed by BREDL prior to April 2015 have been dismissed, and under a previous ruling of the NRC, the contested portion of the COL proceeding remains terminated. The NRC is required to conduct a hearing in all COL proceedings, and if a new contention is not admitted, the mandatory NRC hearing will be uncontested.
In April 2015, BREDL filed a new motion and petition seeking to object to the NRC’s reliance on the continued storage rule in licensing proceedings. The BREDL filings are substantially the
same as those filed in other COL proceedings in which final environmental impact statements were issued prior to promulgation of the continued storage rule, like North Anna 3. In June 2015, the NRC denied the April 2015 motion and petition.
In August 2015, BREDL filed a petition in the U.S. Court of Appeals for the D.C. Circuit seeking review of the NRC’s June 2015 decision. Along with the petition for judicial review, BREDL also filed a motion to hold this judicial review in abeyance pending the outcome of the ongoing judicial review of the NRC’s rule pertaining to the continued onsite storage of spent nuclear fuel in litigation pending before the same court. Similar petitions were filed seeking judicial review of the NRC’s decision as it applies to other COL and license renewal proceedings. Virginia Power has filed a motion with the court to intervene in the proceeding. This case is pending.
North Anna and Offshore Wind Legislation
In April 2014, legislation was enacted in Virginia that permits Virginia Power to recover 70% of the costs previously deferred or capitalized related to the development of a third nuclear unit located at North Anna and offshore wind facilities through December 31, 2013 as part of the 2013 and 2014 base rates. Virginia Power had deferred or capitalized costs totaling $577 million for these projects as of December 31, 2013, substantially all of which relate to North Anna. For the 70% portion of these previously deferred or capitalized costs allocable to customers in Virginia, Virginia Power recognized such amounts as charges against net income beginning in the second quarter of 2014 and for the remainder of the year. During 2014, Virginia Power recognized $374 million ($248 million after-tax) in charges against income representing the cumulative recovery of costs from January 2013 through December 2014, which are primarily included in other operations and maintenance expense in the Consolidated Statements of Income. The remaining deferred or capitalized costs, as well as costs incurred after December 31, 2013, continue to be eligible for inclusion in a future rate adjustment clause.
NORTH CAROLINA REGULATION
In December 2012, the North Carolina Commission approved a $36 million increase in Virginia Power’s annual non-fuel base revenues based on an authorized ROE of 10.2%, and a $14 million decrease in annual base fuel revenues for a combined total base revenue increase of $22 million. These rate changes became effective on January 1, 2013. Following an appeal to the Supreme Court of North Carolina, the North Carolina Commission issued an opinion reaffirming its 10.2% ROE determination in July 2015.
In August 2015, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed an $11 million decrease to the fuel component of its electric rates for the rate year beginning January 1, 2016. This decrease includes the North Carolina Commission’s previous approval to defer recovering 50% of Virginia Power’s estimated $17 million jurisdictional deferred fuel balance to the 2016 fuel year, without interest. In December 2015, 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 its application, East Ohio proposed that PIR investments for 2016 should fall under the existing authorization and that the new five-year period should include investment through December 31, 2021. East Ohio also proposed that the PIR investment should be increased by $20 million in 2017 and another $20 million in 2018, bringing the total annual investment to $200 million. Thereafter, East Ohio proposed capital investment increases of 3% per year for 2019 through 2021 to mitigate inflation and other cost pressures experienced to date, which will continue into the future. This case is pending.
In February 2015, East Ohio filed an application to adjust the PIR cost recovery for 2014 costs. The filing reflects gross plant investment for 2014 of $155 million, cumulative gross plant investment of $829 million and a revenue requirement of $108 million. This application was approved by the Ohio Commission in April 2015.
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 February 2015, East Ohio filed its application with the Ohio Commission to adjust its AMR cost recovery charge to recover costs for calendar year 2014 associated with AMR deployment. The filing reflects a projected revenue requirement of approximately $8 million. This application was approved by the Ohio Commission in April 2015.
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 2015, 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 refund for the twelve-month period from July 2015 through June 2016 of an over-recovery of accumulated arrearages of approximately $57 million as of March 31, 2015, net of projected deferred program costs of approximately $35 million from April 2015 through June 2016.
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 July 2015, the Ohio Commission
approved East Ohio’s application to decrease its UEX Rider, which reflects a refund of over-recovered accumulated bad debt expense of $14 million as of March 31, 2015, and recovery of prospective net bad debt expense projected to total approximately $20 million for the twelve-month period from April 2015 to March 2016.
PSMP
In October 2015, East Ohio requested approval from the Ohio Commission to defer the operation and maintenance costs associated with implementing a proposed PSMP. The costs are not expected to exceed $15 million per year.
WEST VIRGINIA REGULATION
In September 2015, Hope requested approval of PREP from the West Virginia Commission. In the application, Hope proposed a projected capital investment for 2016 of $24 million as part of a total five-year projected capital investment of $158 million. In January 2016, Hope and the West Virginia Commission reached a settlement allowing Hope to include costs related to capital investment for 2016 of $20 million in new PREP customer rates effective March 1, 2016.
FERC-GAS
During the second quarter of 2013, DCG executed binding precedent agreements for the approximately $35 million Edgemoor Project. FERC approved the Edgemoor Project in February 2015, construction commenced in March 2015 and the project was placed into service in December 2015
In April 2014, DCG executed a binding precedent agreement for the approximately $35 million Columbia to Eastover Project. In May 2015, DCG filed an application to request FERC authorization to construct and operate the project facilities, which are expected to be in service in the third quarter of 2016.
In October 2015, Cove Point received authorization to construct the approximately $30 million St. Charles Transportation Project and the approximately $40 million Keys Energy Project. Construction on each project commenced in the fourth quarter of 2015. The St. Charles Transportation Project is anticipated to be placed into service in June 2016. The Keys Energy Project is anticipated to be placed into service in March 2017.
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’s and Virginia Power’s AROs are primarily associated with the decommissioning of their nuclear generation facilities and also include those for ash pond closures and the future abatement of asbestos expected to be disturbed in their generation facilities. Dominion 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’s LNG facility, Dominion Gas’ storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and
Combined Notes to Consolidated Financial Statements, Continued
lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in Dominion’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 2014 and 2015 were as follows:
(1) Relates primarily to a shift of the delayed planned date on which the DOE is expected to begin accepting spent nuclear fuel.
(2) Includes $81 million and $216 million reported in other current liabilities at December 31, 2014, and 2015, respectively.
(3) Primarily reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 for further information.
(4) Includes $140 million and $137 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2014 and 2015, respectively.
Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At both December 31, 2015 and 2014, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $4.2 billion. At both December 31, 2015 and 2014, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.9 billion.
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
Through August 2013, Dominion leased the Fairless generating facility in Pennsylvania, which began commercial operations in June 2004, from Juniper, the lessor. In August 2013, the lease expired and Dominion purchased Fairless for $923 million from Juniper per the terms of the lease agreement. However, as Dominion had previously consolidated Juniper, the purchase was accounted for as an equity transaction to acquire the noncontrolling interests from Juniper for $923 million, while Dominion retained control of Fairless.
Dominion has an initial 45% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the nature of this entity. Dominion concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion 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 is obligated to provide capital contributions based on its ownership percentage. Dominion’s maximum exposure to loss is limited to its current and future investment.
Dominion and Dominion Gas
Dominion Midstream and Dominion Gas own a 25.93% and 24.72% noncontrolling partnership interest in Iroquois, respectively. See Note 3 for further details regarding the nature of this entity. Dominion concluded that Iroquois is a VIE because a non-affiliated Iroquois equity holder has the ability during a limited period of time to transfer its ownership interests to another Iroquois equity holder or its affiliate. At December 31, 2015, Dominion concluded that neither Dominion Midstream nor Dominion Gas is the primary beneficiary of Iroquois as they do not have the power to direct the activities of Iroquois that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. If Iroquois determines capital contributions are required, Dominion Midstream and Dominion Gas each would be obligated to provide the portion of capital contributions based on its ownership percentage. Dominion Midstream’s and Dominion Gas’ maximum exposure to loss is limited to their current and future investment.
Dominion Gas
DTI 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 DTI holds a membership interest in Atlantic Coast Pipeline, therefore DTI 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. DTI 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. DTI has no obligation to absorb any losses of the VIE. See Note 24 for information about associated related party receivable balances.
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 leaving a remaining aggregate summer generation capacity of approximately 418 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 entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The remaining contracts expire at various dates ranging from 2017 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $439 million as of December 31, 2015. Virginia Power paid $200 million, $223 million, and $217 million for electric capacity and $83 million, $138 million, and $98 million for electric energy to these entities for the years ended December 31, 2015, 2014 and 2013, respectively.
Virginia Power and Dominion Gas
Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of $318 million and $115 million, $335 million and $106 million, and $331 million and $115 million for the years ended December 31, 2015, 2014 and 2013, respectively. Virginia Power and Dominion Gas determined that each is not the most closely associated entity with DRS and therefore neither is the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to
all Dominion subsidiaries, including Virginia Power and Dominion Gas. Virginia Power and Dominion Gas have no obligation to absorb more than their allocated shares of DRS 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 January 2016, Dominion expanded its short-term funding resources through a $1.0 billion increase to one of its joint revolving credit facility limits. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.
