NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1
—
Basis of Presentation
NRG Energy, Inc., or NRG or the Company, is a leading integrated power company built on the strength of the nation's largest and most diverse competitive electric generation portfolio and leading retail electricity platform. NRG aims to create a sustainable energy future by producing, selling and delivering electricity and related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. The Company owns and operates approximately
46,000
MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant" and other retail brand names owned by NRG.
The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the consolidated financial statements in the Company's
2016
Form 10-K. Interim results are not necessarily indicative of results for a full year.
In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of
March 31, 2017
, and the results of operations, comprehensive income/(loss) and cash flows for the
three
months ended
March 31, 2017
and
2016
.
GenOn Liquidity and Ability to Continue as a Going Concern
As of March 31, 2017, GenOn had cash and cash equivalents of
$885 million
, of which
$305 million
and
$82 million
were held by GenOn Mid-Atlantic and REMA, respectively. Under their respective operating leases, GenOn Mid-Atlantic and REMA are not permitted to make any distributions and other restricted payments unless: (a) they satisfy the fixed charge coverage ratio for the most recently ended period for four fiscal quarters; (b) they are projected to satisfy the fixed charge coverage ratio for each of the two following periods of four fiscal quarters, commencing with the fiscal quarter in which such payment is proposed to be made; and (c) no significant lease default or event of default has occurred and is continuing. Additionally, GenOn Mid-Atlantic and REMA must be in compliance with the requirement to provide credit support to the owner lessors securing their obligations to pay scheduled rent under their respective leases. As a result, GenOn Mid-Atlantic has not been able to make distributions of cash and certain other restricted payments since the quarter ended March 31, 2014 which was the last quarterly period for which GenOn Mid-Atlantic satisfied the conditions under its operating agreement. REMA has not satisfied the conditions under its operating agreement to make distributions of cash and certain other restricted payments since 2009.
As disclosed in
Note 8
,
Debt and Capital Leases
,
$691 million
of GenOn's Senior Notes, excluding
$4 million
of associated premiums, are current within the GenOn consolidated balance sheet as of March 31, 2017 and are due on June 15, 2017. GenOn's future profitability continues to be adversely affected by (i) a sustained decline in natural gas prices and its resulting effect on wholesale power prices and capacity prices, and (ii) the inability of GenOn Mid-Atlantic and REMA to make distributions of cash and certain other restricted payments to GenOn. GenOn is currently considering all options available to it, including negotiations with creditors and lessors, refinancing the GenOn Senior Notes, potential sales of certain generating assets as well as the possibility for a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. If GenOn is unable to enter into a settlement with its creditors, refinance the senior notes or otherwise raise or generate sufficient capital, GenOn is not expected to have sufficient liquidity to repay the GenOn Senior Notes due in June 2017. Pending resolution, there is substantial doubt about GenOn's ability to continue as a going concern. As a result of the substantial doubt about GenOn’s ability to continue as a going concern, along with additional factors, there is substantial doubt about certain of GenOn’s subsidiaries’ ability to continue as a going concern.
During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process. On April 7, 2017, GenOn also appointed a new dedicated chief executive officer, effective immediately. Any resolution may have a material impact on the NRG's statement of operations, cash flows and financial position.
NRG, GenOn's parent company, has no obligation to provide any financial support to GenOn other than under the secured intercompany revolving credit agreement between NRG and GenOn and NRG Americas. As of March 31, 2017,
$214 million
was available to be used by GenOn under the
$500 million
revolving credit agreement. As controlled group members, ERISA requires that NRG and GenOn are jointly and severally liable for the NRG Pension Plan for Bargained Employees and the NRG Pension Plan, including the pension liabilities associated with GenOn employees.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.
Note 2
—
Summary of Significant Accounting Policies
Other Balance Sheet Information
The following table presents the allowance for doubtful accounts included in accounts receivable, net; accumulated depreciation included in property, plant and equipment, net; accumulated amortization included in intangible assets, net and accumulated amortization included in out-of-market contracts, net:
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
December 31, 2016
|
|
(In millions)
|
Accounts receivable allowance for doubtful accounts
|
$
|
33
|
|
|
$
|
30
|
|
Property, plant and equipment accumulated depreciation
|
6,602
|
|
|
6,314
|
|
Intangible assets accumulated amortization
|
1,724
|
|
|
1,775
|
|
Out-of-market contracts accumulated amortization
|
666
|
|
|
765
|
|
Noncontrolling Interest
The following table reflects the changes in NRG's noncontrolling interest balance:
|
|
|
|
|
|
(In millions)
|
Balance as of December 31, 2016
|
$
|
2,405
|
|
Dividends paid to NRG Yield, Inc. public shareholders
|
(25
|
)
|
Comprehensive loss attributable to noncontrolling interest
|
(22
|
)
|
Distributions to noncontrolling interest
|
(21
|
)
|
Contributions from noncontrolling interest
|
48
|
|
Sale of assets to NRG Yield, Inc.
|
3
|
|
Balance as of March 31, 2017
|
$
|
2,388
|
|
Redeemable Noncontrolling Interest
The following table reflects the changes in the Company's redeemable noncontrolling interest balance:
|
|
|
|
|
|
(In millions)
|
Balance as of December 31, 2016
|
$
|
46
|
|
Contributions from redeemable noncontrolling interest
|
15
|
|
Comprehensive loss attributable to redeemable noncontrolling interest
|
(17
|
)
|
Balance as of March 31, 2017
|
$
|
44
|
|
Recent Accounting Developments - Guidance Adopted in 2017
ASU 2016-16
— In October 2016, the FASB issued ASU No. 2016-16,
Income Taxes (Topic 740)
, Intra-Entity Transfers of Assets Other Than Inventory, or ASU No. 2016-16. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice and increased complexity within financial reporting. The amendments of ASU No. 2016-16 would require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company adopted the guidance in ASU No. 2016-16 effective January 1, 2017. In connection with the adoption of the standard, the Company recorded a reduction to non-current assets of
$267 million
with a corresponding reduction to cumulative retained deficit.
ASU 2016-15
— In August 2016, the FASB issued ASU No. 2016-15,
Statement of Cash Flows (Topic 230)
, Classification of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The Company adopted the guidance in ASU No. 2016-15 effective January 1, 2017. While the Company has applied this guidance retrospectively, the adoption of the standard did not have an impact on the statement of cash flow for the three months ended March 31, 2016.
ASU 2016-09
— In March 2016, the FASB issued ASU No. 2016-09,
Compensation - Stock Compensation
(Topic 718), or ASU No. 2016-09. The amendments focused on simplification specifically with regard to share-based payment transactions, including income tax consequences, classification of awards as equity or liabilities and classification on the statement of cash flows. The Company adopted the guidance in ASU No. 2016-09 effective January 1, 2017 with no material adjustments recorded to the consolidated balance sheet.
Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2017-07
— In March 2017, the FASB issued ASU No. 2017-07,
Compensation - Retirement Benefits (Topic 715)
, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU No. 2017-07. Current GAAP does not indicate where the amount of net benefit cost should be presented in an entity’s income statement and does not require entities to disclose the amount of net benefit cost that is included in the income statement. The amendments of ASU No. 2017-07 require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and outside the subtotal of income from operations. Further, ASU No. 2017-07 prescribes that only the service cost component of net benefit costs is eligible for capitalization. The amendments of ASU No. 2017-07 are effective for fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and must be applied on a retrospective basis, except for the amendments regarding the capitalization of the service cost component, which must be applied prospectively. The Company is currently assessing the impact that the adoption of ASU No. 2017-07 will have on its results of operations, cash flows, and statement of financial position.
ASU 2016-18
— In November 2016, the FASB issued ASU No. 2016-18,
Statement of Cash Flows (Topic 230)
, Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require an entity to include amounts generally described as restricted cash and restricted cash equivalents, including funds deposited by counterparties with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. The amendments of ASU No. 2016-18 are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted and the adoption of ASU No. 2016-18 will be applied retrospectively. The Company calculated the impact of ASU No. 2016-18 on the statement of cash flows to be a decrease of cash flows used by operating activities of
$1 million
and an increase of cash flows used by investing activities of
$49 million
for the three months ended March 31, 2017, and a decrease of cash flows provided by operating activities of
$5 million
and a decrease of cash flows used by investing activities of
$27 million
for the three months ended March 31, 2016.
ASU 2016-02
— In February 2016, the FASB issued ASU No. 2016-02,
Leases (Topic 842)
, or Topic 842, with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company expects to adopt the standard effective January 1, 2019 utilizing the required modified retrospective approach for the earliest period presented. The Company expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. The Company is currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While the Company is currently evaluating the impact the new guidance will have on its financial position and results of operations, the Company expects to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending the Company’s review of its existing lease contracts and service contracts which may contain embedded leases. As this review is still in process, it is currently not practicable to quantify the impact of adopting the ASU at this time.
ASU 2014-09
— In May 2014, the FASB issued ASU No. 2014-09,
Revenue from Contracts with Customers (Topic 606)
, or Topic 606, which was further amended through various updates issued by the FASB thereafter. The amendments of Topic 606 completed the joint effort between the FASB and the IASB, to develop a common revenue standard for GAAP and IFRS, and to improve financial reporting. The guidance under Topic 606 provides that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for the goods or services provided and establishes a five step model to be applied by an entity in evaluating its contracts with customers. The Company expects to adopt the standard effective January 1, 2018 and apply the guidance retrospectively to contracts at the date of adoption. The Company will recognize the cumulative effect of applying Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method. The Company also expects to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that
corresponds directly with the value to the customer for performance completed to date by the entity. The Company continues to assess the new standard with a focus on identifying the performance obligations included within its revenue arrangements with customers and evaluating the Company’s methods of estimating the amount and timing of variable consideration. Based on the assessment to date, the Company is currently evaluating the impact of the new standard on the Company’s results of operations, financial position or cash flows.
Note 3
—
Dispositions
The Company completed the following transfer of assets under common control.
On March 27, 2017, the Company sold to NRG Yield, Inc.: (i) a
16%
interest in the Agua Caliente solar project, representing ownership of approximately
46
net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing
265
net MW of capacity, which have reached commercial operations. NRG Yield Inc. paid cash consideration of
$130 million
, plus
$1 million
in working capital adjustments, and assumed non-recourse debt of approximately
$328 million
.
Note 4
—
Fair Value of Financial Instruments
This footnote should be read in conjunction with the complete description under
Note 4
,
Fair Value of Financial Instruments
, to the Company's
2016
Form 10-K.
For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2017
|
|
As of December 31, 2016
|
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
|
(In millions)
|
Assets:
|
|
|
|
|
|
|
|
Notes receivable
(a)
|
$
|
30
|
|
|
$
|
30
|
|
|
$
|
34
|
|
|
$
|
34
|
|
Liabilities:
|
|
|
|
|
|
|
|
Long-term debt, including current portion
(b)
|
19,539
|
|
|
18,726
|
|
|
19,406
|
|
|
18,566
|
|
(a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.
(b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.
The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non-publicly traded long-term debt and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of
March 31, 2017
and
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2017
|
|
As of December 31, 2016
|
|
Level 2
|
|
Level 3
|
|
Level 2
|
|
Level 3
|
|
(In millions)
|
Long-term debt, including current portion
|
$
|
11,190
|
|
|
$
|
7,536
|
|
|
$
|
11,055
|
|
|
$
|
7,511
|
|
Recurring Fair Value Measurements
Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.
The following tables present assets and liabilities measured and recorded at fair value on the Company's condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2017
|
|
Fair Value
|
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Investment in available-for-sale securities (classified within other
non-current assets):
|
|
|
|
|
|
|
|
Debt securities
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
18
|
|
|
$
|
18
|
|
Available-for-sale securities
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
Other
(a)
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
Nuclear trust fund investments:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
16
|
|
|
—
|
|
|
—
|
|
|
16
|
|
U.S. government and federal agency obligations
|
55
|
|
|
1
|
|
|
—
|
|
|
56
|
|
Federal agency mortgage-backed securities
|
—
|
|
|
67
|
|
|
—
|
|
|
67
|
|
Commercial mortgage-backed securities
|
—
|
|
|
17
|
|
|
—
|
|
|
17
|
|
Corporate debt securities
|
—
|
|
|
100
|
|
|
—
|
|
|
100
|
|
Equity securities
|
309
|
|
|
—
|
|
|
58
|
|
|
367
|
|
Foreign government fixed income securities
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Other trust fund investments:
|
|
|
|
|
|
|
|
U.S. government and federal agency obligations
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Derivative assets:
|
|
|
|
|
|
|
|
Commodity contracts
|
245
|
|
|
534
|
|
|
79
|
|
|
858
|
|
Interest rate contracts
|
—
|
|
|
50
|
|
|
—
|
|
|
50
|
|
Total assets
|
$
|
638
|
|
|
$
|
773
|
|
|
$
|
155
|
|
|
$
|
1,566
|
|
Derivative liabilities:
|
|
|
|
|
|
|
|
Commodity contracts
|
307
|
|
|
541
|
|
|
137
|
|
|
985
|
|
Interest rate contracts
|
—
|
|
|
77
|
|
|
—
|
|
|
77
|
|
Total liabilities
|
$
|
307
|
|
|
$
|
618
|
|
|
$
|
137
|
|
|
$
|
1,062
|
|
(a) Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for certain former employees.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
Fair Value
|
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Investment in available-for-sale securities (classified within other
non-current assets):
|
|
|
|
|
|
|
|
Debt securities
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
17
|
|
|
$
|
17
|
|
Available-for-sale securities
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
Other
(a)
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
Nuclear trust fund investments:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
25
|
|
|
—
|
|
|
—
|
|
|
25
|
|
U.S. government and federal agency obligations
|
72
|
|
|
1
|
|
|
—
|
|
|
73
|
|
Federal agency mortgage-backed securities
|
—
|
|
|
62
|
|
|
—
|
|
|
62
|
|
Commercial mortgage-backed securities
|
—
|
|
|
17
|
|
|
—
|
|
|
17
|
|
Corporate debt securities
|
—
|
|
|
84
|
|
|
—
|
|
|
84
|
|
Equity securities
|
292
|
|
|
—
|
|
|
54
|
|
|
346
|
|
Foreign government fixed income securities
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Other trust fund investments:
|
|
|
|
|
|
|
|
U.S. government and federal agency obligations
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Derivative assets:
|
|
|
|
|
|
|
|
Commodity contracts
|
559
|
|
|
551
|
|
|
92
|
|
|
1,202
|
|
Interest rate contracts
|
—
|
|
|
49
|
|
|
—
|
|
|
49
|
|
Total assets
|
$
|
969
|
|
|
$
|
767
|
|
|
$
|
163
|
|
|
$
|
1,899
|
|
Derivative liabilities:
|
|
|
|
|
|
|
|
Commodity contracts
|
494
|
|
|
635
|
|
|
161
|
|
|
1,290
|
|
Interest rate contracts
|
—
|
|
|
88
|
|
|
—
|
|
|
88
|
|
Total liabilities
|
$
|
494
|
|
|
$
|
723
|
|
|
$
|
161
|
|
|
$
|
1,378
|
|
(a) Primarily consists of mutual funds held in rabbi trusts for non-qualified deferred compensation plans for certain former employees and a total return swap that does not meet the definition of a derivative.
