In addition during 2016,
Dominion acquired 100% of the equity interests of seven solar projects in Virginia, North Carolina and South Carolina for an aggregate purchase price of $32 million, all of which was allocated to property, plant and equipment. The projects are
expected to cost approximately $425 million in total once constructed, including initial acquisition costs, and to generate approximately 221 MW combined. One of the projects commenced commercial operations in 2016 and the remaining projects
are expected to begin commercial operations in 2017.
In August 2016, Dominion entered into an agreement to acquire 100% of the equity
interests of two solar projects in California from Solar Frontier Americas Holding LLC for approximately $128 million in cash. The acquisition is expected to close prior to both projects commencing operations, which is expected by the end of
2017. The projects are expected to cost approximately $130 million once constructed, including the initial acquisition cost, and to generate approximately 50 MW combined.
In September 2016, Dominion entered into an agreement to acquire 100% of the equity interests of a solar project in Virginia from Community
Energy Solar, LLC. The acquisition is expected to close during the first quarter of 2017, prior to the project commencing operations by the end of 2017, for an amount to be determined based on the costs incurred through closing. The project is
expected to cost approximately $210 million once constructed, including the initial acquisition cost, and to generate approximately 100 MW.
In January 2017, Dominion entered into an agreement to acquire 100% of the equity interests of a solar project in North Carolina from Cypress
Creek Renewables, LLC for $154 million in cash. The acquisition is expected to close during the second quarter of 2017, prior to the project commencing commercial operations, which is expected by the end of the third quarter of 2017. The project is
expected to cost $160 million once constructed, including the initial acquisition cost, and to generate approximately 79 MW.
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 425 MW, to SunEdison, including projects discussed in the table above. In December 2015, the sale of interest in 15 of the solar projects closed for $184 million with the sale of
interest in the remaining projects completed in January 2016 for $117 million. Upon closing, SunEdison sold its interest in these projects to Terra Nova Renewable Partners. Terra Nova Renewable Partners has a future option to buy all or a
portion of Dominions remaining 67% ownership in the projects upon the occurrence of certain events, none of which are expected to occur in 2017.
In 2016, Dominion realized a taxable gain resulting from the contribution of Questar Pipeline to Dominion
Midstream. The contribution and related transactions resulted in increases in the tax basis of Questar Pipelines assets and the number of Dominion Midstreams common and convertible preferred units held by noncontrolling interests. The
direct tax effects of the transactions included a provision for current income taxes ($212 million) and an offsetting benefit for deferred income taxes ($96 million) and were charged to common shareholders equity. The federal tax liability was
reduced by $129 million of tax credits generated in 2016 that otherwise would have resulted in additional credit carryforwards and a $17 million benefit provided by the domestic production activities deduction. These benefits, as indirect effects of
the contribution transaction, are reflected in Dominions current federal income tax expense.
In 2015, Dominions current
federal income tax benefit includes the recognition of a $20 million benefit related to a carryback to be filed for nuclear decommissioning expenditures included in its 2014 net operating loss.
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies
effective income tax rate as follows:
In 2016, Dominions effective tax rate reflects a valuation allowance on a state credit not expected to
be utilized by a Dominion subsidiary which files a separate state return.
The following table presents Dominions quantitative information about Level 3 fair
value measurements at December 31, 2016. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility and credit spreads.
Marketable equity and debt securities and cash equivalents held in Dominions rabbi trusts and classified as trading totaled $104 million and
$100 million at December 31, 2016 and 2015, respectively.
Combined Notes to Consolidated Financial Statements, Continued
|
|
|
|
|
|
|
|
|
At December 31,
|
|
2016
|
|
|
2015
|
|
(millions)
|
|
|
|
|
|
|
Dominion Gas
|
|
|
|
|
|
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
Unrecovered gas costs
(3)
|
|
$
|
12
|
|
|
$
|
11
|
|
Deferred rate adjustment clause costs
(2)
|
|
|
12
|
|
|
|
10
|
|
Other
|
|
|
2
|
|
|
|
2
|
|
Regulatory assets-current
|
|
|
26
|
|
|
|
23
|
|
Unrecognized pension and other postretirement benefit
costs
(5)
|
|
|
358
|
|
|
|
282
|
|
Utility reform legislation
(9)
|
|
|
99
|
|
|
|
65
|
|
Deferred rate adjustment clause costs
(2)
|
|
|
79
|
|
|
|
82
|
|
Income taxes recoverable through future
rates
(8)
|
|
|
23
|
|
|
|
20
|
|
Other
|
|
|
18
|
|
|
|
|
|
Regulatory
assets-non-current
|
|
|
577
|
|
|
|
449
|
|
Total regulatory assets
|
|
$
|
603
|
|
|
$
|
472
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
PIPP
(10)
|
|
$
|
28
|
|
|
$
|
46
|
|
Other
|
|
|
7
|
|
|
|
9
|
|
Regulatory liabilities-current
|
|
|
35
|
|
|
|
55
|
|
Provision for future cost of removal and
AROs
(11)
|
|
|
174
|
|
|
|
170
|
|
Other
|
|
|
45
|
|
|
|
31
|
|
Regulatory
liabilities-non-current
|
|
|
219
|
|
|
|
201
|
|
Total regulatory liabilities
|
|
$
|
254
|
|
|
$
|
256
|
|
(1)
|
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.
|
(2)
|
Primarily reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects for Virginia Power and deferrals of costs
associated with certain current and prospective rider projects for Dominion Gas. See Note 13 for more information.
|
(3)
|
Reflects unrecovered gas costs at regulated gas operations, which are recovered through filings with the applicable regulatory authority.
|
(4)
|
Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Dominions and Virginia Powers generation operations. See Note 13 for more information.
|
(5)
|
Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain of
Dominions and Dominion Gas rate-regulated subsidiaries.
|
(6)
|
Reflects amount related to the PJM transmission cost allocation matter. See Note 13 for more information.
|
(7)
|
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.
|
(8)
|
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.
|
(9)
|
Ohio legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more
up-to-date
cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital
investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future.
|
(10)
|
Under PIPP, eligible customers can make reduced payments based on their ability to pay. The difference between the customers 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.
|
(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 Powers utility nuclear generation stations, in excess of the related AROs.
|
At
December 31, 2016, $303 million of Dominions, $230 million of Virginia Powers and $31 million of Dominion Gas regulatory assets represented past expenditures on which they do not currently earn a return.
With the exception of the $192 million PJM transmission cost allocation matter, the majority of these expenditures are expected to be recovered within the next two years.
N
OTE
13. R
EGULATORY
M
ATTERS
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.
FERCE
LECTRIC
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Dominions
merchant generators sell electricity in the PJM, MISO, CAISO and
ISO-NE
wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia,
California and Utah, under Dominions market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in
the wholesale market. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia
Powers service territory. Any such sales would be voluntary.
Rates
In
April 2008, FERC granted an application for Virginia Powers 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 Powers 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 Powers 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 customers share of the
regions 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 customers share of the regions load. A number of parties filed appeals of the order to the U.S. Court of Appeals for the Seventh Circuit. In June 2014, the court again remanded the cost allocation issue
to FERC. In December 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the cost allocation issue. The hearing only concerns the costs of new facilities approved by PJM prior to February 1, 2013.
Transmission facilities approved after February 1, 2013 are allocated on a hybrid cost allocation method approved by FERC and not subject to any court review.
In June 2016, PJM, the PJM transmission owners and state commissions representing substantially all of the load in the PJM market submitted a
settlement to FERC to resolve the outstanding issues regarding this matter. Under the terms of the settlement, Virginia Power would be required to pay approximately $200 million to PJM over the next 10 years. Although the settlement agreement
has not been accepted by FERC, and the settlement is opposed by a small group of parties to the proceeding, Virginia Power believes it is probable it will be required to make payment as an outcome of the settlement. Accordingly, as of December 31,
2016, Virginia Power has 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, during 2015, in the Consolidated Statements of Income.
Other Regulatory
Matters
E
LECTRIC
R
EGULATION
IN
V
IRGINIA
The Regulation Act enacted in 2007 instituted a
cost-of-service
rate model,
ending Virginias 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 Commissions future rate decisions, including actions relating to Virginia
Powers rate adjustment clause filings, differ materially from Virginia Powers 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 Powers 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
Combined Notes to Consolidated Financial Statements, Continued
12-month
test periods beginning January 1, 2015, and ending December 31, 2019. The legislation states that Virginia Powers 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 utilitys ROE for use in connection with rate adjustment clauses and requires utilities to file integrated resource plans
annually rather than biennially. In November 2015, the Virginia Commission ordered testimony, briefs and a separate bifurcated hearing in Virginia Powers then-pending Rider B, R, S, and W cases on whether the Virginia Commission can adjust the
ROE applicable to these rate adjustment clauses prior to 2017. In February 2016, the Virginia Commission issued final orders in these cases, stating that it could adjust the ROE and setting a base ROE of 9.6% for the projects. After separate,
additional bifurcated hearings, the Virginia Commission issued final orders setting base ROEs of 9.6% in March 2016 for Rider GV, in April 2016 for Riders C1A and C2A, in June 2016 for Riders BW and US-2, and in August 2016 for Rider U. In February
2017, the Virginia Commission issued final orders setting base ROEs of 9.4% for Riders B, R, S, W, and GV effective April 1, 2017.
In
February 2016, certain industrial customers of APCo petitioned the Virginia Commission to issue a declaratory judgment that Virginia legislation enacted in 2015 keeping APCos base rates unchanged until at least 2020 (and Virginia
Powers base rates unchanged until at least 2022) is unconstitutional, and to require APCo to make biennial review filings in 2016 and 2018. Virginia Power intervened to support the constitutionality of this legislation. In July 2016,
the Virginia Commission held in a divided opinion that this legislation is constitutional, and the industrial customers appealed this order to the Supreme Court of Virginia. In November 2016, the Supreme Court of Virginia granted the appeal as
a matter of right and consolidated it for oral argument with other similar appeals from the Virginia Commissions order. These appeals are pending.
2015 Biennial Review
Pursuant to the Regulation Act, in
March 2015, Virginia Power filed its base rate case and schedules for the Virginia Commissions 2015 biennial review of Virginia Powers rates, terms and conditions. Per legislation enacted in February 2015, this biennial review was
limited to reviewing Virginia Powers 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 Powers 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 Powers 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 Powers 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 Powers 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 Commissions order denying their petition for rehearing or reconsideration. In April 2016, the Supreme Court of Virginia granted
these appeals as a matter of right. Also in April 2016, the Attorney General filed an unopposed motion to suspend appellate briefing pending the outcome of a separate case at the Virginia Commission raising the same issues. In May 2016, the Supreme
Court of Virginia denied the Attorney Generals unopposed motion to suspend briefing in the previously granted appeals from the Virginia Commissions orders. The Supreme Court of Virginia later granted leave for the industrial customer
appellants to withdraw their appeals, thus concluding this matter.
Virginia Fuel Expenses
In May 2016, Virginia Power submitted its annual fuel factor to the Virginia Commission to recover an estimated $1.4 billion in Virginia jurisdictional
projected fuel expenses for the rate year beginning July 1, 2016. Virginia Powers proposed fuel rate represented a fuel revenue decrease of $286 million when applied to projected kilowatt-hour sales for the period July 1, 2016
to June 30, 2017. In October 2016, the Virginia Commission approved Virginia Powers proposed fuel rate.
Solar Facility Projects
In February 2017, Virginia Power received approval from the Virginia Commission for a CPCN to construct and operate the Remington solar
facility and related distribution interconnection facilities. The total estimated cost of the Remington solar facility is approximately $47 million, excluding financing costs. The facility is now the subject of a public-private partnership
whereby the Commonwealth of Virginia, a
non-jurisdictional
customer, will compensate Virginia Power for the facilitys net electrical energy output, and Microsoft Corporation will purchase all
environmental attributes (including renewable energy certificates) generated by the facility. There is no rate adjustment clause associated with this CPCN, nor will any costs of the project be recovered from jurisdictional customers.
In October 2015, Virginia Power filed an application with the Virginia Commission for CPCNs to construct and operate the Scott Solar,
Whitehouse, and Woodland solar facilities and related distribution-level interconnection facilities. Virginia Power also applied for approval of Rider US-2 to recover the costs of these projects. In June 2016, the Virginia Commission granted
the requested CPCNs and approved a $4 million revenue requirement, subject to true-up on a cost-of-service basis using a 9.6% ROE for Rider US-2 for the rate year beginning September 1, 2016. These projects were placed into service in
December 2016, and increased Dominions renewable generation by a combined 56 MW at a total cost of approximately $130 million, excluding financing costs. See below for further information
on Rider US-2.
In August 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate
the Oceana solar facility and related distribution interconnection facilities on land owned by the U.S. Navy. The facility would begin commercial operations in late 2017 and increase Dominions renewable generation by
approximately 18 MW at an estimated cost of approximately $40 million, excluding financing costs. The facility is the subject of a public-private partnership whereby the Commonwealth of Virginia, a
non-jurisdictional
customer, will compensate Virginia Power for the facilitys net electrical energy output. Virginia Power will retire renewable energy certificates on the Commonwealths behalf
in an amount equal to those generated by the facility. There is no rate adjustment clause associated with this CPCN filing, nor will any costs of the project be recovered from jurisdictional customers. This case is pending.
Rate Adjustment Clauses
Below is a discussion of
significant riders associated with various Virginia Power projects:
|
|
The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2016, Virginia Power proposed a $639 million total revenue requirement for the rate year beginning September 1, 2016,
which represents a $1 million increase over the revenues projected to be produced during the rate year under current rates. In July 2016, the Virginia Commission approved Virginia Powers proposed total revenue requirement.
|
|
|
The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In February 2016, the Virginia Commission approved a $251 million revenue requirement, subject to
true-up,
for the rate year beginning April 1, 2016. It also established a 10.6% ROE for Rider S effective April 1, 2016. In June 2016, Virginia Power proposed a $254 million revenue requirement for
the rate year beginning April 1, 2017, which represents a $3 million increase over the previous year. In February 2017, the Virginia Commission established a 10.4% ROE for Rider S effective April 1, 2017. This case is pending.
|
|
|
The Virginia Commission previously approved Rider W in conjunction with Warren County. In February 2016, the Virginia Commission approved a $118 million revenue requirement, subject to
true-up,
for the rate year beginning April 1, 2016. It also established a 10.6% ROE for Rider W effective April 1, 2016. In June 2016, Virginia Power proposed a $126 million revenue requirement for
the rate year beginning April 1, 2017, which represents an $8 million increase over the previous year. In February 2017, the Virginia Commission established a 10.4% ROE for Rider W effective April 1, 2017. This case is pending.
|
|
|
The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In February 2016, the Virginia Commission approved a $74 million revenue requirement, subject to
true-up,
for the rate year beginning
|
|
|
April 1, 2016. It also established a 10.6% ROE for Rider R effective April 1, 2016. In June 2016, Virginia Power proposed a $75 million revenue requirement for the rate year
beginning April 1, 2017, which represents a $1 million increase over the previous year. In February 2017, the Virginia Commission established a 10.4% ROE for Rider R effective April 1, 2017. This case is pending.
|
|
|
The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In February 2016, the Virginia Commission approved a $30 million revenue requirement for
the rate year beginning April 1, 2016. It also established an 11.6% ROE for Rider B effective April 1, 2016. In June 2016, Virginia Power proposed a $28 million revenue requirement for the rate year beginning April 1, 2017, which
represents a $2 million decrease versus the previous year. In February 2017, the Virginia Commission established an 11.4% ROE for Rider B effective April 1, 2017. This case is pending.
|
|
|
The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by prior Virginia legislation. In August 2016, the
Virginia Commission approved a net $20 million revenue requirement and a 9.6% ROE for the rate year beginning September 1, 2016, and an additional $2 million in credits to offset approved revenue requirements for Phase One for each of
the 2017-2018 and 2018-2019 rate years. The order limited the total investment in Phase One of Virginia Powers proposed program to $140 million, with $123 million recoverable through Rider U. In December 2016, Virginia Power proposed
a total $31 million revenue requirement for Phase One and Phase Two costs for the rate year beginning September 1, 2017. Virginia Powers estimated total investment in Phase Two is $110 million. This case is pending.
|
|
|
The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In April 2016, the Virginia Commission approved a $46 million revenue requirement, subject to
true-up,
for the rate year beginning May 1, 2016. It also established a 9.6% ROE for Riders C1A and C2A effective May 1, 2016. The Virginia Commission approved one new energy efficiency program at a
reduced cost cap, denied a second energy efficiency program, and approved the extension of an existing peak shaving program recovered in base rates at no additional incremental cost. In October 2016, Virginia Power proposed a total revenue
requirement of $45 million for the rate year beginning July 1, 2017. Virginia Power also proposed two new energy efficiency programs for Virginia Commission approval with a requested five-year cost cap of $178 million. Virginia
Power further proposed to extend an existing energy efficiency program for an additional two years under current funding, and an existing peak shaving program for an additional five years with an additional $5 million cost cap. This case
is pending.
|
|
|
The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In June 2016, the
Virginia Commission approved a $119 million revenue requirement for the rate year beginning September 1, 2016. It also established a 10.6% ROE for Rider BW effective September 1, 2016. In October 2016, Virginia Power proposed a
|
Combined Notes to Consolidated Financial Statements, Continued
|
|
$134 million revenue requirement for the rate year beginning September 1, 2017, which represents a $15 million increase over the previous year. This case is pending.
|
|
|
The Virginia Commission previously approved Rider
US-2
in conjunction with the Scott Solar, Whitehouse, and Woodland solar facilities. In June 2016, the Virginia Commission
approved a $4 million revenue requirement for the rate year beginning September 1, 2016. It also established a 9.6% ROE for Rider US-2 effective September 1, 2016. In October 2016, Virginia Power proposed a $10 million revenue requirement for
the rate year beginning September 1, 2017, which represents a $6 million increase over the previous year. This case is pending.
|
|
|
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. In March 2016, the Virginia Commission granted the requested CPCN and approved a $40 million revenue requirement for the rate year beginning April 1, 2016. It also
established a 9.6% ROE for Rider GV effective April 1, 2016. In June 2016, Virginia Power proposed an $89 million revenue requirement for the rate year beginning April 1, 2017, which represents a $49 million increase over the
previous year. In February 2017, the Virginia Commission established a 9.4% ROE for Rider GV effective April 1, 2017. This matter 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 Powers 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 Commissions 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 500 kV overhead transmission line from Surry to the Skiffes Creek switching station site. The court reversed and remanded the Virginia
Commissions 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.
Virginia Power previously 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. In August 2016, the Virginia Commission granted a CPCN to construct and operate the project along a revised route. The total estimated cost of the project is approximately $55 million.
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 $55 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 $105 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 Powers proposed route.
The total estimated cost of the project is approximately $110 million.
In March 2016, Virginia Power filed an application with the
Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 33 miles of the existing 500 kV transmission line between the Cunningham switching station and the Dooms substation, along with associated station
work. The total estimated cost of the project is approximately $60 million. This case is pending.
In August 2016, Virginia Power
filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 28 miles of the existing 500 kV transmission line between the Carson switching station and a terminus located near the
Rogers Road switching station under construction in Greensville County, Virginia, along with associated work at the Carson switching station. The total estimated cost of the project is approximately $55 million. This case is pending.
In January 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and rearrange its Idylwood substation
in Fairfax County, Virginia. The total estimated cost of the project is approximately $110 million. This case is pending.
North Anna
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna nuclear power station. If Virginia Power decides to
build a new unit, it 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 nuclear power station.