Dominion
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 2019, 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) In January 2016, this facility limit was increased from $4.0 billion to $5.0 billion.
(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were 0.62% and 0.38% at December 31, 2015 and 2014, respectively.
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.
Combined Notes to Consolidated Financial Statements, Continued
Virginia Power’s share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion and Dominion Gas were as follows:
(1) The full amount of the facilities is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion and Dominion 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, 2015, the sub-limit for Virginia Power was an aggregate $1.75 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. These credit facilities mature in April 2019, 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) In January 2016, this facility limit was increased from $4.0 billion to $5.0 billion.
(3) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.60% and 0.36% at December 31, 2015 and 2014, respectively.
In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility with a maturity date of April 2019. As of December 31, 2015, this facility supports $119 million of certain variable rate tax-exempt financings of Virginia Power.
Dominion Gas
Dominion Gas’ short-term financing is supported by its access as co-borrower to the two joint revolving credit facilities. In December 2014, Dominion Gas entered into a commercial paper program pursuant to which it began accessing the commercial paper markets in January 2015.
Dominion Gas’ share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion and Virginia Power were as follows:
(1) A maximum of a combined $1.5 billion of the facilities is available to Dominion Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion and Virginia Power. Sub-limits for Dominion Gas are set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2015, the sub-limit for Dominion Gas was an aggregate $500 million. In January 2016, the aggregate sub-limit for Dominion Gas was increased to $1.0 billion. If Dominion 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. These credit facilities mature in April 2019, 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 0.63% at December 31, 2015.
NOTE 17. LONG-TERM DEBT
(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2015.
(2) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. Certain variable rate tax-exempt financings are supported by a $120 million credit facility that terminates in April 2019.
(3) At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 were subject to redemption at 100% of the principal amount plus accrued interest in August 2015. As a result, at December 31, 2014, the notes were included in securities due within one year in Dominion’s Consolidated Balance Sheets. The option to redeem the notes expired in June 2015. At December 31, 2015, the notes are included in long-term debt in Dominion’s Consolidated Balance Sheets.
(4) Represents debt assumed by Dominion from the merger of its former CNG subsidiary.
(5) Represents the valuation of certain fair value hedges associated with Dominion’s fixed rate debt.
(6) Includes $4 million for fair value hedge valuation in 2014. Excludes $100 million of variable rate short-term notes scheduled to mature in May 2016 that were purchased and cancelled using the proceeds from the February 2016 issuance of senior notes that mature in 2018.
Combined Notes to Consolidated Financial Statements, Continued
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, 2015, were as follows:
(1) In February 2016, Dominion purchased and cancelled $100 million of variable rate short-term notes that would have otherwise matured in May 2016 using the proceeds from the February 2016 issuance of senior notes that mature in 2018. As a result, at December 31, 2015, $100 million of the notes were 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, 2015, there were no events of default under these covenants.
In January 2016, Virginia Power issued $750 million of 3.15% senior notes that mature in 2026.
In February 2016, Dominion issued $500 million of 2.125% senior notes in a private placement. The notes mature in 2018.
Senior Note Redemptions
As part of Dominion’s Liability Management Exercise, in December 2014, Dominion redeemed five outstanding series of senior notes with an aggregate outstanding principal of $1.9 billion. The aggregate redemption price paid in December 2014 was $2.2 billion and represents the principal amount outstanding, accrued and unpaid interest and the applicable make-whole premium of $263 million. Total charges for the Liability Management Exercise of $284 million, including the make-whole premium, were recognized and recorded in interest expense in Dominion’s Consolidated Statements of Income. Proceeds from Dominion’s issuance of senior notes in November 2014 were used to offset the payment of the redemption price. Also see Convertible Securities called for redemption below.
Convertible Securities
As part of Dominion’s Liability Management Exercise, in November 2014, Dominion provided notice to redeem all $22 million of outstanding contingent convertible senior notes. The senior notes were eligible for conversion during 2014. However, in lieu of redemption, holders elected to convert the remaining $22 million of notes in December 2014 into $26 million of common stock. Proceeds from Dominion’s issuance of senior notes in November 2014 were used to offset the portion of the conversions paid in cash. At December 31, 2014, all of the senior notes have been converted and none remain outstanding.
Junior Subordinated Notes Payable to Affiliated Trusts
In previous years, Dominion established several subsidiary capital trusts, each as a finance subsidiary of Dominion, which holds 100% of the voting interests. The trusts sold capital securities representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trusts. In exchange for the funds realized from the sale of the capital securities and common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trusts, Dominion issued various junior subordinated notes. The junior subordinated notes constitute 100% of each capital trust’s assets. Each trust must redeem its capital securities when their respective junior subordinated notes are repaid at maturity or if redeemed prior to maturity.
In January 2013, Dominion repaid its $258 million 7.83% unsecured junior subordinated debentures and redeemed all 250 thousand units of the $250 million 7.83% Dominion Resources Capital Trust I capital securities due December 1, 2027. The securities were redeemed at a price of $1,019.58 per capital security plus accrued and unpaid distributions.
Interest charges related to Dominion’s junior subordinated notes payable to affiliated trusts were $1 million for the years ended December 31, 2015, 2014 and 2013.
Enhanced Junior Subordinated Notes
In June 2006 and September 2006, Dominion issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids bear interest at 7.5% per year until June 30, 2016. Thereafter, they will bear interest at the three-month LIBOR plus 2.825%, reset quarterly. The September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly.
In June 2009, Dominion issued $685 million of 8.375% June 2009 hybrids. The June 2009 hybrids were listed on the NYSE under the symbol DRU.
In October 2014, Dominion 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 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 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 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 executed RCCs in connection with its issuance of the June 2006 hybrids, the September 2006 hybrids, and the June 2009 hybrids. Under the terms of the RCCs, Dominion covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion 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 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 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. In July 2014, Dominion amended the RCC of the June 2009 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock or other equity-like issuances from 180 days to 365 days. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.
As part of Dominion’s Liability Management Exercise, in October 2014, Dominion redeemed all $685 million of the June 2009 hybrids plus accrued interest with the net proceeds from the issuance of the October 2014 hybrids. In 2015, Dominion purchased and canceled $14 million and $3 million of the June 2006 hybrids and the September 2006 hybrids, respectively. In the first quarter of 2016, Dominion purchased and cancelled $37 million and $2 million of the June 2006 hybrids and the September 2006 hybrids, respectively. The redemption and all purchases were conducted in compliance with the RCCs.
Remarketable Subordinated Notes
In June 2013, Dominion issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B 6% Equity Units, initially in the form of Corporate Units. In July 2014, Dominion issued $1.0 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbols DCUA, DCUB and DCUC, respectively.
Each Corporate Unit consists of a stock purchase contract and 1/20 interest in a RSN issued by Dominion. The stock purchase contracts obligate the holders to purchase shares of Dominion 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 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 makes quarterly interest payments on the RSNs and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. Dominion 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 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 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 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 applies the treasury stock method to the Equity Units.
Pursuant to the terms of the 2013 Equity Units and 2014 Equity Units, Dominion expects to remarket the 2013 Series A, 2013 Series B and 2014 Series A RSNs during the first and second quarters of 2016, and the second quarter of 2017, respectively. Following a successful remarketing, the interest rate on the RSNs will be reset, interest will be payable on a semi-annual basis and Dominion 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 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 will issue between 8.5 million and 10.0 million shares of its common stock in both April 2016 and July 2016 and between 11.5 million and 14.4 million shares in July 2017. A total of 40.3 million shares of Dominion’s common stock has been reserved for issuance in connection with the stock purchase contracts.
Selected information about Dominion’s Equity Units is presented below:
(1) Payments of $101 million and $66 million were made in 2015 and 2014, respectively. The stock purchase contract liability was $115 million and $216 million at December 31, 2015 and 2014, respectively.
NOTE 18. PREFERRED STOCK
Dominion is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2015 or 2014.
Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference. During 2014, Virginia Power redeemed 2.59 million shares, which represented all outstanding series of its preferred stock, some of which were redeemed as a part of Dominion’s Liability Management Exercise in September 2014. Upon redemption, each series was no longer outstanding for any purpose and dividends ceased to accumulate. Virginia Power had no preferred stock issued and outstanding at December 31, 2015 or 2014.
NOTE 19. EQUITY
Issuance of Common Stock
DOMINION
Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’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 began purchasing its common stock on the open market for these plans. In April 2014, Dominion began issuing new common shares for these direct stock purchase plans.
During 2015, Dominion received cash proceeds, net of fees and commissions, of $783 million from the issuance of approximately 11 million shares of common stock through various programs resulting in approximately 596 million of shares of common stock outstanding at December 31, 2015. These proceeds include cash of $284 million received from the issuance of 4.1 million of such shares through Dominion Direct® and employee savings plans.
In December 2014, Dominion 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 December 2014, Dominion entered into four 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 and the sales agents and in conformance with applicable securities laws. During the first and
second quarters of 2015, Dominion provided sales instructions to the sales agents and issued 4.0 million shares through at-the-market issuances and received cash proceeds of $297 million, net of fees and commissions paid of $3 million. Following these issuances, Dominion has the ability to issue up to approximately $200 million of stock under the 2014 sales agency agreements. However, Dominion completed its 2015 planned market issuances of equity in May 2015 with the issuance of 2.8 million shares and receipt of proceeds of $202 million through a registered underwritten public offering.
