UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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| | |
| x | | Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
| | | |
| | | For the Quarterly Period Ended: September 30, 2017March 31, 2018 |
| | | |
| o | | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
Commission File Number: 001-15891
NRG Energy, Inc.
(Exact name of registrant as specified in its charter)
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| | |
Delaware (State or other jurisdiction of incorporation or organization) | | 41-1724239 (I.R.S. Employer Identification No.) |
| | | |
804 Carnegie Center, Princeton, New Jersey (Address of principal executive offices) | | 08540 (Zip Code) |
(609) 524-4500
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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| | | | | | | |
Large accelerated filer x | | Accelerated filer o | | Non-accelerated filer o | | Smaller reporting company o | Emerging growth company o |
| | | | | (Do not check if a smaller reporting company) | | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No x
As of OctoberMarch 31, 2017,2018, there were 316,641,799314,886,197 shares of common stock outstanding, par value $0.01 per share.
TABLE OF CONTENTS
Index
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A — Risk Factors Related to NRG Energy, Inc., in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 20162017, and the following:
NRG's ability to achieve the expected benefits of its Transformation Plan;
NRG's ability to engage in successful sales and divestitures as well as mergers and acquisitions activity;
The potential adverse effects of the GenOn Entities' filings under Chapter 11 of the Bankruptcy Code and restructuring transactions on NRG's operations, management and employees and the risks associated with operating NRG's business during the restructuring process;
Risks and uncertainties associated with the GenOn Entities' Chapter 11 Cases including the ability to achieve anticipated benefits therefrom;
NRG's ability to engage in successful mergers and acquisitions activity;
General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;
Volatile power supply costs and demand for power;
Changes in law, including judicial decisions;
Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions (including wind and solar conditions), catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;
The effectiveness of NRG's risk management policies and procedures, and the ability of NRG's counterparties to satisfy their financial commitments;
Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;
NRG's ability to operate its businesses efficiently and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;
The liquidity and competitiveness of wholesale markets for energy commodities;
Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws;
Changes in law, including judicial decisions;
Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately and fairly compensate NRG's generation units;
NRG's ability to mitigate forced outage risk for units subject to capacity performance requirements in PJM, performance incentives in ISO-NE, and scarcity pricing in ERCOT;
NRG's ability to borrow funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;
Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG's outstanding notes, in NRG's Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;
Cyber terrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss and the possibility that NRG may not have adequate insurance to cover losses resulting from such hazards or the inability of NRG's insurers to provide coverage;
NRG's ability to develop and build new power generation facilities;
NRG's ability to develop and innovate new products as retail and wholesale markets continue to change and evolve;
NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources while taking advantage of business opportunities;
NRG's ability to increase cash from operations through operational and commercial initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout NRG to reduce costs or generate revenues;
NRG's ability to sell assets to NRG Yield, Inc. and to close drop-down transactions;
NRG's ability to achieve its strategy of regularly returning capital to stockholders;
NRG's ability to obtain and maintain retail market share;
NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives;
NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses; and
NRG's ability to develop and maintain successful partnering relationships.
Forward-looking statements speak only as of the date they were made, and NRG Energy, Inc. undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG's actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
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| | |
20162017 Form 10-K | | NRG’s Annual Report on Form 10-K for the year ended December 31, 20162017 |
| 2023 Term Loan Facility | | The Company's $1.9 billion term loan facility due 2023, a component of the Senior Credit Facility |
| Adjusted EBITDA | | Adjusted earnings before interest, taxes, depreciation and amortization |
| ARO | | Asset Retirement Obligation |
| ASC | | The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP |
| ASU | | Accounting Standards Updates which reflect- updates to the ASC |
| Average realized prices | | Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges |
| BACT | | Best Available Control Technology |
| Bankruptcy Code | | Chapter 11 of Title 11 of the U.S. Bankruptcy Code |
| Bankruptcy Court | | United States Bankruptcy Court for the Southern District of Texas, Houston Division |
| BETM | | Boston Energy Trading and Marketing LLC |
| BTU | | British Thermal Unit |
| Business Solutions | | NRG's business solutions group, which includes demand response, commodity sales, energy efficiency and energy management services |
| CAA | | Clean Air Act |
| CAIR | | Clean Air Interstate Rule |
| CAISO | | California Independent System Operator |
| CASPR | | Competitive Auctions with Sponsored Resources |
| CDD | | Cooling Degree Day |
| CDWR | | California Department of Water Resources |
| CEC | | California Energy Commission |
| CenterPoint | | CenterPoint Energy Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries prior to August 31, 2002Houston Electric, LLC |
| CFTC | | U.S. Commodity Futures Trading Commission |
| Chapter 11 Cases | | Voluntary cases commenced by the GenOn Entities under the Bankruptcy Code in the Bankruptcy Court |
| C&I | | Commercial industrial and governmental/institutional |
| Cleco | | Cleco Energy LLC |
| COD | | Commercial Operation Date |
| ComEd | | Commonwealth Edison |
| Company | | NRG Energy, Inc. |
CPP | | Clean Power Plan |
| CPUC | | California Public Utilities Commission |
| CSAPR | | Cross-State Air Pollution Rule |
| CVSR | | California Valley Solar Ranch |
| CWA | | Clean Water Act |
| D.C. Circuit | | U.S. Court of Appeals for the District of Columbia Circuit |
| DGPV Holdco 1 | | NRG DGPV Holdco 1 LLC |
| DGPV Holdco 2 | | NRG DGPV Holdco 2 LLC |
| DGPV Holdco 3 | | NRG DGPV Holdco 3 LLC |
| Distributed Solar | | Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid |
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| | |
| DNREC | | Delaware Department of Natural Resources and Environmental Control |
| DSI | | Dry Sorbent Injection |
| Economic gross margin | | Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales |
ELG | | Effluent Limitations Guidelines |
| El Segundo Energy Center | | NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center project |
| EME | | Edison Mission Energy |
| Energy Plus Holdings | | Energy Plus Holdings LLC |
| EPA | | U.S. Environmental Protection Agency |
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| | |
| EPC | | Engineering, Procurement and Construction |
| EPSA | | The Electric Power Supply Association |
| ERCOT | | Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas |
ESCO | | Energy Service Company |
| ESP | | Electrostatic Precipitator |
| ESPP | | NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan |
| ESPS | | Existing Source Performance Standards |
| Exchange Act | | The Securities Exchange Act of 1934, as amended |
| FASB | | Financial Accounting Standards Board |
| FERC | | Federal Energy Regulatory Commission |
| FGD | | Flue gas desulfurization |
| Fresh Start | | Reporting requirements as defined by ASC-852, Reorganizations |
| FTRs | | Financial Transmission Rights |
| GAAP | | Accounting principles generally accepted in the U.S. |
| GenConn | | GenConn Energy LLC |
| GenOn | | GenOn Energy, Inc. |
| GenOn Americas Generation | | GenOn Americas Generation, LLC |
| GenOn Americas Generation Senior Notes | | GenOn Americas Generation's $695$395 million outstanding unsecured senior notes consisting of $366$208 million of 8.5% senior notes due 2021 and $329$187 million of 9.125% senior notes due 2031 |
| GenOn Entities | | GenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation. that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court on June 14, 2017 |
| GenOn Mid-Atlantic | | GenOn Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries, which include the coal generation units at two generating facilities under operating leases |
| GenOn Senior Notes | | GenOn's $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $649 million of 9.5% senior notes due 2018, and $489 million of 9.875% senior notes due 2020 |
| GHG | | Greenhouse Gas |
| GIP | | Global Infrastructure Partners |
| GW | | Gigawatt |
| GWh | | Gigawatt Hour |
| HAP | | Hazardous Air Pollutant |
| HDD | | Heating Degree Day |
| Heat Rate | | A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh |
| HLBV | | Hypothetical Liquidation at Book Value |
| IASB | | IndependentInternational Accounting Standards Board |
| IFRS | | International Financial Reporting Standards |
ILU |
| | |
| IPA | | Illinois Union Insurance CompanyPower Agency |
| IPPNY | | Independent Power Producers of New York |
| ISO | | Independent System Operator, also referred to as RTOs |
| ISO-NE | | ISO New England Inc. |
| ITC | | Investment Tax Credit |
| kWh | | Kilowatt-hour |
| LaGen | | Louisiana Generating, L.L.C.LLC |
| LIBOR | | London Inter-Bank Offered Rate |
| LTIPs | | Collectively, the NRG Long-Term Incentive Plan, as amended,LTIP and the NRG GenOn Long-Term Incentive PlanLTIP |
| Marsh Landing | | NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC) |
| Mass Market | | Residential and small commercial customers |
| MATS | | Mercury and Air Toxics Standards promulgated by the EPA |
| MDth | | Thousand Dekatherms |
| Midwest Generation | | Midwest Generation, LLC |
| MISO | | Midcontinent Independent System Operator, Inc. |
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| | |
| MMBtu | | Million British Thermal Units |
| MOPR | | Minimum Offer Price Rule |
| MW | | Megawatts |
| MWh | | Saleable megawatt hour net of internal/parasitic load megawatt-hour |
| MWt | | Megawatts Thermal Equivalent |
| NAAQS | | National Ambient Air Quality Standards |
| NEPGA | | New England Power Generators Association |
| NEPOOL | | New England Power Pool |
| NERC | | North American Electric Reliability Corporation |
| Net Exposure | | Counterparty credit exposure to NRG, net of collateral |
| Net Generation | | The net amount of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation |
| NOL | | Net Operating Loss |
| NOV | | Notice of Violation |
NOx | | Nitrogen Oxides |
| NPDES | | National Pollutant Discharge Elimination System |
| NPNS | | Normal Purchase Normal Sale |
| NRC | | U.S. Nuclear Regulatory Commission |
| NRG | | NRG Energy, Inc. |
| NRG Yield | | Reporting segment including the projects owned by NRG Yield, Inc. |
| NRG Yield 2019 Convertible Notes | | $345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019 issued by NRG Yield, Inc. |
| NRG Yield 2020 Convertible Notes | | $287.5 million aggregate principal amount of 3.25% Convertible Notes due 2020 issued by NRG Yield, Inc. |
| NRG Yield, Inc. | | NRG Yield, Inc., the owner of 53.7% of the economic interests of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A and Class C common stock |
| NSR | | New Source Review |
| Nuclear Decommissioning Trust Fund | | NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, units 1 & 2 |
| NYAG | | State of New York Office of Attorney General |
| NYISO | | New York Independent System Operator |
| NYMEX | | New York Mercantile Exchange |
| NYSPSC | | New York State Public Service Commission |
| OCI/OCL | | Other Comprehensive Income/(Loss) |
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| | |
| Peaking | | Units expected to satisfy demand requirements during the periods of greatest or peak load on the system |
| PER | | Peak Energy Rent |
| Petition Date | | June 14, 2017 |
PG&EPipeline | | Pacific GasProjects that range from identified lead to shortlisted with an offtake, and Electric Companyrepresents a lower level of execution certainty. |
| PJM | | PJM Interconnection, LLC |
PM | | Particulate Matter |
| PPA | | Power Purchase Agreement |
| PSD | | Prevention of Significant Deterioration |
| PTC | | Production Tax Credit |
| PUCT | | Public Utility Commission of Texas |
RAPAPUHCA | | Resource Adequacy Purchase AgreementPublic Utility Holding Company Act of 2005 |
| RCRA | | Resource Conservation and Recovery Act of 1976 |
| REMA | | NRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interests in the Keystone and Conemaugh generating facilities, respectively |
Repowering | | Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility to achieve a substantial emissions reduction, increase facility capacity and improve system efficiency |
| Restructuring Support Agreement | | Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017 and as amended on October 2, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, theand subsidiaries signatory thereto, NRG Energy, Inc. and the noteholders signatory thereto |
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| | |
| Retail | | Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG, as well as Business Solutions |
| Revolving Credit Facility | | The Company’s $2.5 billion revolving credit facility, a component of the Senior Credit Facility. The revolving credit facility consists of $289 million of Tranche A Revolving Credit Facility, due 2018, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021
Prior to June 30, 2016, the Company's $2.5 billion revolving credit facility due 2018, a component of the Senior Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility, including the Revolving Credit Facility
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| RFO | | Request for Offer |
| RGGI | | Regional Greenhouse Gas Initiative |
| RMR | | Reliability Must-Run |
| ROFO | | Right of First Offer |
| ROFO Agreement | | Second Amended and Restated Right of First Offer Agreement by and between the CompanyNRG Energy, Inc. and NRG Yield, Inc. |
| RPM | | Reliability Pricing Model |
| RPV Holdco | | NRG RPV Holdco 1 LLC |
| RTO | | Regional Transmission Organization |
| RTR | | Renewable Technology Resource |
| SCE | | Southern California Edison |
| SDG&E | | San Diego Gas & Electric Company |
| SEC | | U.S. Securities and Exchange Commission |
| Securities Act | | The Securities Act of 1933, as amended |
| Senior Credit Facility | | NRG's senior secured credit facility, compromisedcomprised of the Revolving Credit Facility and the 2023 Term Loan Facility
Prior to June 30, 2016, the Company's senior secured facility, comprised of the Term Loan Facility and the Revolving Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility
|
| Senior Notes | | As of September 30,December 31, 2017, the Company’s $5.4NRG’s $4.8 billion outstanding unsecured senior notes consisting of $398 million of 7.625% senior notes due 2018, $207 million of 7.875% senior notes due 2021, $992 million of 6.25% senior notes due 2022, $869 million of 6.625% senior notes due 2023, $733 million of 6.25% senior notes due 2024, $1.0 billion of 7.25% senior notes due 2026, and $1.25 billion of 6.625% senior notes due 2027, |
Services Agreement | | NRG provides GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn$870 million of 5.75% senior notes due 2028. |
| Settlement Agreement | | A settlement agreement and any other documents necessary to effectuate the settlement among NRG, GenOn, and certain holders of senior unsecured notes of GenOn Americas Generation and GenOn, and certain of GenOn's direct and indirect subsidiaries |
SewardServices Agreement | | The Seward Power Generating Station, a 525 MW coal-fired facilityNRG provided GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in Pennsylvaniathe services agreement with GenOn
|
ShelbySIFMA | | The Shelby County Generating Station, a 352 MW natural gas-fired facility in IllinoisSecurities Industry and Financial Markets Association |
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| | |
SO2 | | Sulfur Dioxide |
SPPSouth Central | | Solar Power Partners |
STP | | NRG's South Texas Project — nuclear generating facility located near Bay City, Texas inCentral business, which NRG owns and operates a 44% interest3,555-MW portfolio of generation assets consisting of 225-MW Bayou Cove, 430-MW Big Cajun-I, 1,461-MW Big Cajun-II, 1,263-MW Cottonwood and 176-MW Sterlington, and serves a customer base of cooperatives, municipalities and regional utilities under load contracts. |
| S&P | | Standard & Poor's |
| TCPA | | Telephone Consumer Protection Act |
Term Loan Facility | | Prior to June 30, 2016, the Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility. |
| TSA | | Transportation Services Agreement |
| TWCC | | Texas Westmoreland Coal Co. |
| U.S. | | United States of America |
| U.S. DOE | | U.S. Department of Energy |
| Utility Scale Solar | | Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level |
| VaR | | Value at Risk |
| VCP | | Voluntary Clean-Up Program |
| VIE | | Variable Interest Entity |
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Walnut CreekWECC | | NRG Walnut Creek, LLC, the operating subsidiary of WCEP Holdings, LLC, which owns the Walnut Creek projectWestern Electricity Coordinating Council |
| WST | | Washington-St. Tammany Electric Cooperative, Inc. |
| Yield Operating | | NRG Yield Operating LLC |
PART I — FINANCIAL INFORMATION
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
| | | | Three months ended September 30, | | Nine months ended September 30, | Three months ended March 31, |