There were
no
transfers during the
three
months ended
March 31, 2017
and
2016
between Levels 1 and 2. The following tables reconcile, for the
three
months ended
March 31, 2017
and
2016
, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, at least annually, using significant unobservable inputs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
|
|
Three months ended March 31, 2017
|
(In millions)
|
Debt Securities
|
|
Trust Fund Investments
|
|
Derivatives
(a)
|
|
Total
|
Beginning balance
|
$
|
17
|
|
|
$
|
54
|
|
|
$
|
(69
|
)
|
|
$
|
2
|
|
Total gains — realized/unrealized:
|
|
|
|
|
|
|
|
|
Included in earnings
|
1
|
|
|
—
|
|
|
6
|
|
|
7
|
|
Included in nuclear decommissioning obligation
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Purchases
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
Transfers into Level 3
(b)
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
(8
|
)
|
Transfers out of Level 3
(b)
|
—
|
|
|
—
|
|
|
10
|
|
|
10
|
|
Ending balance as of March 31, 2017
|
$
|
18
|
|
|
$
|
58
|
|
|
$
|
(58
|
)
|
|
$
|
18
|
|
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of March 31, 2017
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(15
|
)
|
|
$
|
(15
|
)
|
|
|
(a)
|
Consists of derivative assets and liabilities, net.
|
|
|
(b)
|
Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
|
|
Three months ended March 31, 2016
|
(In millions)
|
Debt Securities
|
|
Trust Fund Investments
|
|
Derivatives
(a)
|
|
Total
|
Beginning balance
|
$
|
17
|
|
|
$
|
54
|
|
|
$
|
(33
|
)
|
|
$
|
38
|
|
Total losses — realized/unrealized:
|
|
|
|
|
|
|
|
Included in earnings
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
(17
|
)
|
Included in nuclear decommissioning obligations
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
Purchases
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
Transfers into Level 3
(b)
|
—
|
|
|
—
|
|
|
27
|
|
|
27
|
|
Transfers out of Level 3
(b)
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
Ending balance as of March 31, 2016
|
$
|
17
|
|
|
$
|
52
|
|
|
$
|
(17
|
)
|
|
$
|
52
|
|
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of March 31, 2016
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(24
|
)
|
|
$
|
(24
|
)
|
|
|
(a)
|
Consists of derivative assets and liabilities, net.
|
|
|
(b)
|
Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.
|
Derivative Fair Value Measurements
A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of
March 31, 2017
, contracts valued with prices provided by models and other valuation techniques make up
9%
of the total derivative assets and
13%
of the total derivative liabilities.
NRG's significant positions classified as Level 3 include physical and financial power and physical coal executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power and coal location pricing which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG uses the most recent auction prices to derive the fair value.
The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of
March 31, 2017
and
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant Unobservable Inputs
|
|
March 31, 2017
|
|
Fair Value
|
|
|
|
Input/Range
|
|
Assets
|
|
Liabilities
|
|
Valuation Technique
|
|
Significant Unobservable Input
|
|
Low
|
|
High
|
|
Weighted Average
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
Power Contracts
|
$
|
43
|
|
|
$
|
97
|
|
|
Discounted Cash Flow
|
|
Forward Market Price (per MWh)
|
|
$
|
12
|
|
|
$
|
88
|
|
|
$
|
26
|
|
Coal Contracts
|
—
|
|
|
1
|
|
|
Discounted Cash Flow
|
|
Forward Market Price (per ton)
|
|
42
|
|
|
48
|
|
|
44
|
|
FTRs
|
36
|
|
|
39
|
|
|
Discounted Cash Flow
|
|
Auction Prices (per MWh)
|
|
(17
|
)
|
|
19
|
|
|
—
|
|
|
$
|
79
|
|
|
$
|
137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant Unobservable Inputs
|
|
December 31, 2016
|
|
Fair Value
|
|
|
|
Input/Range
|
|
Assets
|
|
Liabilities
|
|
Valuation Technique
|
|
Significant Unobservable Input
|
|
Low
|
|
High
|
|
Weighted Average
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
Power Contracts
|
$
|
40
|
|
|
$
|
107
|
|
|
Discounted Cash Flow
|
|
Forward Market Price (per MWh)
|
|
$
|
11
|
|
|
$
|
104
|
|
|
$
|
31
|
|
Coal Contracts
|
—
|
|
|
1
|
|
|
Discounted Cash Flow
|
|
Forward Market Price (per ton)
|
|
42
|
|
|
51
|
|
|
45
|
|
FTRs
|
52
|
|
|
53
|
|
|
Discounted Cash Flow
|
|
Auction Prices (per MWh)
|
|
(22
|
)
|
|
17
|
|
|
—
|
|
|
$
|
92
|
|
|
$
|
161
|
|
|
|
|
|
|
|
|
|
|
|
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of
March 31, 2017
and
December 31, 2016
:
|
|
|
|
|
|
|
|
Significant Unobservable Input
|
|
Position
|
|
Change In Input
|
|
Impact on Fair Value Measurement
|
Forward Market Price Power/Coal
|
|
Buy
|
|
Increase/(Decrease)
|
|
Higher/(Lower)
|
Forward Market Price Power/Coal
|
|
Sell
|
|
Increase/(Decrease)
|
|
Lower/(Higher)
|
FTR Prices
|
|
Buy
|
|
Increase/(Decrease)
|
|
Higher/(Lower)
|
FTR Prices
|
|
Sell
|
|
Increase/(Decrease)
|
|
Lower/(Higher)
|
The fair value of each contract is discounted using a risk-free interest rate. In addition, the Company applies a credit reserve to reflect credit risk, which is calculated based on published default probabilities. As of
March 31, 2017
, the credit reserve resulted in a
$2 million
decrease in fair value in operating revenue and cost of operations. As of
December 31, 2016
, the credit reserve resulted in an
$11 million
decrease in fair value in operating revenue and cost of operations.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in
Note 2
,
Summary of Significant Accounting Policies
, to the Company's
2016
Form 10-K, the following is a discussion of the concentration of credit risk for the Company's contractual obligations. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities.
Counterparty Credit Risk
The Company's counterparty credit risk policies are disclosed in its
2016
Form 10-K. As of
March 31, 2017
, the Company's counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was
$191 million
with net exposure of
$188 million
. NRG held collateral (cash and letters of credit) against those positions of
$3 million
. Approximately
76%
of the Company's exposure before collateral is expected to roll off by the end of
2018
. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.
|
|
|
|
|
Net Exposure
(a) (b)
|
Category by Industry Sector
|
(% of Total)
|
Utilities, energy merchants, marketers and other
|
91
|
%
|
Financial institutions
|
9
|
|
Total as of March 31, 2017
|
100
|
%
|
|
|
|
|
|
Net Exposure
(a) (b)
|
Category by Counterparty Credit Quality
|
(% of Total)
|
Investment grade
|
87
|
%
|
Non-Investment grade/Non-Rated
|
13
|
|
Total as of March 31, 2017
|
100
|
%
|
|
|
(a)
|
Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.
|
|
|
(b)
|
The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts.
|
NRG has counterparty credit risk exposure to certain counterparties, each of which represent more than
10%
of total net exposure discussed above. The aggregate of such counterparties' exposure was
$72 million
as of
March 31, 2017
. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.
RTOs and ISOs
The Company participates in the organized markets of CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in these markets is approved by FERC, or in the case of ERCOT, approved by the PUCT and includes credit policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s share of overall market and are excluded from the above exposures.
Exchange Traded Transactions
The Company enters into commodity transactions on registered exchanges, notably ICE and NYMEX. These clearinghouses act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity transactions have limited counterparty credit risk.
Long Term Contracts
Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, Gulf Coast load obligations, and wind and solar PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company estimates its credit exposure for these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of
March 31, 2017
, aggregate credit risk exposure managed by NRG to these counterparties was approximately
$4.4 billion
, including
$2.9 billion
related to assets of NRG Yield, Inc., for the next
five
years. This amount excludes potential credit exposures for projects with long-term PPAs that have not reached commercial operations. The majority of these power contracts are with utilities or public power entities with strong credit quality and public utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in government regulations, which NRG is unable to predict.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through the Company's retail electricity providers, which serve commercial, industrial and governmental/institutional customers and the Mass market. Retail credit risk results when a customer fails to pay for products or services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of
March 31, 2017
, the Company believes its retail customer credit exposure was diversified across many customers and various industries, as well as government entities.
Note 5
—
Nuclear Decommissioning Trust Fund
This footnote should be read in conjunction with the complete description under
Note 6
,
Nuclear Decommissioning Trust Fund
, to the Company's
2016
Form 10-K.
NRG's Nuclear Decommissioning Trust Fund assets are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980,
Regulated Operations
, because the Company's nuclear decommissioning activities are subject to approval by the PUCT with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to nuclear decommissioning trust liability and are not included in net income or accumulated OCI, consistent with regulatory treatment.
The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2017
|
|
As of December 31, 2016
|
(In millions, except otherwise noted)
|
Fair Value
|
|
Unrealized Gains
|
|
Unrealized Losses
|
|
Weighted-average Maturities (In years)
|
|
Fair Value
|
|
Unrealized Gains
|
|
Unrealized Losses
|
|
Weighted-average Maturities (In years)
|
Cash and cash equivalents
|
$
|
16
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
25
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—
|
|
U.S. government and federal agency obligations
|
56
|
|
|
2
|
|
|
—
|
|
|
9
|
|
|
73
|
|
|
1
|
|
|
—
|
|
|
11
|
|
Federal agency mortgage-backed securities
|
67
|
|
|
1
|
|
|
1
|
|
|
24
|
|
|
62
|
|
|
1
|
|
|
1
|
|
|
25
|
|
Commercial mortgage-backed securities
|
17
|
|
|
—
|
|
|
1
|
|
|
26
|
|
|
17
|
|
|
—
|
|
|
1
|
|
|
26
|
|
Corporate debt securities
|
100
|
|
|
1
|
|
|
1
|
|
|
10
|
|
|
84
|
|
|
1
|
|
|
2
|
|
|
11
|
|
Equity securities
|
367
|
|
|
233
|
|
|
—
|
|
|
—
|
|
|
346
|
|
|
214
|
|
|
—
|
|
|
—
|
|
Foreign government fixed income securities
|
4
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
9
|
|
Total
|
$
|
627
|
|
|
$
|
237
|
|
|
$
|
3
|
|
|
|
|
$
|
610
|
|
|
$
|
217
|
|
|
$
|
4
|
|
|
|
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
|
2017
|
|
2016
|
|
(In millions)
|
Realized gains
|
$
|
2
|
|
|
$
|
4
|
|
Realized losses
|
2
|
|
|
3
|
|
Proceeds from sale of securities
|
117
|
|
|
191
|
|
Note 6
—
Accounting for Derivative Instruments and Hedging Activities
This footnote should be read in conjunction with the complete description under
Note 5
,
Accounting for Derivative Instruments and Hedging Activities
, to the Company's
2016
Form 10-K.
Energy-Related Commodities
As of
March 31, 2017
, NRG had energy-related derivative instruments extending through
2031
. The Company marks these derivatives to market through the statement of operations.
Interest Rate Swaps
NRG is exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of
March 31, 2017
, the Company had interest rate derivative instruments on recourse debt extending through 2021, which are not designated as cash flow hedges. The Company had interest rate swaps on non-recourse debt extending through
2036
, most of which are designated as cash flow hedges.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of
March 31, 2017
and
December 31, 2016
. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.
|
|
|
|
|
|
|
|
|
|
|
|
Total Volume
|
|
|
March 31, 2017
|
|
December 31, 2016
|
Category
|
Units
|
(In millions)
|
Emissions
|
Short Ton
|
(4
|
)
|
|
—
|
|
Coal
|
Short Ton
|
32
|
|
|
41
|
|
Natural Gas
|
MMBtu
|
162
|
|
|
85
|
|
Oil
|
Barrel
|
—
|
|
|
1
|
|
Power
|
MWh
|
(12
|
)
|
|
(28
|
)
|
Capacity
|
MW/Day
|
(1
|
)
|
|
(1
|
)
|
Interest
|
Dollars
|
$
|
3,369
|
|
|
$
|
3,429
|
|
Equity
|
Shares
|
1
|
|
|
1
|
|
The increase in the natural gas position was primarily the result of additional generation and retail hedge positions.
Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on the balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
March 31, 2017
|
|
December 31, 2016
|
|
March 31, 2017
|
|
December 31, 2016
|
|
(In millions)
|
Derivatives designated as cash flow hedges:
|
|
|
|
|
|
|
|
Interest rate contracts current
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
22
|
|
|
$
|
28
|
|
Interest rate contracts long-term
|
12
|
|
|
12
|
|
|
31
|
|
|
41
|
|
Total derivatives designated as cash flow hedges
|
12
|
|
|
12
|
|
|
53
|
|
|
69
|
|
Derivatives not designated as cash flow hedges
:
|
|
|
|
|
|
|
|
Interest rate contracts current
|
3
|
|
|
—
|
|
|
8
|
|
|
7
|
|
Interest rate contracts long-term
|
35
|
|
|
37
|
|
|
16
|
|
|
12
|
|
Commodity contracts current
|
679
|
|
|
1,062
|
|
|
717
|
|
|
1,049
|
|
Commodity contracts long-term
|
179
|
|
|
140
|
|
|
268
|
|
|
241
|
|
Total derivatives not designated as cash flow hedges
|
896
|
|
|
1,239
|
|
|
1,009
|
|
|
1,309
|
|
Total derivatives
|
$
|
908
|
|
|
$
|
1,251
|
|
|
$
|
1,062
|
|
|
$
|
1,378
|
|
The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the offsetting of derivatives by counterparty master agreement level and collateral received or paid:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts Not Offset in the Statement of Financial Position
|
|
|
Gross Amounts of Recognized Assets / Liabilities
|
|
Derivative Instruments
|
|
Cash Collateral (Held) / Posted
|
|
Net Amount
|
As of March 31, 2017
|
|
(In millions)
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
$
|
858
|
|
|
$
|
(732
|
)
|
|
$
|
(2
|
)
|
|
$
|
124
|
|
Derivative liabilities
|
|
(985
|
)
|
|
732
|
|
|
64
|
|
|
(189
|
)
|
Total commodity contracts
|
|
(127
|
)
|
|
—
|
|
|
62
|
|
|
(65
|
)
|
Interest rate contracts:
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
50
|
|
|
(4
|
)
|
|
—
|
|
|
46
|
|
Derivative liabilities
|
|
(77
|
)
|
|
4
|
|
|
—
|
|
|
(73
|
)
|
Total interest rate contracts
|
|
(27
|
)
|
|
—
|
|
|
—
|
|
|
(27
|
)
|
Total derivative instruments
|
|
$
|
(154
|
)
|
|
$
|
—
|
|
|
$
|
62
|
|
|
$
|
(92
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts Not Offset in the Statement of Financial Position
|
|
|
Gross Amounts of Recognized Assets / Liabilities
|
|
Derivative Instruments
|
|
Cash Collateral (Held) / Posted
|
|
Net Amount
|
As of December 31, 2016
|
|
(In millions)
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
$
|
1,202
|
|
|
$
|
(1,005
|
)
|
|
$
|
(1
|
)
|
|
$
|
196
|
|
Derivative liabilities
|
|
(1,290
|
)
|
|
1,005
|
|
|
14
|
|
|
(271
|
)
|
Total commodity contracts
|
|
(88
|
)
|
|
—
|
|
|
13
|
|
|
(75
|
)
|
Interest rate contracts:
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
49
|
|
|
(4
|
)
|
|
—
|
|
|
45
|
|
Derivative liabilities
|
|
(88
|
)
|
|
4
|
|
|
—
|
|
|
(84
|
)
|
Total interest rate contracts
|
|
(39
|
)
|
|
—
|
|
|
—
|
|
|
(39
|
)
|
Total derivative instruments
|
|
$
|
(127
|
)
|
|
$
|
—
|
|
|
$
|
13
|
|
|
$
|
(114
|
)
|
Accumulated Other Comprehensive Loss
The following table summarizes the effects of ASC 815 on the Company's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2017
|
|
Interest Rate
|
|
Total
|
|
(In millions)
|
Accumulated OCI beginning balance
|
$
|
(66
|
)
|
|
$
|
(66
|
)
|
Reclassified from accumulated OCI to income:
|
|
|
|
Due to realization of previously deferred amounts
|
3
|
|
|
3
|
|
Mark-to-market of cash flow hedge accounting contracts
|
2
|
|
|
2
|
|
Accumulated OCI ending balance, net of $14 tax
|
$
|
(61
|
)
|
|
$
|
(61
|
)
|
Losses expected to be realized from OCI during the next 12 months, net of $4 tax
|
$
|
(15
|
)
|
|
$
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2016
|
|
Interest Rate
|
|
Total
|
|
(In millions)
|
Accumulated OCI beginning balance
|
$
|
(101
|
)
|
|
$
|
(101
|
)
|
Reclassified from accumulated OCI to income:
|
|
|
|
Due to realization of previously deferred amounts
|
3
|
|
|
3
|
|
Mark-to-market of cash flow hedge accounting contracts
|
(52
|
)
|
|
(52
|
)
|
Accumulated OCI ending balance, net of $24 tax
|
$
|
(150
|
)
|
|
$
|
(150
|
)
|
Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to interest expense for interest rate contracts. There was
no
ineffectiveness for the
three
months ended
March 31, 2017
and
2016
.
Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of December 31, 2016, the Company's regression analysis for Viento Funding II interest rate swaps, while positively correlated, did not meet the required threshold for cash flow hedge accounting. As a result, the Company de-designated the Viento Funding II cash flow hedges as of December 31, 2016, and will prospectively mark these derivatives to market through the income statement.
Impact of Derivative Instruments on the Statements of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges and ineffectiveness of hedge derivatives are reflected in current period consolidated results of operations.
The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges and trading activity on the Company's statement of operations. The effect of energy commodity contracts is included within operating revenues and cost of operations and the effect of interest rate contracts is included in interest expense.
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
|
2017
|
|
2016
|
Unrealized mark-to-market results
|
(In millions)
|
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges
|
$
|
16
|
|
|
$
|
(86
|
)
|
Reversal of acquired loss/(gain) positions related to economic hedges
|
2
|
|
|
(13
|
)
|
Net unrealized (losses)/gains on open positions related to economic hedges
|
(24
|
)
|
|
134
|
|
Total unrealized mark-to-market (losses)/gains for economic hedging activities
|
(6
|
)
|
|
35
|
|
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity
|
(15
|
)
|
|
8
|
|
Net unrealized gains on open positions related to trading activity
|
1
|
|
|
11
|
|
Total unrealized mark-to-market (losses)/gains for trading activity
|
(14
|
)
|
|
19
|
|
Total unrealized (losses)/gains
|
$
|
(20
|
)
|
|
$
|
54
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
|
2017
|
|
2016
|
|
(In millions)
|
Unrealized gains included in operating revenues
|
$
|
114
|
|
|
$
|
45
|
|
Unrealized (losses)/gains included in cost of operations
|
(134
|
)
|
|
9
|
|
Total impact to statement of operations — energy commodities
|
$
|
(20
|
)
|
|
$
|
54
|
|
Total impact to statement of operations — interest rate contracts
|
$
|
5
|
|
|
$
|
(11
|
)
|
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in operating revenue or cost of operations during the same period.
For the
three
months ended
March 31, 2017
, the
$24 million
unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases of natural gas, coal, and ERCOT electricity due to decreases in natural gas, coal and ERCOT electricity prices.
For the
three
months ended
March 31, 2016
, the
$134 million
unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward sales of power due to decreases in electricity prices partially offset by a decrease in value of forward purchases of coal due to decreases in coal prices.
Credit Risk Related Contingent Features
Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or requires the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of
March 31, 2017
, was
$38 million
. The collateral required for contracts with credit rating contingent features as of
March 31, 2017
, was
$33 million
. The Company is also a party to certain marginable agreements where NRG has a net liability position, but the counterparty has not called for the collateral due, which was approximately
$4 million
as of
March 31, 2017
.
See
Note 4
,
Fair Value of Financial Instruments
, to this Form 10-Q for discussion regarding concentration of credit risk.
Note 7
—
Impairments
2016 Impairment Loss
Petra Nova Parish Holdings
—
During the first quarter of 2016, management changed its plans with respect to its future capital commitments driven in part by the continued decline in oil prices. As a result, the Company reviewed its
50%
interest in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value, the Company utilized an income approach and considered project specific assumptions for the future project cash flows. The carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that the decline is considered to be other than temporary. As a result, the Company measured the impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of
$140 million
.
Note 8
—
Debt and Capital Leases
This footnote should be read in conjunction with the complete description under
Note 12
,
Debt and Capital Leases
, to the Company's
2016
Form 10-K. Long-term debt and capital leases consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
(In millions, except rates)
|
|
March 31, 2017
|
|
December 31, 2016
|
|
March 31, 2017 interest rate %
(a)
|
|
|
|
Recourse debt:
|
|
|
|
|
|
|
Senior notes, due 2018
|
|
$
|
398
|
|
|
$
|
398
|
|
|
7.625
|
Senior notes, due 2021
|
|
207
|
|
|
207
|
|
|
7.875
|
Senior notes, due 2022
|
|
992
|
|
|
992
|
|
|
6.250
|
Senior notes, due 2023
|
|
869
|
|
|
869
|
|
|
6.625
|
Senior notes, due 2024
|
|
733
|
|
|
733
|
|
|
6.250
|
Senior notes, due 2026
|
|
1,000
|
|
|
1,000
|
|
|
7.250
|
Senior notes, due 2027
|
|
1,250
|
|
|
1,250
|
|
|
6.625
|
Term loan facility, due 2023
|
|
1,886
|
|
|
1,891
|
|
|
L+2.25
|
Revolving credit facility, due 2018 and 2021
|
|
125
|
|
|
—
|
|
|
L+2.25
|
Tax-exempt bonds
|
|
455
|
|
|
455
|
|
|
4.125 - 6.00
|
Subtotal NRG recourse debt
|
|
7,915
|
|
|
7,795
|
|
|
|
Non-recourse debt:
|
|
|
|
|
|
|
GenOn senior notes
|
|
1,830
|
|
|
1,830
|
|
|
7.875 - 9.875
|
GenOn Americas Generation senior notes
|
|
695
|
|
|
695
|
|
|
8.500 - 9.125
|
GenOn other
|
|
95
|
|
|
96
|
|
|
|
Subtotal GenOn debt (non-recourse to NRG)
|
|
2,620
|
|
|
2,621
|
|
|
|
NRG Yield Operating LLC Senior Notes, due 2024
|
|
500
|
|
|
500
|
|
|
5.375
|
NRG Yield Operating LLC Senior Notes, due 2026
|
|
350
|
|
|
350
|
|
|
5.000
|
NRG Yield Inc. Convertible Senior Notes, due 2019
|
|
345
|
|
|
345
|
|
|
3.500
|
NRG Yield Inc. Convertible Senior Notes, due 2020
|
|
288
|
|
|
288
|
|
|
3.250
|
El Segundo Energy Center, due 2023
|
|
414
|
|
|
443
|
|
|
L+1.625 - L+2.25
|
Marsh Landing, due 2017 and 2023
|
|
361
|
|
|
370
|
|
|
L+1.750 - L+1.875
|
Alta Wind I - V lease financing arrangements, due 2034 and 2035
|
|
965
|
|
|
965
|
|
|
5.696 - 7.015
|
Walnut Creek, term loans due 2023
|
|
303
|
|
|
310
|
|
|
L+1.625
|
Utah Portfolio, due 2022
|
|
287
|
|
|
287
|
|
|
L+2.65
|
Tapestry, due 2021
|
|
168
|
|
|
172
|
|
|
L+1.625
|
CVSR, due 2037
|
|
757
|
|
|
771
|
|
|
2.339 - 3.775
|
CVSR HoldCo, due 2037
|
|
194
|
|
|
199
|
|
|
4.680
|
Alpine, due 2022
|
|
144
|
|
|
145
|
|
|
L+1.750
|
Energy Center Minneapolis, due 2017 and 2025
|
|
94
|
|
|
96
|
|
|
5.95 - 7.25
|
Energy Center Minneapolis, due 2031
|
|
125
|
|
|
125
|
|
|
3.55
|
Viento, due 2023
|
|
178
|
|
|
178
|
|
|
L+2.75
|
NRG Yield - other
|
|
578
|
|
|
540
|
|
|
various
|
Subtotal NRG Yield debt (non-recourse to NRG)
|
|
6,051
|
|
|
6,084
|
|
|
|
Ivanpah, due 2033 and 2038
|
|
1,108
|
|
|
1,113
|
|
|
2.285 - 4.256
|
Agua Caliente, due 2037
|
|
846
|
|
|
849
|
|
|
2.395 - 3.633
|
Agua Caliente Borrower 1, due 2038
|
|
89
|
|
|
—
|
|
|
5.430
|
Cedro Hill, due 2025
|
|
161
|
|
|
163
|
|
|
L+1.75
|
Midwest Generation, due 2019
|
|
213
|
|
|
231
|
|
|
4.390
|
NRG Other
|
|
462
|
|
|
468
|
|
|
various
|
Subtotal other NRG non-recourse debt
|
|
2,879
|
|
|
2,824
|
|
|
|
Subtotal all non-recourse debt
|
|
11,550
|
|
|
11,529
|
|
|
|
Subtotal long-term debt (including current maturities)
|
|
19,465
|
|
|
19,324
|
|
|
|
Capital leases
|
|
12
|
|
|
8
|
|
|
various
|
Subtotal long-term debt and capital leases (including current maturities)
|
|
19,477
|
|
|
19,332
|
|
|
|
Less current maturities
|
|
(1,688
|
)
|
|
(1,220
|
)
|
|
|
Less debt issuance costs
|
|
(191
|
)
|
|
(188
|
)
|
|
|
Premiums, net of discounts
|
|
74
|
|
|
82
|
|
|
|
Total long-term debt and capital leases
|
|
$
|
17,672
|
|
|
$
|
18,006
|
|
|
|
(a) As of
March 31, 2017
, L+ equals
3 month LIBOR
plus x%, with the exception of the Viento Funding II term loan, the Utah Portfolio term loans, the Alpine Term Loan, the NRG Marsh Landing term loan, the Walnut Creek term loan, the 2023 Term Loan Facility, and the Revolving credit facility which are
1 month LIBOR
plus x%.