VIRGINIA POWER
In 2015, 2014 and 2013, Virginia Power did not issue any shares of its common stock to Dominion.
DOMINION GAS
On September 30, 2013, Dominion contributed its wholly-owned subsidiaries DTI, East Ohio and Dominion Iroquois to Dominion Gas in exchange for 100% of its limited liability company membership interests.
Shares Reserved for Issuance
At December 31, 2015, Dominion had approximately 50 million shares reserved and available for issuance for Dominion 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 did not repurchase any shares in 2015 or 2014 and does not plan to repurchase shares during 2016, 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 Midstream Units
In September 2015, Dominion initiated a program to purchase from the market up to $50 million of common units representing limited partner interests in Dominion Midstream. The common units may be acquired by Dominion over the 12 month period following commencement of the program at the discretion of management. Through December 31, 2015, Dominion purchased approximately 887,000 common units for $25 million. In the first quarter of 2016, Dominion purchased approximately 377,000 additional common units for approximately $10 million. At February 23, 2016, Dominion still has the ability to purchase up to $15 million of common units under the program.
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
The following table presents Dominion’s changes in AOCI by component, net of tax:
(1) See table below for details about these reclassifications.
The following table presents Dominion’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 GAS
The following table presents Dominion Gas’ changes in AOCI by component, net of tax:
(1) See table below for details about these reclassifications.
The following table presents Dominion 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, 2015, approximately 25 million shares were available for future grants under these plans.
Dominion 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’s results for the years ended December 31, 2015, 2014 and 2013 include $39 million, $39 million, and $31 million, respectively, of compensation costs and $14 million, $14 million, and $11 million, respectively of income tax benefits related to Dominion’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. Excess Tax Benefits are classified as a financing cash flow. Dominion realized $3 million of excess tax benefits from the vesting of restricted stock awards and exercise of stock options during the year ended December 31, 2015, and less than $1 million during the years ended December 31, 2014 and 2013.
RESTRICTED STOCK
Restricted stock grants are made to officers under Dominion’s LTIP and may also be granted to certain key non-officer employees from time to time. The fair value of Dominion’s restricted stock awards is equal to the closing price of Dominion’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, 2015, 2014 and 2013:
As of December 31, 2015, unrecognized compensation cost related to nonvested restricted stock awards totaled $27 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 $37 million, $19 million, and $20 million in 2015, 2014 and 2013, 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 stock and the applicable federal, state and local tax withholding rates.
GOAL-BASED STOCK
Goal-based stock awards are granted under Dominion’s LTIP to officers who have not achieved a certain targeted level of share
Combined Notes to Consolidated Financial Statements, Continued
ownership, in lieu of cash-based performance grants. Goal-based stock awards may also be made to certain key non-officer employees from time to time. Current outstanding goal-based shares include awards granted to officers in February 2014 and February 2015.
The issuance of awards is based on the achievement of two performance metrics during a two-year period: 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 actual number of shares issued will vary between zero and 200% of targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is equal to the closing price of Dominion’s stock on the date of grant. Goal-based stock awards granted to key non-officer employees convert to restricted stock at the end of the two-year performance period and generally vest three years from the original grant date. Awards to officers vest at the end of the two-year performance period. All goal-based stock awards are settled by issuing new shares.
The following table provides a summary of goal-based stock activity for the years ended December 31, 2015, 2014 and 2013:
At December 31, 2015, the targeted number of shares expected to be issued under the February 2014 and February 2015 awards was approximately 24 thousand. In January 2016, the CGN Committee determined the actual performance against metrics established for the February 2014 awards with a performance period that ended December 31, 2015. Based on that determination, the total number of shares to be issued under the February 2014 goal-based stock awards was approximately 10 thousand.
As of December 31, 2015, unrecognized compensation cost related to nonvested goal-based stock awards was not material.
CASH-BASED PERFORMANCE GRANTS
Cash-based performance grants are made to Dominion’s officers under Dominion’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.
In February 2012, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $8 million was paid in December 2013, based on the achievement of two performance metrics during 2012 and 2013: 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 amount of the award under the grant was $12 million and the remaining portion of the grant was paid in January 2014.
In February 2013, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $14 million was paid in December 2014, based on the achievement of two performance metrics during 2013 and 2014: 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 amount of the award under the grant was $20 million and the remaining portion of the grant was paid in February 2015.
In February 2014, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2016 based on the achievement of two performance metrics during 2014 and 2015: 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 expected award under the grant is $10 million and the grant is expected to be paid by March 15, 2016. At December 31, 2015, a liability of $10 million had been accrued for this award.
In February 2015, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 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. At December 31, 2015, the targeted amount of the grant was $14 million and a liability of $7 million had been accrued for this award.
NOTE 20. DIVIDEND RESTRICTIONS
The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2015, 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, 2015, the Ohio Commission had not restricted the payment of dividends by East Ohio.
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, 2015.
See Note 17 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes and equity units, initially in the form of corporate units.
NOTE 21. EMPLOYEE BENEFIT PLANS
Dominion and Dominion Gas-Defined Benefit Plans
Dominion provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Gas participates in a number of the Dominion-sponsored retirement
plans. Under the terms of its benefit plans, Dominion 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 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’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension program also provides benefits to certain retired executives under a company-sponsored nonqualified employee benefit plan. The nonqualified plan is funded through contributions to a grantor trust. Dominion 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 Gas employees not represented by collective bargaining units are covered by the Dominion Pension Plan, a defined benefit pension plan sponsored by Dominion that provides benefits to multiple Dominion subsidiaries. Pension benefits for Dominion Gas employees represented by collective bargaining units are covered by separate pension plans for East Ohio and, for DTI, a plan that provides benefits to employees of both DTI and Hope. Employee compensation is the basis for allocating pension costs and obligations between DTI and Hope and determining East Ohio’s share of total pension costs.
Retiree healthcare and life insurance benefits for Dominion Gas employees not represented by collective bargaining units are covered by the Dominion Retiree Health and Welfare Plan, a plan sponsored by Dominion that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Retiree healthcare and life insurance benefits for Dominion Gas employees represented by collective bargaining units are covered by separate other postretirement benefit plans for East Ohio and, for DTI, a plan that provides benefits to both DTI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DTI 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 uses December 31 as the measurement date for all of its employee benefit plans, including those in which Dominion Gas participates. Dominion 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 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’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Dominion’s pension and other postretirement plan assets experienced aggregate actual losses of $72 million in 2015 and aggregate actual returns of $706 million in 2014, versus expected returns of $648 million and $610 million, respectively. Dominion Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual losses of $13 million in 2015 and aggregate actual returns of $157 million in 2014, versus expected returns of $150 million and $138 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.
The Medicare Act introduced a federal subsidy to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Dominion determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D. Dominion and Dominion Gas received a federal subsidy of $4 million and $1 million, respectively, for 2014. Effective January 1, 2013, Dominion changed its method of receiving the subsidy under Medicare Part D for retiree prescription drug coverage from the Retiree Drug Subsidy to the EGWP. This change reduced other postretirement benefit costs by approximately $20 million annually beginning in 2012. As a result of the adoption of the EGWP, Dominion begins to receive an increased level of Medicare Part D subsidies in the form of reduced costs rather than a direct reimbursement.
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 changed its assumption for mortality rates to reflect a generational improvement scale. As a result of this change in assumption, at December 31, 2014 Dominion and Dominion Gas (for employees represented by collective bargaining units) increased their pension benefit obligations by $131 million and $10 million, respectively, and increased their accumulated postretirement benefit obligations by $32 million and $7 million, respectively. This change increased net periodic benefit cost for Dominion and Dominion Gas (for employees represented by collective bargaining units) by $25 million and $3 million, respectively, for 2015.
Dominion remeasured all of its pension and other postretirement benefit plans in the second quarter of 2013. The remeasurement resulted in a reduction in the pension benefit obligation of $354 million and a reduction in the accumulated postretirement benefit obligation of $78 million. For Dominion Gas employees represented by collective bargaining units, the remeasurement resulted in a reduction in the pension benefit obligation of $28 million and a reduction in the accumulated postretirement benefit obligation of $9 million. The impact of the
Combined Notes to Consolidated Financial Statements, Continued
remeasurement on net periodic benefit (credit) cost was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by $36 million, excluding the impacts of curtailments, and for Dominion Gas employees represented by collective bargaining units by $2 million. The discount rate used for the remeasurement was 4.80% for the pension plans and 4.70% for the other postretirement benefit plans. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.
In the fourth quarter of 2013, Dominion remeasured its other postretirement benefit plans as a result of a plan amendment that changed medical coverage for certain Medicare-eligible retirees effective April 2014. The remeasurement resulted in a reduction in the accumulated postretirement benefit obligation of $220 million. The impact of the remeasurement on net periodic benefit (credit) cost was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by $8 million. The amendment is expected to reduce net periodic benefit cost by $40 million to $60 million for each of the next five years. The discount rate used for the remeasurement was 4.80%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.
In the third quarter of 2014, East Ohio remeasured its other postretirement benefit plan as a result of an amendment that changed medical coverage upon the attainment of age 65 for certain future retirees effective January 1, 2016. For employees represented by collective bargaining units, the remeasurement resulted in an increase in the accumulated postretirement benefit obligation of $22 million. The impact of the remeasurement on net periodic benefit credit was recognized prospectively from the remeasurement date and reduced net periodic benefit credit for 2014, for employees represented by collective bargaining units, by less than $1 million. The discount rate used for the remeasurement was 4.20% and the expected long-term rate of return used was 8.50%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2013.