Requests by BREDL for a contested NRC hearing on Virginia Powers COL application have been dismissed, and in September 2016, the U.S.
Court of Appeals for the D.C. Circuit dismissed with prejudice petitions for judicial review that BREDL and other organizations had filed challenging the NRCs reliance on a rule generically assessing the environmental impacts of continued
onsite storage of spent nuclear fuel in various licensing proceedings, including Virginia Powers COL proceeding. This dismissal followed the Courts June 2016 decision in New York v. NRC, upholding the NRCs continued storage rule
and August 2016 denial of requests for rehearing en banc. Therefore, the contested portion of the COL proceeding is closed. The NRC is required to conduct a hearing in all COL proceedings. This mandatory NRC hearing is anticipated to occur in the
first half of 2017 and will be uncontested.
In August 2016, Virginia Power received a
60-day
notice of intent to sue from the Sierra Club alleging Endangered Species Act violations. The notice alleges that the U.S. Army Corps of Engineers failed to conduct adequate environmental and consultation reviews, related to a potential third nuclear
unit located at North Anna, prior to issuing a CWA section 404 permit to Virginia Power in September 2011. No lawsuit has been filed and in November 2016, the Army Corps of Engineers suspended the section 404 permit while it gathers additional
information. This permitting issue is not expected to affect the NRCs issuance of the COL. Virginia Power is currently unable to make an estimate of the potential impacts to its consolidated financial statements related to this matter.
N
ORTH
C
AROLINA
R
EGULATION
In March 2016, Virginia Power filed its base rate case and schedules with the North Carolina Commission. Virginia Power proposed a
non-fuel,
base rate increase of $51 million effective November 1, 2016 with an ROE of 10.5%. In October 2016, Virginia Power entered into a stipulation and settlement agreement for a
non-fuel,
base rate increase of $35 million with an ROE of 9.9% effective November 1, 2016, on a temporary basis subject to refund, with any permanent rates ordered by the North Carolina Commission
effective January 1, 2017. In December 2016, the North Carolina Commission approved the stipulation and settlement agreement.
In
August 2016, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $36 million decrease to the fuel component of its electric rates for
the rate year beginning January 1, 2017. In December 2016, the North Carolina Commission approved the requested decrease and an additional $1 million reduction to Virginia Powers fuel rates.
O
HIO
R
EGULATION
PIR
Program
In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In March 2015, East Ohio filed an application with
the Ohio Commission requesting approval to extend the PIR program for an additional five years and to increase the annual capital investment, with corresponding increases in the annual rate-increase caps. In September 2016, the Ohio Commission
approved a stipulation filed jointly by East Ohio and the Staff
of the Ohio Commission to settle East Ohios pending application. As requested, the PIR Program and associated cost recovery will continue for another five-year term, calendar years 2017
through 2021, and East Ohio will be permitted to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio. Costs associated with
calendar year 2016 investment will be recovered under the existing terms.
In February 2016, East Ohio filed an application to adjust the
PIR cost recovery for 2015 costs. The filing reflects gross plant investment for 2015 of $171 million, cumulative gross plant investment of $1 billion and a revenue requirement of $131 million. This application was approved by
the Ohio Commission in April 2016.
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 2016, East Ohio filed an application to adjust the AMR cost recovery for costs incurred during the calendar year 2015. The filing reflects a revenue requirement of approximately $7 million. This application was approved by the Ohio
Commission in April 2016.
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 customers 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 2016, East Ohios annual update of the PIPP Rider was automatically approved by the Ohio Commission after a
45-day
waiting period from the date of the
filing. The revised rider rate reflects the recovery over the twelve-month period from July 2016 through June 2017 of projected deferred program costs of approximately $32 million from April 2016 through June 2017, net of a refund for
over-recovery of accumulated arrearages of approximately $28 million as of March 31, 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 Ohios actual write-offs of uncollectible amounts. In August 2016, the Ohio Commission approved an increase to East Ohios UEX Rider, which reflects a refund of
over-recovered accumulated bad debt expense of approximately $8 million as of March 31, 2016, and recovery of prospective net bad debt expense projected to total approximately $19 million for the twelve-month period from April 2016 to
March 2017.
PSMP
In November 2016, the Ohio
Commission approved East Ohios request to defer the operation and maintenance costs associated with implementing PSMP of up to $15 million per year.
Combined Notes to Consolidated Financial Statements, Continued
W
EST
V
IRGINIA
R
EGULATION
In May 2016, Hope filed a PREP application with the West Virginia Commission requesting approval of a projected capital investment for 2017 of
$27 million as part of a total five-year projected capital investment of $152 million. In September 2016, Hope reached a settlement with all parties to the case agreeing to new PREP customer rates, for the year beginning November 1,
2016, that provide for annual projected revenue of $2 million related to capital investments of $20 million and $27 million for 2016 and 2017, respectively. In October 2016, the West Virginia Commission approved the settlement.
FERCG
AS
Cove Point
In November 2016, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with 23 proposed
rates to be effective January 1, 2017. Cove Point proposed an annual cost-of-service of approximately $140 million. In December 2016, FERC accepted a January 1, 2017 effective date for all proposed rates but five which were suspended
to be effective June 1, 2017.
N
OTE
14. A
SSET
R
ETIREMENT
O
BLIGATIONS
AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of the Companies
long-lived assets. Dominions and Virginia Powers AROs are primarily associated with the decommissioning of their nuclear generation facilities and ash pond and landfill closures. 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 Dominions LNG facility, Dominions and
Dominion Gas storage wells in their underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia
Powers hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in Dominions and Virginia Powers 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 2015 and 2016 were as follows:
|
|
|
|
|
|
|
Amount
|
|
(millions)
|
|
|
|
Dominion
|
|
|
|
|
AROs at December 31, 2014
|
|
$
|
1,714
|
|
Obligations incurred during the period
(1)
|
|
|
315
|
|
Obligations settled during the period
|
|
|
(106
|
)
|
Revisions in estimated cash flows
(1)
|
|
|
88
|
|
Accretion
|
|
|
93
|
|
Other
|
|
|
(1
|
)
|
AROs at December 31, 2015
(2)
|
|
$
|
2,103
|
|
Obligations incurred during the period
(3)
|
|
|
204
|
|
Obligations settled during the period
|
|
|
(171
|
)
|
Revisions in estimated cash flows
(1)
|
|
|
245
|
|
Accretion
|
|
|
104
|
|
AROs at December 31, 2016
(2)
|
|
$
|
2,485
|
|
Virginia Power
|
|
|
|
|
AROs at December 31, 2014
|
|
$
|
855
|
|
Obligations incurred during the period
(1)
|
|
|
289
|
|
Obligations settled during the period
|
|
|
(39
|
)
|
Revisions in estimated cash flows
(1)
|
|
|
92
|
|
Accretion
|
|
|
50
|
|
AROs at December 31, 2015
|
|
$
|
1,247
|
|
Obligations incurred during the period
|
|
|
9
|
|
Obligations settled during the period
|
|
|
(115
|
)
|
Revisions in estimated cash flows
(1)
|
|
|
245
|
|
Accretion
|
|
|
57
|
|
AROs at December 31, 2016
|
|
$
|
1,443
|
|
|
|
|
|
|
|
|
Amount
|
|
(millions)
|
|
|
|
Dominion Gas
|
|
|
|
|
AROs at December 31, 2014
|
|
$
|
147
|
|
Obligations incurred during the period
|
|
|
5
|
|
Obligations settled during the period
|
|
|
(6
|
)
|
Revisions in estimated cash flows
|
|
|
(5
|
)
|
Accretion
|
|
|
9
|
|
Other
|
|
|
(1
|
)
|
AROs at December 31, 2015
(4)
|
|
$
|
149
|
|
Obligations incurred during the period
|
|
|
6
|
|
Obligations settled during the period
|
|
|
(8
|
)
|
Revisions in estimated cash flows
|
|
|
|
|
Accretion
|
|
|
9
|
|
AROs at December 31, 2016
(4)
|
|
$
|
156
|
|
(1)
|
Primarily reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 for further information.
|
(2)
|
Includes $216 million and $249 million reported in other current liabilities at December 31, 2015, and 2016, respectively.
|
(3)
|
Primarily reflects AROs assumed in the Dominion Questar Combination. See Note 3 for further information.
|
(4)
|
Includes $137 million and $147 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2015 and 2016, respectively.
|
Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear
plants. At December 31, 2016 and 2015, the aggregate fair value of Dominions trusts, consisting primarily of equity and debt securities, totaled $4.5 billion and $4.2 billion, respectively. At December 31, 2016 and
2015, the aggregate fair value of Virginia Powers trusts, consisting primarily of debt and equity securities, totaled $2.1 billion and 1.9 billion, respectively.
N
OTE
15. V
ARIABLE
I
NTEREST
E
NTITIES
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 entitys economic performance and 2) the
obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
Dominion
At December 31, 2016, Dominion owns the general partner, 50.9% of the common and subordinated units and 37.5% of the convertible preferred interests in
Dominion Midstream, which owns a preferred equity interest and the general partner interest in Cove Point. Additionally, Dominion owns the manager and 67% of the membership interest in certain merchant solar facilities, as discussed in Note 2.
Dominion has concluded that these entities are VIEs due to the limited partners or members lacking the characteristics of a controlling financial interest. In addition, in 2016 Dominion created a wholly owned subsidiary, SBL Holdco, as a holding
company of its interest in the VIE merchant solar facilities and accordingly SBL Holdco is a VIE. Dominion is the primary beneficiary of Dominion Midstream, SBL Holdco and the merchant solar facilities, and Dominion Midstream is the primary
beneficiary of Cove Point, as they have the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Dominions
securities due within one year and long-term debt include $17 million and $377
mil-
lion, respectively, of debt issued in 2016 by SBL Holdco net of issuance costs that is nonrecourse to Dominion and is secured by SBL Holdcos interest in the merchant solar facilities.
Dominion owns a 48% 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. Dominions maximum exposure to loss is limited to its current and future investment.
Dominion and Virginia
Power
Dominions and Virginia Powers nuclear decommissioning trust funds and Dominions rabbi trusts hold investments in limited
partnerships or similar type entities (see Note 9 for further details). Dominion and Virginia Power concluded that these partnership investments are VIEs due to the limited partners lacking the characteristics of a controlling financial interest.
Dominion and Virginia Power have concluded neither is the primary beneficiary as they do not have the power to direct the activities that most significantly impact these VIEs economic performance. Dominion and Virginia Power are obligated to
provide capital contributions to the partnerships as required by each partnership agreement based on their ownership percentages. Dominion and Virginia Powers maximum exposure to loss is limited to their current and future investments.
Dominion and Dominion Gas
Dominion previously concluded that
Iroquois was a VIE because a
non-affiliated
Iroquois equity holder had the ability during a limited period of time to transfer its ownership interests to another Iroquois equity holder or its affiliate. At the
end of the first quarter of 2016, such right no longer existed and, as a result, Dominion concluded that Iroquois is no longer a VIE.
Virginia Power
Virginia Power had long-term power and capacity contracts with five
non-utility
generators, which contain certain
variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. Contracts with two of these
non-utility
generators expired during 2015 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 Powers 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 Powers 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 Powers contracts and for the years the entities are expected to
operate after its contractual relationships expire. The remaining contracts expire at various
Combined Notes to Consolidated Financial Statements, Continued
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 $287 million as of
December 31, 2016. Virginia Power paid $144 million, $200 million, and $223 million for electric capacity and $31 million, $83 million, and $138 million for electric energy to these entities for the years ended
December 31, 2016, 2015 and 2014, respectively.
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 Pipelines 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 and Dominion Gas
Virginia Power and Dominion Gas
purchased shared services from DRS, an affiliated VIE, of $346 million and $123 million, $318 million and $115 million, and $335 million and $106 million for the years ended December 31, 2016, 2015 and 2014,
respectively. Virginia Power and Dominion Gas determined that neither is the primary beneficiary of DRS as neither has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to
absorb losses and benefits which could be significant to it. 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.
N
OTE
16.
S
HORT
-
TERM
D
EBT
AND
C
REDIT
A
GREEMENTS
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, Dominions 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Facility
Limit
|
|
|
Outstanding
Commercial
Paper
|
|
|
Outstanding
Letters of
Credit
|
|
|
Facility
Capacity
Available
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility
(1)(2)
|
|
$
|
5,000
|
|
|
$
|
3,155
|
|
|
$
|
|
|
|
$
|
1,845
|
|
Joint revolving credit facility
(1)
|
|
|
500
|
|
|
|
|
|
|
|
85
|
|
|
|
415
|
|
Total
|
|
$
|
5,500
|
|
|
$
|
3,155
|
(3)
|
|
$
|
85
|
|
|
$
|
2,260
|
|
At December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility
(1)
|
|
$
|
4,000
|
|
|
$
|
3,353
|
|
|
$
|
|
|
|
$
|
647
|
|
Joint revolving credit facility
(1)
|
|
|
500
|
|
|
|
156
|
|
|
|
59
|
|
|
|
285
|
|
Total
|
|
$
|
4,500
|
|
|
$
|
3,509
|
(3)
|
|
$
|
59
|
|
|
$
|
932
|
|
(1)
|
In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities 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 Dominions credit facilities were 1.05% and 0.62% at December 31, 2016 and 2015, respectively.
|
Dominion Questars revolving multi-year and
364-day
credit facilities with limits of
$500 million and $250 million, respectively, were terminated in October 2016. Questar Gas short-term financing is supported by the two joint revolving credit facilities discussed above with Dominion, Virginia Power and Dominion Gas,
to which Questar Gas was added as a borrower in November 2016, with an initial aggregate sub-limit of $250 million. In December 2016, Questar Gas entered into a commercial paper program pursuant to which it began accessing the commercial paper
markets.
In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which have a stated
maturity date of December 2017 with automatic one-year renewals through the maturity of the SBL Holdco term loan agreement in 2023. As of December 31, 2016, no amounts were outstanding under these facilities.
Virginia Power
Virginia Powers short-term financing is
supported through its access as
co-borrower
to the two joint revolving credit facilities. These credit facilities can be used for working capital, as support for the combined commercial paper programs of the
Companies and for other general corporate purposes.
Virginia Powers share of commercial paper and letters of credit outstanding under its
joint credit facilities with Dominion, Dominion Gas and Questar Gas were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Facility
Limit
(1)
|
|
|
Outstanding
Commercial
Paper
|
|
|
Outstanding
Letters of
Credit
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
At December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility
(1)(2)
|
|
$
|
5,000
|
|
|
$
|
65
|
|
|
$
|
|
|
Joint revolving credit facility
(1)
|
|
|
500
|
|
|
|
|
|
|
|
1
|
|
Total
|
|
$
|
5,500
|
|
|
$
|
65
|
(3)
|
|
$
|
1
|
|
At December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility
(1)
|
|
$
|
4,000
|
|
|
$
|
1,500
|
|
|
$
|
|
|
Joint revolving credit facility
(1)
|
|
|
500
|
|
|
|
156
|
|
|
|
|
|
Total
|
|
$
|
4,500
|
|
|
$
|
1,656
|
(3)
|
|
$
|
|
|
(1)
|
The full amount of the facilities is available to Virginia Power, less any amounts outstanding to
co-borrowers
Dominion, Dominion Gas and Questar Gas.
Sub-limits
for Virginia Power are set within the facility limit but can be changed at the option of Dominion, Dominion Gas and Questar Gas multiple times per year. At December 31, 2016, the
sub-limit
for Virginia Power was an aggregate $2.0 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. In May 2016, the maturity dates for these facilities were extended from April 2019 to April
2020. These credit facilities 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 0.97% and 0.60% at December 31, 2016 and 2015, respectively.
|
In addition to the credit facility commitments mentioned above, Virginia Power also has a $100 million credit facility. In May 2016, the
maturity date for this credit facility was extended from April 2019 to April 2020. In October 2016, this facility was reduced from $120 million to $100 million. As of December 31, 2016, this facility supports $100 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. These credit facilities can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.
Dominion Gas share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion, Virginia Power
and Questar Gas were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Facility
Limit
(1)
|
|
|
Outstanding
Commercial
Paper
|
|
|
Outstanding
Letters of
Credit
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
At December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility
(1)
|
|
$
|
1,000
|
|
|
$
|
460
|
|
|
$
|
|
|
Joint revolving credit facility
(1)
|
|
|
500
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,500
|
|
|
$
|
460
|
(2)
|
|
$
|
|
|
At December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility
(1)
|
|
$
|
1,000
|
|
|
$
|
391
|
|
|
$
|
|
|
Joint revolving credit facility
(1)
|
|
|
500
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,500
|
|
|
$
|
391
|
(2)
|
|
$
|
|
|
(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, Virginia Power and Questar Gas.
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. In November 2016, the
aggregate sub-limit for Dominion Gas was decreased from $750 million to $500 million. 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. In May 2016, the maturity dates for these facilities were extended from April 2019 to April
2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the
sub-limit,
whichever is less) of letters of
credit.
|
(2)
|
The weighted-average interest rate of the outstanding commercial paper supported by these credit facilities was 1.00% and 0.63% at December 31, 2016 and 2015, respectively.