| (In millions, except for per share amounts) | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 |
| Operating Revenues |
| |
| | | | |
| |
|
| Total operating revenues | $ | 3,049 |
|
| $ | 3,421 |
|
| $ | 8,132 |
|
| $ | 8,328 |
| $ | 2,421 |
|
| $ | 2,382 |
|
| Operating Costs and Expenses |
|
|
|
|
|
|
|
| |
|
| Cost of operations | 2,156 |
|
| 2,440 |
|
| 5,852 |
|
| 5,711 |
| 1,558 |
|
| 1,862 |
|
| Depreciation and amortization | 272 |
|
| 298 |
|
| 789 |
|
| 826 |
| 235 |
|
| 257 |
|
| Impairment losses | 14 |
|
| 9 |
|
| 77 |
|
| 65 |
| |
| Selling, general and administrative | 213 |
|
| 277 |
|
| 697 |
|
| 801 |
| 191 |
|
| 260 |
|
| Reorganization | 18 |
|
| — |
|
| 18 |
|
| — |
| |
| Development activity expenses | 14 |
|
| 21 |
|
| 49 |
|
| 65 |
| |
| Reorganization costs | | 20 |
|
| — |
|
| Development costs | | 13 |
|
| 17 |
|
| Total operating costs and expenses | 2,687 |
|
| 3,045 |
|
| 7,482 |
|
| 7,468 |
| 2,017 |
| | 2,396 |
|
| Other income - affiliate | 14 |
|
| 48 |
|
| 104 |
|
| 144 |
| — |
|
| 48 |
|
| Gain/(loss) on sale of assets | — |
|
| 4 |
|
| 4 |
|
| (79 | ) | |
| Gain on sale of assets | | 2 |
|
| 2 |
|
| Operating Income | 376 |
|
| 428 |
|
| 758 |
|
| 925 |
| 406 |
|
| 36 |
|
| Other Income/(Expense) |
|
|
|
|
|
|
|
| |
|
| Equity in earnings of unconsolidated affiliates | 27 |
|
| 16 |
|
| 29 |
|
| 13 |
| |
| Impairment loss on investment | — |
|
| (8 | ) |
| — |
|
| (147 | ) | |
| Other income, net | 15 |
|
| 7 |
|
| 33 |
|
| 29 |
| |
| Equity in (losses)/earnings of unconsolidated affiliates | | (2 | ) |
| 5 |
|
| Other (expense)/income, net | | (3 | ) |
| 13 |
|
| Loss on debt extinguishment, net | (1 | ) |
| (50 | ) |
| (3 | ) |
| (119 | ) | (2 | ) |
| (2 | ) |
| Interest expense | (221 | ) |
| (237 | ) |
| (692 | ) |
| (718 | ) | (167 | ) |
| (225 | ) |
| Total other expense | (180 | ) |
| (272 | ) |
| (633 | ) |
| (942 | ) | (174 | ) | | (209 | ) |
| Income/(Loss) from Continuing Operations Before Income Taxes | 196 |
|
| 156 |
|
| 125 |
|
| (17 | ) | 232 |
|
| (173 | ) |
| Income tax expense | 6 |
|
| 28 |
|
| 5 |
|
| 75 |
| |
| Income tax benefit | | (1 | ) |
| (4 | ) |
| Income/(Loss) from Continuing Operations | 190 |
|
| 128 |
|
| 120 |
|
| (92 | ) | 233 |
|
| (169 | ) |
| (Loss)/Income from discontinued operations, net of income tax | (27 | ) |
| 265 |
|
| (802 | ) |
| 256 |
| |
| Loss from discontinued operations, net of income tax | | — |
|
| (34 | ) |
| Net Income/(Loss) | 163 |
|
| 393 |
|
| (682 | ) |
| 164 |
| 233 |
|
| (203 | ) |
| Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests | (8 | ) |
| (9 | ) |
| (63 | ) |
| (49 | ) | (46 | ) |
| (40 | ) |
| Net Income/(Loss) Attributable to NRG Energy, Inc. | 171 |
|
| 402 |
|
| (619 | ) |
| 213 |
| $ | 279 |
|
| $ | (163 | ) |
| Dividends for preferred shares | — |
|
| — |
|
| — |
|
| 5 |
| |
| Gain on redemption of preferred shares | — |
|
| — |
|
| — |
|
| (78 | ) | |
| Net Income/(Loss) Available for Common Stockholders | $ | 171 |
|
| $ | 402 |
|
| $ | (619 | ) |
| $ | 286 |
| |
| Income/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders |
|
|
|
|
|
|
| |
| Earnings/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders | |
|
|
|
| Weighted average number of common shares outstanding — basic | 317 |
|
| 316 |
|
| 317 |
|
| 315 |
| 318 |
|
| 316 |
|
| Income from continuing operations per weighted average common share — basic | $ | 0.63 |
|
| $ | 0.43 |
|
| $ | 0.58 |
|
| $ | 0.10 |
| |
| (Loss)/Income from discontinued operations per weighted average common share — basic | $ | (0.09 | ) |
| $ | 0.84 |
|
| $ | (2.53 | ) |
| $ | 0.81 |
| |
| Income/(Loss) per Weighted Average Common Share — Basic | $ | 0.54 |
|
| $ | 1.27 |
|
| $ | (1.95 | ) |
| $ | 0.91 |
| |
| Income/(loss) from continuing operations per weighted average common share — basic | | $ | 0.88 |
|
| $ | (0.41 | ) |
| Loss from discontinued operations per weighted average common share — basic | | $ | — |
|
| $ | (0.11 | ) |
| Earnings/(Loss) per Weighted Average Common Share — Basic | | $ | 0.88 |
|
| $ | (0.52 | ) |
| Weighted average number of common shares outstanding — diluted | 322 |
|
| 317 |
|
| 317 |
|
| 316 |
| 322 |
|
| 316 |
|
| Income from continuing operations per weighted average common share — diluted | $ | 0.61 |
|
| $ | 0.43 |
|
| $ | 0.58 |
|
| $ | 0.10 |
| |
| (Loss)/Income from discontinued operations per weighted average common share — diluted | $ | (0.08 | ) |
| $ | 0.84 |
|
| $ | (2.53 | ) |
| $ | 0.81 |
| |
| Income/(Loss) per Weighted Average Common Share — Diluted | $ | 0.53 |
|
| $ | 1.27 |
|
| $ | (1.95 | ) |
| $ | 0.91 |
| |
| Income/(loss) from continuing operations per weighted average common share — diluted | | $ | 0.87 |
|
| $ | (0.41 | ) |
| Loss from discontinued operations per weighted average common share — diluted | | $ | — |
|
| $ | (0.11 | ) |
| Earnings/(Loss) per Weighted Average Common Share — Diluted | | $ | 0.87 |
|
| $ | (0.52 | ) |
| Dividends Per Common Share | $ | 0.03 |
|
| $ | 0.03 |
|
| $ | 0.09 |
|
| $ | 0.21 |
| $ | 0.03 |
|
| $ | 0.03 |
|
See accompanying notes to condensed consolidated financial statements.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
(Unaudited)
|
| | | | | | | | | | | | | | | |
| | Three months ended September 30, | | Nine months ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) |
| Net income/(loss) | $ | 163 |
| | $ | 393 |
| | $ | (682 | ) |
| $ | 164 |
|
| Other comprehensive income/(loss), net of tax |
| |
| |
|
|
|
| Unrealized gain/(loss) on derivatives, net of income tax (benefit)/expense of $0, $(1), $1, and $1 | 7 |
|
| 27 |
|
| 6 |
|
| (8 | ) |
| Foreign currency translation adjustments, net of income tax expense of $0, $0, $0, and $0 | 2 |
|
| 3 |
|
| 10 |
|
| 6 |
|
| Available-for-sale securities, net of income tax expense of $0, $0, $0, and $0 | 1 |
|
| — |
|
| 2 |
|
| 1 |
|
| Defined benefit plans, net of income tax expense of $0, $0, $0, and $0 | (1 | ) |
| 31 |
|
| 26 |
|
| 32 |
|
| Other comprehensive income | 9 |
|
| 61 |
|
| 44 |
|
| 31 |
|
| Comprehensive income/(loss) | 172 |
|
| 454 |
|
| (638 | ) |
| 195 |
|
| Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interests | (5 | ) |
| (2 | ) |
| (61 | ) |
| (70 | ) |
| Comprehensive income/(loss) attributable to NRG Energy, Inc. | 177 |
|
| 456 |
|
| (577 | ) |
| 265 |
|
| Dividends for preferred shares | — |
|
| — |
|
| — |
|
| 5 |
|
| Gain on redemption of preferred shares | — |
| | — |
| | — |
|
| (78 | ) |
| Comprehensive income/(loss) available for common stockholders | $ | 177 |
|
| $ | 456 |
|
| $ | (577 | ) |
| $ | 338 |
|
|
| | | | | | | |
| | Three months ended March 31, |
| | 2018 |
| 2017 |
| | (In millions) |
| Net income/(loss) | $ | 233 |
| | $ | (203 | ) |
| Other comprehensive income/(loss), net of tax |
| |
|
| Unrealized gain on derivatives, net of income tax expense of $0 and $1 | 14 |
|
| 4 |
|
| Foreign currency translation adjustments, net of income tax expense of $0 and $0 | (2 | ) |
| 7 |
|
| Defined benefit plans, net of income tax expense of $0 and $0 | (1 | ) |
| — |
|
| Other comprehensive income | 11 |
| | 11 |
|
| Comprehensive income/(loss) | 244 |
| | (192 | ) |
| Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest | (38 | ) |
| (39 | ) |
| Comprehensive income/(loss) attributable to NRG Energy, Inc. | 282 |
| | (153 | ) |
| Comprehensive income/(loss) available for common stockholders | $ | 282 |
| | $ | (153 | ) |
See accompanying notes to condensed consolidated financial statements.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | September 30, 2017 | | December 31, 2016 | | | | | |
| (In millions, except shares) | | | | March 31, 2018 |
| December 31, 2017 |
| ASSETS | | | | | | |
| Current Assets | | | | |
|
|
| Cash and cash equivalents | $ | 1,223 |
|
| $ | 938 |
| $ | 764 |
|
| $ | 991 |
|
| Funds deposited by counterparties | 31 |
|
| 2 |
| 241 |
|
| 37 |
|
| Restricted cash | 537 |
|
| 446 |
| 407 |
|
| 508 |
|
| Accounts receivable, net | 1,274 |
|
| 1,058 |
| 903 |
|
| 1,079 |
|
| Inventory | 630 |
|
| 721 |
| 528 |
|
| 532 |
|
| Derivative instruments | 475 |
|
| 1,067 |
| 1,015 |
|
| 626 |
|
| Cash collateral posted in support of energy risk management activities | 203 |
|
| 150 |
| |
| Cash collateral paid in support of energy risk management activities | | 211 |
|
| 171 |
|
| Accounts receivable - affiliate | | 73 |
|
| 95 |
|
| Current assets - held for sale | 33 |
|
| 9 |
| 89 |
|
| 115 |
|
| Prepayments and other current assets | 354 |
|
| 404 |
| 326 |
|
| 261 |
|
| Current assets - discontinued operations | — |
|
| 1,919 |
| |
| Total current assets | 4,760 |
|
| 6,714 |
| 4,557 |
|
| 4,415 |
|
| Property, plant and equipment, net | 15,332 |
|
| 15,369 |
| 13,911 |
|
| 13,908 |
|
| Other Assets | |
| | |
| |
| Equity investments in affiliates | 1,138 |
|
| 1,120 |
| 1,011 |
|
| 1,038 |
|
| Notes receivable, less current portion | 5 |
|
| 16 |
| |
| Goodwill | 662 |
|
| 662 |
| 539 |
|
| 539 |
|
| Intangible assets, net | 1,838 |
|
| 1,973 |
| 1,726 |
|
| 1,746 |
|
| Nuclear decommissioning trust fund | 670 |
|
| 610 |
| 680 |
|
| 692 |
|
| Derivative instruments | 206 |
|
| 181 |
| 354 |
|
| 172 |
|
| Deferred income taxes | 205 |
|
| 225 |
| 136 |
|
| 134 |
|
| Non-current assets held-for-sale | 10 |
|
| 10 |
| 157 |
|
| 43 |
|
| Other non-current assets | 644 |
|
| 841 |
| 681 |
|
| 631 |
|
| Non-current assets - discontinued operations | — |
|
| 2,961 |
| |
| Total other assets | 5,378 |
|
| 8,599 |
| 5,284 |
|
| 4,995 |
|
| Total Assets | $ | 25,470 |
|
| $ | 30,682 |
| $ | 23,752 |
|
| $ | 23,318 |
|
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |
| | |
| |
| Current Liabilities | |
| | |
| |
| Current portion of long-term debt and capital leases | $ | 1,247 |
|
| $ | 516 |
| $ | 956 |
|
| $ | 688 |
|
| Accounts payable | 911 |
|
| 813 |
| 787 |
|
| 881 |
|
| Accounts payable - affiliate | | 32 |
|
| 33 |
|
| Derivative instruments | 522 |
|
| 1,092 |
| 790 |
|
| 555 |
|
| Cash collateral received in support of energy risk management activities | 31 |
|
| 81 |
| 240 |
|
| 37 |
|
| Current liabilities held-for-sale | | 80 |
|
| 72 |
|
| Accrued expenses and other current liabilities | 830 |
|
| 990 |
| 662 |
|
| 890 |
|
| Accrued expenses and other current liabilities - affiliate | 164 |
|
| — |
| 161 |
|
| 161 |
|
| Current liabilities - discontinued operations | — |
|
| 1,210 |
| |
| Total current liabilities | 3,705 |
|
| 4,702 |
| 3,708 |
|
| 3,317 |
|
| Other Liabilities | |
| | |
| |
| Long-term debt and capital leases | 15,658 |
|
| 15,957 |
| 15,406 |
|
| 15,716 |
|
| Nuclear decommissioning reserve | 265 |
|
| 287 |
| 272 |
|
| 269 |
|
| Nuclear decommissioning trust liability | 397 |
|
| 339 |
| 400 |
|
| 415 |
|
| Deferred income taxes | 21 |
|
| 20 |
| 20 |
|
| 21 |
|
| Derivative instruments | 307 |
|
| 284 |
| 264 |
|
| 197 |
|
| Out-of-market contracts, net | 213 |
|
| 230 |
| 201 |
|
| 207 |
|
| Non-current liabilities held-for-sale | 13 |
|
| 11 |
| 7 |
|
| 8 |
|
| Other non-current liabilities | 1,116 |
|
| 1,176 |
| 1,136 |
|
| 1,122 |
|
| Non-current liabilities - discontinued operations | — |
|
| 3,184 |
| |
| Total non-current liabilities | 17,990 |
|
| 21,488 |
| 17,706 |
|
| 17,955 |
|
| Total Liabilities | 21,695 |
|
| 26,190 |
| 21,414 |
|
| 21,272 |
|
| Redeemable noncontrolling interest in subsidiaries | 85 |
|
| 46 |
| 80 |
|
| 78 |
|
| Commitments and Contingencies |
|
|
|
|
|
|
|
|
|
|
| Stockholders’ Equity |
|
|
|
|
|
|
| Common stock | 4 |
|
| 4 |
| 4 |
|
| 4 |
|
| Additional paid-in capital | 8,369 |
|
| 8,358 |
| 8,379 |
|
| 8,376 |
|
| Retained deficit | (4,713 | ) |
| (3,787 | ) | |
| Less treasury stock, at cost — 101,580,045 and 102,140,814 shares, respectively | (2,386 | ) |
| (2,399 | ) | |
| Accumulated deficit | | (5,982 | ) |
| (6,268 | ) |
| Less treasury stock, at cost — 104,518,931 and 101,580,045 shares, at March 31, 2018 and December 31, 2017, respectively | | (2,474 | ) |
| (2,386 | ) |
| Accumulated other comprehensive loss | (91 | ) |
| (135 | ) | (61 | ) |
| (72 | ) |
| Noncontrolling interest | 2,507 |
|
| 2,405 |
| 2,392 |
|
| 2,314 |
|
| Total Stockholders’ Equity | 3,690 |
|
| 4,446 |
| 2,258 |
|
| 1,968 |
|
| Total Liabilities and Stockholders’ Equity | $ | 25,470 |
|
| $ | 30,682 |
| $ | 23,752 |
|
| $ | 23,318 |
|
See accompanying notes to condensed consolidated financial statements.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | Nine months ended September 30, | Three months ended March 31, |
| (In millions) | 2017 | | 2016 | 2018 |
| 2017 |
| Cash Flows from Operating Activities | | | | | | |
| Net (loss)/income | $ | (682 | ) |
| $ | 164 |
| |
| (Loss)/Income from discontinued operations, net of income tax | (802 | ) |
| 256 |
| |
| Net income/(loss) | | $ | 233 |
|
| $ | (203 | ) |
| Loss from discontinued operations, net of income tax | | — |
|
| (34 | ) |
| Income/(loss) from continuing operations | 120 |
|
| (92 | ) | 233 |
|
| (169 | ) |
| Adjustments to reconcile net (loss)/income to net cash provided by operating activities: |
|
|
| |
| Adjustments to reconcile net income to net cash provided/(used) by operating activities: | |
|
|
|
| Distributions and equity in earnings of unconsolidated affiliates | 24 |
|
| 44 |
| 12 |
|
| 8 |
|
| Depreciation and amortization | 789 |
|
| 826 |
| 235 |
|
| 257 |
|
| Provision for bad debts | 57 |
|
| 36 |
| 15 |
|
| 9 |
|
| Amortization of nuclear fuel | 37 |
|
| 39 |
| 13 |
|
| 12 |
|
| Amortization of financing costs and debt discount/premiums | 44 |
|
| 42 |
| 14 |
|
| 15 |
|
| Adjustment for debt extinguishment | 3 |
|
| 119 |
| 2 |
|
| — |
|
| Amortization of intangibles and out-of-market contracts | 79 |
|
| 131 |
| 22 |
|
| 30 |
|
| Amortization of unearned equity compensation | 27 |
|
| 23 |
| 13 |
|
| 8 |
|
| Impairment losses | 77 |
|
| 211 |
| |
| Changes in deferred income taxes and liability for uncertain tax benefits | 26 |
|
| 29 |
| (3 | ) |
| 1 |
|
| Changes in nuclear decommissioning trust liability | 20 |
|
| 24 |
| 34 |
|
| 36 |
|
| Changes in derivative instruments | 25 |
|
| 30 |
| (247 | ) |
| 38 |
|
| Changes in collateral posted in support of risk management activities | (103 | ) |
| 261 |
| |
| Proceeds from sale of emission allowances | 21 |
|
| 11 |
| |
| (Gain)/loss on sale of assets | (22 | ) |
| 70 |
| |
| Changes in collateral deposits in support of energy risk management activities | | 163 |
|
| (127 | ) |
| Gain on sale of emission allowances | | (8 | ) |
| — |
|
| Gain on sale of assets | | (2 | ) |
| (2 | ) |
| Changes in other working capital | (380 | ) |
| (130 | ) | (139 | ) |
| (198 | ) |
| Cash provided by continuing operations | 844 |
|
| 1,674 |
| |
| Cash (used)/provided by discontinued operations | (38 | ) |
| 67 |
| |
| Net Cash Provided by Operating Activities | 806 |
|
| 1,741 |
| |
| Cash provided/(used) by continuing operations | | 357 |
|
| (82 | ) |
| Cash provided by discontinued operations | | — |
|
| 15 |
|
| Net Cash Provided/(Used) by Operating Activities | | 357 |
|
| (67 | ) |
| Cash Flows from Investing Activities | |
| | |
| |
| Acquisitions of businesses, net of cash acquired | (36 | ) |
| (18 | ) | (62 | ) |
| (3 | ) |
| Capital expenditures | (760 | ) |
| (659 | ) | (358 | ) |
| (236 | ) |
| Decrease in notes receivable | 11 |
|
| 2 |
| 3 |
|
| 4 |
|
| Purchases of emission allowances | (47 | ) |
| (32 | ) | (17 | ) |
| (9 | ) |
| Proceeds from sale of emission allowances | 105 |
|
| 47 |
| 23 |
|
| 11 |
|
| Investments in nuclear decommissioning trust fund securities | (402 | ) |
| (378 | ) | (216 | ) |
| (153 | ) |
| Proceeds from the sale of nuclear decommissioning trust fund securities | 382 |
|
| 354 |
| 182 |
|
| 117 |
|
| Proceeds from renewable energy grants and state rebates | 8 |
|
| 11 |
| |
| Proceeds from sale of assets, net of cash disposed of | 36 |
|
| 84 |
| 11 |
|
| 14 |
|
| Investments in unconsolidated affiliates | (31 | ) |
| (23 | ) | |
| Changes in investments in unconsolidated affiliates | | 2 |
|
| (12 | ) |
| Other | 22 |
|
| 31 |
| — |
|
| 18 |
|
| Cash used by continuing operations | (712 | ) |
| (581 | ) | (432 | ) |
| (249 | ) |
| Cash (used)/provided by discontinued operations | (53 | ) |
| 326 |
| |
| Cash used by discontinued operations | | — |
|
| (32 | ) |
| Net Cash Used by Investing Activities | (765 | ) |
| (255 | ) | (432 | ) |
| (281 | ) |
| Cash Flows from Financing Activities | |
| | |
| |
| Payment of dividends to common and preferred stockholders | (28 | ) |
| (66 | ) | (10 | ) |
| (9 | ) |
| Payment for preferred shares | — |
|
| (226 | ) | |
| Payment for treasury stock | | (93 | ) |
| — |
|
| Net receipts from settlement of acquired derivatives that include financing elements | 2 |
|
| 6 |
| — |
|
| 1 |
|
| Proceeds from issuance of long-term debt | 1,134 |
|
| 5,237 |
| 179 |
|
| 193 |
|
| Payments for short and long-term debt | (712 | ) |
| (5,353 | ) | (228 | ) |
| (177 | ) |
| Receivable from affiliate | (125 | ) |
| — |
| |
| Payments for debt extinguishment costs | — |
|
| (98 | ) | |
| Contributions from, net of distributions to, noncontrolling interest in subsidiaries | 65 |
|
| (127 | ) | |
| Proceeds from issuance of stock | — |
|
| 1 |
| |
| Net contributions from/(distributions to) noncontrolling interests in subsidiaries | | 110 |
|
| (5 | ) |
| Payment of debt issuance costs | (43 | ) |
| (70 | ) | (7 | ) |
| (14 | ) |
| Other - contingent consideration | (10 | ) |
| (10 | ) | — |
|
| (10 | ) |
| Cash provided/(used) by continuing operations | 283 |
|
| (706 | ) | |
| Cash (used)/provided by discontinued operations | (224 | ) |
| 119 |
| |
| Net Cash provided/(used) by Financing Activities | 59 |
|
| (587 | ) | |
| Cash used by continuing operations | | (49 | ) |
| (21 | ) |
| Cash used by discontinued operations | | — |
|
| (132 | ) |
| Net Cash Used by Financing Activities | | (49 | ) |
| (153 | ) |
| Effect of exchange rate changes on cash and cash equivalents | (10 | ) |
| (6 | ) | — |
|
| (7 | ) |
| Change in Cash from discontinued operations | (315 | ) |
| 512 |
| — |
|
| (149 | ) |
| Net Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | 405 |
|
| 381 |
| |
| Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | | (124 | ) |
| (359 | ) |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 1,386 |
|
| 1,322 |
| 1,536 |
|
| 1,386 |
|
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 1,791 |
|
| $ | 1,703 |
| $ | 1,412 |
|
| $ | 1,027 |
|
See accompanying notes to condensed consolidated financial statements.