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 and Dominion Gas (for employees represented by collective bargaining units):
Combined Notes to Consolidated Financial Statements, Continued
(1) 2015 amount relates primarily to a plan amendment that changed retiree medical benefits for certain nonunion employees after Medicare eligibility.
(2) Relates primarily to a settlement charge for certain executives.
(3) Reflected in other deferred credits and other liabilities in Dominion Gas’ Consolidated Balance Sheets.
The ABO for all of Dominion’s defined benefit pension plans was $5.8 billion and $6.0 billion at December 31, 2015 and 2014, respectively. The ABO for the defined benefit pension plans covering Dominion Gas employees represented by collective bargaining units was $578 million and $604 million at December 31, 2015 and 2014, respectively.
Under its funding policies, Dominion 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 determines the amount of contributions for the current year, if any, at that time. During 2015, Dominion and Dominion Gas made no contributions to the qualified defined benefit pension plans and no contributions are currently expected in 2016. 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 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’s subsidiaries, including Dominion Gas, fund other postretirement benefit costs through VEBAs. Dominion’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion’s contributions to VEBAs, all of which pertained to Dominion Gas employees, totaled $12 million for both 2015 and 2014, and Dominion expects to contribute approximately $12 million to the Dominion VEBAs in 2016, all of which pertains to Dominion Gas employees.
Dominion and Dominion Gas do not expect any pension or other postretirement plan assets to be returned during 2016.
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 and Dominion Gas (for employees represented by collective bargaining units):
The following table provides information on the ABO and fair value of plan assets for Dominion’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’s and Dominion Gas’ (for employees represented by collective bargaining units) plans:
Plan Assets
Dominion’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, Dominion Gas is subject to Dominion’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’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 United States. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the United States 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 REITs and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.
Dominion also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.
Strategic investment policies are established for Dominion’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’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.
Combined Notes to Consolidated Financial Statements, Continued
The fair values of Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) pension plan assets by asset category are as follows:
(1) Common/collective trust funds include $330 million and $360 million of John Hancock insurance contracts held at December 31, 2015 and 2014, respectively. See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund.
(2) These investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Consolidated Balance Sheets.
(3) Includes net assets related to pending sales of securities of $112 million, net accrued income of $16 million, and excludes net assets related to pending purchases of securities of $118 million at December 31, 2015. Includes net assets related to pending sales of securities of $31 million, net accrued income of $18 million, and excludes net assets related to pending purchases of securities of $38 million at December 31, 2014.
(4) Common/collective trust funds include $78 million and $84 million of John Hancock insurance contracts held at December 31, 2015 and 2014, respectively. See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund.
(5) Includes net assets related to pending sales of securities of $27 million, net accrued income of $4 million, and excludes net assets related to pending purchases of securities of $28 million at December 31, 2015. Includes net assets related to pending sales of securities of $7 million, net accrued income of $4 million, and excludes net assets related to pending purchases of securities of $9 million at December 31, 2014.
The fair values of Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) other postretirement plan assets by asset category are as follows:
(1) Common/collective trust funds include $18 million and $19 million of John Hancock insurance contracts held at December 31, 2015 and 2014, respectively. See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund.
(2) These investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Consolidated Balance Sheets.
(3) See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund.
Combined Notes to Consolidated Financial Statements, Continued
Investments in Common/Collective Trust Funds in Dominion’s pension and other postretirement plans, including those in which Dominion Gas participates, are stated at fair value as determined by the issuer of the Common/Collective Trust Funds based on the fair value of the underlying investments. The Common/Collective Trusts 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. Strategies of the Common/Collective Trust Funds are as follows:
Dominion and Dominion Gas
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Wells Fargo Closed End Bond Trust-The Fund invests in stocks, bonds or a combination of both. Shares of the Fund are traded on a stock exchange and are subject to market risk like stocks, bonds and mutual funds. The Fund may invest in a less liquid portfolio of stocks and bonds because the fund does not need to sell securities to meet shareholder redemptions as mutual funds in order to keep a percentage of its portfolio in cash to pay back investors who withdraw shares.
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JPMorgan Core Bond Trust-The Fund seeks to maximize total return by investing primarily in a diversified portfolio of intermediate- and long-term debt securities. The Fund invests primarily in investment-grade bonds; it generally maintains an average weighted maturity between four and 12 years. It may shorten its average weighted maturity if deemed appropriate for temporary defensive purposes.
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SSgA Russell 2000 Value Index Common Trust-The Fund measures the performance of the small-cap value segment of the U.S. equity universe. The Russell 2000 Value Index is constructed to provide a comprehensive and unbiased barometer for the small-cap value segment. The Index is completely reconstituted annually to ensure larger stocks do not distort the performance and characteristics of the true small-cap opportunity set and that the represented companies continue to reflect value characteristics.
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NT Common Short-Term Investment Fund-The Fund seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of approved money market instruments with short maturities. Liquidity is emphasized to provide for redemption of units at par on any business day. Principal preservation is a primary objective. Within quality, maturity, and sector diversification guidelines, investments are made in those securities with the most attractive yields.
Dominion
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SSgA Daily MSCI Emerging Markets Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI Emerging Markets Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company).
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SSgA Daily MSCI ACWI Ex-USA Index Non-Lending Fund-The Fund seeks an investment return that approximates as
closely as practicable, before expenses, the performance of the MSCI ACWI Ex-USA Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company).
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SSgA S&P 400 MidCap Index-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of its benchmark index (the Index) over the long term. The S&P MidCap 400 is comprised of approximately 400 U.S. mid-cap securities and accounts for approximately 7% coverage of the U.S. stock market capitalization. SSgA will typically attempt to invest in the equity securities comprising the Index, in approximately the same proportions as they are represented in the Index.
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SSgA S&P 500 Flagship Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the S&P 500 Index over the long term. The S&P 500 is comprised of approximately 500 large-cap U.S. equities and captures approximately 80% coverage of available market capitalization. SSgA will typically attempt to invest in the equity securities comprising the S&P 500 Index, in approximately the same proportions as they are represented in the Index.
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CF Goldman Sachs GSTCO Long Duration Fund-The Fund seeks to generate total return and prudent investment management through investments in fixed income securities. The Fund is actively managed and benchmarked versus the Barclays U.S. Long Government /Credit Index. At least 75% of the Fund’s total assets will be rated investment grade or better by a NRSRO at the time of purchase. The Fund may invest up to 25% of its total assets at the time of purchase in non-investment grade securities. The Fund may invest in non-dollar denominated securities that are fully hedged, unhedged or partially hedged.
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JPMorgan Chase Bank U.S. Active Core Plus Equity Fund-The Fund seeks to outperform the S&P 500 Index (the Benchmark), gross of fees, over a market cycle. The Fund invests primarily in a portfolio of long and short positions in equity securities of large and mid capitalization U.S. companies with characteristics similar to those of the Benchmark.
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NT Collective Russell 2000 Growth Index-The Fund seeks an investment return that approximates the overall performance of the common stocks included in the Russell 2000 Growth Index. The Fund primarily invests in common stocks of one or more companies that are deemed to be representative of the industry diversification of the entire Russell 2000 Growth Index.
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NT Collective Short-Term Investment Fund-The Fund is composed of high-grade money market instruments with short-term maturities. The Fund’s objective is to provide an investment vehicle for cash reserves while offering a competitive rate of return. Liquidity is emphasized to provide for redemption of units on any business day. Principal preservation is also a prime objective. Admissions and withdrawals are made daily. Interest is accrued daily and distributed monthly.
Investments in Group Insurance 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, and state and municipal debt securities.
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’s and Dominion Gas’ (for employees represented by collective bargaining units) plans are as follows:
(1) 2013 amounts relate primarily to the decommissioning of Kewaunee.
(2) Assumptions used to determine net periodic cost for the following year.
(3) The Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the ultimate trend rate much more quickly than previous models.
Combined Notes to Consolidated Financial Statements, Continued
The components of AOCI and regulatory assets and liabilities for Dominion’s and Dominion 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, 2015, of the $2.4 billion and $(123) million related to pension benefits and other postretirement benefits, $1.4 billion and $(90) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2014, of the $2.4 billion and $(94) million related to pension benefits and other postretirement benefits, $1.4 billion and $(81) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.
(2) As of December 31, 2015, of the $381 million related to pension benefits, $138 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $40 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2014, of the $304 million related to pension benefits, $112 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $50 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’s and Dominion Gas’ (for employees represented by collective bargaining units) plans as of December 31, 2015 that are expected to be amortized as components of net periodic benefit (credit) cost in 2016:
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 develops assumptions, which are then compared to the forecasts of an independent investment advisor (except for the expected long-term rates of return) to ensure reasonableness. An internal committee selects the final assumptions used for Dominion’s pension and other postretirement plans, including those in which Dominion Gas participates, including discount rates, expected long-term rates of return, healthcare cost trend rates and mortality rates.
Dominion 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 Gas participates, by using a combination of:
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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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Forecasts of an independent investment advisor;
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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
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Investment allocation of plan assets.
Dominion 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 Gas participates.