|
Combined Notes to Consolidated Financial Statements, Continued
N
OTE
17. L
ONG
-
TERM
D
EBT
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
2016
Weighted-
average
Coupon
(1)
|
|
|
2016
|
|
|
2015
|
|
(millions, except percentages)
|
|
|
|
|
|
|
|
|
|
Dominion Gas Holdings, LLC:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes:
|
|
|
|
|
|
|
|
|
|
|
|
|
1.05% to 2.8%, due 2016 to 2020
|
|
|
2.68
|
%
|
|
$
|
1,150
|
|
|
$
|
1,550
|
|
2.875% to 4.8%, due 2023 to 2044
(2)
|
|
|
3.90
|
%
|
|
|
2,413
|
|
|
|
1,750
|
|
Dominion Gas Holdings, LLC total principal
|
|
|
|
|
|
$
|
3,563
|
|
|
$
|
3,300
|
|
Securities due within one year
|
|
|
|
|
|
|
|
|
|
|
(400
|
)
|
Unamortized discount and debt issuance costs
|
|
|
|
|
|
|
(35
|
)
|
|
|
(31
|
)
|
Dominion Gas Holdings, LLC total long-term debt
|
|
|
|
|
|
$
|
3,528
|
|
|
$
|
2,869
|
|
Virginia Electric and Power Company:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes:
|
|
|
|
|
|
|
|
|
|
|
|
|
1.2% to 8.625%, due 2016 to 2019
|
|
|
4.93
|
%
|
|
$
|
1,804
|
|
|
$
|
2,261
|
|
2.75% to 8.875%, due 2022 to 2046
|
|
|
4.59
|
%
|
|
|
7,940
|
|
|
|
6,292
|
|
Tax-Exempt
Financings
(3)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable rates, due 2016 to 2027
|
|
|
1.22
|
%
|
|
|
175
|
|
|
|
194
|
|
1.75% to 5.6%, due 2023 to 2041
|
|
|
2.25
|
%
|
|
|
678
|
|
|
|
678
|
|
Virginia Electric and Power Company total principal
|
|
|
|
|
|
$
|
10,597
|
|
|
$
|
9,425
|
|
Securities due within one year
|
|
|
5.47
|
%
|
|
|
(678
|
)
|
|
|
(476
|
)
|
Unamortized discount, premium and debt issuances costs, net
|
|
|
|
|
|
|
(67
|
)
|
|
|
(57
|
)
|
Virginia Electric and Power Company total long-term
debt
|
|
|
|
|
|
$
|
9,852
|
|
|
$
|
8,892
|
|
Dominion Resources, Inc.:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable rate, due 2016
|
|
|
|
|
|
$
|
|
|
|
$
|
600
|
|
1.25% to 6.4%, due 2016 to 2021
|
|
|
2.83
|
%
|
|
|
5,400
|
|
|
|
3,900
|
|
2.75% to 7.0%, due 2022 to 2044
|
|
|
4.68
|
%
|
|
|
4,999
|
|
|
|
4,599
|
|
Tax-Exempt
Financing, variable rate, due 2041
|
|
|
1.41
|
%
|
|
|
75
|
|
|
|
75
|
|
Unsecured Junior Subordinated Notes:
|
|
|
|
|
|
|
|
|
|
|
|
|
2.962% and 4.104%, due 2019 and 2021
|
|
|
3.53
|
%
|
|
|
1,100
|
|
|
|
|
|
Payable to Affiliated Trust, 8.4% due 2031
|
|
|
8.40
|
%
|
|
|
10
|
|
|
|
10
|
|
Enhanced Junior Subordinated Notes:
|
|
|
|
|
|
|
|
|
|
|
|
|
5.25% to 7.5%, due 2054 to 2076
|
|
|
5.48
|
%
|
|
|
1,485
|
|
|
|
971
|
|
Variable rates, due 2066
|
|
|
3.45
|
%
|
|
|
422
|
|
|
|
377
|
|
Remarketable Subordinated Notes, 1.07% to 2.0%, due 2019 to 2024
|
|
|
1.79
|
%
|
|
|
2,400
|
|
|
|
2,100
|
|
Unsecured Debentures and Senior Notes
:
|
|
|
|
|
|
|
|
|
|
|
|
|
6.8% and 6.875%, due 2026 and 2027
(4)
|
|
|
6.81
|
%
|
|
|
89
|
|
|
|
89
|
|
Term Loan, variable rate, due 2017
(5)
|
|
|
1.85
|
%
|
|
|
250
|
|
|
|
|
|
Unsecured Senior and Medium-Term Notes
(5)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
5.31% to 6.85%, due 2017 and 2018
|
|
|
5.84
|
%
|
|
|
135
|
|
|
|
|
|
2.98% to 7.20%, due 2024 to 2051
|
|
|
4.57
|
%
|
|
|
500
|
|
|
|
|
|
Term Loan, variable rate, due 2023
(6)
|
|
|
4.75
|
%
|
|
|
405
|
|
|
|
|
|
Tax-Exempt
Financing, 1.55%, due 2033
(7)
|
|
|
1.55
|
%
|
|
|
27
|
|
|
|
27
|
|
Dominion Midstream Partners, LP:
|
|
|
|
|
|
|
|
|
|
|
|
|
Term Loan, variable rate, due 2019
|
|
|
2.19
|
%
|
|
|
300
|
|
|
|
|
|
Unsecured Senior and Medium-Term Notes, 5.83% and 6.48%, due
2018
(8)
|
|
|
5.84
|
%
|
|
|
255
|
|
|
|
|
|
Unsecured Senior Notes, 4.875%, due 2041
(8)
|
|
|
4.88
|
%
|
|
|
180
|
|
|
|
|
|
Dominion Gas Holdings, LLC total principal (from above)
|
|
|
|
|
|
|
3,563
|
|
|
|
3,300
|
|
Virginia Electric and Power Company total principal (from
above)
|
|
|
|
|
|
|
10,597
|
|
|
|
9,425
|
|
Dominion Resources, Inc. total principal
|
|
|
|
|
|
$
|
32,192
|
|
|
$
|
25,473
|
|
Fair value hedge valuation
(9)
|
|
|
|
|
|
|
(1
|
)
|
|
|
7
|
|
Securities due within one year
(10)
|
|
|
3.13
|
%
|
|
|
(1,709
|
)
|
|
|
(1,825
|
)
|
Unamortized discount, premium and debt issuance costs, net
|
|
|
|
|
|
|
(251
|
)
|
|
|
(187
|
)
|
Dominion Resources, Inc. total long-term debt
|
|
|
|
|
|
$
|
30,231
|
|
|
$
|
23,468
|
|
(1)
|
Represents weighted-average coupon rates for debt outstanding as of December 31, 2016.
|
(2)
|
Beginning June 30, 2016, amount includes foreign currency remeasurement adjustments.
|
(3)
|
These financings relate to certain pollution control equipment at Virginia Powers generating facilities. Certain variable rate
tax-exempt
financings are supported by a
$100 million credit facility that terminates in April 2020.
|
(4)
|
Represents debt assumed by Dominion from the merger of its former CNG subsidiary.
|
(5)
|
Represents debt obligations of Dominion Questar or Questar Gas. See Note 3 for more information.
|
(6)
|
Represents debt associated with SBL Holdco. The debt is nonrecourse to Dominion and is secured by SBL Holdcos interest in certain merchant solar facilities.
|
(7)
|
Represents debt obligations of a DEI subsidiary.
|
(8)
|
Represents debt obligations of Questar Pipeline. See Note 3 for more information.
|
(9)
|
Represents the valuation of certain fair value hedges associated with Dominions fixed rate debt.
|
(10)
|
2015 excludes $100 million of variable rate short-term notes that were purchased and cancelled in February 2016 using proceeds from the issuance of long-term debt. The notes would have otherwise matured in May 2016.
|
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, 2016, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
|
Thereafter
|
|
|
Total
|
|
(millions, except percentages)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Gas
|
|
$
|
|
|
|
$
|
|
|
|
$
|
450
|
|
|
$
|
700
|
|
|
$
|
|
|
|
$
|
2,413
|
|
|
$
|
3,563
|
|
Weighted-average Coupon
|
|
|
|
|
|
|
|
|
|
|
2.50
|
%
|
|
|
2.80
|
%
|
|
|
|
|
|
|
3.90
|
%
|
|
|
|
|
Virginia Power
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes
|
|
$
|
604
|
|
|
$
|
850
|
|
|
$
|
350
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7,940
|
|
|
$
|
9,744
|
|
Tax-Exempt Financings
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
778
|
|
|
|
853
|
|
Total
|
|
$
|
679
|
|
|
$
|
850
|
|
|
$
|
350
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
8,718
|
|
|
$
|
10,597
|
|
Weighted-average Coupon
|
|
|
5.47
|
%
|
|
|
4.17
|
%
|
|
|
5.00
|
%
|
|
|
|
|
|
|
|
|
|
|
4.37
|
%
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Term Loans
|
|
$
|
268
|
|
|
$
|
20
|
|
|
$
|
321
|
|
|
$
|
19
|
|
|
$
|
19
|
|
|
$
|
308
|
|
|
$
|
955
|
|
Unsecured Senior Notes
|
|
|
1,368
|
|
|
|
3,275
|
|
|
|
2,500
|
|
|
|
700
|
|
|
|
900
|
|
|
|
16,122
|
|
|
|
24,865
|
|
Tax-Exempt Financings
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
880
|
|
|
|
955
|
|
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
10
|
|
Unsecured Junior Subordinated Notes
|
|
|
|
|
|
|
|
|
|
|
550
|
|
|
|
|
|
|
|
550
|
|
|
|
|
|
|
|
1,100
|
|
Enhanced Junior Subordinated Notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,907
|
|
|
|
1,907
|
|
Remarketable Subordinated Notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
|
700
|
|
|
|
700
|
|
|
|
2,400
|
|
Total
|
|
$
|
1,711
|
|
|
$
|
3,295
|
|
|
$
|
3,371
|
|
|
$
|
1,719
|
|
|
$
|
2,169
|
|
|
$
|
19,927
|
|
|
$
|
32,192
|
|
Weighted-average Coupon
|
|
|
3.13
|
%
|
|
|
3.62
|
%
|
|
|
3.09
|
%
|
|
|
2.07
|
%
|
|
|
3.12
|
%
|
|
|
4.38
|
%
|
|
|
|
|
The Companies short-term credit facilities and long-term debt agreements contain customary
covenants and default provisions. As of December 31, 2016, there were no events of default under these covenants.
In January
2017, Dominion issued $400 million of 1.875% senior notes and $400 million of 2.75% senior notes that mature in 2019 and 2022, respectively.
Senior
Note Redemptions
As part of Dominions 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 Dominions Consolidated Statements of Income. Proceeds
from Dominions 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 Dominions 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 Dominions issuance of senior notes in November 2014 were used to offset the portion of the conversions paid in cash.
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. Beginning June 30, 2016, the June 2006 hybrids bear interest at three-month LIBOR plus 2.825%, reset quarterly.
Previously, interest was fixed at 7.5% per year. The September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly.
In 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
Combined Notes to Consolidated Financial Statements, Continued
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 Dominions 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 cancelled $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 $38 million and $4 million of the June 2006 hybrids and the September 2006 hybrids, respectively. In July 2016, Dominion launched a tender offer to purchase up to $200 million in
aggregate of additional June 2006 hybrids and September 2006 hybrids, which expired on August 1, 2016. In connection with the tender offer, Dominion purchased and cancelled $125 million and $74 million of the June 2006 hybrids
and the September 2006 hybrids, respectively. All purchases were conducted in compliance with the applicable RCC. Also in July 2016, Dominion issued $800 million of 5.25% July 2016 hybrids. The proceeds were used for general corporate
purposes, including to finance the tender offer. The July 2016 hybrids are listed on the NYSE under the symbol DRUA.
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 additional tender offers or otherwise.
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 6.0% Equity Units, initially in the form of Corporate Units. The Corporate Units were listed on the NYSE under the symbols DCUA and DCUB, respectively.
Each Corporate Unit consisted of a stock purchase contract and 1/20 interest in a RSN issued by Dominion. The stock purchase contracts
obligated the holders to purchase shares of Dominion common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price paid under the stock purchase contracts was $50 per Corporate Unit and the
number of shares purchased was determined under a formula based upon the average closing price of Dominion common stock near the settlement date. The RSNs were pledged as collateral to secure the
purchase of common stock under the related stock purchase contracts.
In March 2016 and May 2016, Dominion successfully remarketed the
$550 million 2013 Series A 1.07% RSNs due 2021 and the $550 million 2013 Series B 1.18% RSNs due 2019, respectively, pursuant to the terms of the related 2013 Equity Units. In connection with the remarketings, the interest rate on the
Series A and Series B junior subordinated notes was reset to 4.104% and 2.962%, respectively, payable on a semi-annual basis and Dominion ceased to have the ability to redeem the notes at its option or defer interest payments. At
December 31, 2016, the securities are included in junior subordinated notes in Dominions Consolidated Balance Sheets. Dominion did not receive any proceeds from the remarketings. Remarketing proceeds belonged to the investors holding
the related 2013 Equity Units and were temporarily used to purchase a portfolio of treasury securities. Upon maturity of each portfolio, the proceeds were applied on behalf of investors on the related stock purchase contract settlement date to
pay the purchase price to Dominion for issuance of 8.5 million shares of its common stock on both April 1, 2016 and July 1, 2016. See Issuance of Common Stock below for a description of common stock issued by Dominion in April
2016 and July 2016 under the stock purchase contracts.
In July 2014, Dominion issued $1.0 billion of 2014 Series A 6.375% Equity
Units, initially in the form of Corporate Units. In August 2016, Dominion issued $1.4 billion of 2016 Series A 6.75% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbols DCUC and
DCUD, respectively. The net proceeds from the 2016 Equity Units were used to finance the Dominion Questar Combination. See Note 3 for more information.
Each 2014 Series A Corporate Unit consists of a stock purchase contract and 1/20 interest in a 2014 Series A RSN issued by Dominion. Each 2016
Series A Corporate Unit consists of a stock purchase contract, a 1/40 interest in a 2016 Series
A-1
RSN issued by Dominion and a 1/40 interest in a 2016 Series
A-2
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 2014 Equity Units and 2016 Equity Units, Dominion expects to remarket the 2014 Series A RSNs during the second quarter of 2017 and both the 2016 Series
A-1
and 2016 Series A-2 RSNs during the third quarter
of 2019. Following a successful remarketing, the interest rate on the RSNs will be reset, interest will be payable on a semi-annual basis and Dominion 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.
Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion will issue
between 11.6 million and 14.5 million shares of its common stock in July 2017 and between 15.0 million and 18.7 million shares in August 2019. A total of 40.9 million shares of Dominions common stock has been reserved
for issuance in connection with the stock purchase contracts.
Selected information about Dominions Equity Units is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance Date
|
|
Units
Issued
|
|
|
Total Net
Proceeds
|
|
|
Total
Long-term Debt
|
|
|
RSN Annual
Interest Rate
|
|
|
Stock Purchase
Contract Annual
Rate
|
|
|
Stock Purchase
Contract Liability
(1)
|
|
|
Stock Purchase
Settlement Date
|
|
|
RSN Maturity
Date
|
|
(millions, except interest rates)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7/1/2014
|
|
|
20
|
|
|
$
|
982.0
|
|
|
$
|
1,000.0
|
|
|
|
1.500
|
%
|
|
|
4.875
|
%
|
|
$
|
142.8
|
|
|
|
7/1/2017
|
|
|
|
7/1/2020
|
|
8/15/2016
(2)
|
|
|
28
|
|
|
$
|
1,374.8
|
|
|
$
|
1,400.0
|
|
|
|
2.000
|
%
(3)
|
|
|
4.750
|
%
|
|
$
|
190.6
|
|
|
|
8/15/2019
|
|
|
|
|
|
(1)
|
Payments of $94 million and $101 million were made in 2016 and 2015, respectively, including payments for the remarketed 2013 Series A and B notes. The stock purchase contract liability was
$212 million and $115 million at December 31, 2016 and 2015, respectively.
|
(2)
|
The maturity dates of the $700 million Series
A-1
RSNs and $700 million Series
A-2
RSNs are August 15, 2021 and
August 15, 2024, respectively.
|
(3)
|
Annual interest rate applies to each of the Series
A-1
RSNs and Series
A-2
RSNs.
|
Combined Notes to Consolidated Financial Statements, Continued
N
OTE
18. P
REFERRED
S
TOCK
Dominion is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2016 or
2015.
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 Dominions 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, 2016 or 2015.
N
OTE
19. E
QUITY
Issuance of Common Stock
D
OMINION
Dominion maintains Dominion Direct
®
and a number of employee savings plans through which
contributions may be invested in Dominions 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 2016,
Dominion received cash proceeds, net of fees and commissions, of $2.2 billion from the issuance of approximately 32 million shares of common stock through various programs resulting in approximately 628 million of shares of common
stock outstanding at December 31, 2016. These proceeds include cash of $295 million received from the issuance of 4.0 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. Following issuances during the first and second quarters of 2015, Dominion has the ability to issue
up to approximately $200 million of stock under the 2014 sales agency agreements; however, no additional issuances occurred under these agreements in 2016.
In both April 2016 and July 2016, Dominion issued 8.5 million shares under the related stock purchase contracts entered into as part of
Dominions 2013 Equity Units and received $1.1 billion of total proceeds. Additionally, Dominion completed a market issuance of equity in April 2016 of 10.2 million shares and received proceeds of $756 million through a registered
underwritten public offering. A portion of the net proceeds was used to finance the Dominion Questar Combination. See Note 3 for more information.
V
IRGINIA
P
OWER
In 2016, 2015 and 2014, Virginia Power did not issue any shares of its common stock to Dominion.
Shares Reserved for Issuance
At December 31, 2016,
Dominion had approximately 63 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 2016 or 2015 and does not plan to repurchase shares during 2017, 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, which expired in September 2016. Dominion purchased approximately 658,000 common units for $17 million and 887,000 common units for $25 million for the years ended December 31, 2016 and 2015,
respectively.
Issuance of Dominion Midstream Units
During the
fourth quarter of 2016, Dominion Midstream received $482 million of proceeds from the issuance of common units and $490 million of proceeds from the issuance of convertible preferred units. The net proceeds were primarily used to finance a portion
of the acquisition of Questar Pipeline from Dominion. See Note 3 for more information.
The holders of the convertible preferred units are
entitled to receive cumulative quarterly distributions payable in cash or additional convertible preferred units, subject to certain conditions. The units are convertible into Dominion Midstream common units on a one-for-one basis, subject to
certain adjustments, (i) in whole or in part at the option of the unitholders any time after December 1, 2018 or, (ii) in whole or in part at Dominion Midstreams option, subject to certain conditions, any time after December 1, 2019. The
conversion of such units would result in a potential increase to Dominions net income attributable to noncontrolling interests.
Accumulated Other Comprehensive Income (Loss)
Presented in the table below is a summary of AOCI by component:
|
|
|
|
|
|
|
|
|
At December 31,
|
|
2016
|
|
|
2015
|
|
(millions)
|
|
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
Net deferred losses on derivatives-hedging activities, net of tax of $173 and $110
|
|
$
|
(280
|
)
|
|
$
|
(176
|
)
|
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(318) and $(281)
|
|
|
569
|
|
|
|
504
|
|
Net unrecognized pension and other postretirement benefit costs, net of tax of $691 and $525
|
|
|
(1,082
|
)
|
|
|
(797
|
)
|
Other comprehensive loss from equity method investees, net of tax of
$4 and $4
|
|
|
(6
|
)
|
|
|
(5
|
)
|
Total AOCI
|
|
$
|
(799
|
)
|
|
$
|
(474
|
)
|
Virginia Power
|
|
|
|
|
|
|
|
|
Net deferred losses on derivatives-hedging activities, net of tax of $5 and $4
|
|
$
|
(8
|
)
|
|
$
|
(7
|
)
|
Net unrealized gains on nuclear decommissioning trust funds, net of
tax of $(35) and $(30)
|
|
|
54
|
|
|
|
47
|
|
Total AOCI
|
|
$
|
46
|
|
|
$
|
40
|
|
Dominion Gas
|
|
|
|
|
|
|
|
|
Net deferred losses on derivatives-hedging activities, net of tax of $15 and $10
|
|
$
|
(24
|
)
|
|
$
|
(17
|
)
|
Net unrecognized pension costs, net of tax of $68 and $56
|
|
|
(99
|
)
|
|
|
(82
|
)
|
Total AOCI
|
|
$
|
(123
|
)
|
|
$
|
(99
|
)
|
D
OMINION
The following table presents Dominions changes in AOCI by component, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
gains and
losses on
derivatives-
hedging
activities
|
|
|
Unrealized
gains and
losses on
investment
securities
|
|
|
Unrecognized
pension and
other
postretirement
benefit costs
|
|
|
Other
comprehensive
loss from
equity method
investees
|
|
|
Total
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
$
|
(176
|
)
|
|
$
|
504
|
|
|
$
|
(797
|
)
|
|
$
|
(5)
|
|
|
$
|
(474
|
)
|
Other comprehensive income before reclassifications: gains (losses)
|
|
|
55
|
|
|
|
93
|
|
|
|
(319
|
)
|
|
|
(1)
|
|
|
|
(172
|
)
|
Amounts reclassified from AOCI: (gains) losses
(1)
|
|
|
(159
|
)
|
|
|
(28
|
)
|
|
|
34
|
|
|
|
|
|
|
|
(153
|
)
|
Net current period other comprehensive income (loss)
|
|
|
(104
|
)
|
|
|
65
|
|
|
|
(285
|
)
|
|
|
(1)
|
|
|
|
(325
|
)
|
Ending balance
|
|
$
|
(280
|
)
|
|
$
|
569
|
|
|
$
|
(1,082
|
)
|
|
$
|
(6)
|
|
|
$
|
(799
|
)
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
$
|
(178
|
)
|
|
$
|
548
|
|
|
$
|
(782
|
)
|
|
$
|
(4)
|
|
|
$
|
(416
|
)
|
Other comprehensive income before reclassifications: gains (losses)
|
|
|
110
|
|
|
|
6
|
|
|
|
(66
|
)
|
|
|
(1)
|
|
|
|
49
|
|
Amounts reclassified from AOCI: (gains) losses
(1)
|
|
|
(108
|
)
|
|
|
(50
|
)
|
|
|
51
|
|
|
|
|
|
|
|
(107
|
)
|
Net current period other comprehensive income (loss)
|
|
|
2
|
|
|
|
(44
|
)
|
|
|
(15
|
)
|
|
|
(1)
|
|
|
|
(58
|
)
|
Ending balance
|
|
$
|
(176
|
)
|
|
$
|
504
|
|
|
$
|
(797
|
)
|
|
$
|
(5)
|
|
|
$
|
(474
|
)
|
(1)
|
See table below for details about these reclassifications.