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 — Basis of Presentation
General
NRG Energy, Inc., or NRG or the Company, is a leadingcustomer-driven integrated power company built on the strengtha portfolio of a diverse competitive electric generation portfolio and leading retail electricity platform.brands and diverse generation assets. NRG is continuously focused on excellence in operating performance of its existing assets and optimal hedging of generation assets and retail load operations, as well as serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels. The Company owns and operates approximately 30,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and Company:
directly sells energy services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant"“Reliant” and other retail brand names owned by NRG.NRG;
owns and operates approximately 30,000 MW of generation;
engages in the trading of wholesale energy, capacity and related products; and
transacts in and trades fuel and transportation services.
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 20162017 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 September 30, 2017,March 31, 2018, and the results of operations, comprehensive income/(loss) and cash flows for the three and nine months ended September 30, 2017March 31, 2018 and 2016.2017.
GenOn Chapter 11 Cases
On June 14, 2017, or the Petition Date, GenOn, along with GenOn Americas Generation and certain of their directly and indirectly-owned subsidiaries, or collectively the GenOn Entities, filed voluntary petitions for relief under Chapter 11, or the Chapter 11 Cases, of the U.S. Bankruptcy Code, or the Bankruptcy Code, in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division, or the Bankruptcy Court. GenOn Mid-Atlantic, as well as its consolidated subsidiaries, REMA and certain other subsidiaries, did not file for relief under Chapter 11.
As a result of the bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries were deconsolidated from NRG’s consolidated financial statements. NRG recorded its investment in GenOn under the cost method with an estimated fair value of zero. NRG determined that this disposal of GenOn and its subsidiaries is a discontinued operation;operation and, accordingly, the financial information for all historical periods havehas been recast to reflect GenOn as a discontinued operation. In connection with the disposal, NRG recorded a loss on deconsolidation of $208 million during the quarter ended June 30, 2017. See Note 3, Discontinued Operations, Dispositions and Acquisitions, for more information.
Prior to the GenOn Entities' filing the Chapter 11 Cases, on June 12, 2017, NRG entered into a restructuring support and lock-up agreement, or the Restructuring Support Agreement, with the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes, that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. The RSA was amended on October 2, 2017 to remove the requirement to conduct a rights offering in connection with the exit financing. There is no assurance that the GenOn Entities' plan will be approved by the requisite stakeholders, confirmed by the Bankruptcy Court, or successfully implemented thereafter. The principal terms of the Restructuring Support Agreement are described further in Note 3, Discontinued Operations, Dispositions and Acquisitions.
As announced on October 31, 2017, NRG and GenOn engaged in arms-length discussions to settle certain items related to the pre-petition Restructuring Support Agreement, including key topics such as: (i) timeline and transition; (ii) cooperation and co-development matters; (iii) post-employment and retiree health and welfare benefits and pension benefits; (iv) tax matters; and (v) intercompany balances. The agreements reached on these topics are expected to be incorporated into definitive documents for GenOn’s emergence from Chapter 11.
Forms of definitive documents were filed with the Bankruptcy Court by the GenOn Entities; however, such definitive documents are subject to ongoing review, revision, and further negotiation by the parties to the Restructuring Support Agreement, including NRG, who have various consent rights over the final form of the plan supplement documents, and may be amended, modified, supplemented, and revised in accordance with those ongoing negotiations.
Transformation Plan
On July 12, 2017, NRG announced its Transformation Plan designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The three-part, three-year plan is comprised of the following targets:
Operations and cost excellence — Cost savings and margin enhancement of $1,065 million recurring, which consists of $590 million of annual cost savings, a $215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales.
Portfolio optimization — Targeting up to $4.0 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG Yield, Inc. and its renewables platform.
Capital structure and allocation enhancements — A prioritized capital allocation strategy that targets a reduction in consolidated debt from approximately $19.5 billion ($18 billion net debt) to approximately $6.5 billion ($6 billion net debt). Following the completion of the contemplated asset sales, the Company expects $4.8-$6.3 billion in excess cash to be available for allocation through 2020, after achieving its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio.
The Company expects to fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018. The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and (ii) approximately $290 million, one-time costs to achieve.
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:
| | | | September 30, 2017 | | December 31, 2016 | March 31, 2018 | | December 31, 2017 |
| | (In millions) | (In millions) |
| Accounts receivable allowance for doubtful accounts | $ | 61 |
| | $ | 29 |
| $ | 27 |
| | $ | 28 |
|
| Property, plant and equipment accumulated depreciation | 6,437 |
| | 5,711 |
| 4,679 |
| | 4,465 |
|
| Intangible assets accumulated amortization | 1,750 |
| | 1,687 |
| 1,393 |
| | 1,818 |
|
| Out-of-market contracts accumulated amortization | 352 |
| | 457 |
| 364 |
| | 358 |
|
Restricted Cash
The following table provides a reconciliation of cash and cash equivalents, restricted cash and funds deposited by counterparties reported within the consolidated balance sheet that sum to the total of the same such amounts shown in the statement of cash flows.
| | | | September 30, 2017 | | December 31, 2016 | | September 30, 2016 | | December 31, 2015 | March 31, 2018 | | December 31, 2017 | | March 31, 2017 | | December 31, 2016 |
| | (In millions) | (In millions) |
| Cash and cash equivalents | $ | 1,223 |
| | $ | 938 |
| | $ | 1,217 |
| | $ | 853 |
| $ | 764 |
| | $ | 991 |
| | $ | 627 |
| | $ | 938 |
|
| Funds deposited by counterparties | 31 |
| | 2 |
| | 6 |
| | 55 |
| 241 |
| | 37 |
| | 3 |
| | 2 |
|
| Restricted cash | 537 |
| | 446 |
| | 480 |
| | 414 |
| 407 |
| | 508 |
| | 397 |
| | 446 |
|
| Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows | $ | 1,791 |
| | $ | 1,386 |
| | $ | 1,703 |
| | $ | 1,322 |
| $ | 1,412 |
| | $ | 1,536 |
| | $ | 1,027 |
| | $ | 1,386 |
|
Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. As of December 31, 2016, $79 million of the cash collateral received was from GenOn, previously a consolidated subsidiary, and is included in cash collateral received in current liabilities as a result of deconsolidating GenOn, with the offset included in cash and cash equivalents.
Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use.
Noncontrolling Interest
The following table reflects the changes in NRG's noncontrolling interest balance:
| | | | (In millions) | (In millions) |
| Balance as of December 31, 2016 | $ | 2,405 |
| |
| Contributions from noncontrolling interest | 116 |
| |
| Non-cash adjustments to noncontrolling interest | 98 |
| |
| Sale of assets to NRG Yield, Inc. | 24 |
| |
| Comprehensive loss attributable to noncontrolling interest | (8 | ) | |
| Balance as of December 31, 2017 | | $ | 2,314 |
|
| Dividends paid to NRG Yield, Inc. public shareholders | (80 | ) | (30 | ) |
| Distributions to noncontrolling interest | (48 | ) | (19 | ) |
| Balance as of September 30, 2017 | $ | 2,507 |
| |
| Comprehensive loss attributable to noncontrolling interest | | (22 | ) |
| Non-cash adjustments to noncontrolling interest | | 6 |
|
| Contributions from noncontrolling interest | | 147 |
|
| Sale of assets to NRG Yield, Inc. | | (4 | ) |
| Balance as of March 31, 2018 | | $ | 2,392 |
|
Redeemable Noncontrolling Interest
The following table reflects the changes in the Company's redeemable noncontrolling interest balance:
| | | | (In millions) | (In millions) |
| Balance as of December 31, 2016 | $ | 46 |
| |
| Balance as of December 31, 2017 | | $ | 78 |
|
| Distributions to redeemable noncontrolling interest | | (1 | ) |
| Contributions from redeemable noncontrolling interest | 73 |
| 12 |
|
| Non-cash adjustments to noncontrolling interest | 21 |
| |
| Non-cash adjustments to redeemable noncontrolling interest | | 7 |
|
| Comprehensive loss attributable to redeemable noncontrolling interest | (53 | ) | (16 | ) |
| Distributions to redeemable noncontrolling interest | (2 | ) | |
| Balance as of September 30, 2017 | $ | 85 |
| |
| Balance as of March 31, 2018 | | $ | 80 |
|
Revenue Recognition
Revenue from Contracts with Customers
On January 1, 2018, the Company adopted the guidance in ASC 606 using the modified retrospective method applied to contracts which were not completed as of the adoption date. The Company recognized the cumulative effect of initially applying the new standard as a credit to the opening balance of accumulated deficit, resulting in a decrease of approximately $16 million. The adjustment primarily related to costs incurred to obtain a contract with customers and customer incentives. Following the adoption of the new standard, the Company’s revenue recognition of its contracts with customers remains materially consistent with its historical practice. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The Company's policies with respect to its various revenue streams are detailed below. In general, the Company applies the invoicing practical expedient to recognize revenue for the revenue streams detailed below, except in circumstances where the invoiced amount does not represent the value transferred to the customer.
Retail Revenues
Gross revenues for energy sales and services to retail customers are recognized as the Company transfers the promised goods and services to the customer. For the majority of its electricity contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligation in a contract for which the timing of the revenue recognized is different. Additionally, customer discounts and incentives reduce the contract consideration and are recognized over the term of the contract.
Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.
As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration, customer type, inception date and other contract-specific factors. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.
Energy Revenue
Both physical and financial transactions are entered into to optimize the financial performance of the Company's generating facilities. Electric energy revenue is recognized upon transmission to the customer over time, using the output method for measuring progress of satisfaction of performance obligations. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. The Company applies the invoicing practical expedient, where applicable, in recognizing energy revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815.
Capacity Revenue
Capacity revenues consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements. Capacity revenues are recognized over time, using the output method for measuring progress of satisfaction of performance obligations. The Company applies the invoicing practical expedient, where applicable, in recognizing capacity revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date.
Capacity revenue contracts mainly consist of:
Capacity auctions — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO. Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time performance, where NRG's actual revenues will be the combination of revenues based on the cleared auction MWs plus the net of any over- and under-performance of NRG's fleet. In addition, MISO has an annual auction, known as the Planning Resource Auction, or PRA. The Gulf Coast assets situated in the MISO market may participate in this auction. Estimated revenues for cleared auction MWs in the various capacity auctions are $554 million, $508 million, $423 million, $222 million and $57 million for fiscal years 2018, 2019, 2020, 2021 and 2022, respectively.
Resource adequacy and bilateral contracts — In California, there is a resource adequacy requirement that is primarily satisfied through bilateral contracts. Such bilateral contracts are typically short-term resource adequacy contracts. When bilateral contracting does not satisfy the resource adequacy need, such shortfalls can be addressed through procurement tools administered by the CAISO, including the capacity procurement mechanism or reliability must-run contracts. Demand payments from the current long-term contracts are tied to summer peak demand and provide a mechanism for recovering a portion of the costs associated with new or changed environmental laws or regulations. In Texas, capacity and contracted revenues are through bilateral contracts with load serving entities.
Long-term PPAs — Energy, capacity and where applicable, renewable attributes, from the majority of renewable energy assets and certain conventional energy plants is sold through long-term PPAs and tolling agreements to a single counterparty, which is often a utility or commercial customer. Many of these PPAs are accounted for as leases.
Renewable Energy Credits
As stated above, renewable energy credits are usually sold through long-term PPAs. Revenue from the sale of self-generated RECs is recognized when related energy is generated and simultaneously delivered even in cases where there is a certification lag as it has been deemed to be perfunctory.
In a bundled contract to sell energy, capacity and/or self-generated RECs, all performance obligations are deemed to be delivered at the same time and hence, timing of recognition of revenue for all performance obligations is the same and occurs over time. In such cases, it is often unnecessary to allocate transaction price to multiple performance obligations.
Sale of Emission Allowances
The Company records its inventory of emission allowances as part of intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. The Company records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations.
Disaggregated Revenues
The following table represents the Company’s disaggregation of revenue from contracts with customers for the three months ended March 31, 2018, along with the reportable segment for each category:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended March 31, 2018 |
| | | | Generation | | | | | | | | |
| (In millions) | Retail | | Gulf Coast | | East/West(a) | | Subtotal | | Renewables | | NRG Yield | | Eliminations | | Total |
Energy revenue(a)(b) | $ | — |
| | $ | 371 |
| | $ | 218 |
| | $ | 589 |
| | $ | 77 |
| | $ | 114 |
| | $ | (161 | ) | | $ | 619 |
|
Capacity revenue(a)(b) | — |
| | 67 |
| | 140 |
| | 207 |
| | — |
| | 82 |
| | (1 | ) | | 288 |
|
| Retail revenue |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| Mass customers | 1,171 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 1,170 |
|
| Business solutions customers | 316 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 316 |
|
| Total retail revenue | 1,487 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 1,486 |
|
Mark-to-market for economic hedging activities(c) | (6 | ) | | (564 | ) | | (10 | ) | | (574 | ) | | (10 | ) | | — |
| | 484 |
| | (106 | ) |
| Contract amortization | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | (17 | ) | | — |
| | (14 | ) |
Other revenue(a)(b) | — |
| | 86 |
| | 16 |
| | 102 |
| | 19 |
| | 46 |
| | (19 | ) | | 148 |
|
| Total operating revenue | 1,481 |
| | (37 | ) | | 364 |
| | 327 |
| | 86 |
| | 225 |
| | 302 |
| | 2,421 |
|
| Less: Lease revenue | 6 |
| | — |
| | 1 |
| | 1 |
| | 64 |
| | 181 |
| | — |
| | 252 |
|
| Less: Derivative revenue | (6 | ) | | (188 | ) | | 80 |
| | (108 | ) | | (10 | ) | | — |
| | 484 |
| | 360 |
|
| Less: Contract amortization | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | (17 | ) | | — |
| | (14 | ) |
| Total revenue from contracts with customers | $ | 1,481 |
| | $ | 148 |
| | $ | 283 |
| | $ | 431 |
| | $ | 32 |
| | $ | 61 |
| | $ | (182 | ) | | $ | 1,823 |
|
| (a) The following amounts of energy and capacity revenue relate to leases and are accounted for under ASC 840: |
| | Retail | | Gulf Coast | | East/West | | Subtotal | | Renewables | | NRG Yield | | Eliminations | | Total |
| Energy revenue | — |
| | — |
| | — |
| | — |
| | 61 |
| | 102 |
| | — |
| | 163 |
|
| Capacity revenue | — |
| | — |
| | — |
| | — |
| | — |
| | 79 |
| | — |
| | 79 |
|
| Other revenue | 6 |
| | — |
| | 1 |
| | 1 |
| | 3 |
| | — |
| | — |
| | 10 |
|
| (b) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815. |
| | Retail | | Gulf Coast | | East/West | | Subtotal | | Renewables | | NRG Yield | | Eliminations | | Total |
| Energy revenue | — |
| | 371 |
| | 61 |
| | 432 |
| | — |
| | — |
| | — |
| | 432 |
|
| Capacity revenue | — |
| | — |
| | 26 |
| | 26 |
| | — |
| | — |
| | — |
| | 26 |
|
| Other revenue | — |
| | 5 |
| | 3 |
| | 8 |
| | — |
| | — |
| | — |
| | 8 |
|
| (c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815. |
Contract Amortization
Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation and/or contracted volumes.