Recourse Debt
Revolving Credit Facility
On January 27, 2017, GenOn Mid-Atlantic entered into an agreement with Natixis Funding Corp., or Natixis, under which Natixis will procure payment and credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson. GenOn Mid-Atlantic made a payment of
$130 million
plus fees of
$1 million
as consideration for Natixis applying for the issuance of, and obtaining, letters of credit from Natixis, New York Branch, the LC Provider, to support the lease payments. Natixis is solely responsible for (i) obtaining letters of credit from the LC Provider, (ii) causing the letters of credit to be issued to the lessors to support the lease payments on behalf of GenOn Mid-Atlantic, (iii) making lease payments and (iv) satisfying any reimbursement obligations payable to the LC Provider. The payment is reflected as a long-term deposit on the Company's consolidated balance sheet as of March 31, 2017.
On February 24, 2017, GenOn Mid-Atlantic received a series of notices from certain of the owner lessors under its operating leases of the Morgantown coal generation unit alleging default, or Notices. The Notices allege the existence of lease events of default as a result of, among other items, the purported failure by GenOn Mid-Atlantic to comply with a covenant requiring the maintenance of qualifying credit support. The Notices instructed the relevant trustees to draw on letters of credit under the secured intercompany revolving credit agreement between NRG and GenOn, supporting the GenOn Mid-Atlantic operating leases that were set to expire on February 28, 2017. The offset was recorded to other non-current assets under the related operating leases pending resolution of the matter which is further described below. On February 28, 2017, the trustees drew on the letters of credit under NRG's revolving credit facility, which resulted in borrowings of
$125 million
. Upon notification, GenOn became obligated under the secured intercompany revolving credit agreement between NRG and GenOn. GenOn requested Genon Mid-Atlantic repay the related amount borrowed under the secured intercompany revolving credit agreement. GenOn Mid-Atlantic is unaware of whether any further action will be taken by the owner lessors or any other person in connection with the Notices. GenOn Mid-Atlantic disagrees with the owner lessors as to the existence of any lease events of default and/or any breaches by GenOn Mid-Atlantic of any terms and conditions of the operating leases and believes that the declaration of a lease event of default, the instruction to draw on the letters of credit under the secured intercompany revolving credit agreement between NRG and GenOn and the draws thereon constituted a violation by the owner lessors and the relevant trustees of the terms and conditions of the GenOn Mid-Atlantic operating leases. GenOn Mid-Atlantic intends to vigorously pursue its rights and remedies in connection with these actions. On March 7, 2017, GenOn Mid-Atlantic filed a complaint in the Supreme Court for the State of New York against the owner lessors of the Morgantown and Dickerson facilities and U.S. Bank National Association in its capacity as the indenture trustee. The complaint seeks,
inter alia
, a declaratory judgment that no lease events of default exist and asserts counts for breach of contract, conversion, tortious interference, breach of the implied covenant of good faith and fair dealing, unjust enrichment, constructive trust, and injunctive relief. The defendants in this action have not yet responded to the complaint and have until June 5, 2017 to do so. The court has set an initial conference hearing for June 12, 2017.
2023 Term Loan Facility
On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to
LIBOR
plus
2.25%
. The
LIBOR
floor remains
0.75%
.
Non-recourse Debt
GenOn Senior Notes
As disclosed in
Note 1
,
Basis of Presentation
, as of
March 31, 2017
,
$691 million
of GenOn's Senior Notes, excluding
$4 million
of associated premiums, of GenOn's Senior Notes outstanding are classified as current within the consolidated balance sheet as they mature on June 15, 2017. GenOn is currently considering all options available to it, including negotiations with creditors and lessors, refinancing the Senior Notes, potential sales of certain generating assets as well as the possibility of a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. If GenOn is unable to enter into a settlement with its creditors, refinance the senior notes or otherwise raise or generate sufficient capital, GenOn is not expected to have sufficient liquidity to repay the GenOn Senior Notes due in June 2017. Pending resolution, there is substantial doubt about GenOn's ability to continue as a going concern.
During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process. On April 7, 2017, GenOn also appointed a new dedicated chief executive officer, effective immediately. Any resolution may have a material impact on the Company's statement of operations, cash flows and financial position.
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility
NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, entered into a senior secured revolving credit facility, which can be used for cash and for the issuance of letters of credit. At
March 31, 2017
, there was
$64 million
of letters of credit issued under the revolving credit facility and
no
borrowing outstanding on the revolver.
Project Financings
Agua Caliente Project Financing
On February 17, 2017, Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC, or Agua Caliente Holdco, the indirect owners of
51%
of the Agua Caliente solar facility, issued
$130 million
of senior secured notes under the Agua Caliente Holdco Financing Agreement, or 2038 Agua Caliente Holdco Notes, that bear interest at
5.43%
and mature on December 31, 2038. As described in
Note 3
,
Dispositions
, on March 27, 2017, NRG Yield, Inc. acquired Agua Caliente Borrower 2 LLC from NRG. The debt is joint and several with respect to Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC and is secured by the equity interests of each borrower in the Agua Caliente solar facility.
Note 9
—
Variable Interest Entities, or VIEs
Entities that are not Consolidated
NRG has interests in entities that are considered VIEs under ASC 810,
Consolidation
, but NRG is not considered the primary beneficiary. NRG accounts for its interests in these entities under the equity method of accounting.
GenConn Energy LLC
—
Through its consolidated subsidiary, NRG Yield Operating LLC, the Company owns a
50%
interest in GCE Holding LLC, the owner of GenConn, which owns and operates
two
190
MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its equity investment, which was
$104 million
as of
March 31, 2017
.
Entities that are Consolidated
The Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax credits as further described in
Note 2
,
Summary of Significant Accounting Policies
to the Company's
2016
Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to
$88 million
as of
March 31, 2017
, which would be required to be funded if the arrangement were to be dissolved.
The summarized financial information for the Company's consolidated VIEs consisted of the following:
|
|
|
|
|
|
|
|
|
(In millions)
|
March 31, 2017
|
|
December 31, 2016
|
Current assets
|
$
|
90
|
|
|
$
|
87
|
|
Net property, plant and equipment
|
1,513
|
|
|
1,534
|
|
Other long-term assets
|
948
|
|
|
954
|
|
Total assets
|
2,551
|
|
|
2,575
|
|
Current liabilities
|
59
|
|
|
59
|
|
Long-term debt
|
439
|
|
|
442
|
|
Other long-term liabilities
|
185
|
|
|
183
|
|
Total liabilities
|
683
|
|
|
684
|
|
Noncontrolling interests
|
535
|
|
|
529
|
|
Net assets less noncontrolling interests
|
$
|
1,333
|
|
|
$
|
1,362
|
|
Note 10
—
Changes in Capital Structure
As of
March 31, 2017
and
December 31, 2016
, the Company had
500,000,000
shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:
|
|
|
|
|
|
|
|
|
|
|
Issued
|
|
Treasury
|
|
Outstanding
|
Balance as of December 31, 2016
|
417,583,825
|
|
|
(102,140,814
|
)
|
|
315,443,011
|
|
Shares issued under LTIPs
|
355,047
|
|
|
—
|
|
|
355,047
|
|
Shares issued under ESPP
|
—
|
|
|
282,530
|
|
|
282,530
|
|
Balance as of March 31, 2017
|
417,938,872
|
|
|
(101,858,284
|
)
|
|
316,080,588
|
|
Amended and Restated Employee Stock Purchase Plan
As of
March 31, 2017
, there were
385,289
shares of treasury stock available for issuance under the ESPP. On April 27, 2017, NRG stockholders approved an increase of
3,000,000
shares available for issuance under the ESPP.
Amended and Restated Long-term Incentive Plan
On April 27, 2017, NRG stockholders approved an increase of
3,000,000
shares available for issuance under the NRG Energy, Inc. Amended and Restated Long-term Incentive Plan.
NRG Common Stock Dividends
The following table lists the dividends paid during the three months ended
March 31, 2017
:
|
|
|
|
|
|
First Quarter 2017
|
Dividends per Common Share
|
$
|
0.030
|
|
On
April 7, 2017
, NRG declared a quarterly dividend on the Company's common stock of
$0.03
per share, payable
May 15, 2017
, to stockholders of record as of
May 1, 2017
, representing
$0.12
per share on an annualized basis.
The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.
Note 11
—
Earnings/(Loss) Per Share
Basic earnings/(loss) per common share is computed by dividing net income/(loss) less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings/(loss) per share is computed in a manner consistent with that of basic income/(loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period. During the second quarter of 2016, the Company repurchased
100%
of the outstanding shares of its
2.822%
preferred stock. The reconciliation of NRG's basic and diluted earnings/(loss) per share is shown in the following table:
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
(In millions, except per share data)
|
2017
|
|
2016
|
Basic (loss)/earnings per share attributable to NRG Energy, Inc. common stockholders
|
Net (loss)/income attributable to NRG Energy, Inc.
|
$
|
(163
|
)
|
|
$
|
82
|
|
Dividends for preferred shares
|
—
|
|
|
5
|
|
(Loss)/income available for common stockholders
|
$
|
(163
|
)
|
|
$
|
77
|
|
Weighted average number of common shares outstanding - basic
|
316
|
|
|
315
|
|
(Loss)/Earnings per weighted average common share — basic
|
$
|
(0.52
|
)
|
|
$
|
0.24
|
|
Diluted (loss)/earnings per share attributable to NRG Energy, Inc. common stockholders
|
Weighted average number of common shares outstanding - diluted
|
316
|
|
|
315
|
|
Incremental shares attributable to the issuance of equity compensation (treasury stock method)
|
—
|
|
|
—
|
|
Total dilutive shares
|
316
|
|
|
315
|
|
(Loss)/earnings per weighted average common share — diluted
|
$
|
(0.52
|
)
|
|
$
|
0.24
|
|
The following table summarizes NRG’s outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted loss per share:
|
|
|
|
|
|
|
|
Three months ended March 31,
|
(In millions of shares)
|
2017
|
|
2016
|
Equity compensation plans
|
6
|
|
|
4
|
|
Embedded derivative of 2.822% redeemable perpetual preferred stock
|
—
|
|
|
16
|
|
Total
|
6
|
|
|
20
|
|
Note 12
—
Segment Reporting
The Company's segment structure reflects how management currently makes financial decisions and allocates resources. The Company's businesses are segregated as follows: Generation, which includes generation, international and BETM; Retail, which includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. Intersegment sales are accounted for at market prices. The financial information for the
three
months ended
March 31, 2016
has been recast to reflect the current segment structure.
On September 1, 2016, NRG Yield acquired the remaining
51.05%
interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, from the Company. On March 27, 2017, NRG Yield acquired from NRG a
16%
interest in the Agua Caliente solar project, and NRG's interests in seven utility-scale solar projects located in Utah. Both acquisitions were treated as a transfer of entities under common control and accordingly, all historical periods have been recast to reflect the acquisition as if they had occurred at the beginning of the financial statement period.
NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and capital for allocation, as well as net income/(loss).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
(a)
|
|
Retail
(a)
|
|
Renewables
(a)(b)
|
|
NRG Yield
|
|
Corporate
(a)
|
|
Eliminations
|
|
Total
|
Three months ended March 31, 2017
|
(In millions)
|
Operating revenues
(a)
|
$
|
1,343
|
|
|
$
|
1,335
|
|
|
$
|
98
|
|
|
$
|
218
|
|
|
$
|
8
|
|
|
$
|
(243
|
)
|
|
$
|
2,759
|
|
Depreciation and amortization
|
138
|
|
|
28
|
|
|
49
|
|
|
75
|
|
|
10
|
|
|
—
|
|
|
300
|
|
Equity in (losses)/earnings of unconsolidated affiliates
|
(13
|
)
|
|
—
|
|
|
(1
|
)
|
|
19
|
|
|
3
|
|
|
(3
|
)
|
|
5
|
|
Gain on sale of assets
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Income/(loss) before income taxes
|
67
|
|
|
(30
|
)
|
|
(37
|
)
|
|
(2
|
)
|
|
(203
|
)
|
|
(2
|
)
|
|
(207
|
)
|
Net Income/(Loss)
|
67
|
|
|
(33
|
)
|
|
(31
|
)
|
|
(1
|
)
|
|
(203
|
)
|
|
(2
|
)
|
|
(203
|
)
|
Net Income/(Loss) attributable to NRG Energy, Inc.
|
$
|
67
|
|
|
$
|
(32
|
)
|
|
$
|
(3
|
)
|
|
$
|
13
|
|
|
$
|
(203
|
)
|
|
$
|
(5
|
)
|
|
$
|
(163
|
)
|
Total assets as of March 31, 2017
|
$
|
12,962
|
|
|
$
|
2,150
|
|
|
$
|
5,123
|
|
|
$
|
8,580
|
|
|
$
|
14,621
|
|
|
$
|
(14,016
|
)
|
|
$
|
29,420
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:
|
$
|
205
|
|
|
$
|
1
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
29
|
|
|
$
|
—
|
|
|
$
|
243
|
|
(b) Includes loss on debt extinguishment
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
(a)
|
|
Retail
(a)
|
|
Renewables
(a)
|
|
NRG Yield
(a)
|
|
Corporate
(a)(b)
|
|
Eliminations
|
|
Total
|
Three months ended March 31, 2016
|
(In millions)
|
Operating revenues
(a)
|
$
|
1,708
|
|
|
$
|
1,370
|
|
|
$
|
96
|
|
|
$
|
234
|
|
|
$
|
18
|
|
|
$
|
(197
|
)
|
|
$
|
3,229
|
|
Depreciation and amortization
|
144
|
|
|
30
|
|
|
48
|
|
|
74
|
|
|
17
|
|
|
—
|
|
|
313
|
|
Impairment losses
|
(137
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
—
|
|
|
(146
|
)
|
Equity in earnings/(loss) of unconsolidated affiliates
|
(8
|
)
|
|
—
|
|
|
(4
|
)
|
|
4
|
|
|
3
|
|
|
(2
|
)
|
|
(7
|
)
|
Gain on sale of assets
|
32
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32
|
|
Income/(Loss) before income taxes
|
191
|
|
|
150
|
|
|
(46
|
)
|
|
2
|
|
|
(231
|
)
|
|
2
|
|
|
68
|
|
Net Income/(Loss)
|
191
|
|
|
150
|
|
|
(40
|
)
|
|
2
|
|
|
(258
|
)
|
|
2
|
|
|
47
|
|
Net Income/(Loss) attributable to NRG Energy, Inc.
|
$
|
191
|
|
|
$
|
150
|
|
|
$
|
(30
|
)
|
|
$
|
10
|
|
|
$
|
(245
|
)
|
|
$
|
6
|
|
|
$
|
82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:
|
$
|
118
|
|
|
$
|
3
|
|
|
$
|
6
|
|
|
$
|
4
|
|
|
$
|
66
|
|
|
$
|
—
|
|
|
$
|
197
|
|
(b) Includes gain on debt extinguishment
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11
|
|
|
$
|
—
|
|
|
$
|
11
|
|
Note 13
—
Income Taxes
Effective Tax Rate
The income tax provision consisted of the following:
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
(In millions except otherwise noted)
|
2017
|
|
2016
|
Income/(loss) before income taxes
|
$
|
(207
|
)
|
|
$
|
68
|
|
Income tax (benefit)/expense
|
(4
|
)
|
|
21
|
|
Effective tax rate
|
1.9
|
%
|
|
30.9
|
%
|
For the
three
months ended
March 31, 2017
, NRG's overall effective tax rate was different than the statutory rate of
35%
primarily due to the change in valuation allowance partially offset by the generation of PTCs and ITCs from various wind and solar facilities, respectively and current state tax expense.