|
Combined Notes to Consolidated Financial Statements, Continued
The following table presents Dominions reclassifications out of AOCI by component:
|
|
|
|
|
|
|
|
|
Details about AOCI components
|
|
Amounts
reclassified
from AOCI
|
|
|
Affected line item in the
Consolidated Statements of
Income
|
|
(millions)
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities:
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
(330
|
)
|
|
|
Operating revenue
|
|
|
|
|
13
|
|
|
|
Purchased gas
|
|
|
|
|
10
|
|
|
|
Electric fuel and other
energy-related purchases
|
|
Interest rate contracts
|
|
|
31
|
|
|
|
Interest and related
charges
|
|
Foreign currency contracts
|
|
|
17
|
|
|
|
Other Income
|
|
Total
|
|
|
(259
|
)
|
|
|
|
|
Tax
|
|
|
100
|
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
(159
|
)
|
|
|
|
|
Unrealized (gains) and losses on investment securities:
|
|
|
|
|
|
|
|
|
Realized (gain) loss on sale of securities
|
|
$
|
(66
|
)
|
|
|
Other income
|
|
Impairment
|
|
|
23
|
|
|
|
Other income
|
|
Total
|
|
|
(43
|
)
|
|
|
|
|
Tax
|
|
|
15
|
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
(28
|
)
|
|
|
|
|
Unrecognized pension and other postretirement benefit costs:
|
|
|
|
|
|
|
|
|
Prior-service costs (credits)
|
|
$
|
(15
|
)
|
|
|
Other operations and
maintenance
|
|
Actuarial losses
|
|
|
71
|
|
|
|
Other operations and
maintenance
|
|
Total
|
|
|
56
|
|
|
|
|
|
Tax
|
|
|
(22
|
)
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
34
|
|
|
|
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities:
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
(203
|
)
|
|
|
Operating revenue
|
|
|
|
|
15
|
|
|
|
Purchased gas
|
|
|
|
|
1
|
|
|
|
Electric fuel and other
energy-related purchases
|
|
Interest rate contracts
|
|
|
11
|
|
|
|
Interest and related
charges
|
|
Total
|
|
|
(176
|
)
|
|
|
|
|
Tax
|
|
|
68
|
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
(108
|
)
|
|
|
|
|
Unrealized (gains) and losses on investment securities:
|
|
|
|
|
|
|
|
|
Realized (gain) loss on sale of securities
|
|
$
|
(110
|
)
|
|
|
Other income
|
|
Impairment
|
|
|
31
|
|
|
|
Other income
|
|
Total
|
|
|
(79
|
)
|
|
|
|
|
Tax
|
|
|
29
|
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
(50
|
)
|
|
|
|
|
Unrecognized pension and other postretirement benefit costs:
|
|
|
|
|
|
|
|
|
Prior-service costs (credits)
|
|
$
|
(12
|
)
|
|
|
Other operations and
maintenance
|
|
Actuarial losses
|
|
|
98
|
|
|
|
Other operations and
maintenance
|
|
Total
|
|
|
86
|
|
|
|
|
|
Tax
|
|
|
(35
|
)
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
51
|
|
|
|
|
|
V
IRGINIA
P
OWER
The following table presents Virginia Powers changes in AOCI by component, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred gains
and losses on
derivatives-
hedging
activities
|
|
|
Unrealized gains
and losses on
investment
securities
|
|
|
Total
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
$
|
(7
|
)
|
|
$
|
47
|
|
|
$
|
40
|
|
Other comprehensive income before reclassifications: gains (losses)
|
|
|
(2
|
)
|
|
|
11
|
|
|
|
9
|
|
Amounts reclassified from AOCI: (gains) losses
(1)
|
|
|
1
|
|
|
|
(4
|
)
|
|
|
(3
|
)
|
Net current period other comprehensive income (loss)
|
|
|
(1
|
)
|
|
|
7
|
|
|
|
6
|
|
Ending balance
|
|
$
|
(8
|
)
|
|
$
|
54
|
|
|
$
|
46
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
$
|
(7
|
)
|
|
$
|
57
|
|
|
$
|
50
|
|
Other comprehensive income before reclassifications: gains (losses)
|
|
|
(1
|
)
|
|
|
(4
|
)
|
|
|
(5
|
)
|
Amounts reclassified from AOCI: (gains) losses
(1)
|
|
|
1
|
|
|
|
(6
|
)
|
|
|
(5
|
)
|
Net current period other comprehensive income (loss)
|
|
|
|
|
|
|
(10
|
)
|
|
|
(10
|
)
|
Ending balance
|
|
$
|
(7
|
)
|
|
$
|
47
|
|
|
$
|
40
|
|
(1)
|
See table below for details about these reclassifications.
|
The following table presents Virginia Powers reclassifications out of AOCI by component:
|
|
|
|
|
|
|
|
|
Details about AOCI components
|
|
Amounts
reclassified
from AOCI
|
|
|
Affected line item in the
Consolidated Statements of
Income
|
|
(millions)
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
(Gains) losses on cash flow hedges:
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
$
|
1
|
|
|
|
Interest and related charges
|
|
Total
|
|
|
1
|
|
|
|
|
|
Tax
|
|
|
|
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
1
|
|
|
|
|
|
Unrealized (gains) and losses on investment securities:
|
|
|
|
|
|
|
|
|
Realized (gain) loss on sale of securities
|
|
$
|
(9
|
)
|
|
|
Other income
|
|
Impairment
|
|
|
3
|
|
|
|
Other income
|
|
Total
|
|
|
(6
|
)
|
|
|
|
|
Tax
|
|
|
2
|
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
(4
|
)
|
|
|
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
(Gains) losses on cash flow hedges:
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
1
|
|
|
|
Electric fuel and other
energy-related purchases
|
|
Total
|
|
|
1
|
|
|
|
|
|
Tax
|
|
|
|
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
1
|
|
|
|
|
|
Unrealized (gains) and losses on investment securities:
|
|
|
|
|
|
|
|
|
Realized (gain) loss on sale of securities
|
|
$
|
(14
|
)
|
|
|
Other income
|
|
Impairment
|
|
|
4
|
|
|
|
Other income
|
|
Total
|
|
|
(10
|
)
|
|
|
|
|
Tax
|
|
|
4
|
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
(6
|
)
|
|
|
|
|
D
OMINION
G
AS
The following table presents Dominion Gas changes in AOCI by component, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred gains
and losses on
derivatives-
hedging
activities
|
|
|
Unrecognized
pension costs
|
|
|
Total
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
$
|
(17
|
)
|
|
$
|
(82
|
)
|
|
$
|
(99
|
)
|
Other comprehensive income before reclassifications: losses
|
|
|
(16
|
)
|
|
|
(20
|
)
|
|
|
(36
|
)
|
Amounts reclassified from AOCI
(1):
losses
|
|
|
9
|
|
|
|
3
|
|
|
|
12
|
|
Net current period other comprehensive loss
|
|
|
(7
|
)
|
|
|
(17
|
)
|
|
|
(24
|
)
|
Ending balance
|
|
$
|
(24
|
)
|
|
$
|
(99
|
)
|
|
$
|
(123
|
)
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
$
|
(20
|
)
|
|
$
|
(66
|
)
|
|
$
|
(86
|
)
|
Other comprehensive income before reclassifications: gains (losses)
|
|
|
6
|
|
|
|
(20
|
)
|
|
|
(14
|
)
|
Amounts reclassified from AOCI
(1)
: (gains) losses
|
|
|
(3
|
)
|
|
|
4
|
|
|
|
1
|
|
Net current period other comprehensive income (loss)
|
|
|
3
|
|
|
|
(16
|
)
|
|
|
(13
|
)
|
Ending balance
|
|
$
|
(17
|
)
|
|
$
|
(82
|
)
|
|
$
|
(99
|
)
|
(1) See table below for details about these reclassifications.
Combined Notes to Consolidated Financial Statements, Continued
The following table presents Dominion Gas reclassifications out of AOCI by component:
|
|
|
|
|
|
|
|
|
Details about AOCI components
|
|
Amounts
reclassified
from AOCI
|
|
|
Affected line item in the
Consolidated Statements of Income
|
|
(millions)
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities:
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
(4
|
)
|
|
|
Operating revenue
|
|
Interest rate contracts
|
|
|
2
|
|
|
|
Interest and related charges
|
|
Foreign currency contracts
|
|
|
17
|
|
|
|
Other income
|
|
Total
|
|
|
15
|
|
|
|
|
|
Tax
|
|
|
(6
|
)
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
9
|
|
|
|
|
|
Unrecognized pension costs:
|
|
|
|
|
|
|
|
|
Actuarial losses
|
|
$
|
5
|
|
|
|
Other operations and
maintenance
|
|
Total
|
|
|
5
|
|
|
|
|
|
Tax
|
|
|
(2
|
)
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
3
|
|
|
|
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities:
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
(6
|
)
|
|
|
Operating revenue
|
|
Total
|
|
|
(6
|
)
|
|
|
|
|
Tax
|
|
|
3
|
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
(3
|
)
|
|
|
|
|
Unrecognized pension costs:
|
|
|
|
|
|
|
|
|
Actuarial losses
|
|
$
|
7
|
|
|
|
Other operations and
maintenance
|
|
Total
|
|
|
7
|
|
|
|
|
|
Tax
|
|
|
(3
|
)
|
|
|
Income tax expense
|
|
Total, net of tax
|
|
$
|
4
|
|
|
|
|
|
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, 2016, approximately 24 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. Dominions results for the years ended
December 31, 2016, 2015 and 2014 include $33 million, $39 million, and $39 million,
respectively, of compensation costs and $11 million, $14 million, and
$14 million, respectively of income tax benefits related to Dominions stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominions Consolidated Statements
of Income. Excess Tax Benefits are classified as a financing cash flow. Dominion realized less than $1 million and $3 million of Excess Tax Benefits from the vesting of restricted stock awards during the year ended December 31, 2016 and
2015, respectively, and less than $1 million during the year ended December 31, 2014.
R
ESTRICTED
S
TOCK
Restricted stock grants are made to officers under Dominions LTIP and may also be granted to certain key
non-officer
employees from time to time. The fair value of Dominions restricted stock awards is equal to the closing price of Dominions 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, 2016, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Weighted
- average
Grant Date
Fair Value
|
|
|
|
(thousands)
|
|
|
|
|
Nonvested at December 31, 2013
|
|
|
1,007
|
|
|
$
|
49.35
|
|
Granted
|
|
|
354
|
|
|
|
67.98
|
|
Vested
|
|
|
(278
|
)
|
|
|
44.50
|
|
Cancelled and forfeited
|
|
|
(18
|
)
|
|
|
53.61
|
|
Nonvested at December 31, 2014
|
|
|
1,065
|
|
|
$
|
56.74
|
|
Granted
|
|
|
302
|
|
|
|
73.26
|
|
Vested
|
|
|
(510
|
)
|
|
|
50.71
|
|
Cancelled and forfeited
|
|
|
(2
|
)
|
|
|
62.62
|
|
Nonvested at December 31, 2015
|
|
|
855
|
|
|
$
|
66.16
|
|
Granted
|
|
|
372
|
|
|
|
71.67
|
|
Vested
|
|
|
(301
|
)
|
|
|
56.83
|
|
Cancelled and forfeited
|
|
|
(40
|
)
|
|
|
71.75
|
|
Nonvested at December 31, 2016
|
|
|
886
|
|
|
$
|
71.40
|
|
As of December 31, 2016, unrecognized compensation cost related to nonvested restricted stock awards
totaled $31 million and is expected to be recognized over a weighted-average period of 1.9 years. The fair value of restricted stock awards that vested was $21 million, $37 million, and $19 million in 2016, 2015 and 2014,
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.
G
OAL
-B
ASED
S
TOCK
Goal-based stock awards are granted under Dominions LTIP to officers who have not achieved a certain targeted level of share ownership, in lieu of
cash-based performance grants. Current outstanding goal-based shares include awards granted to officers in February 2015 and February 2016.
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 determined on the date of grant. 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, 2016, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
Targeted
Number of
Shares
|
|
|
Weighted
- average
Grant
Date Fair
Value
|
|
|
|
(thousands)
|
|
|
|
|
Nonvested at December 31, 2013
|
|
|
5
|
|
|
$
|
53.85
|
|
Granted
|
|
|
13
|
|
|
|
68.83
|
|
Vested
|
|
|
(1
|
)
|
|
|
52.48
|
|
Nonvested at December 31, 2014
|
|
|
17
|
|
|
$
|
65.15
|
|
Granted
|
|
|
14
|
|
|
|
72.72
|
|
Vested
|
|
|
(7
|
)
|
|
|
56.22
|
|
Nonvested at December 31, 2015
|
|
|
24
|
|
|
$
|
72.27
|
|
Granted
|
|
|
12
|
|
|
|
69.93
|
|
Vested
|
|
|
(10
|
)
|
|
|
68.83
|
|
Cancelled and forfeited
|
|
|
(3
|
)
|
|
|
68.83
|
|
Nonvested at December 31, 2016
|
|
|
23
|
|
|
$
|
72.99
|
|
At December 31, 2016, the targeted number of shares expected to be issued under the February 2015 and
February 2016 awards was approximately 23 thousand. In January 2017, the CGN Committee determined the actual performance against metrics established for the February 2015 awards with a performance period that ended December 31, 2016. Based
on that determination, the total number of shares to be issued under the February 2015 goal-based stock awards was approximately 9 thousand.
As of December 31, 2016, unrecognized compensation cost related to nonvested goal-based stock awards was not material.
C
ASH
-B
ASED
P
ERFORMANCE
G
RANTS
Cash-based performance grants are made to Dominions officers under Dominions 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 2014, a cash-based
performance grant was made to officers. The performance grant was paid out in January 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 of the payout under the grant was $10 million.
In February 2015, a
cash-based performance grant was made to officers. Payout of the performance grant occurred in January 2017 based on the achievement of two performance metrics during 2015 and 2016: TSR relative to that of companies listed as members of the
Philadelphia Utility Index as of the end of the performance period and ROIC. The total of the payout under the grant was $10 million.
In February 2016, a cash-based performance grant was made to officers. Payout of the
performance grant is expected to occur by March 15, 2018 based on the achievement of two performance metrics during 2016 and 2017: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the
performance period and ROIC. At December 31, 2016, the targeted amount of the grant was $14 million and a liability of $6 million had been accrued for this award.
N
OTE
20. D
IVIDEND
R
ESTRICTIONS
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, 2016, 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, 2016, the Ohio Commission had not restricted the payment of dividends by East Ohio.
The Utah Commission may prohibit any public service company, including Questar Gas, from declaring or paying a dividend to an affiliate if
found to be detrimental to the public interest. At December 31, 2016, the Utah Commission had not restricted the payment of dividends by Questar Gas.
Certain agreements associated with the Companies credit facilities contain restrictions on the ratio of debt to total capitalization.
These limitations did not restrict the Companies ability to pay dividends or receive dividends from their subsidiaries at December 31, 2016.
See Note 17 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments
on certain junior subordinated notes and equity units, initially in the form of corporate units.
N
OTE
21. E
MPLOYEE
B
ENEFIT
P
LANS
Dominion and Dominion GasDefined 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 employees compensation. Dominions funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension programs also provide benefits to
certain retired executives under company-sponsored nonqualified employee benefit plans. The nonqualified plans are funded through contributions to grantor trusts. Dominion 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 Domin-
Combined Notes to Consolidated Financial Statements, Continued
ion 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 Ohios 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 Ohios 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.
Dominions pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments.
Dominions pension and other postretirement plan assets experienced aggregate actual returns of $534 million in 2016 and aggregate actual losses of $72
million in 2015, versus expected returns of $691 million and $648 million, respectively. Dominion Gas pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns of
$130 million in 2016 and aggregate actual losses of $13 million in 2015, versus expected returns of $157 million and $150 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during
future periods. As such, any investment-related declines in these trusts will result in future increases in the net
periodic cost recognized for such
employee benefit plans and will
be included in the determination of the amount of cash to be contributed to the employee benefit plans.
In October 2014, the Society of Actuaries published new mortality tables and mortality improvement scales. Such tables and scales are used to
develop mortality assumptions for use in determining pension and other postretirement benefit liabilities and expense. Following evaluation of the new tables, Dominion changed its assumption for mortality rates to reflect a generational improvement
scale. This change in assumption 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.
During 2016, Dominion and Dominion Gas (for employees represented by collective bargaining units) engaged their actuary to conduct an
experience study of their employees demographics over a five-year period as compared to significant assumptions that were being used to determine pension and other postretirement benefit obligations and periodic costs. These assumptions primarily
included mortality, retirement rates, termination rates, and salary increase rates. The changes in assumptions implemented as a result of the experience study resulted in increases of $290 million and $38 million in the pension and other
postretirement benefits obligations, respectively, at December 31, 2016 for Dominion and $24 million and $9 million in the pension and other postretirement benefits obligations, respectively, at December 31, 2016 for Dominion
Gas. In addition, these changes will increase net periodic benefit costs for Dominion by $42 million for 2017. The increase in net periodic benefit costs for Dominion Gas for 2017 is immaterial.
Plan Amendments and Remeasurements
In the third quarter of 2016, Dominion remeasured an other postretirement benefit plan as a result of an amendment that changed post-65
retiree medical coverage for certain current and future Local 50 retirees effective April 1, 2017. The remeasurement resulted in a decrease in Dominions accumulated postretirement benefit obligation of $37 million. The impact of the
remeasurement on net periodic benefit credit was recognized prospectively from the remeasurement date and increased the net periodic benefit credit for 2016 by $9 million. The discount rate used for the remeasurement was 3.71% and the demographic
and mortality assumptions were updated using plan-specific studies and mortality improvement scales. The expected long-term rate of return used was consistent with the measurement as of December 31, 2015.