Lease Revenue
Certain of the Company’s revenues are obtained through PPAs or other contractual agreements. Many of these agreements are accounted for as operating leases under ASC 840 Leases. Certain of these leases have no minimum lease payments and all of the rent is recorded as contingent rent on an actual basis when the electricity is delivered. Judgment is required by management in determining the economic life of each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in determining whether a contract contains a lease and whether the lease is an operating lease or capital lease.
Contract Balances
The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of March 31, 2018:
|
| | | | |
| | | |
| (In millions) | | March 31, 2018 |
| Deferred customer acquisition costs | | $ | 85 |
|
| | | |
| Accounts receivable, net - Contracts with customers | | 784 |
|
| Accounts receivable, net - Leases | | 81 |
|
| Accounts receivable, net - Derivative instruments | | 38 |
|
| Total accounts receivable, net | | 903 |
|
| | | |
| Unbilled revenues (included within Accounts receivable, net - Contracts with customers) | | 292 |
|
| | | |
| Deferred revenues | | 63 |
|
The Company’s customer acquisition costs consist of broker fees, commission payments and other costs that represent incremental costs of obtaining the contract with customers for which the Company expects to recover. The Company amortizes these amounts over the estimated life of the customer contract. As a practical expedient, the Company expenses the incremental costs of obtaining a contract if the amortization period of the asset would have been one year or less.
When the Company receives consideration from the customer that is in excess of the amount due, such consideration is reclassified to deferred revenue, which represents a contract liability. Generally, the Company will recognize revenue from contract liabilities in the next period as the Company satisfies its performance obligations.
Recent Accounting Developments - Guidance Adopted in 2017
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 adopted the guidance in ASU No. 2016-18 during the second quarter of 2017. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in a decrease in cash flows from operations of $49 million and an increase in cash flows from investing of $66 million on the statement of cash flows for the nine months ended September 30, 2016.
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. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in an increase in cash flows from operations of $98 million and a decrease in cash flows from financing of $98 million on the statement of cash flows for the nine months ended September 30, 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 2017-12 — In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities, or ASU No. 2017-12. The amendments of ASU No. 2017-12 were issued to simplify the application of hedge accounting guidance and more closely align financial reporting for hedging relationships with economic results of an entity's risk management activities. The issues addressed by ASU No. 2017-12 include but are not limited to alignment of risk management activities and financial reporting, risk component hedging, accounting for the hedged item in fair value hedges of interest rate risk, recognition and presentation of the effects of hedging instruments, amounts excluded from the assessment of hedge effectiveness, and other simplifications of hedge accounting guidance. The amendments of ASU No. 2017-12 are effective for fiscal years beginning after December 15, 2018 and interim periods therein. Early adoption is permitted in any interim period and the effect of the adoption should be reflected as of the beginning of the fiscal year of adoption. The Company does not expect the adoption of ASU No. 2017-12 will have a material impact on its consolidated results of operations, cash flows, and statement of financial position.
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 Company adopted the amendments of ASU No. 2017-07 are effective January 1, 2018. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in an increase in cost of operations of $4 million and a corresponding increase in other income, net on the statement of operations for the three months ended March 31, 2017.
ASU 2016-01 - In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) be generally measured at fair value with changes in fair value recognized in net income. Further, the amendments require that financial assets and financial liabilities be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset. The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, includingand interim periods therein. Early adoption is permitted and must be applied on a retrospective basis, except forwithin those annual periods. The Company adopted the amendments regarding the capitalization of the service cost component, which must be applied prospectively. The Company is currently assessing the impact thatASU No. 2016-01 effective January 1, 2018. In connection with the adoption of ASU No. 2017-07 will havethe standard, the Company has applied the guidance on itsa modified retrospective basis, which resulted in no material adjustments recorded to the consolidated results of operations, cash flows, and statement of financial position.
Recent Accounting Developments - Guidance Not Yet Adopted
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 towill adopt the standard effective January 1, 2019, utilizing the required modified retrospective approach for the earliest period presented. The Companyand 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. While this review is still in process, NRG believes the adoption of Topic 842 will have a material impact on its financial statements.
ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or The Company is also monitoring recent changes to 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 FASB842 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. While the impact remains subject to continued review, the Company does not believe the adoption of Topic 606 will have a materialrelated impact on its financial statements.the implementation process.
Note 3 — Discontinued Operations Dispositions and AcquisitionsDispositions
This footnote should be read in conjunction with the complete description under Note 3, Discontinued Operations, Acquisitions and Dispositions, to the Company's 2017 Form 10-K.
Discontinued Operations
As described in Note 1, Basis of Presentation, on the Petition Date,On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings, NRG has concluded that it no longer controls GenOn as it is subject to the control of the Bankruptcy Court; and, accordingly, NRG no longer consolidates GenOn for financial reporting purposes.
By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG has concluded that GenOn meets the criteria for discontinued operations, as this represents a strategic shift in the markets in which NRG operates. As such, all prior period results for GenOn have been reclassified as discontinued operations while NRG will record all ongoing results of GenOn as a cost method investment, which was valued at zero at the date of deconsolidation.operations.
Summarized results of discontinued operations were as follows:
|
| | | | | | | | | | | | | | | |
| | Three months ended September 30, 2017 (a) | | Three months ended September 30, 2016 | | Nine months ended September 30, 2017 (a) | | Nine months ended September 30, 2016 |
| (In millions) | | | |
| Operating revenues | $ | — |
| | $ | 532 |
| | $ | 646 |
| | $ | 1,509 |
|
| Operating costs and expenses | — |
| | (468 | ) | | (700 | ) | | (1,409 | ) |
| Gain on sale of assets | — |
| | 262 |
| | — |
| | 294 |
|
| Other expenses | — |
| | (43 | ) | | (98 | ) | | (127 | ) |
| (Loss)/Income from operations of discontinued components, before tax | — |
| | 283 |
| | (152 | ) | | 267 |
|
| Income tax expense | — |
| | 21 |
| | 9 |
| | 20 |
|
| (Loss)/Incomes from operations of discontinued components | — |
| | 262 |
| | (161 | ) | | 247 |
|
| Interest income - affiliate | — |
| | 3 |
| | 6 |
| | 9 |
|
| (Loss)/Income from operations of discontinued components, net of tax | — |
| | 265 |
| | (155 | ) | | 256 |
|
| Pre-tax loss on deconsolidation | — |
| | — |
| | (208 | ) | | — |
|
| Settlement consideration and services credit | — |
| | — |
| | (289 | ) | | — |
|
Pension and post-retirement liability assumption(b) | (25 | ) | | — |
| | (144 | ) | | — |
|
| Other | (2 | ) | | — |
| | (6 | ) | | — |
|
| Loss on disposal of discontinued components, net of tax | (27 | ) | | — |
| | (647 | ) | | — |
|
| (Loss)/Income from discontinued operations, net of tax | $ | (27 | ) | | $ | 265 |
| | $ | (802 | ) | | $ | 256 |
|
|
| | | |
| | Three months ended March 31, 2017 |
| (In millions) |
| Operating revenues | $ | 381 |
|
| Operating costs and expenses | (373 | ) |
| Other expenses | (44 | ) |
| Loss from operations of discontinued components, before tax | (36 | ) |
| Income tax expense | 1 |
|
| Loss from operations of discontinued components | (37 | ) |
| Interest income - affiliate | 3 |
|
| Loss from discontinued operations, net of tax | $ | (34 | ) |
(a) As of June 14, 2017, NRG no longer consolidates GenOn for financial reporting purposes.
(b) See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement. As part of this, NRGIncome recorded the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million with a corresponding loss onfrom discontinued operations duringwas immaterial for the third quarter of 2017.three months ended March 31, 2018.
The following table summarizes the major classes of assets and liabilities classified as discontinued operations as of December 31, 2016. As of June 14, 2017, NRG no longer consolidates GenOn for financial reporting purposes.
|
| | | | |
| (In millions) | | December 31, 2016 |
| Cash and cash equivalents | | $ | 1,034 |
|
| Other current assets | | 885 |
|
| Current assets - discontinued operations | | 1,919 |
|
| Property, plant and equipment, net | | 2,543 |
|
| Other non-current assets | | 418 |
|
| Non-current assets - discontinued operations | | 2,961 |
|
| Current portion of long term debt and capital leases | | 704 |
|
| Other current liabilities | | 506 |
|
| Current liabilities - discontinued operations | | 1,210 |
|
| Long-term debt and capital leases | | 2,050 |
|
| Out-of-market contracts | | 811 |
|
| Other non-current liabilities | | 323 |
|
| Non-current liabilities - discontinued operations | | $ | 3,184 |
|
Restructuring Support Agreement
As described in Note 1, Basis of Presentation, NRG, GenOn and certain holders representing greater than 93% in aggregate principal amount of GenOn’s Senior Notes and certain holders representing greater than 93% in aggregate principal amount of GenOn Americas Generation’s Senior Notes entered into a Restructuring Support Agreement that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization.reorganization that was approved by the Bankruptcy Court pursuant to an order of confirmation. Completion of the agreed upon terms is contingent upon certain milestones in the Restructuring Support Agreement.Agreement and the satisfaction or waiver or certain conditions precedent. Certain principal terms of the Restructuring Support Agreement and the plan of reorganization are detailed below:
| |
| 1) | FullThe dismissal of litigation and full releases from GenOn and GenOn Americas Generation in favor of NRG including eitherupon the earlier of the consummation of the GenOn Entities' plan of reorganization or the Settlement Agreement; a condition precedent to the consummation of the Settlement Agreement is a full release or indemnification in favor of NRG forfrom any claims relating toof GenOn Mid-Atlantic or REMA and the dismissal of all litigation against NRG.REMA. |
| |
| 2) | NRG will provide settlement cash consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of September 30, 2017,March 31, 2018, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. See Note 14,13, Related Party Transactions, for further discussion of the intercompany secured revolving credit facility. The net liability for these amounts, along with the services credit described below, is recorded in accrued expenses and other current liabilities - affiliate as of March 31, 2018 and December 31, 2017. |
| |
| 3) | NRG will consent to the cancellation of its interests in the equity of GenOn. The equity interests in the reorganized GenOn will be issued to the holders of the GenOn Senior Notes. |
| |
4) | NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of September 30, 2017March 31, 2018, was approximately $106$91 million. NRG will also retain the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million. These liabilities are recorded within other non-current liabilities as of March 31, 2018 and December 31, 2017. |
| |
5)4) | The shared services agreement between NRG and GenOn will be amended such that (i)was terminated and replaced as of the plan confirmation date with a transition services agreement. Under the transition services agreement, NRG will continue to provide the shared services to GenOnand other separation services at an annualized rate of $84 million, during the pendency of the Chapter 11 Cases, (ii) if the settlement is approved by the bankruptcy court, NRG will provide shared servicessubject to GenOn at no charge for two months,certain credits and (iii) NRG will then provide an option for up to two, one-month extensions for shared services at an annualized rate of $84 million.adjustments. See Note 14,13, Related Party Transactions, for further discussion of the shared services agreement.Services Agreement. |
| |
6)5) | NRG will provide a credit of $28 million to GenOn to apply against amounts owed under the sharedtransition services agreement upon emergence from bankruptcy.agreement. Any unused amount can be paid in cash at GenOn’s request. The credit was intended to reimburse GenOn for its payment of financing costs. |
| |
7) | NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit facility was terminated, as GenOn had obtained a separate letter of credit facility with a third party financial institution. See Note 14, Related Party Transactions, for further discussion of the intercompany secured revolver credit facility and the letter of credit facility obtained in July 2017.
|
| |
8)6) | NRG and GenOn have agreed to cooperate in good faith to maximize the value of certain development projects. Pursuant to this, GenOn made a one-time payment in the amount of $15 million to NRG in December 2017 as compensation for a purchase option with respect to the Canal 3 project. On March 22, 2018, NRG agreed to sell Canal 3 to Stonepeak Kestrel Holdings II LLC in conjunction with GenOn's sale of Canal Units 1 and 2 to Stonepeak Kestrel Holdings LLC. NRG expects to reimburse GenOn for $13.5 million of the one-time payment upon the close of the sale of Canal 3. This amount is recorded as a current liability as of March 31, 2018, and December 31, 2017. |
GenMA Settlement
In addition toThe Bankruptcy Court order confirming the Restructuring Support Agreement, additional support and other agreements are being negotiated, including a transition services agreement. See Note 1, Basisplan of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement.
Settlement Consideration
NRG has determined that the payment ofreorganization also approved the settlement consideration is probable and has recorded a liability for the amount due of $261.3 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations. NRG expectsterms agreed to pay this amount net of amounts due from GenOn under the intercompany secured revolving credit facility, which is further described in Note 14, Related Party Transactions.
Pension Liability
NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, which was paid in September 2017, foramong the GenOn employees for service provided prior to emergence from bankruptcy.Entities, NRG, determined that the retention of this liability is probable and has recorded the estimated accumulated pension benefit obligation as of September 30, 2017 of $106 million in other non-current liabilities with a corresponding loss from discontinued operations. NRG's obligation for this liability will be revalued through and at GenOn's emergence from bankruptcy.
Services Agreement
NRG will continue to provide shared services toConsenting Holders, GenOn under the Services Agreement at an annualized rate of $84 million during the pendency of the Chapter 11 Cases as well as for two months post-emergence at no charge. NRG then will provide an option for up to two, one-month extensions for shared services at an annualized rate of $84 million. Beginning on June 14, 2017, NRG records operating income for the amounts earned for shared services of approximately $5 million per month. NRG has also agreed to provide GenOn with a credit of $28 million against amounts owed under the Services Agreement. Any unused amount can be paid in cash at GenOn’s request. As a result, NRG has concluded that the liability for this credit is probable and has recorded a payable to GenOn for $28 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement and Services Agreement.
Commercial Operations
For pre-disposal periods, NRG provided GenOn with services as described in Note 14, Related Party Transactions. Under intercompany agreements, NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOnMid-Atlantic, and certain of its subsidiaries. SubjectGenOn Mid-Atlantic’s stakeholders, or the GenMA Settlement, and directed the settlement parties to applicable collateral thresholds, these arrangements may provide forcooperate in good faith to negotiate definitive documentation consistent with the bilateral exchangeGenMA Settlement term sheet in order to pursue consummation of the GenMA Settlement. The definitive documentation effectuating the GenMA Settlement was finalized and effective as of April 27, 2018. Certain terms of the compromise with respect to NRG and GenOn Mid-Atlantic are as follows:
Settlement of all pending litigation and objections to the Plan (including with respect to releases and feasibility);
NRG provided $37.5 million in letters of credit as new qualifying credit support based upon market exposureto GenOn Mid-Atlantic; and potential market movements. The terms and conditions
NRG paid approximately $6 million as reimbursement of professional fees incurred by certain of GenOn Mid-Atlantic's stakeholders in connection with the agreements are generally consistent with industry practices and other third party arrangements. For current and pre-disposal periods, revenue and expense associated with these transactions is recorded in continuing operations.GenMA Settlement.
GenOn Debt
As of June 14, 2017, the GenOn Senior Notes and GenOn Americas Generation Senior Notes, which totaled approximately $2.5 billion, were deconsolidated from NRG's consolidated financial statements. The filing of the Chapter 11 Cases constitutes an event of default under the following debt instruments of GenOn:
| |
1) | The intercompany secured revolving credit facility with NRG; |
| |
2) | The indenture governing the GenOn 7.875% Senior Notes due 2017 (as amended or supplemented from time to time); |
| |
3) | The indenture governing the GenOn 9.500% Notes due 2018 (as amended or supplemented from time to time); |
| |
4) | The indenture governing the GenOn 9.875% Notes due 2020 (as amended or supplemented from time to time); |
| |
5) | The indenture governing the GenOn Americas Generation 8.50% Senior Notes due 2021 (as amended or supplemented from time to time); and |
| |
6) | The indenture governing the GenOn Americas Generation 9.125% Senior Notes due 2031 (as amended or supplemented from time to time). |
Transfer of Assets Under Common Control
On November 1, 2017, NRG completedMarch 30, 2018, as part of the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds, in addition to other projects developed by NRG,Transformation Plan, the Company sold to NRG Yield, Inc. for100% of NRG's interests in Buckthorn Renewables, LLC, which owns a 154-MW construction-stage utility-scale solar generation project, located in Texas. NRG Yield, Inc. paid cash consideration of $71approximately $42 million, plus $3 million inexcluding working capital adjustments.
On August 1, 2017, NRG closed onadjustments, and assumed non-recourse debt of approximately $183 million. Concurrently, an initial contribution of approximately $19 million was received from the sale of its remaining 25% interestthird-party investor in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million, including working capital adjustment of $3 million. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginningthe underlying tax equity partnership, which is included in 2027.
noncontrolling interest.