For the
three
months ended
March 31, 2016
, NRG's overall effective tax rate was different than the statutory rate of
35%
primarily due to the change in the valuation allowance, partially offset by the recording of a deferred tax liability associated with the amortization of indefinite lived assets.
Uncertain Tax Benefits
As of
March 31, 2017
, NRG has recorded a non-current tax liability of
$38 million
for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the
three
months ended
March 31, 2017
, NRG accrued
$0.2 million
of interest relating to the uncertain tax benefits. As of
March 31, 2017
, NRG had cumulative interest and penalties related to these uncertain tax benefits of
$3 million
. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.
NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is not subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years before 2010. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.
Note 14
—
Commitments and Contingencies
This footnote should be read in conjunction with the complete description under
Note 22
,
Commitments and Contingencies
, to the Company's
2016
Form 10-K.
Commitments
First Lien Structure
— NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets that have project-level financing, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of
March 31, 2017
, hedges under the first liens were
out-of-the-money
for NRG on a counterparty aggregate basis.
Ivanpah Energy Production Guarantee
— The Company's PPAs with PG&E with respect to the Ivanpah plant contain provisions for contract quantity and guaranteed energy production, which require that Ivanpah units 1 and 3 deliver to PG&E no less than the guaranteed energy production amount specified in the PPAs in any period of twenty-four consecutive months, or performance measurement period, during the term of the PPAs. In January 2017, the Company and PG&E executed amendments to the PPAs that provide, among other things, the ability to cure any failure to meet the guaranteed energy production amounts through performance and liquidated damage provisions. On February 2, 2017, PG&E filed a request with the CPUC to approve the amendments. On April 5, 2017, the CPUC issued a draft resolution proposing approval of the amendments without modification. Pending final and nonappealable CPUC approval, PG&E agreed to refrain from declaring any event of default with respect to any failure to deliver the guaranteed energy production amounts.
Lignite Contract with Texas Westmoreland Coal Co.
— The Company has a contract with TWCC for reclamation activities associated with closure of the Jewett mine. NRG is responsible for reclamation costs and has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of
$95.5 million
on TWCC for the reclamation of the mine. Pursuant to the contract with TWCC, NRG supports this obligation through surety bonds. Additionally, NRG is obligated to provide additional performance assurance if required by the Railroad Commission of Texas.
Contingencies
The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, the Company has established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
Midwest Generation Asbestos Liabilities
— The Company, through its subsidiary, Midwest Generation, may be subject to potential asbestos liabilities as a result of its acquisition of EME. The Company is currently analyzing the scope of potential liability as it may relate to Midwest Generation. The Company believes that it has established an adequate reserve for these cases.
Actions Pursued by MC Asset Recovery
— With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings. MC Asset Recovery is governed by a manager who is independent of NRG and GenOn. MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings. In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants. In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit, or the Fifth Circuit. In March 2012, the Fifth Circuit reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. On December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29, 2015, MC Asset Recovery filed a notice to appeal this judgment with the Fifth Circuit. The appeal has been fully briefed by the parties and was argued before the Fifth Circuit on February 8, 2017.
Natural Gas Litigation
—
GenOn is party to several lawsuits, certain of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of state antitrust law and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of Nevada, which was handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, which reversed the decision of the District Court. GenOn along with the other defendants in the lawsuit filed a petition for a writ of certiorari to the U.S. Supreme Court challenging the Ninth Circuit's decision and the U.S. Supreme Court granted the petition. On April 21, 2015, the U.S. Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution. The U.S. Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. Supreme Court directed that the case be remanded to the U.S. District Court for the District of Nevada for further proceedings. On March 7, 2016, class plaintiffs filed their motions for class certification. Defendants filed their briefs in opposition to class plaintiffs' motions for class certification on June 24, 2016. On March 30, 2017, the court denied the plaintiffs' motions for class certification. On April 13, 2017, the plaintiffs petitioned the Ninth Circuit for interlocutory review of the court’s order denying class certification.
In May 2016 in one of the Kansas cases, the U.S. District Court for the District of Nevada granted the defendants' motion for summary judgment. Subsequently in December 2016, the plaintiffs filed a notice of appeal with the Ninth Circuit. On March 28, 2017, plaintiffs filed their appellate brief. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.
In September 2012, the State of Nevada Supreme Court, which was handling the remaining case, affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffs in the Nevada case filed a petition for a writ of certiorari to the U.S. Supreme Court. In June 2013, the U.S. Supreme Court denied the petition for a writ of certiorari, thereby ending one of the five lawsuits.
Energy Plus Holdings
—
On August 7, 2012, Energy Plus Holdings received a subpoena from the NYAG which generally sought information and business records related to Energy Plus Holdings' sales, marketing and business practices. Energy Plus Holdings provided documents and information to the NYAG. On June 22, 2015, the NYAG issued another subpoena seeking additional information. Energy Plus Holdings provided responsive documents to this second subpoena. The Company does not expect the resolution of this matter to have a material impact on the Company's consolidated financial position, results of operation, or cash flows.
Midwest Generation New Source Review Litigation
— In August 2009, the EPA and the Illinois Attorney General, or the Government Plaintiffs, filed a complaint, or the Governments’ Complaint, in the U.S. District Court for the Northern District of Illinois alleging violations of CAA PSD requirements by Midwest Generation arising from maintenance, repair or replacement projects at six Illinois coal-fired electric generating stations performed by Midwest Generation or ComEd, a prior owner of the stations, including alleged failures to obtain PSD construction permits and to comply with BACT requirements. The Government Plaintiffs also alleged violations of opacity and PM standards at the Midwest Generation plants. Finally, the Government Plaintiffs alleged that Midwest Generation violated certain operating permit requirements under Title V of the CAA allegedly arising from such claimed PSD, opacity and PM emission violations. In addition to seeking penalties of up to
$37,500
per violation, per day, the complaint seeks an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at the units subject to the complaint and other remedies, which could go well beyond the requirements of the CPS. Several environmental groups intervened as plaintiffs in this litigation and filed a complaint, or the Intervenors’ Complaint, which alleged opacity, PM and related Title V violations. Midwest Generation filed a motion to dismiss nine of the ten PSD counts in the Governments’ Complaint, and to dismiss the tenth PSD count to the extent the Governments’ Complaint sought civil penalties for that count. The trial court granted the motion in March 2010.
In June 2010, the Government Plaintiffs and Intervenors each filed an amended complaint. The Governments’ Amended Complaint again alleged that Midwest Generation violated PSD (based upon the same projects as alleged in their original complaint, but adding allegations that the Company was liable as the “successor” to ComEd), Title V and opacity and PM standards. It named EME and ComEd as additional defendants and alleged PSD violations (again, premised on the same projects) against them. The Intervenors’ Amended Complaint named only Midwest Generation as a defendant and alleged Title V and opacity/PM violations, as well as one of the ten PSD violations alleged in the Governments’ Amended Complaint. Midwest Generation again moved to dismiss all but one of the Government Plaintiffs’ PSD claims and the related Title V claims. Midwest Generation also filed a motion to dismiss the PSD claim in the Intervenors’ Amended Complaint and the related Title V claims. In March 2011, the trial court granted Midwest Generation’s partial motion to dismiss the Government Plaintiffs’ PSD claims. The trial court denied Midwest Generation’s motion to dismiss the PSD claim asserted in the Intervenors’ Amended Complaint, but noted that the plaintiffs would be required to convince the court that the statute of limitations should be equitably tolled. The trial court did not address other counts in the amended complaints that allege violations of opacity and PM emission limitations under the Illinois State Implementation Plan and related Title V claims. The trial court also granted the motions to dismiss the PSD claims asserted against EME and ComEd.
Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims, including the dismissal of nine of the ten PSD claims against Midwest Generation and of the PSD claims against the other defendants. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in July 2013. In addition, in 2012, all but one of the environmental groups that had intervened in the case dismissed their claims without prejudice. As a result, only one environmental group remains a plaintiff intervenor in the case. The Company does not expect the resolution of this matter to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.
Potomac River Environmental Investigation
— In March 2013, NRG Potomac River LLC, a subsidiary of GenOn, received notice that the District of Columbia Department of Environment (now renamed the Department of Energy and Environment, or DOEE) was investigating potential discharges to the Potomac River originating from the Potomac River Generating facility site, a site where the generation facility is no longer in operation. In connection with that investigation, DOEE served a civil subpoena on NRG Potomac River LLC requesting information related to the site and potential discharges occurring from the site. NRG Potomac River LLC provided various responsive materials. In January 2016, DOEE advised NRG Potomac River LLC that DOEE believed various environmental violations had occurred as a result of discharges DOEE believes occurred to the Potomac River from the Potomac River Generating facility site and as a result of associated failures to accurately or sufficiently report such discharges. DOEE has indicated it believes that penalties are appropriate in light of the violations. NRG is currently reviewing the information provided by DOEE.
Telephone Consumer Protection Act Purported Class Actions
—
Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC — one in California and two in New Jersey. The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to
$1,500
per plaintiff, actual damages and equitable relief. On July 8, 2016, NRG filed a Rule 11 Motion seeking dismissal of NRG from the California case. The Rule 11 Motion was denied on August 16, 2016. Class certification hearings are scheduled on August 21, 2017 and June 19, 2017 in the New Jersey and California cases respectively.
California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC
— On January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation. In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR. At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not. As such, the plaintiffs have brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions. Plaintiffs generally claim damages of
$1.2 million
per month for the remaining
70
months of the TSA. On April 20, 2016, the defendants filed demurrers in response to the plaintiffs' complaint. The demurrers were granted on June 14, 2016; however, the plaintiffs were allowed to file amended complaints on July 1, 2016. On July 27, 2016, defendants filed demurrers to the amended complaints. On November 18, 2016, the court sustained the demurrers and allowed plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. On April 21, 2017, the court issued an order sustaining the demurrers without leave to amend.
Braun v. NRG Yield, Inc.
— On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the current and former members of its board of directors individually, and other parties in California Superior Court in Kern County, CA. Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. On August 3, 2016, the court approved a stipulation entered into by the parties. The stipulation provided that the plaintiffs would file an amended complaint by August 19, 2016, which they did on August 18, 2016. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On February 24, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on June 15, 2017 and defendants' reply is due on August 14, 2017.
Ahmed v. NRG Energy, Inc. and the NRG Yield Board of Directors
— On September 15, 2016, plaintiffs filed a putative class action lawsuit against NRG Energy, Inc., the directors of NRG Yield, Inc., and other parties in the Delaware Chancery Court. The complaint alleges that the defendants breached their respective fiduciary duties with regard to the recapitalization of NRG Yield, Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s fees and injunctive relief. The defendants filed a motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objection to the motion to dismiss on February 15, 2017. The Defendants' reply was filed on March 24, 2017. Oral argument is scheduled for June 20, 2017.
GenOn Noteholders' Lawsuit
—
On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc.
7.875%
Senior Notes due 2017,
9.500%
Notes due 2018, and
9.875%
Notes due 2020, and the GenOn Americas Generation, LLC
8.50%
Senior Notes due 2021 and
9.125%
Senior Notes due 2031, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims related to a services agreement between NRG and GenOn. Plaintiffs generally seek recovery of all monies paid under the services agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017. The Standstill Agreement terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty by certain current and former officers and directors of GenOn in relation to the management services agreement and the alleged usurpation of corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs generally seek recovery of all monies paid under the services agreement and any other damages that the court deems appropriate. On March 31, 2017, NRG and GenOn filed separate motions to dismiss the complaint, but such motions are superseded by the amended complaint.
Griffoul v. NRG Residential Solar Solutions
— On February 28, 2017, plaintiffs, consisting of New Jersey residential solar customers, filed a purported class action lawsuit in New Jersey state court. Plaintiffs allege violations of the New Jersey Consumer Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar contracts. The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits.
Rice v. NRG
— On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court for the Western District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc. Plaintiffs generally claim personal injury, trespass, nuisance and property damage related to the disposal of coal ash from the Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property.
Note 15
—
Regulatory Matters
This footnote should be read in conjunction with the complete description under
Note 23
,
Regulatory Matters
, to the Company's
2016
Form 10-K.
NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.