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
Year Ended December 31,
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
(millions, except percentages)
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$
|
6,391
|
|
|
$
|
6,667
|
|
|
$
|
1,430
|
|
|
$
|
1,571
|
|
Dominion Questar Combination
|
|
|
817
|
|
|
|
|
|
|
|
85
|
|
|
|
|
|
Service cost
|
|
|
118
|
|
|
|
126
|
|
|
|
31
|
|
|
|
40
|
|
Interest cost
|
|
|
317
|
|
|
|
287
|
|
|
|
65
|
|
|
|
67
|
|
Benefits paid
|
|
|
(286
|
)
|
|
|
(246
|
)
|
|
|
(83
|
)
|
|
|
(79
|
)
|
Actuarial (gains) losses during the year
|
|
|
784
|
|
|
|
(443
|
)
|
|
|
166
|
|
|
|
(138
|
)
|
Plan amendments
(1)
|
|
|
|
|
|
|
|
|
|
|
(216
|
)
|
|
|
(31
|
)
|
Settlements and curtailments
(2)
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
$
|
8,132
|
|
|
$
|
6,391
|
|
|
$
|
1,478
|
|
|
$
|
1,430
|
|
Changes in fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
$
|
6,166
|
|
|
$
|
6,480
|
|
|
$
|
1,382
|
|
|
$
|
1,402
|
|
Dominion Questar Combination
|
|
|
704
|
|
|
|
|
|
|
|
45
|
|
|
|
|
|
Actual return (loss) on plan assets
|
|
|
426
|
|
|
|
(71
|
)
|
|
|
108
|
|
|
|
(1
|
)
|
Employer contributions
|
|
|
15
|
|
|
|
3
|
|
|
|
12
|
|
|
|
12
|
|
Benefits paid
|
|
|
(286
|
)
|
|
|
(246
|
)
|
|
|
(35
|
)
|
|
|
(31
|
)
|
Settlements
(2)
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
$
|
7,016
|
|
|
$
|
6,166
|
|
|
$
|
1,512
|
|
|
$
|
1,382
|
|
Funded status at end of year
|
|
$
|
(1,116
|
)
|
|
$
|
(225
|
)
|
|
$
|
34
|
|
|
$
|
(48
|
)
|
Amounts recognized in the Consolidated Balance Sheets at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent pension and other postretirement benefit assets
|
|
$
|
930
|
|
|
$
|
931
|
|
|
$
|
148
|
|
|
$
|
12
|
|
Other current liabilities
|
|
|
(43
|
)
|
|
|
(14
|
)
|
|
|
(5
|
)
|
|
|
(3
|
)
|
Noncurrent pension and other postretirement benefit
liabilities
|
|
|
(2,003
|
)
|
|
|
(1,142
|
)
|
|
|
(109
|
)
|
|
|
(57
|
)
|
Net amount recognized
|
|
$
|
(1,116
|
)
|
|
$
|
(225
|
)
|
|
$
|
34
|
|
|
$
|
(48
|
)
|
Significant assumptions used to determine benefit obligations as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
3.31%4.50
|
%
|
|
|
4.96%4.99
|
%
|
|
|
3.92%4.47
|
%
|
|
|
4.93%4.94
|
%
|
Weighted average rate of increase for compensation
|
|
|
4.09
|
%
|
|
|
4.22
|
%
|
|
|
3.29
|
%
|
|
|
4.22
|
%
|
Dominion Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$
|
608
|
|
|
$
|
638
|
|
|
$
|
292
|
|
|
$
|
320
|
|
Service cost
|
|
|
13
|
|
|
|
15
|
|
|
|
5
|
|
|
|
7
|
|
Interest cost
|
|
|
30
|
|
|
|
27
|
|
|
|
14
|
|
|
|
14
|
|
Benefits paid
|
|
|
(32
|
)
|
|
|
(29
|
)
|
|
|
(19
|
)
|
|
|
(18
|
)
|
Actuarial (gains) losses during the year
|
|
|
64
|
|
|
|
(43
|
)
|
|
|
28
|
|
|
|
(31
|
)
|
Benefit obligation at end of year
|
|
$
|
683
|
|
|
$
|
608
|
|
|
$
|
320
|
|
|
$
|
292
|
|
Changes in fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
$
|
1,467
|
|
|
$
|
1,510
|
|
|
$
|
283
|
|
|
$
|
288
|
|
Actual return (loss) on plan assets
|
|
|
107
|
|
|
|
(14
|
)
|
|
|
23
|
|
|
|
1
|
|
Employer contributions
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
12
|
|
Benefits paid
|
|
|
(32
|
)
|
|
|
(29
|
)
|
|
|
(19
|
)
|
|
|
(18
|
)
|
Fair value of plan assets at end of year
|
|
$
|
1,542
|
|
|
$
|
1,467
|
|
|
$
|
299
|
|
|
$
|
283
|
|
Funded status at end of year
|
|
$
|
859
|
|
|
$
|
859
|
|
|
$
|
(21
|
)
|
|
$
|
(9
|
)
|
Amounts recognized in the Consolidated Balance Sheets at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent pension and other postretirement benefit assets
|
|
$
|
859
|
|
|
$
|
859
|
|
|
$
|
|
|
|
$
|
|
|
Noncurrent pension and other postretirement benefit liabilities
(3)
|
|
|
|
|
|
|
|
|
|
|
(21
|
)
|
|
|
(9
|
)
|
Net amount recognized
|
|
$
|
859
|
|
|
$
|
859
|
|
|
$
|
(21
|
)
|
|
$
|
(9
|
)
|
Significant assumptions used to determine benefit obligations as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
4.50
|
%
|
|
|
4.99
|
%
|
|
|
4.47
|
%
|
|
|
4.93
|
%
|
Weighted average rate of increase for compensation
|
|
|
4.11
|
%
|
|
|
3.93
|
%
|
|
|
n/a
|
|
|
|
3.93
|
%
|
(1)
|
2016 amount relates primarily to a plan amendment that changed post-65 retiree medical coverage for certain current and future Local 50 retirees effective April 1, 2017. 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 for certain executives.
|
(3)
|
Reflected in other deferred credits and other liabilities in Dominion Gas Consolidated Balance Sheets.
|
Combined Notes to Consolidated Financial Statements, Continued
The ABO for all of Dominions defined benefit pension plans was $7.3 billion and $5.8
billion at December 31, 2016 and 2015, respectively. The ABO for the defined benefit pension plans covering Dominion Gas employees represented by collective bargaining units was $640 million and $578 million at December 31, 2016 and 2015,
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 2016, Dominion and Dominion Gas made
no contributions to the qualified defined benefit pension plans and no contributions are currently expected in 2017. In January 2017, Dominion made a $75 million contribution to Dominion Questars qualified pension plan to satisfy a regulatory
condition to closing of the Dominion Questar Combination. 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 Dominions subsidiaries, including Dominion Gas, fund other postretirement benefit costs
through VEBAs. Dominions remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominions contributions to VEBAs, all of which pertained to Dominion Gas employees, totaled $12
million for both 2016 and 2015, and Dominion expects to contribute approximately $12 million to the Dominion VEBAs in 2017, 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 2017.
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement
Benefits
|
|
As of December 31,
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation
|
|
$
|
7,386
|
|
|
$
|
5,728
|
|
|
$
|
470
|
|
|
$
|
359
|
|
Fair value of plan assets
|
|
|
5,340
|
|
|
|
4,571
|
|
|
|
356
|
|
|
|
299
|
|
Dominion Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation
|
|
$
|
|
|
|
$
|
|
|
|
$
|
320
|
|
|
$
|
292
|
|
Fair value of plan assets
|
|
|
|
|
|
|
|
|
|
|
299
|
|
|
|
283
|
|
The following table provides information on the ABO and fair value of plan assets for Dominions pension
plans with an ABO in excess of plan assets:
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
2016
|
|
|
2015
|
|
(millions)
|
|
|
|
|
|
|
Accumulated benefit obligation
|
|
$
|
5,987
|
|
|
$
|
5,198
|
|
Fair value of plan assets
|
|
|
4,653
|
|
|
|
4,571
|
|
The following benefit payments, which reflect expected future service, as appropriate, are expected to be
paid for Dominions and Dominion Gas (for employees represented by collective bargaining units) plans:
|
|
|
|
|
|
|
|
|
|
|
Estimated Future Benefit Payments
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement
Benefits
|
|
(millions)
|
|
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
2017
|
|
$
|
380
|
|
|
$
|
92
|
|
2018
|
|
|
361
|
|
|
|
96
|
|
2019
|
|
|
373
|
|
|
|
97
|
|
2020
|
|
|
398
|
|
|
|
99
|
|
2021
|
|
|
415
|
|
|
|
100
|
|
2022-2026
|
|
2,345
|
|
|
490
|
|
Dominion Gas
|
|
|
|
|
|
|
|
|
2017
|
|
$
|
33
|
|
|
$
|
17
|
|
2018
|
|
|
35
|
|
|
|
18
|
|
2019
|
|
|
37
|
|
|
|
19
|
|
2020
|
|
|
38
|
|
|
|
19
|
|
2021
|
|
|
40
|
|
|
|
20
|
|
2022-2026
|
|
|
211
|
|
|
|
101
|
|
Plan Assets
Dominions 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 Dominions 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 Dominions pension funds are 28% U.S. equity, 18% non-U.S. equity, 35% fixed income, 3% real estate and 16% other alternative
investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the U.S. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the U.S. including both developed and
emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real
estate includes equity real estate investment trusts and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.
Dominion 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 Dominions 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 Dominions 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 Dominions and Dominion Gas (for employees represented by
collective bargaining units) pension plan assets by asset category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
2016
|
|
|
2015
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
12
|
|
|
$
|
2
|
|
|
$
|
|
|
|
$
|
14
|
|
|
$
|
16
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
16
|
|
Common and preferred stocks:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
1,705
|
|
|
|
|
|
|
|
|
|
|
|
1,705
|
|
|
|
1,736
|
|
|
|
|
|
|
|
|
|
|
|
1,736
|
|
International
|
|
|
928
|
|
|
|
|
|
|
|
|
|
|
|
928
|
|
|
|
786
|
|
|
|
|
|
|
|
|
|
|
|
786
|
|
Insurance contracts
|
|
|
|
|
|
|
334
|
|
|
|
|
|
|
|
334
|
|
|
|
|
|
|
|
330
|
|
|
|
|
|
|
|
330
|
|
Corporate debt instruments
|
|
|
35
|
|
|
|
682
|
|
|
|
|
|
|
|
717
|
|
|
|
44
|
|
|
|
695
|
|
|
|
|
|
|
|
739
|
|
Government securities
|
|
|
13
|
|
|
|
522
|
|
|
|
|
|
|
|
535
|
|
|
|
85
|
|
|
|
390
|
|
|
|
|
|
|
|
475
|
|
Total recorded at fair value
|
|
$
|
2,693
|
|
|
$
|
1,540
|
|
|
$
|
|
|
|
$
|
4,233
|
|
|
$
|
2,667
|
|
|
$
|
1,415
|
|
|
$
|
|
|
|
$
|
4,082
|
|
Assets recorded at NAV
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common/collective trust funds
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,200
|
|
Alternative investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real estate funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
153
|
|
Private equity funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
506
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
465
|
|
Debt funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
170
|
|
Hedge funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86
|
|
Total recorded at NAV
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,765
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,074
|
|
Total
investments
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,156
|
|
Dominion Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3
|
|
|
$
|
4
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4
|
|
Common and preferred stocks:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
375
|
|
|
|
|
|
|
|
|
|
|
|
375
|
|
|
|
413
|
|
|
|
|
|
|
|
|
|
|
|
413
|
|
International
|
|
|
203
|
|
|
|
|
|
|
|
|
|
|
|
203
|
|
|
|
187
|
|
|
|
|
|
|
|
|
|
|
|
187
|
|
Insurance contracts
|
|
|
|
|
|
|
73
|
|
|
|
|
|
|
|
73
|
|
|
|
|
|
|
|
78
|
|
|
|
|
|
|
|
78
|
|
Corporate debt instruments
|
|
|
8
|
|
|
|
150
|
|
|
|
|
|
|
|
158
|
|
|
|
10
|
|
|
|
165
|
|
|
|
|
|
|
|
175
|
|
Government securities
|
|
|
3
|
|
|
|
115
|
|
|
|
|
|
|
|
118
|
|
|
|
20
|
|
|
|
93
|
|
|
|
|
|
|
|
113
|
|
Total recorded at fair value
|
|
$
|
592
|
|
|
$
|
338
|
|
|
$
|
|
|
|
$
|
930
|
|
|
$
|
634
|
|
|
$
|
336
|
|
|
$
|
|
|
|
$
|
970
|
|
Assets recorded at NAV
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common/collective trust funds
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
286
|
|
Alternative investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real estate funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
Private equity funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
111
|
|
Debt funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
|
|
Hedge funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
|
|
Total recorded at NAV
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
494
|
|
Total
investments
(5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,464
|
|
(1)
|
These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient are not required to be categorized in the fair value hierarchy.
|
(2)
|
Also included in the common collective trust funds is the Northern Trust Collective Short-Term Investment Fund, totaling $167 million and $125 million at December 31, 2016 and 2015, respectively, which is comprised
of money market instruments with short-term maturities used for temporary investment. 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.
|
(3)
|
Includes net assets related to pending sales of securities of $46 million, net accrued income of $19 million, and excludes net assets related to pending purchases of securities of $47 million at December 31, 2016.
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.
|
(4)
|
Also included in the common collective trust funds is the Northern Trust Collective Short-Term Investment Fund, totaling $37 million and $30 million at December 31, 2016 and 2015, respectively, which is comprised of
money market instruments with short-term maturities used for temporary investment. 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.
|
(5)
|
Includes net assets related to pending sales of securities of $10 million, net accrued income of $4 million, and excludes net assets related to pending purchases of securities of $10 million at December 31, 2016.
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.
|
The fair values of Dominions and Dominion Gas (for employees represented by
collective bargaining units) other postretirement plan assets by asset category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
2016
|
|
|
2015
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
|
|
|
$
|
2
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
|
|
|
$
|
2
|
|
Common and preferred stocks:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
571
|
|
|
|
|
|
|
|
|
|
|
|
571
|
|
|
|
531
|
|
|
|
|
|
|
|
|
|
|
|
531
|
|
International
|
|
|
143
|
|
|
|
|
|
|
|
|
|
|
|
143
|
|
|
|
134
|
|
|
|
|
|
|
|
|
|
|
|
134
|
|
Insurance contracts
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
18
|
|
Corporate debt instruments
|
|
|
2
|
|
|
|
40
|
|
|
|
|
|
|
|
42
|
|
|
|
3
|
|
|
|
38
|
|
|
|
|
|
|
|
41
|
|
Government securities
|
|
|
1
|
|
|
|
30
|
|
|
|
|
|
|
|
31
|
|
|
|
4
|
|
|
|
22
|
|
|
|
|
|
|
|
26
|
|
Total recorded at fair value
|
|
$
|
718
|
|
|
$
|
90
|
|
|
$
|
|
|
|
$
|
808
|
|
|
$
|
673
|
|
|
$
|
79
|
|
|
$
|
|
|
|
$
|
752
|
|
Assets recorded at NAV
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common/collective trust funds
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
543
|
|
Alternative investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real estate funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Private equity funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
|
|
Debt funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Hedge funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
Total recorded at NAV
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
630
|
|
Total
investments
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,382
|
|
Dominion Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common and preferred stocks:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
121
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
121
|
|
|
$
|
113
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
113
|
|
International
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
24
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
24
|
|
Total recorded at fair value
|
|
$
|
145
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
145
|
|
|
$
|
137
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
137
|
|
Assets recorded at NAV
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common/collective trust funds
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
140
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
132
|
|
Alternative investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real estate funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Private equity funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
Debt funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Total recorded at NAV
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
146
|
|
Total investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
283
|
|
(1)
|
These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient are not required to be categorized in the fair value hierarchy.
|
(2)
|
Also included in the common collective trust funds is the Northern Trust Collective Short-Term Investment Fund, totaling $16 million and $9 million at December 31, 2016 and 2015, respectively, which is comprised of
money market instruments with short-term maturities used for temporary investment. 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.
|
(3)
|
Includes net assets related to pending sales of securities of $5 million, net accrued income of $2 million, and excludes net assets related to pending purchases of securities of $5 million at December 31, 2016.
|
(4)
|
Also included in the common collective trust funds is the Northern Trust Collective Short-Term Investment Fund, totaling $2 million and $3 million at December 31, 2016 and 2015, respectively, which is comprised of
money market instruments with short-term maturities used for temporary investment. 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.
|
Combined Notes to Consolidated Financial Statements, Continued
The Plans investments are determined based on the fair values of the investments and the underlying
investments, which have been determined as follows:
|
|
|
Cash and Cash Equivalents
Investments are held primarily in short-term notes and treasury bills, which are valued at cost plus accrued interest.
|
|
|
|
Common and Preferred Stocks
Investments are valued at the closing price reported on the active market on which the individual securities are traded.
|
|
|
|
Insurance Contracts
Investments in Group Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the
managers and include investments in U.S. government securities, corporate debt instruments, state and municipal debt securities.
|
|
|
|
Corporate Debt Instruments
Investments are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable
securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar instruments, the instrument is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of
similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks or a broker quote, if available.
|
|
|
|
Government Securities
Investments are valued using pricing models maximizing the use of observable inputs for similar securities.
|
|
|
|
Common/Collective Trust Funds
Common/collective trust funds invest in debt and equity securities and other instruments with characteristics similar to those of the funds benchmarks. The primary
objectives of the funds are to seek investment returns that approximate the overall performance of their benchmark indexes. These benchmarks are major equity indices, fixed income indices, and money market indices that focus on growth, income, and
liquidity strategies, as applicable. Investments in common/collective trust funds are stated at the NAV as determined by the issuer of the common/collective trust funds and is based on the fair value of the underlying investments held by the fund
less its liabilities. The NAV is used as a practical expedient to estimate fair value. The common/collective trust funds do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held.