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.
On September 1, 2016, the Company completed the sale of its remaining 51.05% interest in the CVSR project to NRG Yield, Inc. for total cash consideration of $78.5 million, plus an immaterial working capital adjustment. In addition, NRG Yield, Inc. assumed non-recourse project level debt of $496 million.
Acquisitions
SunEdison Utility-Scale Solar and Wind Acquisition
On November 2, 2016, the Company acquired equity interests in a tax equity portfolio from SunEdison, located in Utah, comprised of 530 MW of mechanically-complete solar assets, of which NRG’s net interest based on cash to be distributed is 265 MW, for upfront cash consideration of $111 million. In connection with the acquisition, the Company assumed non-recourse debt of $222 million. The Company also borrowed additional amounts of $65 million during the fourth quarter of 2016, which effectively reduced the Company's use of liquidity related to the acquisition. The Company does not have a controlling interest in the tax equity portfolio and, accordingly, its interest is recorded as an equity method investment. The purchase price was preliminarily allocated to the equity method investment balance of approximately $328 million, current assets of $5 million and the assumed non-recourse debt of $222 million. The assets reached commercial operations during the fourth quarter of 2016 and have 20-year PPAs with PacificCorp.
The Company acquired a 110 MW portfolio of construction-ready and 71 MW of development solar assets in Hawaii from SunEdison for upfront cash consideration of $2 million on October 3, 2016 and a 154 MW construction-ready solar project in Texas for upfront cash consideration of $11 million on November 9, 2016.
In addition to the total $124 million in upfront cash consideration paid for the above acquisitions, the Company expects to make an estimated $59 million in additional payments contingent upon future development milestones, of which $15 million was paid as of September 30, 2017.
SunEdison Solar Distributed Generation Acquisition
On October 3, 2016, the Company acquired a 29 MW portfolio of mechanically-complete and construction-ready distributed generation solar assets from SunEdison for cash consideration of approximately $67 million excluding post-closing adjustments which reduced the purchase price by $5 million. Subsequent to the acquisition, the Company sold the majority of these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc., and expects to sell the remaining assets into a similar portfolio in 2017. The purchase price was allocated to $47 million in construction in progress and $15 million in intangible assets.
Dispositions
Disposition of Majority Interest in EVgo
On June 17, 2016, the Company completed the sale of a majority interest in its EVgo business to Vision Ridge Partners for total consideration of approximately $39 million, including $17 million in cash received, which is net of $2.5 million in working capital adjustments, $15 million contributed as capital to the EVgo business and $7 million of future contributions by Vision Ridge Partners, all of which were determined based on forecasted cash requirements to operate the business in future periods. In addition, the Company has future earnout potential of up to $70 million based on future profitability targets. NRG will retain its original financial obligation of $102.5 million under its agreement with the CPUC whereby EVgo will build at least 200 public fast charging Freedom Station sites and perform the associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California. As part of the sale, NRG has contracted with EVgo to continue to build the remaining required Freedom Stations and commercial and multi-family parking spaces for electric vehicle charging required under this obligation and will be directly reimbursed by NRG for the costs. As a result of the sale, the Company recorded a loss on sale of $83 million during the second quarter of 2016, which reflects the loss on the sale of the equity interest of $27 million and the accrual of NRG's remaining obligation under its agreement with the CPUC of $56 million. On February 22, 2017, the Company and CPUC entered into a second amendment to the agreement which extended the operating period commitment for the Freedom Stations to December 5, 2020. At September 30, 2017, the Company's remaining 35% interest in EVgo of $2 million was accounted for as an equity-method investment.
Rockford Disposition
On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford I and Rockford II generating stations, or Rockford, for cash consideration of $55 million, subject to adjustments for working capital and the results of the PJM 2019/2020 base residual auction. Rockford is a 450 MW natural gas facility located in Rockford, Illinois. The transaction triggered an indicator of impairment as the sales price was less than the carrying amount of the assets, and, as a result the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sales price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016 to reduce the carrying amount of the assets held for sale to the fair market value. At June 30, 2016, the Company had $2 million of current assets and $54 million of non-current assets classified as held for sale for Rockford on its balance sheet. On July 12, 2016, the Company completed the sale of Rockford for cash proceeds of $56 million, including $1 million in adjustments for the PJM base residual auction results. For further discussion on this impairment, refer to Note 7, Impairments, to this Form 10-Q.
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 20162017 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 September 30, 2017 | | As of December 31, 2016 | As of March 31, 2018 | | As of December 31, 2017 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| | (In millions) | (In millions) |
| Assets: | | | | | | | | | | | | | | |
Notes receivable (a) | $ | 22 |
| | $ | 21 |
| | $ | 34 |
| | $ | 34 |
| $ | 15 |
| | $ | 14 |
| | $ | 16 |
| | $ | 15 |
|
| Liabilities: | | | | | | | | | | | | | | |
Long-term debt, including current portion (b) | 17,097 |
| | 17,423 |
| | 16,655 |
| | 16,620 |
| 16,559 |
| | 16,687 |
| | 16,603 |
| | 16,894 |
|
(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 September 30, 2017March 31, 2018 and December 31, 2016:2017:
|
| | | | | | | | | | | | | | | |
| | As of September 30, 2017 | | As of December 31, 2016 |
| | Level 2 | | Level 3 | | Level 2 | | Level 3 |
| | (In millions) |
| Long-term debt, including current portion | $ | 9,571 |
| | $ | 7,852 |
| | $ | 9,205 |
| | $ | 7,415 |
|
|
| | | | | | | | | | | | | | | |
| | As of March 31, 2018 | | As of December 31, 2017 |
| | Level 2 | | Level 3 | | Level 2 | | Level 3 |
| | (In millions) |
| Long-term debt, including current portion | $ | 8,772 |
| | $ | 7,915 |
| | $ | 8,934 |
| | $ | 7,960 |
|
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 September 30, 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 | $ | — |
| | $ | — |
| | $ | 19 |
| | $ | 19 |
|
| Available-for-sale securities | 5 |
| | — |
| | — |
| | 5 |
|
| Nuclear trust fund investments: | | | | | | | |
| Cash and cash equivalents | 31 |
| | — |
| | — |
| | 31 |
|
| U.S. government and federal agency obligations | 43 |
| | 1 |
| | — |
| | 44 |
|
| Federal agency mortgage-backed securities | — |
| | 74 |
| | — |
| | 74 |
|
| Commercial mortgage-backed securities | — |
| | 11 |
| | — |
| | 11 |
|
| Corporate debt securities | — |
| | 108 |
| | — |
| | 108 |
|
| Equity securities | 333 |
| | — |
| | 65 |
| | 398 |
|
| Foreign government fixed income securities | — |
| | 4 |
| | — |
| | 4 |
|
| Other trust fund investments: | | | | | | | |
| U.S. government and federal agency obligations | 1 |
| | — |
| | — |
| | 1 |
|
| Derivative assets: | | | | | | | |
| Commodity contracts | 132 |
| | 409 |
| | 98 |
| | 639 |
|
| Interest rate contracts | — |
| | 42 |
| | — |
| | 42 |
|
| Total assets | $ | 545 |
| | $ | 649 |
| | $ | 182 |
| | $ | 1,376 |
|
| Derivative liabilities: | | | | | | | |
| Commodity contracts | 201 |
| | 404 |
| | 146 |
| | 751 |
|
| Interest rate contracts | — |
| | 78 |
| | — |
| | 78 |
|
| Total liabilities | $ | 201 |
| | $ | 482 |
| | $ | 146 |
| | $ | 829 |
|
.
|
| | | | | | | | | | | | | | | |
| | As of March 31, 2018 |
| | Fair Value |
| (In millions) | Total | | Level 1 | | Level 2 | | Level 3 |
| Investments in securities (classified within other non-current assets) | $ | 22 |
| | $ | 3 |
| | $ | — |
| | $ | 19 |
|
| Nuclear trust fund investments: | | | | | | | |
| Cash and cash equivalents | 16 |
| | 16 |
| | — |
| | — |
|
| U.S. government and federal agency obligations | 56 |
| | 55 |
| | 1 |
| | — |
|
| Federal agency mortgage-backed securities | 92 |
| | — |
| | 92 |
| | — |
|
| Commercial mortgage-backed securities | 16 |
| | — |
| | 16 |
| | — |
|
| Corporate debt securities | 100 |
| | — |
| | 100 |
| | — |
|
| Equity securities | 333 |
| | 333 |
| | — |
| | — |
|
| Foreign government fixed income securities | 5 |
| | — |
| | 5 |
| | — |
|
| Other trust fund investments: | | | | | | | |
| U.S. government and federal agency obligations | 1 |
| | 1 |
| | — |
| | — |
|
| Derivative assets: | | | | | | | |
| Commodity contracts | 1,277 |
| | 168 |
| | 1,060 |
| | 49 |
|
| Interest rate contracts | 92 |
| | — |
| | 92 |
| | — |
|
| Measured using net asset value practical expedient: | | | | | | | |
| Equity securities — nuclear trust fund investments | 62 |
| |
|
| |
|
| |
|
|
| Total assets | $ | 2,072 |
| | $ | 576 |
| | $ | 1,366 |
| | $ | 68 |
|
| Derivative liabilities: | | | | | | | |
| Commodity contracts | 1,024 |
| | 224 |
| | 729 |
| | 71 |
|
| Interest rate contracts | 30 |
| | — |
| | 30 |
| | — |
|
| Total liabilities | $ | 1,054 |
| | $ | 224 |
| | $ | 759 |
| | $ | 71 |
|
| | | | As of December 31, 2016 | As of December 31, 2017 |
| | Fair Value | Fair Value |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total | Total | | Level 1 | | Level 2 | | Level 3 |
Investment in available-for-sale securities (classified within other non-current assets): | | | | | | | | |
| Debt securities | $ | — |
| | $ | — |
| | $ | 17 |
| | $ | 17 |
| |
| Available-for-sale securities | 10 |
| | — |
| | — |
| | 10 |
| |
| Investments in securities (classified within other non-current assets) | | $ | 22 |
| | $ | 3 |
| | $ | — |
| | $ | 19 |
|
| Nuclear trust fund investments: | | | | | | | | | | | | | | |
| Cash and cash equivalents | 25 |
| | — |
| | — |
| | 25 |
| 47 |
| | 45 |
| | 2 |
| | — |
|
| U.S. government and federal agency obligations | 72 |
| | 1 |
| | — |
| | 73 |
| 43 |
| | 42 |
| | 1 |
| | — |
|
| Federal agency mortgage-backed securities | — |
| | 62 |
| | — |
| | 62 |
| 82 |
| | — |
| | 82 |
| | — |
|
| Commercial mortgage-backed securities | — |
| | 17 |
| | — |
| | 17 |
| 14 |
| | — |
| | 14 |
| | — |
|
| Corporate debt securities | — |
| | 84 |
| | — |
| | 84 |
| 99 |
| | — |
| | 99 |
| | — |
|
| Equity securities | 292 |
| | — |
| | 54 |
| | 346 |
| 334 |
| | 334 |
| | — |
| | — |
|
| Foreign government fixed income securities | — |
| | 3 |
| | — |
| | 3 |
| 5 |
| | — |
| | 5 |
| | — |
|
| Other trust fund investments: | | | | | | | | | | | | | | |
| U.S. government and federal agency obligations | 1 |
| | — |
| | — |
| | 1 |
| 1 |
| | 1 |
| | — |
| | — |
|
| Derivative assets: | | | | | | | | | | | | | | |
| Commodity contracts | 560 |
| | 549 |
| | 90 |
| | 1,199 |
| 745 |
| | 191 |
| | 509 |
| | 45 |
|
| Interest rate contracts | — |
| | 49 |
| | — |
| | 49 |
| 53 |
| | — |
| | 53 |
| | — |
|
| Measured using net asset value practical expedient: | | | | | | | | |
| Equity securities — nuclear trust fund investments | | 68 |
| | | | | | |
| Total assets | $ | 960 |
| | $ | 765 |
| | $ | 161 |
| | $ | 1,886 |
| $ | 1,513 |
| | $ | 616 |
| | $ | 765 |
| | $ | 64 |
|
| Derivative liabilities: | | | | | | | | | | | | | | |
| Commodity contracts | 494 |
| | 636 |
| | 158 |
| | 1,288 |
| 693 |
| | 257 |
| | 359 |
| | 77 |
|
| Interest rate contracts | — |
| | 88 |
| | — |
| | 88 |
| 59 |
| | — |
| | 59 |
| | — |
|
| Total liabilities | $ | 494 |
| | $ | 724 |
| | $ | 158 |
| | $ | 1,376 |
| $ | 752 |
| | $ | 257 |
| | $ | 418 |
| | $ | 77 |
|
There were no transfers during the three and nine months ended September 30, 2017March 31, 2018 and 20162017 between Levels 1 and 2. The following tables reconcile, for the three and nine months ended September 30, 2017March 31, 2018 and 20162017, 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) | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
| | Three months ended September 30, 2017 | | Nine months ended September 30, 2017 | Three months ended March 31, 2018 |
| (In millions) | Debt Securities | | Trust Fund Investments | | Derivatives(a) | | Total | | Debt Securities | | Trust Fund Investments | | Derivatives(a) | | Total | Debt Securities | | Derivatives(a) | | Total |
| Beginning balance | $ | 18 |
| | $ | 61 |
| | $ | (11 | ) | | $ | 68 |
| | $ | 17 |
| | $ | 54 |
| | $ | (68 | ) | | $ | 3 |
| $ | 19 |
| | $ | (32 | ) | | $ | (13 | ) |
| Total gains/(losses) — realized/unrealized: | | | | | | |
|
| | | | | | | |
|
| |
| Total gains — realized/unrealized: | | | | | |
|
|
| Included in earnings | 1 |
| | — |
| | (28 | ) | | (27 | ) | | 2 |
| | — |
| | 18 |
| | 20 |
| — |
| | 2 |
| | 2 |
|
| Included in nuclear decommissioning obligation | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | 10 |
| | — |
| | 10 |
| |
| Purchases | — |
| | 1 |
| | (9 | ) | | (8 | ) | | — |
| | 1 |
| | — |
| | 1 |
| — |
| | 1 |
| | 1 |
|
Transfers into Level 3 (b) | — |
| | — |
| | (6 | ) | | (6 | ) | | — |
| | — |
| | (11 | ) | | (11 | ) | — |
| | 4 |
| | 4 |
|
Transfers out of Level 3 (b) | — |
| | — |
| | 6 |
| | 6 |
| | — |
| | — |
| | 13 |
| | 13 |
| — |
| | 3 |
| | 3 |
|
| Ending balance as of September 30, 2017 | $ | 19 |
| | $ | 65 |
| | $ | (48 | ) | | $ | 36 |
| | $ | 19 |
| | $ | 65 |
| | $ | (48 | ) | | $ | 36 |
| |
| 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 September 30, 2017 | $ | — |
| | $ | ��� |
| | $ | (13 | ) | | $ | (13 | ) | | $ | — |
| | $ | — |
| | $ | (6 | ) | | $ | (6 | ) | |
| Ending balance as of March 31, 2018 | | $ | 19 |
| | $ | (22 | ) | | $ | (3 | ) |
| Gains 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, 2018 | | $ | — |
| | $ | 3 |
| | $ | 3 |
|
| |
| (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) | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
| | Three months ended September 30, 2016 | | Nine months ended September 30, 2016 | Three months ended March 31, 2017 |
| (In millions) | Debt Securities | | Trust Fund Investments | | Derivatives(a) | | Total | | Debt Securities | | Trust Fund Investments | | Derivatives(a) | | Total | Debt Securities | | Trust Fund Investments | | Derivatives(a) | | Total |
| Beginning balance | $ | 16 |
| | $ | 51 |
| | $ | 18 |
| | $ | 85 |
| | $ | 17 |
| | $ | 54 |
| | $ | (22 | ) | | $ | 49 |
| $ | 17 |
| | $ | 54 |
| | $ | (68 | ) | | $ | 3 |
|
| Total (losses)/gains — realized/unrealized: | | | | | | | | | | | | | | | | |
| Total gains — realized/unrealized: | | | | | | | | |
| Included in earnings | — |
| | — |
| | (5 | ) | | (5 | ) | | — |
| | — |
| | 4 |
| | 4 |
| 1 |
| | — |
| | 6 |
| | 7 |
|
| Included in OCI | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| |
| Included in nuclear decommissioning obligations | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | (1 | ) | | — |
| | (1 | ) | |
| Included in nuclear decommissioning obligation | | — |
| | 4 |
| | — |
| | 4 |
|
| Purchases | — |
| | — |
| | (25 | ) | | (25 | ) | | — |
| | 1 |
| | 2 |
| | 3 |
| — |
| | — |
| | 4 |
| | 4 |
|
Transfers into Level 3 (b) | — |
| | — |
| | (13 | ) | | (13 | ) | | — |
| | — |
| | (6 | ) | | (6 | ) | — |
| | — |
| | (8 | ) | | (8 | ) |
Transfers out of Level 3 (b) | — |
| | — |
| | 3 |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | 10 |
| | 10 |
|
| Ending balance as of September 30, 2016 | $ | 17 |
| | $ | 54 |
| | $ | (22 | ) | | $ | 49 |
| | $ | 17 |
| | $ | 54 |
| | $ | (22 | ) | | $ | 49 |
| |
| 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 September 30, 2016 | $ | — |
| | $ | — |
| | $ | (4 | ) | | $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | (11 | ) | | $ | (11 | ) | |
| Ending balance as of March 31, 2017 | | $ | 18 |
| | $ | 58 |
| | $ | (56 | ) | | $ | 20 |
|
| 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. |
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 September 30, 2017March 31, 2018, contracts valued with prices provided by models and other valuation techniques make up 14%4% of the total derivative assets and 18%7% of the total derivative liabilities.