In addition to the regulatory proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
National
Zero-Emission Credits for Nuclear Plants in Illinois
— In 2016, the Illinois legislature approved a Zero Emission Credit, or ZEC, program for selected nuclear units in Illinois. In total, the program directs over
$2.5 billion
over
ten
years to nuclear plants in Illinois that would otherwise retire. Pursuant to the legislation
,
the Illinois Power Agency, or IPA, conducts a competitive solicitation to procure ZECs, although both the Governor of Illinois and Exelon have already announced that the ZECs will be awarded to two Exelon-owned nuclear power plants in Illinois. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On February 14, 2017, NRG, along with other companies, filed a complaint in the U.S. District Court for the Northern District of Illinois alleging that the state program is preempted by federal law and in violation of the dormant commerce clause. Another plaintiff group filed a similar complaint on the same day.
Subsequently, on March 31, 2017, NRG, along with other companies, filed a motion for preliminary injunction. On April 10, 2017, Exelon, as an intervenor defendant, and State defendants filed motions to dismiss. The motions are pending before the U.S. District Court.
Zero-Emission Credits for Nuclear Plants in New York
— On August 1, 2016, the NYSPSC issued its Clean Energy Standard, or CES, which provided for ZECs which would provide more than
$7.6 billion
over
12
years in out-of-market subsidy payments to certain selected nuclear generating units in the state. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On October 19, 2016, NRG, along with other companies, filed a complaint in the U.S. District Court for the Southern District of New York, challenging the validity of the NYSPSC action and the ZEC program. On March 29, 2017, the U.S. District Court heard oral arguments on a motion to dismiss filed by defendants.
Current Administration and Changeover at FERC
— FERC is currently without a quorum and cannot issue orders in contested proceedings until a new Commissioner is appointed. FERC continues to issue orders through authority that was delegated by the full Commission to FERC Staff. The legal validity of these actions has been questioned in connection with several of those orders. With a new administration and three vacant positions at FERC, NRG’s business may be affected because its generation fleet is subject to changes in FERC regulatory policy.
Note 16
—
Environmental Matters
This footnote should be read in conjunction with the complete description under
Note 24
,
Environmental Matters
, to the Company's
2016
Form 10-K.
NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. The electric generation industry has been facing requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the new U.S. presidential administration, some of these rules are being reconsidered and reviewed. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the new U.S. presidential administration.
The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SO
2
budgets for four states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.
In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacate the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In December 2015, the D.C. Circuit remanded the MATS rule to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the case in abeyance. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.
Water
In August 2014, the EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are renewed.
Effluent Limitations Guidelines
— In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, fly ash, bottom ash, and flue gas mercury control. The Company estimated that it would have cost approximately
$200 million
over the next eight years (the majority of the cost would be incurred after 2019) to comply with this rule at 11 coal-fired plants. In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed the deadlines. This regulation also has been challenged. The Company expects the legal challenges to be suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company expects to reduce its estimate of the environmental capital expenditures that would be required to comply with permits issued that incorporate the revised guidelines. The Company decides to invest capital for environmental controls based on: the certainty of regulations; evaluation of different technologies; options to convert to gas; and the expected economic returns on the capital. Over the next several years, the Company will decide whether to proceed with these investments at each of the plants as permits are renewed based on, among other things, the legal certainty of the regulation and market conditions at that time.
Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. The Company has evaluated the impact of the new rule on the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of March 31, 2017.
East Region
Burton Island Old Ash Landfill
— In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program, or the VCP. On February 4, 2008, DNREC issued findings that no further action was required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. DNREC approved the Feasibility Study in December 2012. In January 2013, DNREC proposed a remediation plan based on the Feasibility Study. The remediation plan was approved in October 2013. In December 2015, DNREC approved the Company's remediation design and the Company's Long Term Stewardship Plan. The cost of completing the work required by the approved remediation plan is consistent with amounts budgeted in early 2016 and on track for completion in the second quarter of 2017. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in December 2016.
In addition to the VCP, on May 29, 2008, DNREC requested that NRG's Indian River Power LLC participate in the development and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is working with DNREC and other trustees to close out the assessment process.
Note 17
—
Condensed Consolidating Financial Information
As of
March 31, 2017
, the Company had outstanding
$5.4 billion
of Senior Notes due from 2018 to 2027, as shown in
Note 8
,
Debt and Capital Leases
. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, including GenOn and its subsidiaries and NRG Yield, Inc. and its subsidiaries.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of
March 31, 2017
:
|
|
|
|
Ace Energy, Inc.
|
Norwalk Power LLC
|
NRG Operating Services, Inc.
|
Allied Home Warranty GP LLC
|
NRG Advisory Services LLC
|
NRG Oswego Harbor Power Operations Inc.
|
Allied Warranty LLC
|
NRG Affiliate Services Inc.
|
NRG PacGen Inc.
|
Arthur Kill Power LLC
|
NRG Artesian Energy LLC
|
NRG Portable Power LLC
|
Astoria Gas Turbine Power LLC
|
NRG Arthur Kill Operations Inc.
|
NRG Power Marketing LLC
|
Bayou Cove Peaking Power, LLC
|
NRG Astoria Gas Turbine Operations Inc.
|
NRG Reliability Solutions LLC
|
BidURenergy, Inc.
|
NRG Bayou Cove LLC
|
NRG Renter's Protection LLC
|
Cabrillo Power I LLC
|
NRG Business Services LLC
|
NRG Retail LLC
|
Cabrillo Power II LLC
|
NRG Business Solutions LLC
|
NRG Retail Northeast LLC
|
Carbon Management Solutions LLC
|
NRG Cabrillo Power Operations Inc.
|
NRG Rockford Acquisition LLC
|
Cirro Group, Inc.
|
NRG California Peaker Operations LLC
|
NRG Saguaro Operations Inc.
|
Cirro Energy Services, Inc.
|
NRG Cedar Bayou Development Company, LLC
|
NRG Security LLC
|
Clean Edge Energy LLC
|
NRG Connected Home LLC
|
NRG Services Corporation
|
Conemaugh Power LLC
|
NRG Connecticut Affiliate Services Inc.
|
NRG SimplySmart Solutions LLC
|
Connecticut Jet Power LLC
|
NRG Construction LLC
|
NRG South Central Affiliate Services Inc.
|
Cottonwood Development LLC
|
NRG Curtailment Solutions Holdings LLC
|
NRG South Central Generating LLC
|
Cottonwood Energy Company LP
|
NRG Curtailment Solutions, Inc
|
NRG South Central Operations Inc.
|
Cottonwood Generating Partners I LLC
|
NRG Development Company Inc.
|
NRG South Texas LP
|
Cottonwood Generating Partners II LLC
|
NRG Devon Operations Inc.
|
NRG SPV #1 LLC
|
Cottonwood Generating Partners III LLC
|
NRG Dispatch Services LLC
|
NRG Texas C&I Supply LLC
|
Cottonwood Technology Partners LP
|
NRG Distributed Generation PR LLC
|
NRG Texas Gregory LLC
|
Devon Power LLC
|
NRG Dunkirk Operations Inc.
|
NRG Texas Holding Inc.
|
Dunkirk Power LLC
|
NRG El Segundo Operations Inc.
|
NRG Texas LLC
|
Eastern Sierra Energy Company LLC
|
NRG Energy Efficiency-L LLC
|
NRG Texas Power LLC
|
El Segundo Power, LLC
|
NRG Energy Labor Services LLC
|
NRG Warranty Services LLC
|
El Segundo Power II LLC
|
NRG ECOKAP Holdings LLC
|
NRG West Coast LLC
|
Energy Alternatives Wholesale, LLC
|
NRG Energy Services Group LLC
|
NRG Western Affiliate Services Inc.
|
Energy Choice Solutions LLC
|
NRG Energy Services International Inc.
|
O'Brien Cogeneration, Inc. II
|
Energy Plus Holdings LLC
|
NRG Energy Services LLC
|
ONSITE Energy, Inc.
|
Energy Plus Natural Gas LLC
|
NRG Generation Holdings, Inc.
|
Oswego Harbor Power LLC
|
Energy Protection Insurance Company
|
NRG Greenco
|
RE Retail Receivables, LLC
|
Everything Energy LLC
|
NRG Home & Business Solutions LLC
|
Reliant Energy Northeast LLC
|
Forward Home Security, LLC
|
NRG Home Services LLC
|
Reliant Energy Power Supply, LLC
|
GCP Funding Company, LLC
|
NRG Home Solutions LLC
|
Reliant Energy Retail Holdings, LLC
|
Green Mountain Energy Company
|
NRG Home Solutions Product LLC
|
Reliant Energy Retail Services, LLC
|
Gregory Partners, LLC
|
NRG Homer City Services LLC
|
RERH Holdings, LLC
|
Gregory Power Partners LLC
|
NRG Huntley Operations Inc.
|
Saguaro Power LLC
|
Huntley Power LLC
|
NRG HQ DG LLC
|
Somerset Operations Inc.
|
Independence Energy Alliance LLC
|
NRG Identity Protect LLC
|
Somerset Power LLC
|
Independence Energy Group LLC
|
NRG Ilion Limited Partnership
|
Texas Genco Financing Corp.
|
Independence Energy Natural Gas LLC
|
NRG Ilion LP LLC
|
Texas Genco GP, LLC
|
Indian River Operations Inc.
|
NRG International LLC
|
Texas Genco Holdings, Inc.
|
Indian River Power LLC
|
NRG Maintenance Services LLC
|
Texas Genco LP, LLC
|
Keystone Power LLC
|
NRG Mextrans Inc.
|
Texas Genco Operating Services, LLC
|
Langford Wind Power, LLC
|
NRG MidAtlantic Affiliate Services Inc.
|
Texas Genco Services, LP
|
Louisiana Generating LLC
|
NRG Middletown Operations Inc.
|
US Retailers LLC
|
Meriden Gas Turbines LLC
|
NRG Montville Operations Inc.
|
Vienna Operations Inc.
|
Middletown Power LLC
|
NRG New Roads Holdings LLC
|
Vienna Power LLC
|
Montville Power LLC
|
NRG North Central Operations Inc.
|
WCP (Generation) Holdings LLC
|
NEO Corporation
|
NRG Northeast Affiliate Services Inc.
|
West Coast Power LLC
|
New Genco GP, LLC
|
NRG Norwalk Harbor Operations Inc.
|
|
|
|
|
NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. However, there may be restrictions for certain non-guarantor subsidiaries.
The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the SEC Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended March 31, 2017
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
NRG Energy, Inc.
(Note Issuer)
|
|
Eliminations
(a)
|
|
Consolidated
|
|
(In millions)
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
$
|
1,599
|
|
|
$
|
1,243
|
|
|
$
|
—
|
|
|
$
|
(83
|
)
|
|
$
|
2,759
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
1,261
|
|
|
933
|
|
|
14
|
|
|
(83
|
)
|
|
2,125
|
|
Depreciation and amortization
|
102
|
|
|
190
|
|
|
8
|
|
|
—
|
|
|
300
|
|
Selling, general and administrative
|
96
|
|
|
106
|
|
|
70
|
|
|
—
|
|
|
272
|
|
Development activity expenses
|
—
|
|
|
12
|
|
|
5
|
|
|
—
|
|
|
17
|
|
Total operating costs and expenses
|
1,459
|
|
|
1,241
|
|
|
97
|
|
|
(83
|
)
|
|
2,714
|
|
Gain on sale of assets
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Operating Income/(Loss)
|
142
|
|
|
2
|
|
|
(97
|
)
|
|
—
|
|
|
47
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
Equity in (losses)/earnings of consolidated subsidiaries
|
(77
|
)
|
|
(34
|
)
|
|
67
|
|
|
44
|
|
|
—
|
|
Equity in (losses)/earnings of unconsolidated affiliates
|
(1
|
)
|
|
7
|
|
|
(1
|
)
|
|
—
|
|
|
5
|
|
Other income
|
1
|
|
|
8
|
|
|
4
|
|
|
(1
|
)
|
|
12
|
|
Loss on debt extinguishment
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
Interest expense
|
(4
|
)
|
|
(151
|
)
|
|
(114
|
)
|
|
—
|
|
|
(269
|
)
|
Total other expense
|
(81
|
)
|
|
(172
|
)
|
|
(44
|
)
|
|
43
|
|
|
(254
|
)
|
Income/(Loss) Before Income Taxes
|
61
|
|
|
(170
|
)
|
|
(141
|
)
|
|
43
|
|
|
(207
|
)
|
Income tax expense/(benefit)
|
19
|
|
|
(46
|
)
|
|
25
|
|
|
(2
|
)
|
|
(4
|
)
|
Net Income/(Loss)
|
42
|
|
|
(124
|
)
|
|
(166
|
)
|
|
45
|
|
|
(203
|
)
|
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests
|
—
|
|
|
(38
|
)
|
|
(3
|
)
|
|
1
|
|
|
(40
|
)
|
Net Income/(Loss) Attributable to
NRG Energy, Inc.
|
$
|
42
|
|
|
$
|
(86
|
)
|
|
$
|
(163
|
)
|
|
$
|
44
|
|
|
$
|
(163
|
)
|
|
|
(a)
|
All significant intercompany transactions have been eliminated in consolidation.
|
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the three months ended March 31, 2017
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
NRG Energy, Inc.
(Note Issuer)
|
|
Eliminations
(a)
|
|
Consolidated
|
|
(In millions)
|
Net Income/(Loss)
|
$
|
42
|
|
|
$
|
(124
|
)
|
|
$
|
(166
|
)
|
|
$
|
45
|
|
|
$
|
(203
|
)
|
Other Comprehensive Income/(Loss), net of tax
|
|
|
|
|
|
|
|
|
|
Unrealized gain on derivatives, net
|
—
|
|
|
5
|
|
|
4
|
|
|
(5
|
)
|
|
4
|
|
Foreign currency translation adjustments, net
|
5
|
|
|
4
|
|
|
7
|
|
|
(9
|
)
|
|
7
|
|
Defined benefit plans, net
|
—
|
|
|
1
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
Other comprehensive income
|
5
|
|
|
10
|
|
|
10
|
|
|
(14
|
)
|
|
11
|
|
Comprehensive Income/(Loss)
|
47
|
|
|
(114
|
)
|
|
(156
|
)
|
|
31
|
|
|
(192
|
)
|
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest
|
—
|
|
|
(37
|
)
|
|
(3
|
)
|
|
1
|
|
|
(39
|
)
|
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.
|
47
|
|
|
(77
|
)
|
|
(153
|
)
|
|
30
|
|
|
(153
|
)
|
Comprehensive Income/(Loss) Available for Common Stockholders
|
$
|
47
|
|
|
$
|
(77
|
)
|
|
$
|
(153
|
)
|
|
$
|
30
|
|
|
$
|
(153
|
)
|
|
|
(a)
|
All significant intercompany transactions have been eliminated in consolidation.
|
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
March 31, 2017
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
NRG Energy, Inc.