The majority of the common/collective trust funds have limited withdrawal or redemption rights during the term of the investment.
|
|
|
|
Alternative Investments
Investments in real estate funds, private equity funds, debt funds and hedge funds are stated at fair value based on the NAV of the Plans proportionate share of the partnership,
joint venture or other alternative investments fair value as determined by reference to audited financial statements or NAV statements provided by the investment manager. The NAV is used as a practical expedient to estimate fair value.
|
Net Periodic Benefit (Credit) Cost
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 Dominions and Dominion Gas (for employees represented by collective bargaining units) plans
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
Year Ended December 31,
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
(millions, except percentages)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
118
|
|
|
$
|
126
|
|
|
$
|
114
|
|
|
$
|
31
|
|
|
$
|
40
|
|
|
$
|
32
|
|
Interest cost
|
|
|
317
|
|
|
|
287
|
|
|
|
290
|
|
|
|
65
|
|
|
|
67
|
|
|
|
67
|
|
Expected return on plan assets
|
|
|
(573
|
)
|
|
|
(531
|
)
|
|
|
(499
|
)
|
|
|
(118
|
)
|
|
|
(117
|
)
|
|
|
(111
|
)
|
Amortization of prior service (credit) cost
|
|
|
1
|
|
|
|
2
|
|
|
|
3
|
|
|
|
(35
|
)
|
|
|
(27
|
)
|
|
|
(28
|
)
|
Amortization of net actuarial loss
|
|
|
111
|
|
|
|
160
|
|
|
|
111
|
|
|
|
8
|
|
|
|
6
|
|
|
|
2
|
|
Settlements and curtailments
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit (credit) cost
|
|
$
|
(25
|
)
|
|
$
|
44
|
|
|
$
|
20
|
|
|
$
|
(49
|
)
|
|
$
|
(31
|
)
|
|
$
|
(38
|
)
|
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory
assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current year net actuarial (gain) loss
|
|
$
|
931
|
|
|
$
|
159
|
|
|
$
|
784
|
|
|
$
|
178
|
|
|
$
|
(18
|
)
|
|
$
|
183
|
|
Prior service (credit) cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(216
|
)
|
|
|
(31
|
)
|
|
|
9
|
|
Settlements and curtailments
|
|
|
(1
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Less amounts included in net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial loss
|
|
|
(111
|
)
|
|
|
(160
|
)
|
|
|
(111
|
)
|
|
|
(8
|
)
|
|
|
(6
|
)
|
|
|
(2
|
)
|
Amortization of prior service credit (cost)
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
(3
|
)
|
|
|
35
|
|
|
|
27
|
|
|
|
28
|
|
Total recognized in other comprehensive income and regulatory assets
and liabilities
|
|
$
|
818
|
|
|
$
|
(3
|
)
|
|
$
|
669
|
|
|
$
|
(11
|
)
|
|
$
|
(28
|
)
|
|
$
|
218
|
|
Significant assumptions used to determine periodic cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
2.87%-4.99
|
%
|
|
|
4.40
|
%
|
|
|
5.20%-5.30
|
%
|
|
|
3.56%-4.94
|
%
|
|
|
4.40
|
%
|
|
|
4.20%-5.10
|
%
|
Expected long-term rate of return on plan assets
|
|
|
8.75
|
%
|
|
|
8.75
|
%
|
|
|
8.75
|
%
|
|
|
8.50
|
%
|
|
|
8.50
|
%
|
|
|
8.50
|
%
|
Weighted average rate of increase for compensation
|
|
|
4.22
|
%
|
|
|
4.22
|
%
|
|
|
4.21
|
%
|
|
|
4.22
|
%
|
|
|
4.22
|
%
|
|
|
4.22
|
%
|
Healthcare cost trend rate
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.00
|
%
|
|
|
7.00
|
%
|
|
|
7.00
|
%
|
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
Year that the rate reaches the ultimate trend rate
(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
2019
|
|
|
|
2018
|
|
Dominion Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
13
|
|
|
$
|
15
|
|
|
$
|
12
|
|
|
$
|
5
|
|
|
$
|
7
|
|
|
$
|
6
|
|
Interest cost
|
|
|
30
|
|
|
|
27
|
|
|
|
28
|
|
|
|
14
|
|
|
|
14
|
|
|
|
13
|
|
Expected return on plan assets
|
|
|
(134
|
)
|
|
|
(126
|
)
|
|
|
(115
|
)
|
|
|
(23
|
)
|
|
|
(24
|
)
|
|
|
(23
|
)
|
Amortization of prior service (credit) cost
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
Amortization of net actuarial loss
|
|
|
13
|
|
|
|
20
|
|
|
|
19
|
|
|
|
1
|
|
|
|
2
|
|
|
|
|
|
Net periodic benefit (credit) cost
|
|
$
|
(78
|
)
|
|
$
|
(63
|
)
|
|
$
|
(55
|
)
|
|
$
|
(2
|
)
|
|
$
|
(2
|
)
|
|
$
|
(5
|
)
|
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory
assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current year net actuarial (gain) loss
|
|
$
|
91
|
|
|
$
|
97
|
|
|
$
|
43
|
|
|
$
|
28
|
|
|
$
|
(9
|
)
|
|
$
|
40
|
|
Prior service cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
Less amounts included in net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial loss
|
|
|
(13
|
)
|
|
|
(20
|
)
|
|
|
(19
|
)
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
|
|
Amortization of prior service credit (cost)
|
|
|
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
1
|
|
Total recognized in other comprehensive income and regulatory assets
and liabilities
|
|
$
|
78
|
|
|
$
|
76
|
|
|
$
|
23
|
|
|
$
|
26
|
|
|
$
|
(10
|
)
|
|
$
|
51
|
|
Significant assumptions used to determine periodic cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
4.99
|
%
|
|
|
4.40
|
%
|
|
|
5.20
|
%
|
|
|
4.93
|
%
|
|
|
4.40
|
%
|
|
|
4.20%-5.00
|
%
|
Expected long-term rate of return on plan assets
|
|
|
8.75
|
%
|
|
|
8.75
|
%
|
|
|
8.75
|
%
|
|
|
8.50
|
%
|
|
|
8.50
|
%
|
|
|
8.50
|
%
|
Weighted average rate of increase for compensation
|
|
|
3.93
|
%
|
|
|
3.93
|
%
|
|
|
3.93
|
%
|
|
|
3.93
|
%
|
|
|
3.93
|
%
|
|
|
3.93
|
%
|
Healthcare cost trend rate
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.00
|
%
|
|
|
7.00
|
%
|
|
|
7.00
|
%
|
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
Year that the rate reaches the ultimate trend rate
(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
2019
|
|
|
|
2018
|
|
(1)
|
Assumptions used to determine net periodic cost for the following year.
|
(2)
|
The Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the ultimate trend rate much more quickly than previous models.
|
Combined Notes to Consolidated Financial Statements, Continued
The components of AOCI and regulatory assets and liabilities for Dominions 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other
Postretirement
Benefits
|
|
At December 31,
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss
|
|
$
|
3,200
|
|
|
$
|
2,381
|
|
|
$
|
283
|
|
|
$
|
114
|
|
Prior service (credit) cost
|
|
|
4
|
|
|
|
5
|
|
|
|
(419
|
)
|
|
|
(237
|
)
|
Total
(1)
|
|
$
|
3,204
|
|
|
$
|
2,386
|
|
|
$
|
(136
|
)
|
|
$
|
(123
|
)
|
Dominion Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss
|
|
$
|
458
|
|
|
$
|
380
|
|
|
$
|
60
|
|
|
$
|
33
|
|
Prior service (credit) cost
|
|
|
|
|
|
|
1
|
|
|
|
7
|
|
|
|
7
|
|
Total
(2)
|
|
$
|
458
|
|
|
$
|
381
|
|
|
$
|
67
|
|
|
$
|
40
|
|
(1)
|
As of December 31, 2016, of the $3.2 billion and $(136) million related to pension benefits and other postretirement benefits, $1.9 billion and $(103) million, respectively, are included in AOCI, with the remainder
included in regulatory assets and liabilities. 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.
|
(2)
|
As of December 31, 2016, of the $458 million related to pension benefits, $167 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $67 million related to other
postretirement benefits is included entirely in regulatory assets and liabilities. 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.
|
The following table provides the components of AOCI and regulatory assets and liabilities for Dominions and Dominion Gas (for
employees represented by collective bargaining units) plans as of December 31, 2016 that are expected to be amortized as components of net periodic benefit (credit) cost in 2017:
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement
Benefits
|
|
(millions)
|
|
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
Net actuarial loss
|
|
$
|
161
|
|
|
$
|
13
|
|
Prior service (credit) cost
|
|
|
1
|
|
|
|
(47
|
)
|
Dominion Gas
|
|
|
|
|
|
|
|
|
Net actuarial loss
|
|
$
|
16
|
|
|
$
|
2
|
|
Prior service (credit) cost
|
|
|
|
|
|
|
1
|
|
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 Dominions 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:
|
|
|
Expected inflation and risk-free interest rate assumptions;
|
|
|
|
Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;
|
|
|
|
Expected future risk premiums, asset volatilities and correlations;
|
|
|
|
Forecasts of an independent investment advisor;
|
|
|
|
Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; and
|
|
|
|
Investment allocation of plan assets.
|
Dominion 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.
Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominions actuary conducts an
experience study periodically as part of the process to select its best estimate of mortality. Dominion considers both standard mortality tables and improvement factors as well as the plans actual experience when selecting a best estimate.
During 2016, Dominion conducted a new experience study as scheduled and, as a result, updated its mortality assumptions 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 Dominions 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 Dominions and Dominion Gas (for employees represented by collective bargaining units)
other postretirement benefit plans:
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefits
|
|
|
|
One percentage
point increase
|
|
|
One percentage
point decrease
|
|
(millions)
|
|
|
|
|
|
|
Dominion
|
|
|
|
|
|
|
|
|
Effect on net periodic cost for 2017
|
|
$
|
23
|
|
|
$
|
(18
|
)
|
Effect on other postretirement benefit obligation at December 31,
2016
|
|
|
152
|
|
|
|
(127
|
)
|
Dominion Gas
|
|
|
|
|
|
|
|
|
Effect on net periodic cost for 2017
|
|
$
|
5
|
|
|
$
|
(4
|
)
|
Effect on other postretirement benefit obligation at December 31,
2016
|
|
|
41
|
|
|
|
(34
|
)
|
Dominion Gas (Employees Not Represented by Collective Bargaining Units) and Virginia PowerParticipation 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 Dominions funding policy, which is to contribute annually an amount that is in accordance with ERISA. During 2016, Virginia Power and Dominion Gas made no
contributions to the Dominion Pension Plan, and no contributions to this plan are currently
expected in 2017. Virginia Powers net periodic pension cost related to this plan was $79 million, $97 million and $75 million in 2016, 2015 and 2014, respectively. Dominion Gas net
periodic pension credit related to this plan was $(45) million, $(38) million and $(37) million in 2016, 2015 and 2014, 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 Powers net periodic benefit (credit) cost related to this plan
was $(29) million, $(16) million and $(18) million in 2016, 2015 and 2014, respectively. Dominion Gas net periodic benefit (credit) cost related to this plan was $(4) million, $(5) million and $(5) million for 2016, 2015 and 2014,
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 2016 and 2015, Virginia Power
made no contributions to the VEBA and does not expect to contribute to the VEBA in 2017. Dominion Gas made no contributions to the VEBAs for employees not represented by collective bargaining units during 2016 and 2015 and does not expect to
contribute in 2017.
Defined Contribution Plans
Dominion also
sponsors defined contribution employee savings plans that cover substantially all employees. During 2016, 2015 and 2014, Dominion recognized $44 million, $43 million and $41 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 2016, 2015 and 2014, Dominion Gas recognized $7 million as employer matching contributions to these plans.
Virginia Power also participates in these employee savings plans. During 2016, 2015 and 2014, Virginia Power
recognized $19 million, $18 million and $17 million, respectively, as employer matching contributions to these plans.
Organizational Design Initiative
In the first quarter of 2016, the
Companies announced an organizational design initiative that reduced their total workforces during 2016. The goal of the organizational design initiative was to streamline leadership structure and push decision making lower while also improving
efficiency. For the year ended December 31, 2016, Dominion recorded a $65 million ($40 million after-tax) charge, including $33 million ($20 million after-tax) at Virginia Power and $8 million ($5 million after-tax) at Dominion Gas, primarily
reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other costs related to the organizational design initiative. The terms of the severance under the organizational design
initiative were consistent with the Companies existing severance plans.
N
OTE
22.
C
OMMITMENTS
A
ND
C
ONTINGENCIES
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.
Combined Notes to Consolidated Financial Statements, Continued
A
IR
CAA
The CAA, as amended, is a comprehensive program
utilizing a broad range of regulatory tools to protect and preserve the nations 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 CAAs permitting and other requirements.
MATS
In December 2011, the EPA issued MATS for
coal and
oil-fired
electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for
acid gases. The rule includes a limited use provision for
oil-fired
units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work
practice standards. Compliance was required by April 16, 2015, with certain limited exceptions. However, in June 2014, the VDEQ granted a
one-year
MATS compliance extension for two coal-fired units at
Yorktown power station 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. Therefore, in October 2015 Virginia Power submitted a request to the EPA for an additional one year compliance extension under an EPA
Administrative Order. The order was signed by the EPA in April 2016 allowing the Yorktown units to operate for up to one additional year, as required to maintain reliable power availability while transmission upgrades are being made.
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 U.S. Court of Appeals for the D.C. Circuit. However, the Supreme Court did not vacate or stay the effective date
and implementation of the MATS rule. In November 2015, in response to the Supreme Court decision, the EPA proposed a supplemental finding that consideration of cost does not alter the agencys 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. In December 2015, the U.S. Court of Appeals for the D.C. Circuit 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 a final finding regarding its consideration of cost. In April 2016, the EPA issued a final supplemental
finding that consideration of costs does not alter its conclusion regarding appropriateness and necessity for the regulation. These actions do not change Virginia Powers plans to close coal units at Yorktown power station by April 2017 or the
need to complete necessary electricity transmission upgrades which are expected to be in service approximately 20 months following receipt of all required permits and approvals for construction. 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.
CSAPR
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 SO
2
and NO
X
emissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO
2
and NO
X
emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NO
X
emissions caps, NO
X
emissions caps during the ozone season (May 1 through September 30) and annual SO
2
emission caps with differing requirements for two
groups of affected states. 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 EPAs motion to lift the stay of
CSAPR be granted. Further, the Court granted the EPAs 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) applied in 2015 and 2016, and Phase 2
emissions budgets will apply in 2017 and beyond. CSAPR replaced CAIR beginning in January 2015. In September 2016, the EPA issued a revision to CSAPR that reduces the ozone season NO
X
emission
budgets in 22 states beginning in 2017. The cost to comply with CSAPR, including the recent revision to the CSAPR ozone season NO
X
program, is not expected to be material to Dominions or
Virginia Powers Consolidated Financial Statements.
Ozone Standards
In October 2015, the EPA issued a final rule tightening the ozone standard from
75-ppb
to
70-ppb.
To comply with this standard, in April 2016 Virginia Power submitted the NO
X
Reasonable Available Control Technology analysis for Unit 5 at Possum
Point power station. In December 2016, the VDEQ determined that NO
X
controls are required on Unit 5. Installation and operation of these
NO
X
controls including an associated water treatment system will be required by
mid-2019
with an expected cost in the range of $25 to $35 million.
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 materially affect the Companies results of operations and cash flows.
NO
x
and VOC Emissions
In April 2016, the Pennsylvania Department of Environmental Protection issued
final regulations, with an effective date of January 2017, to reduce NO
X
and VOC emissions from combustion sources. To comply with the regulations, Dominion Gas is installing emission
control systems on existing engines at several compressor stations in Pennsylvania. The compliance costs associated with engineering and installation of controls and compliance demonstration with the regulation are expected to be approximately
$25 million.
NSPS
In
August 2012, the EPA issued the first NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish
equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In June 2016, the EPA issued a final NSPS regulation,
for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after
September 2015 will be required to comply with this regulation. Dominion and Dominion Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.
C
LIMATE
C
HANGE
R
EGULATION
Carbon Regulations
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 U.S. Court of Appeals for the D.C. Circuits June 2012 decision upholding the EPAs regulation of GHG emissions from
stationary sources under the CAAs 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 EPAs ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. In August 2016, the EPA issued a draft rule proposing to reaffirm that a sources
obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant
emissions rate at 75,000 tons per year of CO
2
equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on
this rulemaking, the Companies cannot predict the impact to their financial statements.
In July 2011, the EPA signed a final rule
deferring the need for PSD and Title V permitting for CO
2
emissions for biomass projects. This rule temporarily deferred for a period of up to three years the consideration of CO
2
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 CO
2
deferral period. It is unclear how the courts decision or the EPAs 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 Dominions and Virginia Powers financial statements.
Methane Emissions
In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR Program, the Natural Gas STAR Methane Challenge Program. The program
covers the entire natural gas sector from production to distribution, with more emphasis on transparency and increased reporting for both annual emissions and reductions achieved through implementation measures. In March 2016, East Ohio, Hope,
DTI and Questar Gas (prior to the Dominion Questar Combination) joined the EPA as founding partners in the new Methane Challenge program and submitted implementation plans in September 2016. DCG joined the EPAs voluntary Natural Gas STAR
Program in July 2016 and submitted an implementation plan in September 2016. Dominion and Dominion Gas do not expect the costs related to these programs to have a material impact on their results of operations, financial condition and/or cash flows.
W
ATER
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 Dominions and Virginia Powers 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
Combined Notes to Consolidated Financial Statements, Continued
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. While the impacts of this rule could be material to Dominions and Virginia Powers 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.
S
OLID
AND
H
AZARDOUS
W
ASTE
The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened
releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation
to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These
potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an
EPA-directed
cleanup, voluntarily settle with the U.S. government concerning their liability for
cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.
From time to time, Dominion,
Virginia Power, or Dominion Gas may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or
conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution
actions against each other and seek reimbursement from their insurance companies. As a result, Dominion, Virginia Power, or Dominion Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or
regulations regarding the remediation of waste. The Companies do not believe these matters 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, pursuant to CERCLA, ordering specific remedial action of
certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. In September 2016, the U.S., on behalf of the EPA, lodged a proposed Remedial Design/Remedial Action Consent Decree with the U.S. District Court for the Eastern
District of North Carolina, settling claims related to the site between the EPA and a number of parties, including Virginia Power. In November 2016, the court approved and entered the final Consent Decree and closed the case. The Consent Decree
identifies Virginia Power as a
non-performing
cash-out
party to the settlement and resolves Virginia Powers alleged liability under CERCLA with respect to the
site, including liability pursuant to the UAO. Virginia Powers cash settlement for this case was less than $1 million.
Dominion has determined that it is associated with 19 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of
which pertain to Dominion Gas. Studies
con-
ducted 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.
A
PPALACHIAN
G
ATEWAY
Pipeline Contractor Litigation
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 contractors motion in August 2013. In November 2013, the court granted the contractors 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. In March 2016, the
Pennsylvania court granted the motion to dismiss and transferred the case to the U.S. District Court for the Eastern District of Virginia. In April 2016, the Virginia court issued an order staying the proceedings and ordering mediation. A mediation
occurred in May 2016 but was unsuccessful. In July 2016, DTI filed a motion to dismiss. 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.
Gas Producers Litigation
In connection with the Appalachian Gateway project, Dominion Field Services, Inc. entered into contracts for firm purchase rights with a group of small gas
producers. In June 2016, the gas pro-
ducers filed a complaint in the Circuit Court of Marshall County, West Virginia against Dominion, DTI and Dominion Field Services, Inc., among other defendants, claiming that the contracts are
unenforceable and seeking compensatory and punitive damages. During the third quarter of 2016, Dominion, DTI and Dominion Field Services, Inc. were served with the complaint. Also in the third quarter of 2016, Dominion and DTI, with the consent of
the other defendants, removed the case to the U.S. District Court for the Northern District of West Virginia. In October 2016, the defendants filed a motion to dismiss and the plaintiffs filed a motion to remand. In February 2017, the U.S. District
Court entered an order remanding the matter to the Circuit Court of Marshall County, West Virginia. This case is pending. Dominion and Dominion Gas cannot currently estimate financial statement impacts, but there could be a material impact to their
financial condition and/or cash flows.
A
SH
P
OND
AND
L
ANDFILL
C
LOSURE
C
OSTS
In September 2014, Virginia Power received a notice from the Southern Environmental Law Center on behalf of the Potomac
Riverkeeper and Sierra Club alleging CWA violations at Possum Point power station. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point power stations historical and active ash storage facilities. A
similar notice from the Southern Environmental Law Center on behalf of the Sierra Club was subsequently received related to Chesapeake power station. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum
Point power station, Chesapeake and Bremo power stations as settlement of the potential litigation. While the issue is open to potential further negotiations, the Southern Environmental Law Center 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 power station. Virginia Power filed a motion to dismiss in April 2015, which was denied in November 2015. A trial was held in June 2016. This case is
pending. 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 for the year ended December 31, 2014.
In April 2015, the EPAs 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. The CCR rule requires that groundwater impacts associated with ash ponds be remediated. It is too early in the
implementation phase of the rule to determine the scope of any potential groundwater remediation, but the costs, if required, could be material.
In April 2016, the EPA announced a partial settlement with certain environmental and industry organizations that had challenged the final CCR
rule in the U.S. Court of Appeals for the
D.C. Circuit. As part of the settlement, certain exemptions included in the final rule for inactive ponds that closed by April 2018 will be removed, resulting in inactive ponds ultimately
being subject to the same requirements as existing ponds. In June 2016, the court issued an order approving the settlement, which requires the EPA to modify provisions in the final CCR rule concerning inactive ponds. In August 2016, the EPA
issued a final rule, effective October 2016, extending certain compliance deadlines in the final CCR rule for inactive ponds.
In February
and March 2016, respectively, two parties filed administrative appeals in the Circuit Court for the City of Richmond challenging certain provisions, relating to ash pond dewatering activities, of Possum Point power stations wastewater
discharge permit issued by the VDEQ in January 2016. One of those parties withdrew its appeal in June 2016. In November 2016, the court dismissed the remaining appeal.