NRG's significant positions classified as Level 3 include physical and financial power executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power 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 September 30, 2017March 31, 2018 and December 31, 2016:2017:
| | | | Significant Unobservable Inputs | Significant Unobservable Inputs |
| | September 30, 2017 | March 31, 2018 |
| | Fair Value | | Input/Range | Fair Value | | Input/Range |
| | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| | (In millions) | | | | | | | (In millions) | | | | | | |
| Power Contracts | $ | 47 |
| | $ | 101 |
| | Discounted Cash Flow | | Forward Market Price (per MWh) | | $ | 10 |
| | $ | 88 |
| | $ | 24 |
| $ | 38 |
| | $ | 63 |
| | Discounted Cash Flow | | Forward Market Price (per MWh) | | $ | 9 |
| | $ | 319 |
| | $ | 40 |
|
| FTRs | 51 |
| | 45 |
| | Discounted Cash Flow | | Auction Prices (per MWh) | | (31 | ) | | 36 |
| | — |
| 11 |
| | 8 |
| | Discounted Cash Flow | | Auction Prices (per MWh) | | (28 | ) | | 46 |
| | — |
|
| | $ | 98 |
| | $ | 146 |
| | | | | | | $ | 49 |
| | $ | 71 |
| | | | | | |
| | | | Significant Unobservable Inputs | Significant Unobservable Inputs |
| | December 31, 2016 | December 31, 2017 |
| | Fair Value | | Input/Range | Fair Value | | Input/Range |
| | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| | (In millions) | | | | | | | (In millions) | | | | | | |
| Power Contracts | $ | 39 |
| | $ | 108 |
| | Discounted Cash Flow | | Forward Market Price (per MWh) | | $ | 11 |
| | $ | 104 |
| | $ | 31 |
| $ | 34 |
| | $ | 65 |
| | Discounted Cash Flow | | Forward Market Price (per MWh) | | $ | 10 |
| | $ | 142 |
| | $ | 33 |
|
| FTRs | 51 |
| | 50 |
| | Discounted Cash Flow | | Auction Prices (per MWh) | | (22 | ) | | 17 |
| | — |
| 11 |
| | 12 |
| | Discounted Cash Flow | | Auction Prices (per MWh) | | (28 | ) | | 46 |
| | — |
|
| | $ | 90 |
| | $ | 158 |
| | | | | | | $ | 45 |
| | $ | 77 |
| | | | | | |
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of September 30, 2017March 31, 2018 and December 31, 2016:2017:
|
| | | | | | |
| Significant Unobservable Input | | Position | | Change In Input | | Impact on Fair Value Measurement |
| Forward Market Price Power | | Buy | | Increase/(Decrease) | | Higher/(Lower) |
| Forward Market Price Power | | 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 September 30, 2017March 31, 2018, the credit reserve resulted in a $1$2 million increasedecrease in fair value in operating revenue and cost of operations. As of December 31, 2016,2017, the credit reserve resulted in a $10 million decreaseno change 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 20162017 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 20162017 Form 10-K. As of September 30, 2017March 31, 2018, the Company's counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $134505 million with net exposure of $129$244 million. NRG held collateral (cash and letters of credit) against those positions of $14264 million. Approximately 74%83% of the Company's exposure before collateral is expected to roll off by the end of 2018.2019. 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 | 9178 | % |
| Financial institutions | 922 |
|
Total as of September 30, 2017March 31, 2018 | 100 | % |
|
| | |
| | Net Exposure (a) (b) |
| Category by Counterparty Credit Quality | (% of Total) |
| Investment grade | 7978 | % |
| Non-Investment grade/Non-Rated | 2122 |
|
Total as of September 30, 2017March 31, 2018 | 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 $5065 million as of September 30, 2017.March 31, 2018. 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 September 30, 2017,March 31, 2018, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.3$4.1 billion, including $2.8$2.5 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 or treatment by regulatory agencies which NRG is unable to predict.
Retail Customer Credit Risk
NRGThe Company is exposed to retail credit risk through the Company's retail electricity providers, which serve commercial, industrial and governmental/institutionalC&I customers and the Mass market. Retail credit risk results in losses 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. NRGThe Company 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 September 30, 2017March 31, 2018, the Company believes itsCompany's retail customer credit exposure to C&I and Mass customers 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 20162017 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 trustthe 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 September 30, 2017 | | As of December 31, 2016 | As of March 31, 2018 | | As of December 31, 2017 |
| (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) | 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 | $ | 31 |
| | $ | — |
| | $ | — |
| | — |
| | $ | 25 |
| | $ | — |
| | $ | — |
| | — |
| $ | 16 |
| | $ | — |
| | $ | — |
| | — |
| | $ | 47 |
| | $ | — |
| | $ | — |
| | — |
|
| U.S. government and federal agency obligations | 44 |
| | 2 |
| | — |
| | 10 |
| | 73 |
| | 1 |
| | — |
| | 11 |
| 56 |
| | 1 |
| | 1 |
| | 11 |
| | 43 |
| | 1 |
| | — |
| | 11 |
|
| Federal agency mortgage-backed securities | 74 |
| | 1 |
| | 1 |
| | 24 |
| | 62 |
| | 1 |
| | 1 |
| | 25 |
| 92 |
| | — |
| | 2 |
| | 23 |
| | 82 |
| | 1 |
| | 1 |
| | 23 |
|
| Commercial mortgage-backed securities | 11 |
| | — |
| | — |
| | 23 |
| | 17 |
| | — |
| | 1 |
| | 26 |
| 16 |
| | — |
| | 1 |
| | 22 |
| | 14 |
| | — |
| | — |
| | 20 |
|
| Corporate debt securities | 108 |
| | 2 |
| | 1 |
| | 11 |
| | 84 |
| | 1 |
| | 2 |
| | 11 |
| 100 |
| | 1 |
| | 2 |
| | 11 |
| | 99 |
| | 2 |
| | 1 |
| | 11 |
|
| Equity securities | 398 |
| | 260 |
| | — |
| | — |
| | 346 |
| | 214 |
| | — |
| | — |
| 395 |
| | 265 |
| | — |
| | — |
| | 402 |
| | 272 |
| | — |
| | — |
|
| Foreign government fixed income securities | 4 |
| | — |
| | — |
| | 9 |
| | 3 |
| | — |
| | — |
| | 9 |
| 5 |
| | — |
| | — |
| | 8 |
| | 5 |
| | — |
| | — |
| | 9 |
|
| Total | $ | 670 |
| | $ | 265 |
| | $ | 2 |
| | | | $ | 610 |
| | $ | 217 |
| | $ | 4 |
| | | $ | 680 |
| | $ | 267 |
| | $ | 6 |
| | | | $ | 692 |
| | $ | 276 |
| | $ | 2 |
| | |
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.
| | | | Nine months ended September 30, | Three months ended March 31, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (In millions) | (In millions) |
| Realized gains | $ | 8 |
| | $ | 7 |
| $ | 3 |
| | $ | 2 |
|
| Realized losses | 6 |
| | 3 |
| 3 |
| | 2 |
|
| Proceeds from sale of securities | 382 |
|
| 354 |
| 182 |
|
| 117 |
|
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 20162017 Form 10-K.
Energy-Related Commodities
As of September 30, 2017March 31, 2018, 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 September 30, 2017March 31, 2018, the CompanyNRG 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 2041, mosta portion 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 September 30, 2017March 31, 2018 and December 31, 20162017. 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 | | Total Volume |
| | | September 30, 2017 | | December 31, 2016 | | March 31, 2018 | | December 31, 2017 |
| Category | Units | (In millions) | Units | (In millions) |
| Emissions | Short Ton | (1 | ) | | — |
| Short Ton | 2 |
| | 1 |
|
| Coal | Short Ton | 15 |
| | 35 |
| Short Ton | 17 |
| | 21 |
|
| Natural Gas | MMBtu | (62 | ) | | (53 | ) | MMBtu | (208 | ) | | (17 | ) |
| Oil | Barrel | — |
| | 1 |
| |
| Power | MWh | 19 |
| | 7 |
| MWh | 16 |
| | 14 |
|
| Capacity | MW/Day | (1 | ) | | (1 | ) | MW/Day | (1 | ) | | (1 | ) |
| Interest | Dollars | $ | 3,806 |
| | $ | 3,429 |
| Dollars | $ | 3,938 |
| | $ | 3,876 |
|
| Equity | Shares | 1 |
| | 1 |
| Shares | 1 |
| | 1 |
|
The decrease in the coal position was primarily the result of the settlement of hedge positions, and the increase in the powernatural gas position was primarily the result of additional retailgeneration 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 | Fair Value |
| | Derivative Assets | | Derivative Liabilities | Derivative Assets | | Derivative Liabilities |
| | September 30, 2017 | | December 31, 2016 | | September 30, 2017 | | December 31, 2016 | March 31, 2018 | | December 31, 2017 | | March 31, 2018 | | December 31, 2017 |
| | (In millions) | (In millions) |
| Derivatives designated as cash flow hedges: |
| | | |
|
| | |
| Derivatives Designated as Cash Flow or Fair Value Hedges: | |
| | | |
|
| |
| Interest rate contracts current | $ | — |
| | $ | — |
| | $ | 8 |
|
| $ | 28 |
| $ | 2 |
| | $ | 1 |
| | $ | 2 |
|
| $ | 5 |
|
| Interest rate contracts long-term | 10 |
| | 12 |
| | 15 |
|
| 41 |
| 20 |
| | 11 |
| | 7 |
|
| 11 |
|
| Total derivatives designated as cash flow hedges | 10 |
| | 12 |
| | 23 |
|
| 69 |
| |
| Derivatives not designated as cash flow hedges: |
| | | | |
| | |
| Total Derivatives Designated as Cash Flow or Fair Value Hedges | | 22 |
| | 12 |
| | 9 |
|
| 16 |
|
| Derivatives Not Designated as Cash Flow or Fair Value Hedges: | |
| | | | |
| |
| Interest rate contracts current | 5 |
| | — |
| | 19 |
|
| 7 |
| 13 |
| | 9 |
| | 7 |
|
| 15 |
|
| Interest rate contracts long-term | 27 |
| | 37 |
| | 36 |
|
| 12 |
| 57 |
| | 32 |
| | 14 |
|
| 28 |
|
| Commodity contracts current | 470 |
| | 1,067 |
| | 495 |
|
| 1,057 |
| 1,000 |
| | 616 |
| | 781 |
|
| 535 |
|
| Commodity contracts long-term | 169 |
| | 132 |
| | 256 |
|
| 231 |
| 277 |
| | 129 |
| | 243 |
|
| 158 |
|
| Total derivatives not designated as cash flow hedges | 671 |
| | 1,236 |
| | 806 |
|
| 1,307 |
| |
| Total derivatives | $ | 681 |
|
| $ | 1,248 |
| | $ | 829 |
|
| $ | 1,376 |
| |
| Total Derivatives Not Designated as Cash Flow or Fair Value Hedges | | 1,347 |
| | 786 |
| | 1,045 |
|
| 736 |
|
| Total Derivatives | | $ | 1,369 |
|
| $ | 798 |
| | $ | 1,054 |
|
| $ | 752 |
|
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 Not Offset in the Statement of Financial Position |
| | | Gross Amounts of Recognized Assets / Liabilities | | Derivative Instruments | | Cash Collateral (Held) / Posted | | Net Amount | | Gross Amounts of Recognized Assets / Liabilities | | Derivative Instruments | | Cash Collateral (Held) / Posted | | Net Amount |
| As of September 30, 2017 | | (In millions) | |
| As of March 31, 2018 | | | (In millions) |
| Commodity contracts: | | | | | | | | | | | | | | | | |
| Derivative assets | | $ | 639 |
| | $ | (546 | ) | | $ | (5 | ) | | $ | 88 |
| | $ | 1,277 |
| | $ | (835 | ) | | $ | (201 | ) | | $ | 241 |
|
| Derivative liabilities | | (751 | ) | | 546 |
| | 83 |
| | (122 | ) | | (1,024 | ) | | 835 |
| | 120 |
| | (69 | ) |
| Total commodity contracts | | (112 | ) | | — |
| | 78 |
| | (34 | ) | | 253 |
| | — |
| | (81 | ) | | 172 |
|
| Interest rate contracts: | | | | | | | | | | | | | | | | |
| Derivative assets | | 42 |
| | (2 | ) | | — |
| | 40 |
| | 92 |
| | (4 | ) | | — |
| | 88 |
|
| Derivative liabilities | | (78 | ) | | 2 |
| | — |
| | (76 | ) | | (30 | ) | | 4 |
| | — |
| | (26 | ) |
| Total interest rate contracts | | (36 | ) | | — |
| | — |
| | (36 | ) | | 62 |
| | — |
| | — |
| | 62 |
|
| Total derivative instruments | | $ | (148 | ) | | $ | — |
| | $ | 78 |
| | $ | (70 | ) | | $ | 315 |
| | $ | — |
| | $ | (81 | ) | | $ | 234 |
|
| | | | | Gross Amounts Not Offset in the Statement of Financial Position | | Gross Amounts Not Offset in the Statement of Financial Position |
| | | Gross Amounts of Recognized Assets / Liabilities | | Derivative Instruments | | Cash Collateral (Held) / Posted | | Net Amount | | Gross Amounts of Recognized Assets / Liabilities | | Derivative Instruments | | Cash Collateral (Held) / Posted | | Net Amount |
| As of December 31, 2016 | | (In millions) | |
| As of December 31, 2017 | | | (In millions) |
| Commodity contracts: | | | | | | | |
| | | | | | | |
|
| Derivative assets | | $ | 1,199 |
| | $ | (1,021 | ) | | $ | (13 | ) | | $ | 165 |
| | $ | 745 |
| | $ | (578 | ) | | $ | (11 | ) | | $ | 156 |
|
| Derivative liabilities | | (1,288 | ) | | 1,021 |
| | 13 |
| | (254 | ) | | (693 | ) | | 578 |
| | 73 |
| | (42 | ) |
| Total commodity contracts | | (89 | ) | | — |
| | — |
| | (89 | ) | | 52 |
| | — |
| | 62 |
| | 114 |
|
| Interest rate contracts: | | | | | | | |
| | | | | | | |
|
| Derivative assets | | 49 |
| | (4 | ) | | — |
| | 45 |
| | 53 |
| | (3 | ) | | — |
| | 50 |
|
| Derivative liabilities | | (88 | ) | | 4 |
| | — |
| | (84 | ) | | (59 | ) | | 3 |
| | — |
| | (56 | ) |
| Total interest rate contracts | | (39 | ) | | — |
| | — |
| | (39 | ) | | (6 | ) | | — |
| | — |
| | (6 | ) |
| Total derivative instruments | | $ | (128 | ) | | $ | — |
| | $ | — |
|
| $ | (128 | ) | | $ | 46 |
| | $ | — |
| | $ | 62 |
|
| $ | 108 |
|
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:
| | | | Interest Rate Contracts | Interest Rate Contracts |
| | Three months ended September 30, | | Nine months ended September 30, | Three months ended March 31, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 |
| | (In millions) | (In millions) |
| Accumulated OCI beginning balance | $ | (67 | ) | | $ | (165 | ) | | $ | (66 | ) | | $ | (101 | ) | $ | (54 | ) | | $ | (66 | ) |
| Reclassified from accumulated OCI to income: | | | | | | | | | | |
| Due to realization of previously deferred amounts | 4 |
| | 2 |
| | 10 |
| | 12 |
| 4 |
| | 3 |
|
| Mark-to-market of cash flow hedge accounting contracts | 4 |
| | 32 |
| | (3 | ) | | (42 | ) | 19 |
| | 2 |
|
| Accumulated OCI ending balance, net of $15, and $28 tax | $ | (59 | ) | | $ | (131 | ) |
| $ | (59 | ) |
| $ | (131 | ) | |
| Losses expected to be realized from OCI during the next 12 months, net of $4 tax | $ | 14 |
| |
| | $ | 14 |
| |
|
| |
| Accumulated OCI ending balance, net of $6, and $14 tax | | $ | (31 | ) | | $ | (61 | ) |
| Losses expected to be realized from OCI during the next 12 months, net of $2 tax | | $ | (9 | ) | |
|
|
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 and nine months ended September 30, 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.