(Note Issuer)
|
|
Eliminations
(a)
|
|
Consolidated
|
ASSETS
|
(In millions)
|
Current Assets
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
1,257
|
|
|
$
|
256
|
|
|
$
|
—
|
|
|
$
|
1,513
|
|
Funds deposited by counterparties
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Restricted cash
|
5
|
|
|
392
|
|
|
—
|
|
|
—
|
|
|
397
|
|
Accounts receivable - trade, net
|
592
|
|
|
378
|
|
|
4
|
|
|
—
|
|
|
974
|
|
Accounts receivable - affiliate
|
251
|
|
|
23
|
|
|
(36
|
)
|
|
(231
|
)
|
|
7
|
|
Inventory
|
483
|
|
|
657
|
|
|
—
|
|
|
—
|
|
|
1,140
|
|
Derivative instruments
|
594
|
|
|
207
|
|
|
3
|
|
|
(122
|
)
|
|
682
|
|
Cash collateral paid in support of energy risk management activities
|
173
|
|
|
104
|
|
|
—
|
|
|
—
|
|
|
277
|
|
Prepayments and other current assets
|
94
|
|
|
295
|
|
|
58
|
|
|
—
|
|
|
447
|
|
Total current assets
|
2,195
|
|
|
3,313
|
|
|
285
|
|
|
(353
|
)
|
|
5,440
|
|
Net property, plant and equipment
|
4,168
|
|
|
13,555
|
|
|
246
|
|
|
(27
|
)
|
|
17,942
|
|
Other Assets
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries
|
1,067
|
|
|
1,062
|
|
|
10,040
|
|
|
(12,169
|
)
|
|
—
|
|
Equity investments in affiliates
|
—
|
|
|
1,144
|
|
|
4
|
|
|
—
|
|
|
1,148
|
|
Notes receivable, less current portion
|
—
|
|
|
13
|
|
|
125
|
|
|
(125
|
)
|
|
13
|
|
Goodwill
|
359
|
|
|
303
|
|
|
—
|
|
|
—
|
|
|
662
|
|
Intangible assets, net
|
566
|
|
|
1,394
|
|
|
—
|
|
|
(3
|
)
|
|
1,957
|
|
Nuclear decommissioning trust fund
|
627
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
627
|
|
Derivative instruments
|
178
|
|
|
66
|
|
|
34
|
|
|
(52
|
)
|
|
226
|
|
Deferred income tax
|
(2
|
)
|
|
911
|
|
|
(686
|
)
|
|
—
|
|
|
223
|
|
Non-current assets held-for-sale
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
Other non-current assets
|
71
|
|
|
1,037
|
|
|
64
|
|
|
—
|
|
|
1,172
|
|
Total other assets
|
2,866
|
|
|
5,940
|
|
|
9,581
|
|
|
(12,349
|
)
|
|
6,038
|
|
Total Assets
|
$
|
9,229
|
|
|
$
|
22,808
|
|
|
$
|
10,112
|
|
|
$
|
(12,729
|
)
|
|
$
|
29,420
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
$
|
—
|
|
|
$
|
1,268
|
|
|
$
|
420
|
|
|
$
|
—
|
|
|
$
|
1,688
|
|
Accounts payable
|
436
|
|
|
403
|
|
|
33
|
|
|
—
|
|
|
872
|
|
Accounts payable — affiliate
|
738
|
|
|
1,686
|
|
|
(2,193
|
)
|
|
(231
|
)
|
|
—
|
|
Derivative instruments
|
584
|
|
|
285
|
|
|
—
|
|
|
(122
|
)
|
|
747
|
|
Cash collateral received in support of energy risk management activities
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Accrued expenses and other current liabilities
|
251
|
|
|
368
|
|
|
268
|
|
|
—
|
|
|
887
|
|
Total current liabilities
|
2,012
|
|
|
4,010
|
|
|
(1,472
|
)
|
|
(353
|
)
|
|
4,197
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
244
|
|
|
10,443
|
|
|
7,110
|
|
|
(125
|
)
|
|
17,672
|
|
Nuclear decommissioning reserve
|
291
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
291
|
|
Nuclear decommissioning trust liability
|
352
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
352
|
|
Deferred income taxes
|
200
|
|
|
(1,095
|
)
|
|
915
|
|
|
—
|
|
|
20
|
|
Derivative instruments
|
183
|
|
|
184
|
|
|
—
|
|
|
(52
|
)
|
|
315
|
|
Out-of-market contracts, net
|
77
|
|
|
940
|
|
|
—
|
|
|
—
|
|
|
1,017
|
|
Non-current liabilities held-for-sale
|
—
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
12
|
|
Other non-current liabilities
|
402
|
|
|
763
|
|
|
322
|
|
|
—
|
|
|
1,487
|
|
Total non-current liabilities
|
1,749
|
|
|
11,247
|
|
|
8,347
|
|
|
(177
|
)
|
|
21,166
|
|
Total liabilities
|
3,761
|
|
|
15,257
|
|
|
6,875
|
|
|
(530
|
)
|
|
25,363
|
|
Redeemable noncontrolling interest in subsidiaries
|
—
|
|
|
44
|
|
|
—
|
|
|
—
|
|
|
44
|
|
Stockholders’ Equity
|
5,468
|
|
|
7,507
|
|
|
3,237
|
|
|
(12,199
|
)
|
|
4,013
|
|
Total Liabilities and Stockholders’ Equity
|
$
|
9,229
|
|
|
$
|
22,808
|
|
|
$
|
10,112
|
|
|
$
|
(12,729
|
)
|
|
$
|
29,420
|
|
|
|
(a)
|
All significant intercompany transactions have been eliminated in consolidation.
|
NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
For the three months ended March 31, 2017
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
NRG Energy, Inc.
(Note Issuer)
|
|
Eliminations
(a)
|
|
Consolidated
|
|
(In millions)
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
$
|
42
|
|
|
$
|
(124
|
)
|
|
$
|
(166
|
)
|
|
$
|
45
|
|
|
$
|
(203
|
)
|
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
Distributions from unconsolidated affiliates
|
—
|
|
|
18
|
|
|
—
|
|
|
(5
|
)
|
|
13
|
|
Equity in losses/(earnings) of unconsolidated affiliates
|
1
|
|
|
(7
|
)
|
|
1
|
|
|
—
|
|
|
(5
|
)
|
Depreciation and amortization
|
102
|
|
|
190
|
|
|
8
|
|
|
—
|
|
|
300
|
|
Provision for bad debts
|
8
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
9
|
|
Amortization of nuclear fuel
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
Amortization of financing costs and debt discount/premiums
|
—
|
|
|
(3
|
)
|
|
4
|
|
|
—
|
|
|
1
|
|
Amortization of intangibles and out-of-market contracts
|
6
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
10
|
|
Amortization of unearned equity compensation
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
8
|
|
Changes in deferred income taxes and liability for uncertain tax benefits
|
19
|
|
|
(46
|
)
|
|
28
|
|
|
—
|
|
|
1
|
|
Changes in nuclear decommissioning trust liability
|
36
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
36
|
|
Changes in derivative instruments
|
(4
|
)
|
|
30
|
|
|
(1
|
)
|
|
—
|
|
|
25
|
|
Changes in collateral deposits supporting energy risk management activities
|
(136
|
)
|
|
62
|
|
|
—
|
|
|
—
|
|
|
(74
|
)
|
Gain on sale of assets
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
Cash (used)/provided by changes in other working capital
|
(86
|
)
|
|
499
|
|
|
(604
|
)
|
|
(8
|
)
|
|
(199
|
)
|
Net Cash (Used)/Provided by Operating Activities
|
(2
|
)
|
|
624
|
|
|
(722
|
)
|
|
32
|
|
|
(68
|
)
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
Dividends from NRG Yield, Inc.
|
—
|
|
|
—
|
|
|
22
|
|
|
(22
|
)
|
|
—
|
|
Acquisition of Drop Down Assets, net of cash acquired
|
—
|
|
|
(131
|
)
|
|
—
|
|
|
131
|
|
|
—
|
|
Intercompany dividends
|
—
|
|
|
—
|
|
|
129
|
|
|
(129
|
)
|
|
—
|
|
Acquisition of business, net of cash acquired
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
Capital expenditures
|
(64
|
)
|
|
(200
|
)
|
|
(4
|
)
|
|
—
|
|
|
(268
|
)
|
Decrease in restricted cash, net
|
2
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
13
|
|
Decrease in restricted cash - U.S. DOE projects
|
4
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|
36
|
|
Decrease in notes receivable
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
Purchases of emission allowances
|
(9
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
Proceeds from sale of emission allowances
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
Investments in nuclear decommissioning trust fund securities
|
(153
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(153
|
)
|
Proceeds from sales of nuclear decommissioning trust fund securities
|
117
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
117
|
|
Proceeds from sale of assets, net of cash disposed of
|
11
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
14
|
|
Investments in unconsolidated affiliates
|
—
|
|
|
(12
|
)
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
Other
|
18
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18
|
|
Net Cash (Used)/Provided by Investing Activities
|
(63
|
)
|
|
(296
|
)
|
|
147
|
|
|
(20
|
)
|
|
(232
|
)
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends from NRG Yield, Inc.
|
—
|
|
|
(22
|
)
|
|
—
|
|
|
22
|
|
|
—
|
|
Payments from/(for) intercompany loans
|
65
|
|
|
(428
|
)
|
|
395
|
|
|
(32
|
)
|
|
—
|
|
Acquisition of Drop Down Assets, net of cash acquired
|
—
|
|
|
—
|
|
|
131
|
|
|
(131
|
)
|
|
—
|
|
Intercompany dividends
|
—
|
|
|
(129
|
)
|
|
—
|
|
|
129
|
|
|
—
|
|
Payment of dividends to common and preferred stockholders
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
—
|
|
|
(9
|
)
|
Net receipts from settlement of acquired derivatives that include financing elements
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Proceeds from issuance of long-term debt
|
—
|
|
|
166
|
|
|
26
|
|
|
—
|
|
|
192
|
|
Payments for short and long-term debt
|
—
|
|
|
(146
|
)
|
|
(31
|
)
|
|
—
|
|
|
(177
|
)
|
Payment for credit support in long-term deposits
|
—
|
|
|
(130
|
)
|
|
—
|
|
|
—
|
|
|
(130
|
)
|
Proceeds from draw on revolving credit facility for long-term deposits
|
—
|
|
|
125
|
|
|
—
|
|
|
—
|
|
|
125
|
|
Increase in long-term deposits
|
—
|
|
|
(125
|
)
|
|
—
|
|
|
—
|
|
|
(125
|
)
|
Contributions to, net of distributions from, noncontrolling interest in subsidiaries
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
Payment of debt issuance costs
|
—
|
|
|
(11
|
)
|
|
(4
|
)
|
|
—
|
|
|
(15
|
)
|
Other - contingent consideration
|
—
|
|
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
Net Cash Provided/(Used) by Financing Activities
|
65
|
|
|
(714
|
)
|
|
508
|
|
|
(12
|
)
|
|
(153
|
)
|
Effect of exchange rate changes on cash and cash equivalents
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
Net Decrease in Cash and Cash Equivalents
|
—
|
|
|
(393
|
)
|
|
(67
|
)
|
|
—
|
|
|
(460
|
)
|
Cash and Cash Equivalents at Beginning of Period
|
—
|
|
|
1,650
|
|
|
323
|
|
|
—
|
|
|
1,973
|
|
Cash and Cash Equivalents at End of Period
|
$
|
—
|
|
|
$
|
1,257
|
|
|
$
|
256
|
|
|
$
|
—
|
|
|
$
|
1,513
|
|
|
|
(a)
|
All significant intercompany transactions have been eliminated in consolidation.
|
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended March 31, 2016
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
NRG Energy, Inc.
(Note Issuer)
|
|
Eliminations
(a)
|
|
Consolidated
|
|
(In millions)
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
$
|
1,956
|
|
|
$
|
1,299
|
|
|
$
|
—
|
|
|
$
|
(26
|
)
|
|
$
|
3,229
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
1,455
|
|
|
759
|
|
|
10
|
|
|
(30
|
)
|
|
2,194
|
|
Depreciation and amortization
|
117
|
|
|
190
|
|
|
6
|
|
|
—
|
|
|
313
|
|
Selling, general and administrative
|
93
|
|
|
99
|
|
|
60
|
|
|
—
|
|
|
252
|
|
Development activity expenses
|
—
|
|
|
19
|
|
|
7
|
|
|
—
|
|
|
26
|
|
Total operating costs and expenses
|
1,665
|
|
|
1,067
|
|
|
83
|
|
|
(30
|
)
|
|
2,785
|
|
Gain on sale of assets
|
—
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|
32
|
|
Operating Income/(Loss)
|
291
|
|
|
264
|
|
|
(83
|
)
|
|
4
|
|
|
476
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
Equity in (losses)/earnings of consolidated subsidiaries
|
(24
|
)
|
|
4
|
|
|
213
|
|
|
(193
|
)
|
|
—
|
|
Equity in losses of unconsolidated affiliates
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
1
|
|
|
(7
|
)
|
Impairment loss on investment
|
—
|
|
|
(140
|
)
|
|
(6
|
)
|
|
—
|
|
|
(146
|
)
|
Other income/(expense), net
|
—
|
|
|
20
|
|
|
(2
|
)
|
|
—
|
|
|
18
|
|
Gain on debt extinguishment
|
—
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
Interest expense
|
(5
|
)
|
|
(150
|
)
|
|
(129
|
)
|
|
—
|
|
|
(284
|
)
|
Total other (expense)/income
|
(29
|
)
|
|
(274
|
)
|
|
87
|
|
|
(192
|
)
|
|
(408
|
)
|
Income/(Loss) Before Income Taxes
|
262
|
|
|
(10
|
)
|
|
4
|
|
|
(188
|
)
|
|
68
|
|
Income tax expense/(benefit)
|
100
|
|
|
(8
|
)
|
|
(83
|
)
|
|
12
|
|
|
21
|
|
Net Income/(Loss)
|
162
|
|
|
(2
|
)
|
|
87
|
|
|
(200
|
)
|
|
47
|
|
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest
|
—
|
|
|
(33
|
)
|
|
5
|
|
|
(7
|
)
|
|
(35
|
)
|
Net Income Attributable to NRG Energy, Inc.
|
$
|
162
|
|
|
$
|
31
|
|
|
$
|
82
|
|
|
$
|
(193
|
)
|
|
$
|
82
|
|
|
|
(a)
|
All significant intercompany transactions have been eliminated in consolidation.
|
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the three months ended March 31, 2016
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
NRG Energy, Inc.