Dominion develops its mortality assumption using plan-specific studies and projects mortality improvement using scales developed by the Society of Actuaries for all its plans, including those in which Dominion Gas participates.
Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion’s retiree healthcare plans, including those in which Dominion Gas participates. A one percentage point change in assumed healthcare cost trend rates would have had the following effects for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) other postretirement benefit plans:
Dominion Gas (Employees Not Represented by Collective Bargaining Units) and Virginia Power-Participation in Defined Benefit Plans
Virginia Power employees and Dominion Gas employees not represented by collective bargaining units are covered by the Dominion Pension Plan described above. As participating employers, Virginia Power and Dominion Gas are subject to Dominion’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. During 2015, Virginia Power and Dominion Gas made no contributions to the Dominion Pension Plan, and no contributions to this plan are currently expected in 2016. Virginia Power’s net periodic pension cost related to this plan was $97 million, $75 million and $96 million in 2015, 2014 and 2013, respectively. Dominion Gas’ net periodic pension credit related to this plan was $(38) million, $(37) million and $(27) million in 2015, 2014 and 2013,
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 subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion subsidiaries. See Note 24 for Virginia Power and Dominion Gas amounts due to/from Dominion related to this plan.
Retiree healthcare and life insurance benefits, for Virginia Power employees and for Dominion Gas employees not represented by collective bargaining units, are covered by the Dominion Retiree Health and Welfare Plan described above. Virginia Power’s net periodic benefit (credit) cost related to this plan was $(16) million, $(18) million and $5 million in 2015, 2014 and 2013, respectively. Dominion Gas’ net periodic benefit (credit) cost related to this plan was $(5) million, $(5) million and less than $1 million for 2015, 2014 and 2013, 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 subsidiaries. See Note 24 for Virginia Power and Dominion Gas amounts due to/from Dominion related to this plan.
Dominion holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power and Dominion 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 Gas will provide to Dominion 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 Gas fund other postretirement benefit costs through VEBAs. During 2015 and 2014, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2016. Dominion Gas made no contributions to the VEBAs for employees not represented by collective bargaining units during 2015 and does not expect to contribute in 2016. Dominion Gas’ contributions to VEBAs for employees not represented by collective bargaining units were $1 million for 2014.
Defined Contribution Plans
Dominion also sponsors defined contribution employee savings plans that cover substantially all employees. During 2015, 2014 and 2013, Dominion recognized $43 million, $41 million and $40 million, respectively, as employer matching contributions to these plans. Dominion Gas participates in these employee savings plans, both specific to Dominion Gas and that cover multiple Dominion subsidiaries. During 2015, 2014 and 2013, Dominion Gas recognized $7 million as employer matching contributions to these plans. Virginia Power also participates in these employee savings plans. During 2015, 2014 and 2013, Virginia Power recognized $18 million, $17 million and $16 million, respectively, as employer matching contributions to these 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
In December 2011, the EPA issued MATS for coal and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units
Combined Notes to Consolidated Financial Statements, Continued
with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance was required by April 16, 2015, with certain limited exceptions. However, in June 2014,
the Virginia Department of Environmental Quality granted a one-year MATS compliance extension for two coal-fired units at Yorktown to defer planned retirements and allow for continued operation of the units to address reliability concerns while necessary electric transmission upgrades are being completed. These coal units will need to continue operating until at least April 2017 due to delays in transmission upgrades needed to maintain electric reliability, which based on assumptions about the timing for required agency actions and construction schedules are expected to be completed by no earlier than the second quarter of 2017. Therefore, in October 2015 Virginia Power submitted a request to the EPA for an additional one year compliance extension under an EPA Administrative Order.
In June 2015, the U.S. Supreme Court issued a decision holding that the EPA failed to take cost into account when the agency first decided to regulate the emissions from coal- and oil-fired plants, and remanded the MATS rule back to the D.C. Circuit Court. However, the Supreme Court did not vacate or stay the effective date and implementation of the MATS rule. On November 20, 2015, in response to the Supreme Court decision, the EPA proposed a supplemental finding that consideration of cost does not alter the agency’s previous conclusion that it is appropriate and necessary to regulate coal- and oil-fired electric utility steam generating units under Section 112 of the CAA. On December 15, 2015, the D.C. Court of Appeals issued an order remanding the MATS rulemaking proceeding back to the EPA without setting aside judgment, noting that EPA had represented it was on track to issue by April 15, 2016, a final finding regarding its consideration of cost. These actions do not change Virginia Power’s plans to close coal units at Yorktown or the need to complete necessary electricity transmission upgrades by 2017. Since the MATS rule remains in effect and Dominion is complying with the requirements of the rule, Dominion does not expect any adverse impacts to its operations at this time.
CAIR
The EPA established CAIR with the intent to require significant reductions in SO2 and NOX emissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO2 and NOX emissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO2 and NOX emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NOX emissions caps, NOX emissions caps during the ozone season (May 1 through September 30) and annual SO2 emission caps with differing requirements for two groups of affected states.
CSAPR
Following numerous petitions by industry participants for review and a successful motion for stay, in October 2014, the
U.S. Court of Appeals for the D.C. Circuit ordered that the EPA’s motion to lift the stay of CSAPR be granted. Further, the Court granted the EPA’s request to shift the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets (which would have gone into effect in 2012 and 2013) will apply in 2015 and 2016, and Phase 2 emissions budgets will apply in 2017 and beyond. CSAPR replaced CAIR beginning in January 2015. The cost to comply is not expected to be material to the Consolidated Financial Statements. Future outcomes of any additional litigation and/or any action to issue a revised rule could affect the assessment regarding cost of compliance.
Ozone Standards
In October 2015, the EPA issued a final rule tightening the ozone standard from 75-ppb to 70-ppb. The EPA is expected to complete attainment designations for a new standard by December 2017 and states will have until 2020 or 2021 to develop plans to address the new standard. Until the states have developed implementation plans, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significant expenditures are required to implement additional controls, it could adversely affect the Companies’ results of operations and cash flows.
Hazardous Air Pollutants Standards
In August 2010, the EPA issued revised National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines, which was amended in March 2011 and January 2013. The rule establishes emission standards for control of hazardous air pollutants for engines at smaller facilities, known as area sources. As a result of these regulations, Dominion Gas has spent $2 million to install emissions controls on several compressor engines. Further capital spending is not expected to be material.
NSPS
In August 2012, the EPA issued the first NSPS impacting the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In September 2015, the EPA issued a proposed NSPS to regulate methane and VOC emissions from transmission and storage, gathering and boosting, production and processing facilities. All projects which commence construction after September 2015 will be required to comply with this regulation. Dominion is evaluating the proposed regulation and cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.
Methane Emissions
In January 2015, as part of its Climate Action Plan, the EPA announced plans to reduce methane emissions from the oil and gas sector including natural gas processing and transmission sources. In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR program, the Natural Gas STAR Methane Challenge Program. The proposed program covers the entire natural gas sector from production to distribution, with
more emphasis on transparency and increased reporting for both annual emissions and reductions achieved through implementation measures. Dominion is evaluating the proposed program and cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.
CLIMATE CHANGE LEGISLATION AND REGULATION
In October 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the D.C. Circuit Court’s June 2012 decision upholding the EPA’s regulation of GHG emissions from stationary sources under the CAA’s permitting programs. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the EPA’s ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. In July 2014, the EPA issued a memorandum specifying that it will no longer apply or enforce federal regulations or EPA-approved PSD state implementation plan provisions that require new and modified stationary sources to obtain a PSD permit when GHGs are the only pollutant that would be emitted at levels that exceed the permitting thresholds. In August 2015, the EPA published a final rule rescinding the requirement for all new and modified major sources to obtain permits based solely on their GHG emissions. In addition, the EPA stated that it will continue to use the existing thresholds to apply to sources that are otherwise subject to PSD for conventional pollutants until it completes a new rulemaking either justifying and upholding those thresholds or setting new ones. Some states have issued interim guidance that follows the EPA guidance. Due to uncertainty regarding what additional actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the Court ruling under a new rulemaking, the Companies cannot predict the impact to their financial statements at this time.
In July 2011, the EPA signed a final rule deferring the need for PSD and Title V permitting for CO2 emissions for biomass projects. This rule temporarily deferred for a period of up to three years the consideration of CO2 emissions from biomass projects when determining whether a stationary source meets the PSD and Title V applicability thresholds, including those for the application of BACT. The deferral policy expired in July 2014. In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however, a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the CO2 deferral period. It is unclear how the court’s decision or the EPA’s final policy regarding the treatment of specific feedstock will affect biomass sources that were permitted during the deferral period; however, the expenditures to comply with any new requirements could be material to Dominion’s and Virginia Power’s financial statements.
WATER
The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong
enforcement mechanisms. The Companies must comply with applicable aspects of the CWA programs at their operating facilities.
In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. While the impacts of this rule could be material to Dominion’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.
In September 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule establishes updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. Virginia Power has eight facilities that may be subject to additional wastewater treatment requirements associated with the final rule. The expenditures to comply with these new requirements are expected to be material.
SOLID AND HAZARDOUS WASTE
The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.
Combined Notes to Consolidated Financial Statements, Continued
From time to time, Dominion, Virginia Power, or Dominion Gas may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion, Virginia Power, or Dominion Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. Except as noted below, the Companies do not believe this will have a material effect on results of operations, financial condition and/or cash flows.