In 2015, Virginia Power recorded a $386 million ARO related to future ash pond and landfill closure costs, which resulted in a $99 million
incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $166 million increase in property, plant, and equipment associated with asset retirement costs, and a $121 million reduction in other
noncurrent liabilities related to reversal of the contingent liability described above since the ARO obligation created by the final CCR rule represents similar activities. In 2016, Virginia Power recorded an increase to this ARO of $238 million,
which resulted in a $197 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $17 million increase in property, plant, and equipment and a $24 million increase in regulatory
assets. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the obligation at December 31, 2016.
In December 2016, the U.S. Congress passed and the President signed legislation that creates a framework for EPA- approved state CCR permit
programs. Under this legislation, an approved state CCR permit program functions in lieu of the self-implementing Federal CCR rule. The legislation allows states more flexibility in developing permit programs to implement the environmental criteria
in the CCR rule. It is unknown how long it will take for the EPA to develop the framework for state program approvals. The EPA has enforcement authority until these new CCR rules are in place and state programs are approved. The EPA and states with
approved programs both will have authority to enforce CCR requirements under their respective rules and programs. Dominion cannot forecast potential incremental impacts or costs related to existing coal ash sites until rules implementing the 2016
CCR legislation are in place.
C
OVE
P
OINT
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.
Combined Notes to Consolidated Financial Statements, Continued
Two parties have separately filed petitions for review of the FERC order in the U.S. Court of
Appeals for the D.C. Circuit, which petitions were consolidated. Separately, one party requested a stay of the FERC order until the judicial proceedings are complete, which the court denied in June 2015. In July 2016, the court denied one
partys petition for review of the FERC order authorizing the Liquefaction Project. The court also issued a decision remanding the other partys petition for review of the FERC order to FERC for further explanation of FERCs decision
that a previous transaction with an existing import shipper was not unduly discriminatory. Cove Point believes that on remand FERC will be able to justify its decision.
In September 2013, the DOE granted Non-FTA Authorization approval for the export of up to 0.77 bcfe/day of natural gas to countries that do
not have an FTA for trade in natural gas. In June 2016, a party filed a petition for review of this approval in the U.S. Court of Appeals for the D.C. Circuit. This case is pending.
FERC
The FERC staff in the Office of Enforcement,
Division of Investigations, is conducting a
non-public
investigation of Virginia Powers offers of combustion turbines generators into the PJM
day-ahead
markets
from April 2010 through September 2014. The FERC staff notified Virginia Power of its preliminary findings relating to Virginia Powers alleged violation of FERCs rules in connection with these activities. Virginia Power has provided its
response to the FERC staffs preliminary findings letter explaining why Virginia Powers conduct was lawful and refuting any allegation of wrongdoing. Virginia Power is cooperating fully with the investigation; however, it cannot currently
predict whether or to what extent it may incur a material liability.
G
REENSVILLE
C
OUNTY
Virginia Power is constructing Greensville County and related transmission interconnection facilities. In July 2016, the Sierra Club filed an administrative
appeal in the Circuit Court for the City of Richmond challenging certain provisions in Greensville Countys PSD air permit issued by VDEQ in June 2016. Virginia Power is currently unable to make an estimate of the potential impacts to its
consolidated financial statements related to this matter.
Nuclear Matters
In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan.
These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as the Institute of Nuclear Power Operations. Like other U.S. nuclear operators, Dominion 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 staffs 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 emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevaluation of the seismic and external flooding hazards
is expected to continue through 2018. Dominion and Virginia Power do not currently expect that compliance with the NRCs 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 do not expect material financial impacts related to compliance with Tier 2 and Tier 3
recommendations.
Nuclear Operations
N
UCLEAR
D
ECOMMISSIONING
M
INIMUM
F
INANCIAL
A
SSURANCE
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 2016 calculation for the NRC minimum financial assurance amount, aggregated for Dominions and Virginia Powers 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 2016 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2016 U.S. Bureau of Labor Statistics
indices. Dominion believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also
believes that the decommissioning funds and
their expected earnings for the Surry and North Anna units will be sufficient to cover decommissioning costs, particularly when combined with future ratepayer collections and contributions to
these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion and
Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by
the NRC. See Note 9 for additional information on nuclear decommissioning trust investments.
N
UCLEAR
I
NSURANCE
The Price-Anderson Amendments Act of 1988 provides the public up to $13.36 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 Dominions and Virginia Powers
nuclear units is as follows:
|
|
|
|
|
|
|
Coverage
|
|
(billions)
|
|
|
|
Dominion
|
|
|
|
|
Millstone
|
|
$
|
1.70
|
|
Kewaunee
|
|
|
1.06
|
|
Virginia Power
(1)
|
|
|
|
|
Surry
|
|
$
|
1.70
|
|
North Anna
|
|
|
1.70
|
|
(1)
|
Surry and North Anna share a blanket property limit of $200 million.
|
Dominions and Virginia Powers 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. Dominions and Virginia Powers maximum
retrospective premium assessment for the current policy period is $87 million and $49 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. Dominions and Virginia Powers 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 Millstones 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.
S
PENT
N
UCLEAR
F
UEL
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 Dominions and Virginia Powers contracts with the DOE. Dominion and Virginia Power have previously
received damages award payments and settlement payments related to these contracts.
By mutual agreement of the parties, the settlement
agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone plants have been extended to provide for periodic payments for damages incurred through
December 31, 2016, and additional extensions are contemplated by the settlement agreements. Possible settlement of the Kewaunee claims for damages incurred after December 31, 2013 is being evaluated.
In 2016, Virginia Power and Dominion received payments of $30 million for resolution of claims incurred at North Anna and Surry for the
period of January 1, 2014 through December 31, 2014, and $22 million for resolution of claims incurred at Millstone for the period of July 1, 2014 through June 30, 2015.
In 2015, Virginia Power and Dominion 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. Dominions receivables
Combined Notes to Consolidated Financial Statements, Continued
for spent nuclear fuel-related costs totaled $56 million and $87 million at December 31, 2016 and 2015, respectively. Virginia Powers receivables for spent nuclear
fuel-related costs totaled $37 million and $54 million at December 31, 2016 and 2015, 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, 2016, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
|
Thereafter
|
|
|
Total
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased electric capacity
(1)
|
|
$
|
149
|
|
|
$
|
93
|
|
|
$
|
60
|
|
|
$
|
52
|
|
|
$
|
46
|
|
|
$
|
|
|
|
$
|
400
|
|
(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, 2016, the present value of Virginia Powers total commitment for capacity payments is
$347 million. Capacity payments totaled $248 million, $305 million, and $330 million, and energy payments totaled $126 million, $198 million, and $304 million for the years ended 2016, 2015 and 2014, respectively.
|
Lease Commitments
The Companies lease real
estate, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have
initial or remaining lease terms in excess of one year as of December 31, 2016 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
|
Thereafter
|
|
|
Total
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion
(1)
|
|
$
|
72
|
|
|
$
|
69
|
|
|
$
|
58
|
|
|
$
|
39
|
|
|
$
|
32
|
|
|
$
|
238
|
|
|
$
|
508
|
|
Virginia Power
|
|
$
|
33
|
|
|
$
|
30
|
|
|
$
|
24
|
|
|
$
|
20
|
|
|
$
|
16
|
|
|
$
|
32
|
|
|
$
|
155
|
|
Dominion Gas
|
|
$
|
27
|
|
|
$
|
26
|
|
|
$
|
21
|
|
|
$
|
8
|
|
|
$
|
5
|
|
|
$
|
18
|
|
|
$
|
105
|
|
(1)
|
Amounts include a lease agreement for the Dominion Questar corporate office, which is accounted for as a capital lease. At December 31, 2016, the Consolidated Balance Sheets include $30 million in property,
plant and equipment and $35 million in other deferred credits and other liabilities. The Consolidated Statements of Income include less than $1 million recorded in depreciation, depletion and amortization for the year ended December 31, 2016.
|
Rental expense for Dominion totaled $104 million, $99 million, and $92 million
for 2016, 2015 and 2014, respectively. Rental expense for Virginia Power totaled $52 million, $51 million, and $43 million for 2016, 2015, and 2014, respectively. Rental expense for Dominion Gas totaled $37 million,
$37 million, and $35 million for 2016, 2015 and 2014, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.
In July 2016, Dominion signed an agreement with a lessor to construct and lease a new corporate office property in Richmond, Virginia. The
lessor is providing equity and has obtained financing commitments from debt investors, totaling $365 million, to fund the estimated project costs. The project is expected to be completed by mid-2019. Dominion has been appointed to act as the
construction agent for the lessor, during which time Dominion will request cash draws from the lessor and debt investors to fund all project costs, which totaled $46 million as of December 31, 2016. If the project is terminated under
certain events of default, Dominion could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion could be required to pay up to 100% of the then funded amount.
The five-year lease term will commence once construction is substantially complete and the facility is able to be occupied. At the end of the
initial lease term, Dominion can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or,
(iii) subject to certain terms and conditions, sell the property to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are
insufficient to repay the investors for the project costs, Dominion may be required to make a payment to the lessor, up to 87% of project costs, for the difference between the project costs and sale proceeds.
Guarantees, Surety Bonds and Letters of Credit
At
December 31, 2016, Dominion had issued $48 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded.
Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial
transactions with third parties. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion would be obligated to satisfy such obligation. To the extent that a liability
subject to a guarantee has been incurred by one of Dominions 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, 2016, Dominion had issued the following subsidiary guarantees:
|
|
|
|
|
|
|
Maximum Exposure
|
|
(millions)
|
|
|
|
Commodity transactions
(1)
|
|
$
|
2,074
|
|
Nuclear obligations
(2)
|
|
|
169
|
|
Cove Point
(3)
|
|
|
1,900
|
|
Solar
(4)
|
|
|
1,130
|
|
Other
(5)
|
|
|
545
|
|
Total
(6)
|
|
$
|
5,818
|
|
(1)
|
Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction related commodities and services.
|
(2)
|
Guarantees related to certain DEI subsidiaries regarding all aspects of running a nuclear facility.
|
(3)
|
Guarantees related to Cove Point, in support of terminal services, transportation and construction. Cove Point has two guarantees that have no maximum limit and, therefore, are not included in this amount.
|
(4)
|
Includes guarantees to facilitate the development of solar projects. Also includes guarantees entered into by DEI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.
|
(5)
|
Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Due to the uncertainty of workers compensation claims,
the parental guarantee has no stated limit. Also included are guarantees related to certain DEI subsidiaries obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of December 31, 2016,
Dominions maximum remaining cumulative exposure under these equity funding agreements is $36 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million.
|
(6)
|
Excludes Dominions guarantee for the construction of the new corporate office property discussed further within Lease Commitments above.
|
Additionally, at December 31, 2016, Dominion had purchased $149 million of surety bonds, including $71 million at Virginia
Power and $22 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $85 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, 2016, 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 Powers
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, 2016, 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.
N
OTE
23. C
REDIT
R
ISK
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, 2016 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.
G
ENERAL
D
OMINION
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,
Midwest and Rocky
Mountain 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.
Dominions 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, 2016, Dominions credit exposure totaled $98 million. Of this amount, investment grade counterparties, including those internally
rated, represented 53%, and no single counterparty, whether investment grade or
non-investment
grade, exceeded $9 million of exposure.
V
IRGINIA
P
OWER
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 Powers customer
base, which includes residential, commercial and
Combined Notes to Consolidated Financial Statements, Continued
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 Powers exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Powers 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, 2016, Virginia Powers credit exposure totaled $42 million. Of this amount, investment grade counterparties, including those internally rated, represented 33%, and no single counterparty, whether
investment grade or
non-investment
grade, exceeded $6 million of exposure.
D
OMINION
G
AS
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 2016, DTI provided service to 289 customers with approximately 96% of its storage and transportation revenue being provided through firm
services. The ten largest customers provided approximately 40% of the total storage and transportation revenue and the thirty largest provided approximately 70% 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 Ohios bad debt risk is mitigated by the regulatory framework established by the Ohio Commission. See Note 13 for further information about
Ohios PIPP and UEX Riders that mitigate East Ohios overall credit risk.
C
REDIT
-R
ELATED
C
ONTINGENT
P
ROVISIONS
The majority of Dominions 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, 2016 and 2015, Dominion would have been required to post an additional $3 million and $12 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, 2016 and 2015, 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, 2016 and 2015 was $9 million and $49 million, respectively, 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, 2016 and 2015. See Note 7 for further information about derivative instruments.
N
OTE
24.
R
ELATED
-
PARTY
T
RANSACTIONS
Virginia Power and Dominion Gas engage in related party transactions
primarily with other Dominion subsidiaries (affiliates). Virginia Powers 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 Dominions consolidated federal income tax return and, where applicable, combined income tax returns for Dominion are filed in various states. See Note 2 for further
information. Dominions transactions with equity method investments are described in Note 9. A discussion of significant related party transactions follows.
V
IRGINIA
P
OWER
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, 2016, Virginia Powers derivative assets and liabilities with affiliates were $41 million and $8 million, respectively. As of December 31, 2015, Virginia Powers
derivative assets and liabilities with affiliates were $13 million and $22 million, respectively.
Virginia Power participates
in certain Dominion benefit plans as described in Note 21. At December 31, 2016 and 2015, Virginia Powers 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 $396 million and $316 million, respectively. At December 31, 2016 and 2015, Virginia Powers amounts due from Dominion associated with the Dominion Retiree Health and
Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $130 million and $77 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.
The financial statements
for all years presented include costs for certain general, administrative and corporate expenses assigned by DRS to Virginia Power on the basis of direct and allocated methods in accordance with Virginia Powers services agreements with DRS.
Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DRS resources that is attributable
to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DRS service. Management believes the assumptions and methodologies
underlying the allocation of general corporate overhead expenses are reasonable.
Presented below are significant transactions with DRS
and other affiliates:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
Commodity purchases from affiliates
|
|
$
|
571
|
|
|
$
|
555
|
|
|
$
|
543
|
|
Services provided by affiliates
(1)
|
|
|
454
|
|
|
|
422
|
|
|
|
432
|
|
Services provided to affiliates
|
|
|
22
|
|
|
|
22
|
|
|
|
22
|
|
(1)
|
Includes capitalized expenditures of $144 million, $143 million and $146 million for the year ended December 31, 2016, 2015, and 2014, respectively.
|
Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were $262 million and $376 million in
short-term demand note borrowings from Dominion as of December 31, 2016 and 2015, respectively. The weighted-average interest rate of these borrowings was 0.97% and 0.60% at December 31, 2016 and 2015, respectively. Virginia Power had no outstanding
borrowings, net of repayments under the Dominion money pool for its nonregulated subsidiaries as of December 31, 2016 and 2015. Interest charges related to Virginia Powers borrowings from Dominion were immaterial for the years ended
December 31, 2016, 2015 and 2014.
There were no issuances of Virginia Powers common stock to Dominion in 2016, 2015 or 2014.
D
OMINION
G
AS
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, 2016 and 2015, all of Dominion Gas commodity derivatives were with affiliates. See Notes 7 and 19 for more information. See Note 9 for information regarding transactions with an affiliate.
Dominion Gas participates in certain Dominion benefit plans as described in Note 21. At December 31, 2016 and 2015, 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 $697 million and $652 million, respectively. At
December 31, 2016 and 2015, Dominion Gas amounts due from Dominion and liabilities due to Dominion associated with the Dominion Retiree Health and Welfare Plan were immaterial.
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
financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DRS to Dominion Gas on the basis of direct and allocated methods in accordance with Dominion Gas services
agreements with DRS. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DRS resources that is attributable to the entity, determined by reference to
number of employees, salaries and wages and other similar measures for the relevant DRS service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. The costs of
these services follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
Purchases of natural gas and transportation and storage services from affiliates
|
|
$
|
9
|
|
|
$
|
10
|
|
|
$
|
34
|
|
Sales of natural gas and transportation and storage services to affiliates
|
|
|
69
|
|
|
|
69
|
|
|
|
84
|
|
Services provided by related parties
(1)
|
|
|
141
|
|
|
|
133
|
|
|
|
106
|
|
Services provided to related parties
(2)
|
|
|
128
|
|
|
|
101
|
|
|
|
17
|
|
(1)
|
Includes capitalized expenditures of $49 million, $57 million and $49 million for the year ended December 31, 2016, 2015, and 2014, respectively.
|
(2)
|
Amounts primarily attributable to Atlantic Coast Pipeline.
|
The following table presents affiliated and
related party balances reflected in Dominion Gas Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
At December 31,
|
|
2016
|
|
|
2015
|
|
(millions)
|
|
|
|
|
|
|
Other receivables
(1)
|
|
$
|
10
|
|
|
$
|
7
|
|
Customer receivables from related parties
|
|
|
1
|
|
|
|
4
|
|
Imbalances receivable from affiliates
|
|
|
2
|
|
|
|
1
|
|
Imbalances payable to affiliates
(2)
|
|
|
4
|
|
|
|
|
|
Affiliated notes receivable
(3)
|
|
|
18
|
|
|
|
14
|
|
(1)
|
Represents amounts due from Atlantic Coast Pipeline, a related party VIE.
|
(2)
|
Amounts are presented in other current liabilities 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 $118 million and $95 million as of December 31, 2016 and
2015, respectively. The weighted-average interest rate of these borrowings was 1.08% and 0.65% at December 31, 2016 and 2015, respectively. Interest charges related to Dominion Gas total borrowings from Dominion were immaterial for the years
ended December 31, 2016 and 2015 and $4 million for the year ended December 31, 2014.
Combined Notes to Consolidated Financial Statements, Continued
N
OTE
25. O
PERATING
S
EGMENTS
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:
|
|
|
|
|
|
|
|
|
Primary Operating
Segment
|
|
Description of Operations
|
|
Dominion
|
|
Virginia
Power
|
|
Dominion
Gas
|
DVP
|
|
Regulated electric distribution
|
|
X
|
|
X
|
|
|
|
|
Regulated electric transmission
|
|
X
|
|
X
|
|
|
Dominion Generation
|
|
Regulated electric fleet
|
|
X
|
|
X
|
|
|
|
|
Merchant electric fleet
|
|
X
|
|
|
|
|
Dominion Energy
|
|
Gas transmission and storage
|
|
X
(1)
|
|
|
|
X
|
|
|
Gas distribution and storage
|
|
X
|
|
|
|
X
|
|
|
Gas gathering and processing
|
|
X
|
|
|
|
X
|
|
|
LNG import and storage
|
|
X
|
|
|
|
|
|
|
Nonregulated retail energy marketing
|
|
X
|
|
|
|
|
(1)
|
Includes remaining producer services activities.
|
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). In addition,
Corporate and Other includes specific items attributable to Dominions operating segments that are not included in profit measures evaluated by executive management in assessing the segments performance or in allocating resources.
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 2016, Dominion reported
after-tax
net expenses of
$484 million in the Corporate and Other segment, with $180 million of these net expenses attributable to specific items related to its operating segments.
The net expenses for specific items in 2016 primarily related to the impact of the following items:
|
|
A $197 million ($122 million
after-tax)
charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Dominion
Generation; and
|
|
|
A $59 million ($36 million
after-tax)
charge related to an organizational design initiative, attributable to:
|
|
|
|
DVP ($5 million
after-tax);
|
|
|
|
Dominion Energy ($12 million
after-tax);
and
|
|
|
|
Dominion Generation ($19 million
after-tax).
|
In
2015, Dominion reported
after-tax
net expenses of $391 million in the Corporate and Other segment, with $136 million of these net expenses attributable to specific items related to its operating
segments.