The Company's regression analysis for Marsh Landing, Walnut Creek, and Avra Valley interest rate swaps, while positively correlated, no longer contain match terms for cash flow hedge accounting. As a result, the Company voluntarily de-designated the Marsh Landing, Walnut Creek, and Avra Valley cash flow hedges as of April 28, 2017, 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 September 30, | | Nine months ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Unrealized mark-to-market results | (In millions) |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (6 | ) | | $ | (30 | ) | | $ | 19 |
| | $ | (75 | ) |
| Reversal of acquired gain positions related to economic hedges | (2 | ) | | (7 | ) | | (1 | ) | | (11 | ) |
| Net unrealized (losses)/gains on open positions related to economic hedges | (16 | ) | | (50 | ) | | (1 | ) | | 27 |
|
| Total unrealized mark-to-market (losses)/gains for economic hedging activities | (24 | ) | | (87 | ) | | 17 |
| | (59 | ) |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity | (5 | ) | | 3 |
| | (24 | ) | | 13 |
|
| Net unrealized (losses)/gains on open positions related to trading activity | — |
| | (8 | ) | | 17 |
| | 14 |
|
| Total unrealized mark-to-market (losses)/gains for trading activity | (5 | ) | | (5 | ) | | (7 | ) | | 27 |
|
| Total unrealized (losses)/gains | $ | (29 | ) | | $ | (92 | ) | | $ | 10 |
| | $ | (32 | ) |
|
| | | | | | | |
| | Three months ended March 31, |
| | 2018 | | 2017 |
| Unrealized mark-to-market results | (In millions) |
| Reversal of previously recognized unrealized losses on settled positions related to economic hedges | $ | 2 |
| | $ | 3 |
|
| Net unrealized gains/(losses) on open positions related to economic hedges | 194 |
| | (22 | ) |
| Total unrealized mark-to-market gains/(losses) for economic hedging activities | 196 |
| | (19 | ) |
| Reversal of previously recognized unrealized gains on settled positions related to trading activity | (3 | ) | | (15 | ) |
| Net unrealized gains on open positions related to trading activity | 11 |
| | 1 |
|
| Total unrealized mark-to-market gains/(losses) for trading activity | 8 |
| | (14 | ) |
| Total unrealized gains/(losses) | $ | 204 |
| | $ | (33 | ) |
| | | | Three months ended September 30, | | Nine months ended September 30, | Three months ended March 31, |
| | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 |
| | (In millions) | (In millions) |
| Unrealized gains/(losses) included in operating revenues | $ | 21 |
| | $ | 57 |
| | $ | 178 |
| | $ | (333 | ) | |
| Unrealized (losses)/gains included in cost of operations | (50 | ) | | (149 | ) | | (168 | ) | | 301 |
| |
| Unrealized (losses)/gains included in operating revenues | | $ | (98 | ) | | $ | 104 |
|
| Unrealized gains/(losses) included in cost of operations | | 302 |
| | (137 | ) |
| Total impact to statement of operations — energy commodities | $ | (29 | ) | | $ | (92 | ) | | $ | 10 |
| | $ | (32 | ) | $ | 204 |
| | $ | (33 | ) |
| Total impact to statement of operations — interest rate contracts | $ | 11 |
| | $ | 9 |
| | $ | (8 | ) | | $ | (9 | ) | $ | 48 |
| | $ | 5 |
|
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 ninethree months ended September 30,March 31, 2018, the $194 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of ERCOT heat rate contracts due to ERCOT heat rate expansion.
For the three months ended March 31, 2017, the $1$22 million unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases of coal, natural gas, coal, and ERCOT powerelectricity due to decreases in coal, natural gas, coal, and ERCOT electricity prices, which was largely offset by an increase in value of forward sales of PJM power and New York capacity due to decreases in PJM electricity and New York capacity prices.
For the nine months ended September 30, 2016, the $27 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of natural gas due to increases in natural gas 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 requiresrequire 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 September 30, 2017,March 31, 2018, was $27$20 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of September 30, 2017,March 31, 2018, was $34$5 million. The Company is also a party to certain marginable agreements where NRGunder which it has a net liability position, but the counterparty has not called for the collateral due, which was approximately $175 million as of September 30, 2017March 31, 2018.
See Note 4, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.
Note 7 — Impairments
2017 Impairment Losses
Bacliff Project — On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. As a result of the MIPA termination, the Company recorded an impairment loss of $41 million to reduce the carrying amount of the related construction in progress to $0 during the second quarter of 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.
Other Impairments — During the second quarter of 2017, the Company recorded impairment losses of approximately $22 million in connection with the Company's Renewables business. During the third quarter of 2017, the Company recorded an additional $14 million in impairment losses, in connection with the Company's Renewable business.
2016 Impairment Losses
Rockford — On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford generating stations for cash consideration of $55 million. The transaction triggered an indicator of impairment as the sale price was less than the carrying amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016, to reduce the carrying amount of the assets held for sale to the fair market value.
Other Impairments — During the second quarter of 2016, the Company recorded impairment losses for intangible assets of $8 million in connection with the Company's strategic change in its residential solar business as well as $10 million of deferred marketing expenses. In addition, the Company also recorded an impairment loss of $17 million to record certain previously purchased solar panels at fair market value. During the third quarter of 2016, the Company recorded an additional $9 million in impairment losses related to investments and $8 million in other impairments.
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 20162017 Form 10-K. Long-term debt and capital leases consisted of the following:
| | | (In millions, except rates) | September 30, 2017 | | December 31, 2016 | | September 30, 2017 interest rate % (a) | March 31, 2018 | | December 31, 2017 | | March 31, 2018 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 | 992 |
| | 992 |
| | 6.250 |
| Senior notes, due 2023 | 869 |
| | 869 |
| | 6.625 | |
| Senior notes, due 2024 | 733 |
| | 733 |
| | 6.250 | 733 |
| | 733 |
| | 6.250 |
| Senior notes, due 2026 | 1,000 |
| | 1,000 |
| | 7.250 | 1,000 |
| | 1,000 |
| | 7.250 |
| Senior notes, due 2027 | 1,250 |
| | 1,250 |
| | 6.625 | 1,250 |
| | 1,250 |
| | 6.625 |
| Senior notes, due 2028 | | 870 |
| | 870 |
| | 5.750 |
| Term loan facility, due 2023 | 1,876 |
| | 1,891 |
| | L+2.25 | 1,867 |
| | 1,872 |
| | L+1.75 |
| Tax-exempt bonds | 465 |
| | 455 |
| | 4.125 - 6.00 | 465 |
| | 465 |
| | 4.125 - 6.00 |
| Subtotal NRG recourse debt | 7,790 |
| | 7,795 |
| |
| |
| Subtotal recourse debt | | 7,177 |
| | 7,182 |
| |
|
| Non-recourse debt: | | | | | | | | |
| NRG Yield, Inc. Convertible Senior Notes, due 2019 | | 345 |
| | 345 |
| | 3.500 |
| NRG Yield, Inc. Convertible Senior Notes, due 2020 | | 288 |
| | 288 |
| | 3.250 |
| NRG Yield Operating LLC Senior Notes, due 2024 | 500 |
| | 500 |
| | 5.375 | 500 |
| | 500 |
| | 5.375 |
| NRG Yield Operating LLC Senior Notes, due 2026 | 350 |
| | 350 |
| | 5.000 | 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 | |
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2023(b) | | 75 |
| | 55 |
| | L+2.500 |
| El Segundo Energy Center, due 2023 | 400 |
| | 443 |
| | L+1.75 - L+2.375 | 369 |
| | 400 |
| | L+1.75 - L+2.375 |
| Marsh Landing, due 2017 and 2023 | 334 |
| | 370 |
| | L+1.750 - L+1.875 | |
| Marsh Landing, due 2023 | | 309 |
| | 318 |
| | L+2.125 |
| Alta Wind I - V lease financing arrangements, due 2034 and 2035 | 940 |
| | 965 |
| | 5.696 - 7.015 | 926 |
| | 926 |
| | 5.696 - 7.015 |
| Walnut Creek, term loans due 2023 | 279 |
| | 310 |
| | L+1.625 | 259 |
| | 267 |
| | L+1.625 |
| Utah Portfolio, due 2022 | 284 |
| | 287 |
| | L+2.625 | 278 |
| | 278 |
| | various |
| Tapestry, due 2021 | 165 |
| | 172 |
| | L+1.625 | 158 |
| | 162 |
| | L+1.625 |
| CVSR, due 2037 | 746 |
| | 771 |
| | 2.339 - 3.775 | 731 |
| | 746 |
| | 2.339 - 3.775 |
| CVSR HoldCo, due 2037 | 194 |
| | 199 |
| | 4.680 | 188 |
| | 194 |
| | 4.680 |
| Alpine, due 2022 | 138 |
| | 145 |
| | L+1.750 | 135 |
| | 135 |
| | L+1.750 |
| Energy Center Minneapolis, due 2017 and 2025 | 82 |
| | 96 |
| | 5.95 - 7.25 | |
| Energy Center Minneapolis, due 2025 | | 83 |
| | 83 |
| | 5.95 |
| Energy Center Minneapolis, due 2031 | 125 |
| | 125 |
| | 3.55 | 125 |
| | 125 |
| | 3.55 |
| Viento, due 2023 | 169 |
| | 178 |
| | L+3.00 | 163 |
| | 163 |
| | L+3.00 |
| Buckthorn Solar, due 2018 and 2025 | | 183 |
| | 169 |
| | L+1.750 |
| NRG Yield - other | 562 |
| | 540 |
| | various | 573 |
| | 579 |
| | various |
Subtotal NRG Yield debt (non-recourse to NRG) | 5,901 |
| | 6,084 |
| | 6,038 |
| | 6,083 |
| |
| Ivanpah, due 2033 and 2038 | 1,097 |
| | 1,113 |
| | 2.285 - 4.256 | 1,068 |
| | 1,073 |
| | 2.285 - 4.256 |
Carlsbad Energy Project | 407 |
| | — |
| | 4.120 | 475 |
| | 427 |
| | L+1.625 - 4.120 |
| Agua Caliente, due 2037 | 833 |
| | 849 |
| | 2.395 - 3.633 | 815 |
| | 818 |
| | 2.395 - 3.633 |
| Agua Caliente Borrower 1, due 2038 | 89 |
| | — |
| | 5.430 | 86 |
| | 89 |
| | 5.430 |
Cedro Hill, due 2025 | 153 |
| | 163 |
| | L+1.75 | 149 |
| | 151 |
| | L+1.75 |
| Midwest Generation, due 2019 | 173 |
| | 231 |
| | 4.390 | 132 |
| | 152 |
| | 4.390 |
NRG Other Renewables (c) | | 466 |
| | 478 |
| | various |
| NRG Other | 689 |
| | 468 |
| | various | 178 |
| | 180 |
| | various |
| Subtotal other NRG non-recourse debt | 3,441 |
| | 2,824 |
| | 3,369 |
| | 3,368 |
| |
| Subtotal all non-recourse debt | 9,342 |
| | 8,908 |
| | 9,407 |
| | 9,451 |
| |
| Subtotal long-term debt (including current maturities) | 17,132 |
|
| 16,703 |
| | 16,584 |
|
| 16,633 |
| |
| Capital leases | 6 |
| | 6 |
| | various | 4 |
| | 5 |
| | various |
| Subtotal long-term debt and capital leases (including current maturities) | 17,138 |
|
| 16,709 |
| | 16,588 |
|
| 16,638 |
| |
| Less current maturities | (1,247 | ) |
| (516 | ) | | |
Less current maturities(d) | | (956 | ) |
| (688 | ) | |
| Less debt issuance costs | (198 | ) | | (188 | ) | | (201 | ) | | (204 | ) | |
| Discounts | (35 | ) | | (48 | ) | | (25 | ) | | (30 | ) | |
| Total long-term debt and capital leases | $ | 15,658 |
|
| $ | 15,957 |
| | $ | 15,406 |
|
| $ | 15,716 |
| |
(a) As of September 30, 2017,March 31, 2018, L+ equals 3 month LIBOR plus x%, except for the Buckthorn Solar and Utah Solar Portfolio where L+ equals 1 month LIBOR plus x%.
(b) Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement.
(c) Debt associated with the exceptionasset sales announced in February 2018
(d) The NRG Yield, Inc. Convertible Senior Notes, due 2019, become due in February 2019 and are recorded in current maturities as of the Utah Portfolio term loans.
March 31, 2018.
Recourse Debt
2023 Term Loan Facility
On January 24, 2017,March 21, 2018, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%. The1.75% and reducing the LIBOR floor remains 0.75%to 0.00%.
Revolving Credit Facility
On June 12, 2017, NRG repaid $125 million on the Revolving Credit Facility. As of September 30, 2017, no cash borrowings were outstanding on the revolver.
Senior Notes
2017 Senior Note Redemptions
On October 16, 2017, the Company redeemed $398 million of its 7.625% Senior Notes due 2018 and $206 million of its 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest.
2016 Senior Note Repurchases
During the nine months ended September 30, 2016, the Company repurchased $2.6 billion in aggregate principal of its Senior Notes in the open market for $2.7 billion, which included accrued interest of $67 million. In connection with the repurchases, a $94 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $15 million.
Issuance of 2026 Senior Notes
On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the 2026 Senior Notes. The 2026 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on November 15, 2016, until the maturity date of May 15, 2026.
Issuance of 2027 Senior Notes
On August 2, 2016, NRG issued $1.25 billion in aggregate principal amount at par of 6.625% senior notes due 2027, or the 2027 Senior Notes. The 2027 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on January 15, 2017, until the maturity date of January 15, 2027. The proceeds from the issuance of the 2027 Senior Notes were utilized to retire the Company's 8.250% senior notes due 2020 and reduce the balance of the Company's 7.875% senior notes due 2021.
Non-recourse Debt
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 intoare parties to a senior secured revolving credit facility, which can be used for cash and for the issuance of letters of credit. At September 30, 2017,March 31, 2018, there was $68$67 million of letters of credit issued under the revolving credit facility and no borrowing outstanding borrowings of $75 million on the revolver. On April 30, 2018, NRG Yield LLC and NRG Yield Operating LLC refinanced the revolving credit facility, which extended the maturity of the facility to April 28, 2023, and decreased the overall cost of borrowing from L+ 2.50% to L+1.75%.
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, Discontinued Operations Dispositions and AcquisitionsDispositions, 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.
Carlsbad Project Financing
On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038. As of September 30, 2017, all $407 million of these notes were outstanding.
Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into2038, and a credit agreement or the Carlsbad Financing Agreement, with the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completion of the project. The Carlsbad Financing Agreement also includesproject as well as a letter of credit facility with an aggregate principleprincipal amount not to exceed $83 million, and a working capital loan facility with an aggregate principleprincipal amount not to exceed $4 million. As of March 31, 2018, $475 million was outstanding under both the note and the construction loan.
Note 98 — 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.
Utility-Scale Solar Portfolio—Through its consolidated subsidiary, NRG Yield, Inc., the Company has equity interests in Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC which are accounted for as equity method investments as the Company does not have a controlling financial interest. The assets have 20-year PPAs with PacifiCorp. NRG's maximum exposure to loss is limited to its equity investment, which was $338 million as of March 31, 2018.
GenConn Energy LLC — Through its consolidated subsidiary, NRG Yield, Operating LLC,Inc., 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 $102100 million as of September 30, 2017March 31, 2018.
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 20162017 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $100$81 million as of September 30, 2017,March 31, 2018, 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) | September 30, 2017 | | December 31, 2016 | March 31, 2018 | | December 31, 2017 |
| Current assets | $ | 74 |
| | $ | 87 |
| $ | 171 |
| | $ | 118 |
|
| Net property, plant and equipment | 1,466 |
| | 1,534 |
| 2,712 |
| | 2,337 |
|
| Other long-term assets | 1,026 |
| | 954 |
| 665 |
| | 658 |
|
| Total assets | 2,566 |
| | 2,575 |
| 3,548 |
| | 3,113 |
|
| Current liabilities | 69 |
| | 59 |
| 111 |
| | 96 |
|
| Long-term debt | 420 |
| | 442 |
| 856 |
| | 661 |
|
| Other long-term liabilities | 187 |
| | 183 |
| 211 |
| | 209 |
|
| Total liabilities | 676 |
| | 684 |
| 1,178 |
| | 966 |
|
| Redeemable noncontrolling interest | | 80 |
| | 78 |
|
| Noncontrolling interests | 578 |
| | 529 |
| 646 |
| | 507 |
|
| Net assets less noncontrolling interests | $ | 1,312 |
| | $ | 1,362 |
| $ | 1,644 |
| | $ | 1,562 |
|
Note 109 — Changes in Capital Structure
As of September 30, 2017March 31, 2018 and December 31, 20162017, 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 | Issued | | Treasury | | Outstanding |
| Balance as of December 31, 2016 | 417,583,825 |
| | (102,140,814 | ) | | 315,443,011 |
| |
| Balance as of December 31, 2017 | | 418,323,134 |
| | (101,580,045 | ) | | 316,743,089 |
|
| Shares issued under LTIPs | 634,738 |
| | — |
| | 634,738 |
| 1,081,994 |
| | — |
| | 1,081,994 |
|
| Shares issued under ESPP | — |
| | 560,769 |
| | 560,769 |
| — |
| | 175,862 |
| | 175,862 |
|
| Balance as of September 30, 2017 | 418,218,563 |
| | (101,580,045 | ) | | 316,638,518 |
| |
| Shares repurchased | | — |
| | (3,114,748 | ) | | (3,114,748 | ) |
| Balance as of March 31, 2018 | | 419,405,128 |
| | (104,518,931 | ) | | 314,886,197 |
|
Preferred Stock
On May 24, 2016, NRG entered an agreement with Credit Suisse Group to repurchase 100% of the outstanding shares of its $344.5 million 2.822% preferred stock. On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares at a price of $226 million. The transaction resulted in a gain on redemption of $78 million, measured as the difference between the fair value of the cash consideration paid upon redemption of $226 million and the carrying value of the preferred stock at the time of the redemption of $304 million. This amount is reflected in net income/(loss) available to NRG common stockholders in the calculation of earnings per share.
Amended and Restated Employee Stock Purchase Plan
On April 27, 2017, NRG stockholders approved an increase of 3,000,000 shares available for issuance under the ESPP. As of September 30, 2017, there were 3,107,050In January 2018, 175,862 shares of common stock were issued to employee accounts from treasury stock available for issuance underthe offering period of July 1, 2017 to December 31, 2017. In January 2018, NRG suspended the ESPP.
AmendedShare Repurchases
In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock, with the first $500 million program beginning as soon as permitted. In March 2018, share repurchases were made as follows:
|
| | | | | | | | | | |
| | Total number of shares purchased | | Average price paid per share (a) | | Amounts paid for shares purchased (in millions) (a) |
| Board Authorized Share Repurchases | | | | | |
| March 2018 | 3,114,748 |
| | $ | 29.75 |
| | $ | 93 |
|
(a) The average price paid per share and Restated Long-term Incentive Plan
On April 27, 2017, NRG stockholders approved an increaseamounts paid for shares purchased exclude the commissions of 3,000,000 shares available for issuance under$0.01 per share paid in connection with the NRG Energy, Inc. Amended and Restated Long-term Incentive Plan.share repurchase.