In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. In November 2011, Virginia Power and a number of other parties notified the EPA that they are declining to undertake the work set forth in the UAO.
The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO. Virginia Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter.
Dominion has determined that it is associated with 17 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion Gas. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which the Companies are associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.
See below for discussion on ash pond and landfill closure costs.
Other Legal Matters
The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.
APPALACHIAN GATEWAY
Following the completion of the Appalachian Gateway project in 2012, DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DTI filed a complaint in U.S. District Court for the Eastern District of Virginia for breach of contract as well as accounting and declaratory relief. The contractor filed a motion to dismiss, or in the alternative, a motion to transfer venue to Pennsylvania and/or West Virginia, where the pipelines were constructed. DTI filed an opposition to the contractor’s motion in August 2013. In November 2013, the court granted the contractor’s motion on the basis that DTI must first comply with the dispute resolution process. In July 2015, the contractor filed a complaint against DTI in U.S. District Court for the Western District of Pennsylvania. In August 2015, DTI filed a motion to dismiss, or in the alternative, a motion to transfer venue to Virginia. This case is pending. DTI has accrued a liability of $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.
ASH POND AND LANDFILL CLOSURE COSTS
In September 2014, Virginia Power received a notice from the SELC on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at Possum Point. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point’s historical and active ash storage facilities. A similar notice from the SELC on behalf of the Sierra Club was subsequently received related to Chesapeake. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum Point, Chesapeake and Bremo as settlement of the potential litigation. While the issue is open to potential further negotiations, the SELC declined the offer as presented in January 2015 and, in March 2015, filed a lawsuit related to its claims of the alleged CWA violations at Chesapeake. Virginia Power filed a motion to dismiss in April 2015, which was denied in November 2015. As a result of the December 2014 settlement offer, Virginia Power recognized a charge of $121 million in other operations and maintenance expense in its Consolidated Statements of Income in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.
In April 2015, the EPA’s final rule regulating the management of CCRs stored in impoundments (ash ponds) and landfills was published in the Federal Register. The final rule regulates CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store CCRs. Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. The enactment of the final rule in April 2015 created a legal obligation for Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary. In 2015, Virginia Power recorded a $386 million ARO related to future ash pond and landfill closure costs. Recognition of the ARO also resulted in a $99 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $166 million increase in property, plant, and equip-
ment associated with asset retirement costs, and a $121 million reduction in other noncurrent liabilities related to reversal of the contingent liability described above since the ARO obligation created by the final CCR rule represents similar activities. Virginia Power is in the process of obtaining the necessary permits to complete the work. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the increased obligation in 2015.
COVE POINT
Dominion is constructing the Liquefaction Project at the Cove Point facility, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project. In October 2014, several parties filed a motion with FERC to stay the order and requested rehearing. In May 2015, FERC denied the requests for stay and rehearing.
Two parties have separately filed petitions for review of the FERC order in the U.S. Court of Appeals for the D.C. Circuit, which petitions have been consolidated. Separately, one party requested a stay of the FERC order until the judicial proceedings are complete, which the court denied in June 2015.
In May 2014, the Maryland Commission granted the CPCN authorizing the construction of a generating station in connection with the Liquefaction Project. The CPCN obligates Cove Point to make payments totaling $48 million. These payments consist of $40 million to the Strategic Energy Investments Fund over a five-year period beginning in 2015 and $8 million to Maryland low income energy assistance programs over a twenty-year period expected to begin in 2018. In December 2014, upon receipt of applicable approvals to commence construction of the generating station, Dominion recorded the present value of the obligation as an increase to property, plant and equipment and a corresponding liability.
In June 2014, a party filed a notice of petition for judicial review of the CPCN with the Circuit Court for Baltimore City in Maryland. In September 2014, the party filed with the Maryland Commission a motion to stay the CPCN pending judicial review of the CPCN. In December 2014, the Circuit Court issued an order affirming the Maryland Commission’s grant of the CPCN and dismissing the appeal, and the motion for stay was denied by the Maryland Commission. In January 2015, the same party filed a Notice of Appeal of the Baltimore Circuit Court’s Order affirming the Maryland Commission’s grant of the CPCN with the Court of Special Appeals of Maryland. In February 2016, the Court of Special Appeals of Maryland issued an order affirming the judgment of the Circuit Court for Baltimore City in Maryland which affirmed the decision of the Maryland Commission granting the CPCN.
Nuclear Matters
In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as INPO. Like other U.S. nuclear operators, Dominion has been gathering supporting data and participating in industry initiatives focused on the ability to respond to
and mitigate the consequences of design-basis and beyond-design-basis events at its stations.
In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3, with the Tier 1 recommendations consisting of actions which the staff determined should be started without unnecessary delay. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.
Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion requiring implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation have been implemented. The information requests issued by the NRC request each reactor to reevaluate the seismic and external flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. The walkdowns of each unit have been completed, audited by the NRC and found to be adequate. Reevaluation of the seismic and external flooding hazards is expected to continue through 2018. Dominion and Virginia Power do not currently expect that compliance with the NRC’s information requests will materially impact their financial position, results of operations or cash flows during the implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion and Virginia Power are currently unable to estimate the potential financial impacts related to compliance with Tier 2 and Tier 3 recommendations.
Nuclear Operations
NUCLEAR DECOMMISSIONING-MINIMUM FINANCIAL ASSURANCE
The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 2015 calculation for the NRC minimum financial assurance amount, aggregated for Dominion’s and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.9 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2015 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2015 U.S. Bureau of Labor Statistics indices. Dominion believes that the
Combined Notes to Consolidated Financial Statements, Continued
amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion and Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. See Note 9 for additional information on nuclear decommissioning trust investments.
NUCLEAR INSURANCE
The Price-Anderson Amendments Act of 1988 provides the public up to $13.5 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. However, the NRC granted an exemption in March 2015 to remove Kewaunee from the Secondary Financial Protection program.
The current levels of nuclear property insurance coverage for Dominion’s and Virginia Power’s nuclear units is as follows:
(1) Surry and North Anna share a blanket property limit of $200 million.
Dominion’s and Virginia Power’s nuclear property insurance coverage for Millstone, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. Kewaunee meets the NRC minimum requirement of $1.06 billion. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion’s and Virginia Power’s maximum retrospective
premium assessment for the current policy period is $84 million and $48 million, respectively. Based on the severity of the incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.
Millstone and Virginia Power also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, Dominion and Virginia Power are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $23 million and $10 million, respectively.
ODEC, a part owner of North Anna, and Massachusetts Municipal and Green Mountain, part owners of Millstone’s Unit 3, are responsible to Dominion and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.
SPENT NUCLEAR FUEL
Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by Dominion’s and Virginia Power’s contracts with the DOE. Dominion and Virginia Power have previously received damages award payments and settlement payments related to these contracts.
In 2012, Dominion and Virginia Power resolved additional claims for damages incurred at Millstone, Kewaunee, Surry and North Anna with the Authorized Representative of the Attorney General. Dominion and Virginia Power entered into settlement agreements that resolved claims for damages incurred through December 31, 2010, and also provided for periodic payments after that date for damages incurred through December 31, 2013.
By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone plants have been extended to provide for periodic payments for damages incurred through December 31, 2016. Possible extension of the Kewaunee settlement agreement is being evaluated.
In 2015, Virginia Power and Dominion received payments of $8 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2013 through December 31, 2013, and $17 million for resolution of claims incurred at Millstone for the period of July 1, 2013 through June 30, 2014.
In 2014, Virginia Power and Dominion received payments of $27 million for the resolution of claims incurred at North Anna and Surry for the period January 1, 2011 through December 31, 2012 and $17 million for the resolution of claims incurred at Millstone for the period of July 1, 2012 through June 30, 2013. In 2014, Dominion also received payments totaling $7 million for the resolution of claims incurred at Kewaunee for periods from January 1, 2011 through December 31, 2013.
Dominion and Virginia Power continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion’s receivables for spent nuclear fuel-related costs totaled $87 million and $69 million at December 31, 2015 and 2014, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $54 million and $41 million at December 31, 2015 and 2014, respectively.
Pursuant to a November 2013 decision of the U.S Court of Appeals for the D.C. Circuit, in January 2014 the Secretary of the DOE sent a recommendation to the U.S. Congress to adjust to zero the current fee of $1 per MWh for electricity paid by civilian nuclear power generators for disposal of spent nuclear fuel. The processes specified in the Nuclear Waste Policy Act for adjustment of the fee have been completed, and as of May 2014, Dominion and Virginia Power are no longer required to pay the waste fee. In 2014, Dominion and Virginia Power recognized fees of $16 million and $10 million, respectively.
Dominion and Virginia Power will continue to manage their spent fuel until it is accepted by the DOE.
Long-Term Purchase Agreements
At December 31, 2015, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:
(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2015, the present value of Virginia Power’s total commitment for capacity payments is $577 million. Capacity payments totaled $305 million, $330 million, and $345 million, and energy payments totaled $198 million, $304 million, and $236 million for the years ended 2015, 2014 and 2013, respectively.
Lease Commitments
The Companies’ lease various facilities, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2015 are as follows:
Rental expense for Dominion totaled $99 million, $92 million, and $101 million for 2015, 2014 and 2013, respectively. Rental expense for Virginia Power totaled $51 million, $43 million, and $42 million for 2015, 2014, and 2013, respectively. Rental expense for Dominion Gas totaled $37 million, $35 million and $15 million for 2015, 2014 and 2013, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.