(Note Issuer)
|
|
Eliminations
(a)
|
|
Consolidated
|
|
(In millions)
|
Net Income/(Loss)
|
$
|
162
|
|
|
$
|
(2
|
)
|
|
$
|
87
|
|
|
$
|
(200
|
)
|
|
$
|
47
|
|
Other Comprehensive Income/(Loss), net of tax
|
|
|
|
|
|
|
|
|
|
Unrealized (loss)/gain on derivatives, net
|
—
|
|
|
(50
|
)
|
|
24
|
|
|
(6
|
)
|
|
(32
|
)
|
Foreign currency translation adjustments, net
|
4
|
|
|
4
|
|
|
6
|
|
|
(8
|
)
|
|
6
|
|
Available-for-sale securities, net
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Defined benefit plans, net
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Other comprehensive income/(loss)
|
5
|
|
|
(46
|
)
|
|
33
|
|
|
(14
|
)
|
|
(22
|
)
|
Comprehensive Income/Loss
|
167
|
|
|
(48
|
)
|
|
120
|
|
|
(214
|
)
|
|
25
|
|
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest
|
—
|
|
|
(50
|
)
|
|
5
|
|
|
(7
|
)
|
|
(52
|
)
|
Comprehensive Income Attributable to NRG Energy, Inc.
|
167
|
|
|
2
|
|
|
115
|
|
|
(207
|
)
|
|
77
|
|
Dividends for preferred shares
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
Comprehensive Income Available for Common Stockholders
|
$
|
167
|
|
|
$
|
2
|
|
|
$
|
110
|
|
|
$
|
(207
|
)
|
|
$
|
72
|
|
|
|
(a)
|
All significant intercompany transactions have been eliminated in consolidation.
|
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
NRG Energy, Inc.
(Note Issuer)
|
|
Eliminations
(a)
|
|
Consolidated
|
ASSETS
|
(In millions)
|
Current Assets
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
1,650
|
|
|
$
|
323
|
|
|
$
|
—
|
|
|
$
|
1,973
|
|
Funds deposited by counterparties
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Restricted cash
|
11
|
|
|
435
|
|
|
—
|
|
|
—
|
|
|
446
|
|
Accounts receivable - trade, net
|
734
|
|
|
429
|
|
|
3
|
|
|
—
|
|
|
1,166
|
|
Accounts receivable - affiliate
|
309
|
|
|
(241
|
)
|
|
200
|
|
|
(262
|
)
|
|
6
|
|
Inventory
|
482
|
|
|
629
|
|
|
—
|
|
|
—
|
|
|
1,111
|
|
Derivative instruments
|
962
|
|
|
305
|
|
|
—
|
|
|
(205
|
)
|
|
1,062
|
|
Cash collateral paid in support of energy risk management activities
|
37
|
|
|
166
|
|
|
—
|
|
|
—
|
|
|
203
|
|
Current assets held-for-sale
|
—
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
9
|
|
Prepayments and other current assets
|
76
|
|
|
279
|
|
|
62
|
|
|
—
|
|
|
417
|
|
Total current assets
|
2,613
|
|
|
3,661
|
|
|
588
|
|
|
(467
|
)
|
|
6,395
|
|
Net Property, Plant and Equipment
|
4,216
|
|
|
13,472
|
|
|
251
|
|
|
(27
|
)
|
|
17,912
|
|
Other Assets
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries
|
837
|
|
|
1,973
|
|
|
10,128
|
|
|
(12,938
|
)
|
|
—
|
|
Equity investments in affiliates
|
(14
|
)
|
|
1,129
|
|
|
5
|
|
|
—
|
|
|
1,120
|
|
Notes receivable, less current portion
|
—
|
|
|
17
|
|
|
(76
|
)
|
|
76
|
|
|
17
|
|
Goodwill
|
359
|
|
|
303
|
|
|
—
|
|
|
—
|
|
|
662
|
|
Intangible assets, net
|
592
|
|
|
1,447
|
|
|
—
|
|
|
(3
|
)
|
|
2,036
|
|
Nuclear decommissioning trust fund
|
610
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
610
|
|
Derivative instruments
|
143
|
|
|
60
|
|
|
36
|
|
|
(50
|
)
|
|
189
|
|
Deferred income taxes
|
3
|
|
|
868
|
|
|
(646
|
)
|
|
—
|
|
|
225
|
|
Non-current assets held for sale
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
Other non-current assets
|
67
|
|
|
784
|
|
|
328
|
|
|
—
|
|
|
1,179
|
|
Total other assets
|
2,597
|
|
|
6,591
|
|
|
9,775
|
|
|
(12,915
|
)
|
|
6,048
|
|
Total Assets
|
$
|
9,426
|
|
|
$
|
23,724
|
|
|
$
|
10,614
|
|
|
$
|
(13,409
|
)
|
|
$
|
30,355
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
$
|
—
|
|
|
$
|
1,202
|
|
|
$
|
(58
|
)
|
|
$
|
76
|
|
|
$
|
1,220
|
|
Accounts payable
|
499
|
|
|
362
|
|
|
34
|
|
|
—
|
|
|
895
|
|
Accounts payable — affiliate
|
655
|
|
|
1,834
|
|
|
(2,227
|
)
|
|
(262
|
)
|
|
—
|
|
Derivative instruments
|
947
|
|
|
342
|
|
|
—
|
|
|
(205
|
)
|
|
1,084
|
|
Cash collateral received in support of energy risk management activities
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Current liabilities held-for-sale
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Accrued expenses and other current liabilities
|
317
|
|
|
400
|
|
|
464
|
|
|
—
|
|
|
1,181
|
|
Total current liabilities
|
2,420
|
|
|
4,140
|
|
|
(1,787
|
)
|
|
(391
|
)
|
|
4,382
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
244
|
|
|
10,302
|
|
|
7,460
|
|
|
—
|
|
|
18,006
|
|
Nuclear decommissioning reserve
|
287
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
287
|
|
Nuclear decommissioning trust liability
|
339
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
339
|
|
Deferred income taxes
|
186
|
|
|
(1,094
|
)
|
|
928
|
|
|
—
|
|
|
20
|
|
Derivative instruments
|
157
|
|
|
187
|
|
|
—
|
|
|
(50
|
)
|
|
294
|
|
Out-of-market contracts, net
|
80
|
|
|
960
|
|
|
—
|
|
|
—
|
|
|
1,040
|
|
Non-current liabilities held-for-sale
|
—
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
12
|
|
Other non-current liabilities
|
397
|
|
|
762
|
|
|
324
|
|
|
—
|
|
|
1,483
|
|
Total non-current liabilities
|
1,690
|
|
|
11,129
|
|
|
8,712
|
|
|
(50
|
)
|
|
21,481
|
|
Total Liabilities
|
4,110
|
|
|
15,269
|
|
|
6,925
|
|
|
(441
|
)
|
|
25,863
|
|
Redeemable noncontrolling interest in subsidiaries
|
—
|
|
|
46
|
|
|
—
|
|
|
—
|
|
|
46
|
|
Stockholders’ Equity
|
5,316
|
|
|
8,409
|
|
|
3,689
|
|
|
(12,968
|
)
|
|
4,446
|
|
Total Liabilities and Stockholders’ Equity
|
$
|
9,426
|
|
|
$
|
23,724
|
|
|
$
|
10,614
|
|
|
$
|
(13,409
|
)
|
|
$
|
30,355
|
|
|
|
(a)
|
All significant intercompany transactions have been eliminated in consolidation.
|
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the three months ended March 31, 2016
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
NRG Energy, Inc.
(Note Issuer)
|
|
Eliminations
(a)
|
|
Consolidated
|
|
(In millions)
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
$
|
162
|
|
|
$
|
(2
|
)
|
|
$
|
87
|
|
|
$
|
(200
|
)
|
|
$
|
47
|
|
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
Distributions from unconsolidated affiliates
|
—
|
|
|
22
|
|
|
—
|
|
|
(12
|
)
|
|
10
|
|
Equity in losses of unconsolidated affiliates
|
—
|
|
|
8
|
|
|
—
|
|
|
(1
|
)
|
|
7
|
|
Depreciation and amortization
|
117
|
|
|
190
|
|
|
6
|
|
|
—
|
|
|
313
|
|
Provision for bad debts
|
8
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
10
|
|
Amortization of nuclear fuel
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
Amortization of financing costs and debt discount/premiums
|
—
|
|
|
7
|
|
|
(6
|
)
|
|
—
|
|
|
1
|
|
Adjustment for debt extinguishment
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
—
|
|
|
(11
|
)
|
Amortization of intangibles and out-of-market contracts
|
11
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
26
|
|
Amortization of unearned equity compensation
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
8
|
|
Impairment losses
|
—
|
|
|
140
|
|
|
6
|
|
|
—
|
|
|
146
|
|
Changes in deferred income taxes and liability for uncertain tax benefits
|
(613
|
)
|
|
(1,696
|
)
|
|
2,284
|
|
|
—
|
|
|
(25
|
)
|
Changes in nuclear decommissioning trust liability
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
Changes in derivative instruments
|
(28
|
)
|
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
(50
|
)
|
Changes in collateral deposits supporting energy risk management activities
|
150
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
156
|
|
Proceeds from sale of emission allowances
|
47
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47
|
|
Gain on sale of assets
|
—
|
|
|
(32
|
)
|
|
—
|
|
|
—
|
|
|
(32
|
)
|
Cash provided/(used) by changes in other working capital
|
338
|
|
|
1,728
|
|
|
(2,400
|
)
|
|
213
|
|
|
(121
|
)
|
Net Cash Provided/(Used) by Operating Activities
|
214
|
|
|
366
|
|
|
(26
|
)
|
|
—
|
|
|
554
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
Dividends from NRG Yield, Inc.
|
—
|
|
|
(19
|
)
|
|
—
|
|
|
19
|
|
|
—
|
|
Acquisition of businesses, net of cash acquired
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Capital expenditures
|
(44
|
)
|
|
(219
|
)
|
|
(16
|
)
|
|
—
|
|
|
(279
|
)
|
Increase in restricted cash, net
|
(2
|
)
|
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
Decrease in restricted cash - U.S. DOE funded projects
|
—
|
|
|
39
|
|
|
—
|
|
|
—
|
|
|
39
|
|
Decrease in notes receivable
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Purchases of emission allowances
|
(12
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
Proceeds from sale of emission allowances
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
Investments in nuclear decommissioning trust fund securities
|
(200
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(200
|
)
|
Proceeds from sales of nuclear decommissioning trust fund securities
|
191
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
191
|
|
Proceeds from renewable energy grants and state rebates
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
Proceeds from sale of assets, net of cash disposed of
|
—
|
|
|
120
|
|
|
—
|
|
|
—
|
|
|
120
|
|
Investments in unconsolidated affiliates
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
Other
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
Net Cash Used by Investing Activities
|
(60
|
)
|
|
(86
|
)
|
|
(16
|
)
|
|
19
|
|
|
(143
|
)
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
Dividends from NRG Yield, Inc.
|
—
|
|
|
—
|
|
|
19
|
|
|
(19
|
)
|
|
—
|
|
Payments (for)/from intercompany loans
|
(151
|
)
|
|
(11
|
)
|
|
162
|
|
|
|
|
|
—
|
|
Payment of dividends to common and preferred stockholders
|
—
|
|
|
—
|
|
|
(48
|
)
|
|
—
|
|
|
(48
|
)
|
Net receipts for settlement of acquired derivatives that include financing elements
|
—
|
|
|
39
|
|
|
—
|
|
|
—
|
|
|
39
|
|
Proceeds from issuance of long-term debt
|
—
|
|
|
61
|
|
|
—
|
|
|
—
|
|
|
61
|
|
Payments for short and long-term debt
|
—
|
|
|
(121
|
)
|
|
(195
|
)
|
|
—
|
|
|
(316
|
)
|
Distributions from, net of contributions to, noncontrolling interest in subsidiaries
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
Other
|
(3
|
)
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
Net Cash Used by Financing Activities
|
(154
|
)
|
|
(29
|
)
|
|
(62
|
)
|
|
(19
|
)
|
|
(264
|
)
|
Effect of exchange rate changes on cash and cash equivalents
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Net Increase/(Decrease) in Cash and Cash Equivalents
|
—
|
|
|
245
|
|
|
(104
|
)
|
|
—
|
|
|
141
|
|
Cash and Cash Equivalents at Beginning of Period
|
—
|
|
|
825
|
|
|
693
|
|
|
—
|
|
|
1,518
|
|
Cash and Cash Equivalents at End of Period
|
$
|
—
|
|
|
$
|
1,070
|
|
|
$
|
589
|
|
|
$
|
—
|
|
|
$
|
1,659
|
|
|
|
(a)
|
All significant intercompany transactions have been eliminated in consolidation.
|