The net expenses for specific items in 2015 primarily related to the impact of the following items:
|
|
A $99 million ($60 million
after-tax)
charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to 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
expenses 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.
|
The following table presents segment information pertaining to Dominions operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
DVP
|
|
|
Dominion
Generation
|
|
|
Dominion
Energy
|
|
|
Corporate and
Other
|
|
|
Adjustments &
Eliminations
|
|
|
Consolidated
Total
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers
|
|
$
|
2,210
|
|
|
$
|
6,747
|
|
|
$
|
2,069
|
|
|
$
|
(7
|
)
|
|
$
|
718
|
|
|
$
|
11,737
|
|
Intersegment revenue
|
|
|
23
|
|
|
|
10
|
|
|
|
697
|
|
|
|
609
|
|
|
|
(1,339
|
)
|
|
|
|
|
Total operating revenue
|
|
|
2,233
|
|
|
|
6,757
|
|
|
|
2,766
|
|
|
|
602
|
|
|
|
(621
|
)
|
|
|
11,737
|
|
Depreciation, depletion and amortization
|
|
|
537
|
|
|
|
662
|
|
|
|
330
|
|
|
|
30
|
|
|
|
|
|
|
|
1,559
|
|
Equity in earnings of equity method investees
|
|
|
|
|
|
|
(16
|
)
|
|
|
105
|
|
|
|
22
|
|
|
|
|
|
|
|
111
|
|
Interest income
|
|
|
|
|
|
|
74
|
|
|
|
34
|
|
|
|
36
|
|
|
|
(78
|
)
|
|
|
66
|
|
Interest and related charges
|
|
|
244
|
|
|
|
290
|
|
|
|
38
|
|
|
|
516
|
|
|
|
(78
|
)
|
|
|
1,010
|
|
Income taxes
|
|
|
308
|
|
|
|
279
|
|
|
|
431
|
|
|
|
(363
|
)
|
|
|
|
|
|
|
655
|
|
Net income (loss) attributable to Dominion
|
|
|
484
|
|
|
|
1,397
|
|
|
|
726
|
|
|
|
(484
|
)
|
|
|
|
|
|
|
2,123
|
|
Investment in equity method investees
|
|
|
|
|
|
|
228
|
|
|
|
1,289
|
|
|
|
44
|
|
|
|
|
|
|
|
1,561
|
|
Capital expenditures
|
|
|
1,320
|
|
|
|
2,440
|
|
|
|
2,322
|
|
|
|
43
|
|
|
|
|
|
|
|
6,125
|
|
Total assets (billions)
|
|
|
15.6
|
|
|
|
27.1
|
|
|
|
26.0
|
|
|
|
10.2
|
|
|
|
(7.3
|
)
|
|
|
71.6
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers
|
|
$
|
2,091
|
|
|
$
|
7,001
|
|
|
$
|
1,877
|
|
|
$
|
(27
|
)
|
|
$
|
741
|
|
|
$
|
11,683
|
|
Intersegment revenue
|
|
|
20
|
|
|
|
15
|
|
|
|
695
|
|
|
|
554
|
|
|
|
(1,284
|
)
|
|
|
|
|
Total operating revenue
|
|
|
2,111
|
|
|
|
7,016
|
|
|
|
2,572
|
|
|
|
527
|
|
|
|
(543
|
)
|
|
|
11,683
|
|
Depreciation, depletion and amortization
|
|
|
498
|
|
|
|
591
|
|
|
|
262
|
|
|
|
44
|
|
|
|
|
|
|
|
1,395
|
|
Equity in earnings of equity method investees
|
|
|
|
|
|
|
(15
|
)
|
|
|
60
|
|
|
|
11
|
|
|
|
|
|
|
|
56
|
|
Interest income
|
|
|
|
|
|
|
64
|
|
|
|
25
|
|
|
|
13
|
|
|
|
(44
|
)
|
|
|
58
|
|
Interest and related charges
|
|
|
230
|
|
|
|
262
|
|
|
|
27
|
|
|
|
429
|
|
|
|
(44
|
)
|
|
|
904
|
|
Income taxes
|
|
|
307
|
|
|
|
465
|
|
|
|
423
|
|
|
|
(290
|
)
|
|
|
|
|
|
|
905
|
|
Net income (loss) attributable to Dominion
|
|
|
490
|
|
|
|
1,120
|
|
|
|
680
|
|
|
|
(391
|
)
|
|
|
|
|
|
|
1,899
|
|
Investment in equity method investees
|
|
|
|
|
|
|
245
|
|
|
|
1,042
|
|
|
|
33
|
|
|
|
|
|
|
|
1,320
|
|
Capital expenditures
|
|
|
1,607
|
|
|
|
2,190
|
|
|
|
2,153
|
|
|
|
43
|
|
|
|
|
|
|
|
5,993
|
|
Total assets (billions)
|
|
|
14.7
|
|
|
|
25.6
|
|
|
|
15.2
|
|
|
|
8.9
|
|
|
|
(5.8
|
)
|
|
|
58.6
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers
|
|
$
|
1,918
|
|
|
$
|
7,135
|
|
|
$
|
2,446
|
|
|
$
|
(12
|
)
|
|
$
|
949
|
|
|
$
|
12,436
|
|
Intersegment revenue
|
|
|
18
|
|
|
|
34
|
|
|
|
880
|
|
|
|
572
|
|
|
|
(1,504
|
)
|
|
|
|
|
Total operating revenue
|
|
|
1,936
|
|
|
|
7,169
|
|
|
|
3,326
|
|
|
|
560
|
|
|
|
(555
|
)
|
|
|
12,436
|
|
Depreciation, depletion and amortization
|
|
|
462
|
|
|
|
514
|
|
|
|
243
|
|
|
|
73
|
|
|
|
|
|
|
|
1,292
|
|
Equity in earnings of equity method investees
|
|
|
|
|
|
|
(18
|
)
|
|
|
54
|
|
|
|
10
|
|
|
|
|
|
|
|
46
|
|
Interest income
|
|
|
|
|
|
|
58
|
|
|
|
23
|
|
|
|
20
|
|
|
|
(33
|
)
|
|
|
68
|
|
Interest and related charges
|
|
|
205
|
|
|
|
240
|
|
|
|
11
|
|
|
|
770
|
|
|
|
(33
|
)
|
|
|
1,193
|
|
Income taxes
|
|
|
317
|
|
|
|
365
|
|
|
|
463
|
|
|
|
(693
|
)
|
|
|
|
|
|
|
452
|
|
Net income (loss) attributable to Dominion
|
|
|
502
|
|
|
|
1,061
|
|
|
|
717
|
|
|
|
(970
|
)
|
|
|
|
|
|
|
1,310
|
|
Capital expenditures
|
|
|
1,652
|
|
|
|
2,466
|
|
|
|
1,329
|
|
|
|
104
|
|
|
|
|
|
|
|
5,551
|
|
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 Powers revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an
unbundled rate methodology among Virginia Powers 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 in allocating resources.
In 2016, Virginia Power reported
after-tax
net expenses of $173 million for specific items
attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2016 primarily
related to the impact of the following item:
|
|
A $197 million ($121 million
after-tax)
charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Dominion
Generation.
|
In 2015, Virginia Power reported
after-tax
net expenses of
$153 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2015 primarily related to the impact of the following
items:
|
|
A $99 million ($60 million
after-tax)
charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to 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 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; 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.
|
Combined Notes to Consolidated Financial Statements, Continued
The following table presents segment information pertaining to Virginia Powers
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
DVP
|
|
|
Dominion
Generation
|
|
|
Corporate and
Other
|
|
|
Adjustments &
Eliminations
|
|
|
Consolidated
Total
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
2,217
|
|
|
$
|
5,390
|
|
|
$
|
(19
|
)
|
|
$
|
|
|
|
$
|
7,588
|
|
Depreciation and amortization
|
|
|
537
|
|
|
|
488
|
|
|
|
|
|
|
|
|
|
|
|
1,025
|
|
Interest income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and related charges
|
|
|
244
|
|
|
|
219
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
461
|
|
Income taxes
|
|
|
307
|
|
|
|
524
|
|
|
|
(104
|
)
|
|
|
|
|
|
|
727
|
|
Net income (loss)
|
|
|
482
|
|
|
|
909
|
|
|
|
(173
|
)
|
|
|
|
|
|
|
1,218
|
|
Capital expenditures
|
|
|
1,313
|
|
|
|
1,336
|
|
|
|
|
|
|
|
|
|
|
|
2,649
|
|
Total assets (billions)
|
|
|
15.6
|
|
|
|
17.8
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
33.3
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
2,099
|
|
|
$
|
5,566
|
|
|
$
|
(43
|
)
|
|
$
|
|
|
|
$
|
7,622
|
|
Depreciation and amortization
|
|
|
498
|
|
|
|
453
|
|
|
|
2
|
|
|
|
|
|
|
|
953
|
|
Interest income
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
Interest and related charges
|
|
|
230
|
|
|
|
210
|
|
|
|
4
|
|
|
|
(1
|
)
|
|
|
443
|
|
Income taxes
|
|
|
308
|
|
|
|
437
|
|
|
|
(86
|
)
|
|
|
|
|
|
|
659
|
|
Net income (loss)
|
|
|
490
|
|
|
|
750
|
|
|
|
(153
|
)
|
|
|
|
|
|
|
1,087
|
|
Capital expenditures
|
|
|
1,569
|
|
|
|
1,120
|
|
|
|
|
|
|
|
|
|
|
|
2,689
|
|
Total assets (billions)
|
|
|
14.7
|
|
|
|
17.0
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
31.6
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
1,928
|
|
|
$
|
5,651
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7,579
|
|
Depreciation and amortization
|
|
|
462
|
|
|
|
416
|
|
|
|
37
|
|
|
|
|
|
|
|
915
|
|
Interest income
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
Interest and related charges
|
|
|
205
|
|
|
|
203
|
|
|
|
3
|
|
|
|
|
|
|
|
411
|
|
Income taxes
|
|
|
317
|
|
|
|
416
|
|
|
|
(185
|
)
|
|
|
|
|
|
|
548
|
|
Net income (loss)
|
|
|
509
|
|
|
|
691
|
|
|
|
(342
|
)
|
|
|
|
|
|
|
858
|
|
Capital expenditures
|
|
|
1,651
|
|
|
|
1,456
|
|
|
|
|
|
|
|
|
|
|
|
3,107
|
|
D
OMINION
G
AS
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 segments performance or in allocating resources and the effect of certain items recorded at Dominion Gas as a
result of Dominions basis in the net assets contributed.
In 2016, Dominion Gas reported
after-tax
net expenses of $3 million in its Corporate and Other segment, with $7 million of these net expenses attributable to its operating segment.
The net expense for specific items in 2016 primarily related to the impact of the following item:
|
|
An $8 million ($5 million
after-tax)
charge related to an organizational design initiative.
|
In 2015, Dominion Gas reported
after-tax
net expenses
of $21 million in its Corporate and Other segment, with $13 million of these net expenses attributable to specific items related to its operating segment.
The net expenses for specific items in 2015 primarily related to the impact of the following item:
|
|
$16 million ($10 million
after-tax)
ceiling test impairment charge.
|
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.
The following table presents segment information pertaining to Dominion Gas
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Dominion
Energy
|
|
|
Corporate and
Other
|
|
|
Consolidated
Total
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
1,638
|
|
|
$
|
|
|
|
$
|
1,638
|
|
Depreciation and amortization
|
|
|
214
|
|
|
|
(10
|
)
|
|
|
204
|
|
Equity in earnings of equity method investees
|
|
|
21
|
|
|
|
|
|
|
|
21
|
|
Interest income
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
Interest and related charges
|
|
|
92
|
|
|
|
2
|
|
|
|
94
|
|
Income taxes
|
|
|
237
|
|
|
|
(22
|
)
|
|
|
215
|
|
Net income (loss)
|
|
|
395
|
|
|
|
(3
|
)
|
|
|
392
|
|
Investment in equity method investees
|
|
|
98
|
|
|
|
|
|
|
|
98
|
|
Capital expenditures
|
|
|
854
|
|
|
|
|
|
|
|
854
|
|
Total assets (billions)
|
|
|
10.5
|
|
|
|
0.6
|
|
|
|
11.1
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
1,716
|
|
|
$
|
|
|
|
$
|
1,716
|
|
Depreciation and amortization
|
|
|
213
|
|
|
|
4
|
|
|
|
217
|
|
Equity in earnings of equity method investees
|
|
|
23
|
|
|
|
|
|
|
|
23
|
|
Interest income
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
Interest and related charges
|
|
|
72
|
|
|
|
1
|
|
|
|
73
|
|
Income taxes
|
|
|
296
|
|
|
|
(13
|
)
|
|
|
283
|
|
Net income (loss)
|
|
|
478
|
|
|
|
(21
|
)
|
|
|
457
|
|
Investment in equity method investees
|
|
|
102
|
|
|
|
|
|
|
|
102
|
|
Capital expenditures
|
|
|
795
|
|
|
|
|
|
|
|
795
|
|
Total assets (billions)
|
|
|
9.7
|
|
|
|
0.6
|
|
|
|
10.3
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
1,898
|
|
|
$
|
|
|
|
$
|
1,898
|
|
Depreciation and amortization
|
|
|
197
|
|
|
|
|
|
|
|
197
|
|
Equity in earnings of equity method investees
|
|
|
21
|
|
|
|
|
|
|
|
21
|
|
Interest income
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
Interest and related charges
|
|
|
27
|
|
|
|
|
|
|
|
27
|
|
Income taxes
|
|
|
340
|
|
|
|
(6
|
)
|
|
|
334
|
|
Net income (loss)
|
|
|
521
|
|
|
|
(9
|
)
|
|
|
512
|
|
Capital expenditures
|
|
|
719
|
|
|
|
|
|
|
|
719
|
|
Combined Notes to Consolidated Financial Statements, Continued
N
OTE
26. Q
UARTERLY
F
INANCIAL
AND
C
OMMON
S
TOCK
D
ATA
(U
NAUDITED
)
A summary of the Companies quarterly results of operations for the years ended December 31, 2016 and 2015
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.
D
OMINION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
Fourth
Quarter
|
|
|
Year
|
|
(millions, except per
share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
2,921
|
|
|
$
|
2,598
|
|
|
$
|
3,132
|
|
|
$
|
3,086
|
|
|
$
|
11,737
|
|
Income from operations
|
|
|
882
|
|
|
|
781
|
|
|
|
1,145
|
|
|
|
819
|
|
|
|
3,627
|
|
Net income including noncontrolling interests
|
|
|
531
|
|
|
|
462
|
|
|
|
728
|
|
|
|
491
|
|
|
|
2,212
|
|
Net income attributable to Dominion
|
|
|
524
|
|
|
|
452
|
|
|
|
690
|
|
|
|
457
|
|
|
|
2,123
|
|
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Dominion
|
|
|
0.88
|
|
|
|
0.73
|
|
|
|
1.10
|
|
|
|
0.73
|
|
|
|
3.44
|
|
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Dominion
|
|
|
0.88
|
|
|
|
0.73
|
|
|
|
1.10
|
|
|
|
0.73
|
|
|
|
3.44
|
|
Dividends declared per share
|
|
|
0.7000
|
|
|
|
0.7000
|
|
|
|
0.7000
|
|
|
|
0.7000
|
|
|
|
2.8000
|
|
Common stock prices (intraday
high-low)
|
|
$
|
75.18 -
66.25
|
|
|
$
|
77.93 -
68.71
|
|
|
$
|
78.97 -
72.49
|
|
|
$
|
77.32 -
69.51
|
|
|
$
|
78.97 -
66.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
Fourth
Quarter
|
|
|
Year
|
|
(millions, except per
share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
3,409
|
|
|
$
|
2,747
|
|
|
$
|
2,971
|
|
|
$
|
2,556
|
|
|
$
|
11,683
|
|
Income from operations
|
|
|
1,002
|
|
|
|
773
|
|
|
|
1,123
|
|
|
|
638
|
|
|
|
3,536
|
|
Net income including noncontrolling interests
|
|
|
540
|
|
|
|
418
|
|
|
|
599
|
|
|
|
366
|
|
|
|
1,923
|
|
Net income attributable to Dominion
|
|
|
536
|
|
|
|
413
|
|
|
|
593
|
|
|
|
357
|
|
|
|
1,899
|
|
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Dominion
|
|
|
0.91
|
|
|
|
0.70
|
|
|
|
1.00
|
|
|
|
0.60
|
|
|
|
3.21
|
|
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Dominion
|
|
|
0.91
|
|
|
|
0.70
|
|
|
|
1.00
|
|
|
|
0.60
|
|
|
|
3.20
|
|
Dividends declared per share
|
|
|
0.6475
|
|
|
|
0.6475
|
|
|
|
0.6475
|
|
|
|
0.6475
|
|
|
|
2.5900
|
|
Common stock prices (intraday
high-low)
|
|
$
|
79.89 -
68.25
|
|
|
$
|
74.34 -
66.52
|
|
|
$
|
76.59 -
66.65
|
|
|
$
|
74.88 -
64.54
|
|
|
$
|
79.89 -
64.54
|
|
Dominions 2016 results include the
impact of the following significant item:
|
|
Fourth quarter results include a $122 million
after-tax
charge related to future ash pond and landfill closure costs at certain utility generation facilities.
|
There were no significant items impacting Dominions 2015 quarterly results.
V
IRGINIA
P
OWER
Virginia Powers quarterly results of operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
Fourth
Quarter
|
|
|
Year
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
1,890
|
|
|
$
|
1,776
|
|
|
$
|
2,211
|
|
|
$
|
1,711
|
|
|
$
|
7,588
|
|
Income from operations
|
|
|
514
|
|
|
|
553
|
|
|
|
914
|
|
|
|
369
|
|
|
|
2,350
|
|
Net income
|
|
|
263
|
|
|
|
280
|
|
|
|
503
|
|
|
|
172
|
|
|
|
1,218
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
2,137
|
|
|
$
|
1,813
|
|
|
$
|
2,058
|
|
|
$
|
1,614
|
|
|
$
|
7,622
|
|
Income from operations
|
|
|
525
|
|
|
|
481
|
|
|
|
741
|
|
|
|
374
|
|
|
|
2,121
|
|
Net income
|
|
|
269
|
|
|
|
246
|
|
|
|
385
|
|
|
|
187
|
|
|
|
1,087
|
|
Virginia Powers 2016 results include the impact of the following significant item:
|
|
Fourth quarter results include a $121 million
after-tax
charge related to future ash pond and landfill closure costs at certain utility generation facilities.
|
Virginia Powers 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.
|
D
OMINION
G
AS
Dominion Gas quarterly results of operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
Fourth
Quarter
|
|
|
Year
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
431
|
|
|
$
|
368
|
|
|
$
|
382
|
|
|
$
|
457
|
|
|
$
|
1,638
|
|
Income from operations
|
|
|
175
|
|
|
|
186
|
|
|
|
133
|
|
|
|
175
|
|
|
|
669
|
|
Net income
|
|
98
|
|
|
105
|
|
|
83
|
|
|
106
|
|
|
392
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
531
|
|
|
$
|
395
|
|
|
$
|
365
|
|
|
$
|
425
|
|
|
$
|
1,716
|
|
Income from operations
|
|
|
271
|
|
|
|
153
|
|
|
|
202
|
|
|
|
163
|
|
|
|
789
|
|
Net income
|
|
|
161
|
|
|
|
85
|
|
|
|
111
|
|
|
|
100
|
|
|
|
457
|
|
There were no significant items impacting Dominion Gas 2016 quarterly results.
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.
|