Guarantees, Surety Bonds and Letters of Credit
At December 31, 2015, Dominion had issued $74 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2015, Dominion’s exposure under these guarantees was $39 million, primarily related to certain reserve requirements associated with non-recourse financing.
Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.
At December 31, 2015, Dominion had issued the following subsidiary guarantees:
(1) Represents the estimated portion of the guarantee’s stated limit that is utilized as of December 31, 2015 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount.
Combined Notes to Consolidated Financial Statements, Continued
(2) Guarantee of debt of a DEI subsidiary. In the event of default by the subsidiary, Dominion would be obligated to repay such amounts.
(3) Guarantees related to commodity commitments of certain subsidiaries, including subsidiaries of Virginia Power, Dominion Gas and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion would be obligated to satisfy such obligation. Dominion and its subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits.
(4) Guarantees related to certain DEI subsidiaries’ potential retrospective premiums that could be assessed if there is a nuclear incident under Dominion’s nuclear insurance programs and guarantees for a DEI subsidiary’s and Virginia Power’s commitment to buy nuclear fuel. Excludes Dominion’s agreement to provide up to $150 million and $60 million to two DEI subsidiaries to pay the operating expenses of Millstone (in the event of a prolonged outage) and Kewaunee, respectively, as part of satisfying certain NRC requirements concerned with ensuring adequate funding for the operations of nuclear power stations. The agreement for Kewaunee also provides for funds through the completion of decommissioning.
(5) Guarantees related to Cove Point, in support of terminal services, transportation and construction. Two of the guarantees have no stated limit, one guarantee has a $150 million limit, and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million.
(6) Includes guarantees to facilitate the development of solar projects including guarantees that do not have stated limits. Also includes guarantees entered into by DEI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.
(7) Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of December 31, 2015, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $55 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits.
Additionally, at December 31, 2015, Dominion had purchased $92 million of surety bonds, including $34 million at Virginia Power and $23 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $59 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.
As of December 31, 2015, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. The related debt matures in 2031 and is included in long-term debt in Virginia Power’s Consolidated Balance Sheets. In the event of default by a conduit, Virginia Power would be obligated to repay such amounts, which are limited to the principal and interest then outstanding.
Indemnifications
As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that
would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2015, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.
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, 2015 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
As a diversified energy company, Dominion 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 and Midwest regions of the U.S. Dominion 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 is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.
Dominion’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion 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, 2015, Dominion’s credit exposure totaled $149 million. Of this amount, investment grade counterparties, including those internally rated, represented 79%, and no single counterparty, whether investment grade or non-investment grade, exceeded $31 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, 2015, Virginia Power’s exposure to potential concentrations of credit risk was not considered material.
DOMINION GAS
Dominion 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 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 Gas is not exposed to a significant concentration of credit risk for receivables arising from gas utility operations.
In 2015, DTI provided service to 266 customers with approximately 94% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 42% of the total storage and transportation revenue and the thirty largest provided approximately 72% 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’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion 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, 2015 and 2014, Dominion would have been required to post an additional $12 million and $20 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 had posted no collateral at December 31, 2015 and $1 million in collateral at December 31, 2014, 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, 2015 and 2014 was $49 million, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and Dominion Gas were not material as of December 31, 2015 and 2014. See Note 7 for further information about derivative instruments.
NOTE 24. RELATED-PARTY TRANSACTIONS
Virginia Power and Dominion Gas engage in related party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s and Dominion 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 Gas are included in Dominion’s consolidated federal income tax return. See Note 2 for further information. Dominion’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, 2015, Virginia Power’s derivative assets and liabilities with affiliates were $13 million and $22 million, respectively. As of December 31, 2014, Virginia Power’s derivative assets and liabilities with affiliates were not material.
Virginia Power participates in certain Dominion benefit plans as described in Note 21. At December 31, 2015 and 2014, Virginia Power’s amounts due to Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $316 million and $219 million, respectively. At December 31, 2015 and 2014, Virginia Power’s amounts due from Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred charges and other assets in the Consolidated Balance Sheets were $77 million and $37 million, respectively.
DRS 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.
Combined Notes to Consolidated Financial Statements, Continued
Presented below are significant transactions with DRS and other affiliates:
(1) Includes capitalized expenditures.
Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were $376 million and $427 million in short-term demand note borrowings from Dominion as of December 31, 2015 and 2014, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion money pool for its nonregulated subsidiaries as of December 31, 2015 and 2014. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the years ended December 31, 2015, 2014 and 2013.
There were no issuances of Virginia Power’s common stock to Dominion in 2015, 2014 or 2013.
DOMINION GAS
Transactions with Related Parties
Dominion Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Gas provides transportation and storage services to affiliates. Dominion Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of December 31, 2015 and 2014, all of Dominion Gas’ commodity derivatives were with affiliates. See Notes 7 and 19 for more information. See Note 9 for information regarding sales of assets to an affiliate.
Dominion Gas participates in certain Dominion benefit plans as described in Note 21. At December 31, 2015 and 2014, Dominion Gas’ amounts due from Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $652 million and $614 million, respectively. At December 31, 2015 and 2014, Dominion Gas’ liabilities to Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred credits and other liabilities in the Consolidated Balance Sheets were $2 million and $7 million, respectively.
DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Gas. Dominion Gas provides certain services to related parties, including technical services. The costs of these services follow:
(1) Includes capitalized expenditures.
(2) Amounts primarily attributable to Atlantic Coast Pipeline.
The following table presents affiliated and related party activity reflected in Dominion Gas’ Consolidated Balance Sheets:
(1) Represents amounts due from Atlantic Coast Pipeline, a related party VIE.
(2) Amounts are presented in other current assets in Dominion Gas’ Consolidated Balance Sheets.
(3) Amounts are presented in other deferred charges and other assets in Dominion Gas’ Consolidated Balance Sheets.
Dominion Gas’ borrowings under the IRCA with Dominion totaled $95 million and $384 million as of December 31, 2015 and 2014, respectively. Interest charges related to Dominion Gas’ total borrowings from Dominion were immaterial for the year ended December 31, 2015 and $4 million and $35 million for the years ended December 31, 2014 and 2013, respectively.
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.
(2) As a result of Dominion’s decision to realign its business units effective for 2015 year-end reporting, nonregulated retail energy marketing operations were moved from the Dominion Generation segment to the Dominion Energy segment.
In addition to the operating segments above, the Companies also report a Corporate and Other segment.
Dominion
The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued or sold. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
In March 2014, Dominion exited the electric retail energy marketing business. As a result, the earnings impact from the electric retail energy marketing business has been included in the Corporate and Other Segment of Dominion for 2014 first quarter results of operations.
In the second quarter of 2013, Dominion commenced a restructuring of its producer services business, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates. The restructuring, which was completed in the first quarter of 2014, resulted in the termination of natural gas trading and certain energy marketing activities. As a result, the earnings impact from natural gas trading and certain energy marketing activities has been included in the Corporate and Other Segment of Dominion for 2014.
In 2015, Dominion reported after-tax net expense 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 Dominion 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 Dominion Generation.
In 2014, Dominion reported after-tax net expense of $970 million in the Corporate and Other segment, with $544 million of these net expenses attributable to specific items related to its operating segments.
The net expenses for specific items in 2014 primarily related to the impact of the following items:
•
$374 million ($248 million after-tax) in 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, attributable to Dominion Generation;
•
A $319 million ($193 million after-tax) net loss related to the producer services business discussed above, attributable to Dominion Energy; and
•
A $121 million ($74 million after-tax) charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities, attributable to Dominion Generation.
In 2013, Dominion reported after-tax net expense of $452 million in the Corporate and Other segment, with $184 million of these net expenses attributable to specific items related to its operating segments.
The net expenses for specific items in 2013 primarily related to the impact of the following items:
•
A $135 million ($92 million after-tax) net loss from discontinued operations of Brayton Point and Kincaid, including debt extinguishment of $64 million ($38 million after-tax) related to the sale, impairment charges of $48 million ($28 million after-tax), a $17 million ($18 million after-tax) loss on the sale which includes a $16 million write-off of goodwill, and a $6 million ($8 million after-tax) loss from operations, attributable to Dominion Generation; and
•
A $182 million ($109 million after-tax) net loss, including a $55 million ($33 million after-tax) impairment charge related to certain natural gas infrastructure assets and a $127 million ($76 million after-tax) loss related to the producer services business discussed above, attributable to Dominion Energy; partially offset by
•
An $81 million ($49 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.
Combined Notes to Consolidated Financial Statements, Continued
The following table presents segment information pertaining to Dominion’s operations:
(1) Amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Energy segment.
Intersegment sales and transfers for Dominion 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 DVP and Dominion 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 allocating resources among the segments.
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:
•
A $99 million ($60 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Dominion 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 Dominion Generation.
In 2014, Virginia Power reported after-tax net expenses of $342 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2014 primarily related to the impact of the following:
•
$374 million ($248 million after-tax) in 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, attributable to Dominion Generation; and
•
A $121 million ($74 million after-tax) charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities, attributable to Dominion Generation.
In 2013, Virginia Power reported after-tax net expenses of $47 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2013 primarily related to the impact of the following:
•
A $40 million ($28 million after-tax) charge in connection with the 2013 Biennial Review Order, attributable to Dominion Generation.
The following table presents segment information pertaining to Virginia Power’s operations:
DOMINION GAS
The Corporate and Other Segment of Dominion Gas primarily includes specific items attributable to Dominion Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance and the effect of certain items recorded at Dominion Gas as a result of Dominion’s basis in the net assets contributed.
In 2015, Dominion 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:
•
$16 million ($10 million after-tax) ceiling test impairment charge.
In 2014, Dominion Gas reported after-tax net expenses of $9 million in its Corporate and Other segment, with none of these net expenses attributable to specific items related to its operating segment.
In 2013, Dominion Gas reported after-tax net expenses of $49 million in the Corporate and Other segment, with $41 million of these net expenses attributable to specific items related to its operating segment.
The net expenses for specific items in 2013 primarily related to the impact of the following:
•
$55 million ($33 million after-tax) of impairment charges related to certain natural gas infrastructure assets; and
•
A $14 million ($8 million after-tax) charge primarily reflecting severance pay and other benefits related to workforce reductions.
Combined Notes to Consolidated Financial Statements, Continued
The following table presents segment information pertaining to Dominion 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, 2015 and 2014 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
(1) Amounts attributable to Dominion’s common shareholders.
There were no significant items impacting Dominion’s 2015 quarterly results.
Dominion’s 2014 results include the impact of the following significant items:
•
Fourth quarter results include $172 million in after-tax charges associated with the Liability Management Exercise in 2014 and $74 million in after-tax costs related to Virginia Power’s settlement offer to incur future ash pond closure costs at certain utility generation facilities.
•
Second quarter results include $191 million in 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.
•
First quarter results include a $193 million after-tax reduction in revenues associated with the repositioning of Dominion’s producer services business which was completed in the first quarter of 2014.
VIRGINIA POWER
Virginia Power’s quarterly results of operations were as follows:
Virginia Power’s 2015 results include the impact of the following significant items:
•
Fourth quarter results include a $32 million after-tax charge related to incremental future ash pond and landfill closure costs at certain utility generation facilities.
•
Second quarter results include a $28 million after-tax charge related to incremental future ash pond and landfill closure costs at certain utility generation facilities due to the enactment of the final CCR rule in April 2015.
•
First quarter results include a $52 million after-tax write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015.
Virginia Power’s 2014 results include the impact of the following significant items:
•
Fourth quarter results include $74 million in after-tax costs related to Virginia Power’s settlement offer to incur future ash pond closure costs at certain utility generation facilities.
•
Second quarter results include a $191 million after-tax charge 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.
DOMINION GAS
Dominion Gas’ quarterly results of operations were as follows:
Dominion Gas’ 2015 results include the impact of the following significant items:
•
Third quarter results include a $29 million after-tax gain from an agreement to convey shale development rights underneath a natural gas storage field.
•
First quarter results include a $43 million after-tax gain from agreements to convey shale development rights underneath several natural gas storage fields.
Dominion Gas’ 2014 results include the impact of the following significant item:
•
Fourth quarter results include a $36 million after-tax gain from agreements to convey Marcellus Shale development rights underneath several natural gas storage fields.
Combined Notes to Consolidated Financial Statements, Continued
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
DOMINION
Senior management, including Dominion’s CEO and CFO, evaluated the effectiveness of Dominion’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion’s CEO and CFO have concluded that Dominion’s disclosure controls and procedures are effective. There were no changes in Dominion’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’s internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Dominion understands and accepts responsibility for Dominion’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion does throughout all aspects of its business.
Dominion 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, 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 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 Committee at any time.
SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion’s 2015 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 tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2015, Dominion makes the following assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion.
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’s internal control over financial reporting as of December 31, 2015. 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 maintained effective internal control over financial reporting as of December 31, 2015.
Dominion’s independent registered public accounting firm is engaged to express an opinion on Dominion’s internal control over financial reporting, as stated in their report which is included herein.
February 26, 2016
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the internal control over financial reporting of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Dominion’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’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Dominion maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2015 of Dominion and our report dated February 26, 2016 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 26, 2016
VIRGINIA POWER
Senior management, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes in Virginia Power’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Power’s internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Virginia Power understands and accepts responsibility for Virginia Power’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Virginia Power continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.
Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.
The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.
SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s 2015 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, 2015, 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, 2015. 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, 2015.
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 26, 2016
DOMINION GAS
Senior management, including Dominion Gas’ CEO and CFO, evaluated the effectiveness of Dominion Gas’ disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion Gas’ CEO and CFO have concluded that Dominion Gas’ disclosure controls and procedures are effective. There were no changes in Dominion 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 Gas’ internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Dominion Gas understands and accepts responsibility for Dominion Gas’ financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion 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 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 Gas’ Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Dominion 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 Gas’ 2015 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Dominion Gas tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2015, Dominion Gas makes the following assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion 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 Gas’ internal control over financial reporting as of December 31, 2015. 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 Gas maintained effective internal control over financial reporting as of December 31, 2015.
This annual report does not include an attestation report of Dominion Gas’ independent registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Dominion Gas’ independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.
February 26, 2016
Item 9B.
Item 9B. Other Information
None.
Part III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
DOMINION
The following information for Dominion is incorporated by reference from the Dominion 2016 Proxy Statement, which will be filed on or around March 23, 2016:
•
Information regarding the directors required by this item is found under the heading Election of Directors.
•
Information regarding a material change in the procedures by which shareholders recommend director nominees required by this item is found under the headings Election of Directors and Shareholder Proposals and Director Nominations.
•
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 Audit Committee Financial expert(s) required by this item is found under the heading Board of Directors Committees-Audit Committee.
•
Information regarding the Dominion Audit Committee required by this item is found under the headings Board of Directors Committees-Audit Committee and Audit Committee Report.
•
Information regarding Dominion’s Code of Ethics required by this item is found under the heading Corporate Governance and Board Matters.
The information concerning the executive officers of Dominion required by this item is included in Part I of this Form 10-K under the caption Executive Officers of Dominion. Each executive officer of Dominion is elected annually.
Item 11.
Item 11. Executive Compensation
DOMINION
The following information about Dominion is contained in the 2016 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the headings Compensation Discussion and Analysis and Executive Compensation; the information regarding Compensation Committee interlocks contained under the heading Compensation Committee Interlocks and Insider Participation; The 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
The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the heading Securities Ownership in the 2016 Proxy Statement is incorporated by reference.
The information regarding equity securities of Dominion that are authorized for issuance under its equity compensation plans
contained under the heading Executive Compensation-Equity Compensation Plans in the 2016 Proxy Statement is incorporated by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
DOMINION
The information regarding related party transactions required by this item found under the heading Other Information-Related Party Transactions, and information regarding director independence found under the heading Corporate Governance and Board Matters-Independence of Directors, in the 2016 Proxy Statement is incorporated by reference.
Item 14.
Item 14. Principal Accountant Fees and Services
DOMINION
The information concerning principal accountant fees and services contained under the heading Auditor Fees and Pre-Approval Policy in the 2016 Proxy Statement is incorporated by reference.
VIRGINIA POWER AND DOMINION GAS
The following table presents fees paid to Deloitte & Touche LLP for services related to Virginia Power and Dominion Gas for the fiscal years ended December 31, 2015 and 2014.
Audit fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power’s and Dominion Gas’ annual consolidated financial statements, the review of financial statements included in Virginia Power’s and Dominion 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’s and Dominion 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’s and Dominion Gas’ Boards of Directors have adopted the Dominion Audit Committee pre-approval policy for their independent auditor’s services and fees and have delegated the execution of this policy to the Dominion Audit Committee. In accordance with this delegation, each year the Dominion 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 2016 meeting, the Dominion Audit Committee approved Virginia Power’s and Dominion Gas’ schedules of services and fees for 2016. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Audit Committee or a member of the Dominion Audit Committee.
The fees for Dominion Gas presented above for the year ended December 31, 2014, were for professional services rendered during the period subsequent to Dominion Gas becoming an SEC registrant. Total audit fees and audit-related fees incurred prior to Dominion Gas becoming an SEC registrant were $680 thousand and $70 thousand, respectively, and were paid by Dominion.
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 58.
2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.
3. Exhibits (incorporated by reference unless otherwise noted)
Exhibit
Number
Description
Dominion
Virginia
Power
Dominion
Gas
32.b
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
X
32.c
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
X
The following financial statements from Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC Annual Report on Form 10-K for the year ended December 31, 2015, filed on February 26, 2016, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.
X
X
X
* Indicates management contract or compensatory plan or arrangement
Signatures
DOMINION
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 RESOURCES, INC.
By:
/s/ Thomas F. Farrell II
(Thomas F. Farrell II, Chairman, President and Chief Executive Officer)
Date: February 26, 2016
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 26th day of February, 2016.
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 26, 2016
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 26th day of February, 2016.
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 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 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 26, 2016
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 26th day of February, 2016.
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
Exhibit Index
Exhibit
Number
Description
Dominion
Virginia
Power
Dominion
Gas
The following financial statements from Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC Annual Report on Form 10-K for the year ended December 31, 2015, filed on February 26, 2016, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.
X
X
X
* Indicates management contract or compensatory plan or arrangement