NRG Common Stock Dividends
The following table lists the dividends paid during the ninethree months ended September 30, 2017:March 31, 2018:
|
| | | | | | | | | | | |
| | Third Quarter 2017 | | Second Quarter 2017 |
| First Quarter 2017 |
| Dividends per Common Share | $ | 0.03 |
| | $ | 0.03 |
|
| $ | 0.03 |
|
|
| | | |
| | First Quarter 2018 |
| Dividends per Common Share | $ | 0.03 |
|
On October 18, 2017,April 19, 2018, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable NovemberMay 15, 2017,2018, to stockholders of record as of NovemberMay 1, 2017,2018, 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 1110 — 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)loss per share is shown in the following table:
| | | | Three months ended September 30, | | Nine months ended September 30, | Three months ended March 31, |
| (In millions, except per share data) | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 |
| Basic and diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders | |
| Basic income/(loss) per share attributable to NRG Energy, Inc. common stockholders | | Basic income/(loss) per share attributable to NRG Energy, Inc. common stockholders |
| Net income/(loss) attributable to NRG Energy, Inc. | $ | 171 |
| | $ | 402 |
| | $ | (619 | ) | | $ | 213 |
| $ | 279 |
| | $ | (163 | ) |
| Dividends for preferred shares | — |
| | — |
| | — |
| | 5 |
| |
| Gain on redemption of 2.822% redeemable perpetual preferred stock | — |
| | — |
| | — |
| | (78 | ) | |
| Income/(loss) available for common stockholders | $ | 171 |
|
| $ | 402 |
|
| $ | (619 | ) |
| $ | 286 |
| |
| Weighted average number of common shares outstanding - basic | 317 |
| | 316 |
|
| 317 |
| | 315 |
| 318 |
| | 316 |
|
| Income/(loss) per weighted average common share — basic | $ | 0.54 |
| | $ | 1.27 |
| | $ | (1.95 | ) | | $ | 0.91 |
| |
| Earnings/(loss) per weighted average common share — basic | | $ | 0.88 |
| | $ | (0.52 | ) |
| Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders | Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders | | | | | Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders |
| Weighted average number of common shares outstanding - diluted | 317 |
| | 316 |
| | 317 |
| | 315 |
| 318 |
| | 316 |
|
| Incremental shares attributable to the issuance of equity compensation (treasury stock method) | 5 |
| | 1 |
| | — |
| | 1 |
| 4 |
| | — |
|
| Total dilutive shares | 322 |
| | 317 |
| | 317 |
| | 316 |
| 322 |
| | 316 |
|
| Income/(loss) per weighted average common share — diluted | $ | 0.53 |
| | $ | 1.27 |
| | $ | (1.95 | ) | | $ | 0.91 |
| |
| Earnings/(loss) per weighted average common share — diluted | | $ | 0.87 |
| | $ | (0.52 | ) |
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 earnings/(loss)loss per share:
| | | | Three months ended September 30, | | Nine months ended September 30, | Three months ended March 31, |
| (In millions of shares) | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 |
| Equity compensation plans | 1 |
| | 2 |
| | 6 |
| | 3 |
| 1 |
| | 6 |
|
| Total | 1 |
| | 2 |
| | 6 |
| | 3 |
| 1 |
| | 6 |
|
Note 1211 — 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. The financial information for the three and nine months ended September 30, 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,During 2017, NRG Yield acquired several projects totaling 555 MW from NRG. On March 30, 2018, the Company sold to NRG a 16% interest in the Agua Caliente solar project, andYield, Inc. 100% of NRG's interests in sevenBuckthorn Renewables, LLC, which owns a 154 MW construction-stage utility-scale solar projectsgeneration project, located in Utah. On August 1, 2017, NRG Yield acquired the remaining 25% interest in NRG Wind TE Holdco from the Company. All threeTexas. These 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.
On June 14, 2017, as described in Note 3, Discontinued Operations Dispositions and AcquisitionsDispositions, NRG deconsolidated GenOn for financial reporting purposes. The financial information for all historical periods have been recast to reflect the deconsolidationpresentation of GenOn and to presentas discontinued operations within the corporate segment.
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) | | NRG Yield | | Corporate(a) | | Eliminations | | Total |
| Three months ended September 30, 2017 | (In millions) |
Operating revenues(a) | $ | 1,224 |
| | $ | 1,937 |
| | $ | 144 |
| | $ | 265 |
| | $ | 2 |
| | $ | (523 | ) | | $ | 3,049 |
|
| Depreciation and amortization | 96 |
| | 29 |
| | 51 |
| | 88 |
| | 8 |
| | — |
| | 272 |
|
| Impairment losses | 1 |
| | — |
| | 13 |
| | — |
| | — |
| | — |
| | 14 |
|
| Equity in (losses)/earnings of unconsolidated affiliates | 12 |
| | — |
| | (3 | ) | | 28 |
| | — |
| | (10 | ) | | 27 |
|
| Loss on debt extinguishment, net | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Income/(loss) from continuing operations before income taxes | 258 |
| | 69 |
| | (7 | ) | | 49 |
| | (161 | ) | | (12 | ) | | 196 |
|
| Income/(loss) from continuing operations | 258 |
| | 69 |
| | (4 | ) | | 41 |
| | (162 | ) | | (12 | ) | | 190 |
|
| Loss from discontinued operations, net of tax | — |
| | — |
| | — |
| | — |
| | (27 | ) | | — |
| | (27 | ) |
| Net Income/(loss) | 258 |
| | 69 |
|
| (4 | ) | | 41 |
| | (189 | ) | | (12 | ) | | 163 |
|
| Net Income/(loss) attributable to NRG Energy, Inc. | $ | 258 |
| — |
| $ | 69 |
| | $ | 9 |
| | $ | 35 |
|
| $ | (220 | ) | | $ | 20 |
| | $ | 171 |
|
| Total assets as of September 30, 2017 | $ | 8,585 |
| | $ | 2,445 |
| | $ | 5,357 |
| | $ | 8,442 |
| | $ | 11,090 |
| | $ | (10,449 | ) | | $ | 25,470 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Retail (a) | | Generation(a) | | Renewables(a) | | NRG Yield | | Corporate(a) | | Eliminations | | Total |
| Three months ended March 31, 2018 | | | (In millions) |
Operating revenues(a) | $ | 1,481 |
| | $ | 327 |
| | $ | 86 |
| | $ | 225 |
| | $ | 2 |
| | $ | 300 |
| | $ | 2,421 |
|
| Depreciation and amortization | 28 |
| | 67 |
| | 51 |
| | 81 |
| | 8 |
| | — |
| | 235 |
|
| Reorganization costs | 3 |
| | 4 |
| | — |
| | — |
| | 13 |
| | — |
| | 20 |
|
| Equity in earnings/(losses) of unconsolidated affiliates | — |
| | 2 |
| | — |
| | 4 |
| | (1 | ) | | (7 | ) | | (2 | ) |
| Income/(loss) from continuing operations before income taxes | 946 |
| | (536 | ) | | (40 | ) | | (1 | ) | | (126 | ) | | (11 | ) | | 232 |
|
| Income/(loss) from continuing operations | 946 |
| | (536 | ) | | (34 | ) | | — |
| | (132 | ) | | (11 | ) | | 233 |
|
| Net Income/(Loss) | 946 |
| | (536 | ) | | (34 | ) | | — |
| | (132 | ) | | (11 | ) | | 233 |
|
| Net Income/(Loss) attributable to NRG Energy, Inc. | $ | 940 |
| | $ | (536 | ) | | $ | 1 |
| | $ | 21 |
| — |
| $ | (148 | ) | | $ | 1 |
| | $ | 279 |
|
| Total assets as of March 31, 2018 | $ | 3,521 |
| | $ | 7,313 |
| | $ | 5,191 |
| | $ | 8,362 |
| | $ | 9,108 |
| | $ | (9,743 | ) | | $ | 23,752 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Operating revenues include inter-segment sales and net derivative gains and losses of: | $ | 491 |
| | $ | (8 | ) | | $ | 19 |
| | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | 523 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Operating revenues include inter-segment sales and net derivative gains and losses of: | $ | 1 |
| | $ | (307 | ) | | $ | 8 |
| | $ | — |
| | $ | (2 | ) | | $ | — |
| | $ | (300 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation(a) | | Retail(a) | | Renewables(a) | | NRG Yield | | Corporate(a) | | Eliminations | | Total |
| Three months ended September 30, 2016 | (In millions) |
Operating revenues(a) | $ | 1,536 |
| | $ | 2,012 |
| | $ | 139 |
| | $ | 272 |
| | $ | 24 |
| | $ | (562 | ) | | $ | 3,421 |
|
| Depreciation and amortization | 134 |
| | 26 |
| | 48 |
| | 75 |
| | 15 |
| | — |
| | 298 |
|
| Impairment losses | 9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 9 |
|
| Equity in earnings/(losses) of unconsolidated affiliates | 6 |
| | — |
| | (10 | ) | | 16 |
| | 5 |
| | (1 | ) | | 16 |
|
| Gain on sale of assets |
|
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
|
| Loss on debt extinguishment, net | — |
| | — |
| | — |
| | — |
| | (50 | ) | | — |
| | (50 | ) |
| Income/(loss) from continuing operations before income taxes | 370 |
| | (78 | ) | | (1 | ) | | 63 |
| | (202 | ) | | 4 |
| | 156 |
|
| Income/(loss) from continuing operations | 372 |
| | (78 | ) | | 2 |
| | 50 |
| | (222 | ) | | 4 |
| | 128 |
|
| Income from discontinued operations, net of tax | — |
| | — |
| | — |
| | — |
| | 265 |
| | — |
| | 265 |
|
| Net Income/(Loss) | 372 |
| | (78 | ) | | 2 |
| | 50 |
| | 43 |
| | 4 |
| | 393 |
|
| Net Income/(Loss) attributable to NRG Energy, Inc. | $ | 372 |
| | $ | (78 | ) | | $ | (9 | ) | | $ | 55 |
| | $ | 19 |
| | $ | 43 |
| | $ | 402 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Retail(a) | | Generation(a) | | Renewables(a) | | NRG Yield | | Corporate(a)(b) | | Eliminations | | Total |
| Three months ended March 31, 2017 | | | (In millions) |
Operating revenues(a) | $ | 1,335 |
| | $ | 965 |
| | $ | 95 |
| | $ | 221 |
| | $ | 10 |
| | $ | (244 | ) | | $ | 2,382 |
|
| Depreciation and amortization | 28 |
| | 97 |
| | 47 |
| | 77 |
| | 8 |
| | — |
| | 257 |
|
| Equity in (losses)/earnings of unconsolidated affiliates | — |
| | (13 | ) | | — |
| | 19 |
| | 3 |
| | (4 | ) | | 5 |
|
| (Loss)/income from continuing operations before income taxes | (31 | ) | | 37 |
| | (35 | ) | | (3 | ) | | (137 | ) | | (4 | ) | | (173 | ) |
| (Loss)/income from continuing operations | (34 | ) | | 37 |
| | (29 | ) | | (2 | ) | | (137 | ) | | (4 | ) | | (169 | ) |
| Loss from discontinued operations, net of tax | — |
| | — |
| | — |
| | — |
| | (34 | ) | | — |
| | (34 | ) |
| Net (Loss)/Income | (34 | ) | | 37 |
| | (29 | ) | | (2 | ) | | (171 | ) | | (4 | ) | | (203 | ) |
| Net (Loss)/Income attributable to NRG Energy, Inc. | $ | (33 | ) | | $ | 37 |
| | $ | (1 | ) | | $ | 12 |
| | $ | (171 | ) | | $ | (7 | ) | | $ | (163 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Operating revenues include inter-segment sales and net derivative gains and losses of: | $ | 506 |
| | $ | (2 | ) | | $ | 8 |
| | $ | — |
| | $ | 50 |
| $ | 52 |
| $ | — |
| | $ | 562 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Operating revenues include inter-segment sales and net derivative gains and losses of: | $ | 1 |
| | $ | 209 |
| | $ | 8 |
| | $ | — |
| | $ | 26 |
| | $ | — |
| | $ | 244 |
|
| (b) Includes other income - affiliate | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 48 |
| | $ | — |
| | $ | 48 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation(a) | | Retail (a) | | Renewables(a) | | NRG Yield | | Corporate(a) | | Eliminations | | Total |
| Nine months ended September 30, 2017 | (In millions) |
Operating revenues(a) | $ | 3,072 |
| | $ | 4,875 |
| | $ | 364 |
| | $ | 767 |
| | $ | 13 |
| | $ | (959 | ) | | $ | 8,132 |
|
| Depreciation and amortization | 287 |
| | 87 |
| | 150 |
| | 241 |
| | 24 |
| | — |
| | 789 |
|
| Impairment losses | 42 |
| | — |
| | 35 |
| | — |
| | — |
| | — |
| | 77 |
|
| Equity in (losses)/earnings of unconsolidated affiliates | (16 | ) | | — |
| | (6 | ) | | 63 |
| | 7 |
| | (19 | ) | | 29 |
|
| Gain on sale of assets | 4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
| Loss on debt extinguishment, net | — |
| | — |
| | (3 | ) | | — |
| | — |
| | — |
| | (3 | ) |
| Income/(loss) from continuing operations before income taxes | 202 |
| | 371 |
| | (97 | ) | | 100 |
| | (430 | ) | | (21 | ) | | 125 |
|
| Income/(loss) from continuing operations | 200 |
| | 380 |
| | (84 | ) | | 85 |
| | (440 | ) | | (21 | ) | | 120 |
|
| Loss from discontinued operations, net of tax | — |
| | — |
| | — |
| | — |
| | (802 | ) | | — |
| | (802 | ) |
| Net Income/(Loss) | 200 |
| | 380 |
| | (84 | ) | | 85 |
| | (1,242 | ) | | (21 | ) | | (682 | ) |
| Net Income/(Loss) attributable to NRG Energy, Inc. | $ | 200 |
| | $ | 380 |
| | $ | (18 | ) | | $ | 87 |
| | $ | (1,306 | ) | | $ | 38 |
| | $ | (619 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Operating revenues include inter-segment sales and net derivative gains and losses of: | $ | 897 |
| | $ | 3 |
| | $ | 23 |
| | $ | — |
| | $ | 36 |
| | $ | — |
| | $ | 959 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation(a) | | Retail(a) | | Renewables(a) | | NRG Yield(a) | | Corporate(a) | | Eliminations | | Total |
| Nine months ended September 30, 2016 | (In millions) |
Operating revenues(a) | $ | 3,173 |
| | $ | 4,918 |
| | $ | 336 |
| | $ | 789 |
| | $ | 54 |
| | $ | (942 | ) | | $ | 8,328 |
|
| Depreciation and amortization | 331 |
| | 83 |
| | 143 |
| | 224 |
| | 45 |
| | — |
| | 826 |
|
| Impairment losses | 26 |
| | — |
| | 27 |
| | — |
| | 12 |
| | — |
| | 65 |
|
| Equity in earnings/(losses) of unconsolidated affiliates | 1 |
| | — |
| | (16 | ) | | 34 |
| | 11 |
| | (17 | ) | | 13 |
|
| Loss on sale of assets | — |
| | — |
| | — |
| | — |
| | (79 | ) | | — |
| | (79 | ) |
| Impairment loss on investment | (142 | ) | | — |
| | 1 |
| | — |
| | (6 | ) | | — |
| | (147 | ) |
| Loss on debt extinguishment, net | — |
| | — |
| | — |
| | — |
| | (119 | ) | | — |
| | (119 | ) |
| (Loss)/income from continuing operations before income taxes | (51 | ) | | 735 |
| | (121 | ) | | 141 |
| | (706 | ) | | (15 | ) | | (17 | ) |
| (Loss)/income from continuing operations | (49 | ) | | 734 |
| | (107 | ) | | 116 |
| | (771 | ) | | (15 | ) | | (92 | ) |
| Income from discontinued operations, net of tax | — |
| | — |
| | — |
| | — |
| | 256 |
| | — |
| | 256 |
|
| Net (Loss)/Income | (49 | ) | | 734 |
| | (107 | ) | | 116 |
| | (515 | ) | | (15 | ) | | 164 |
|
| Net (Loss)/Income attributable to NRG Energy, Inc. | $ | (49 | ) | | $ | 734 |
| | $ | (103 | ) | | $ | 113 |
| | $ | (547 | ) | | $ | 65 |
| | $ | 213 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Operating revenues include inter-segment sales and net derivative gains and losses of: | $ | 836 |
| | $ | 3 |
| | $ | 16 |
| | $ | 6 |
| | $ | 81 |
| | $ | — |
| | $ | 942 |
|
Note 1312 — Income Taxes
Effective Tax Rate
The income tax provision consisted of the following:
| | | | Three months ended September 30, | | Nine months ended September 30, | Three months ended March 31, |
| (In millions except otherwise noted) | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 |
| Income/(Loss) before income taxes | $ | 196 |
| | $ | 156 |
| | $ | 125 |
| | $ | (17 | ) | $ | 232 |
| | $ | (173 | ) |
| Income tax expense from continuing operations | 6 |
| | 28 |
| | 5 |
| | 75 |
| |
| Income tax benefit from continuing operations | | (1 | ) | | (4 | ) |
| Effective tax rate | 3.1 | % | | 17.9 | % |
| 4.0 | % |
| (441.2 | )% | (0.4 | )% | | 2.3 | % |
For the three months and nine months ended September 30, 2017March 31, 2018, NRG's overall effective tax rate was different than the statutory rate of 35%21% primarily due to the tax benefit for the change in valuation allowance, and the generation of PTCs and ITCs from various wind and solar facilities respectively, partially offset byand the inclusion of consolidated partnerships andpartially offset by current state tax expense.
For the three months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance, partially offset by amortization of indefinite lived assets, inclusion of consolidated partnerships and state tax expense.
For the nine months ended September 30, 2016March 31, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the amortization of indefinite lived assets, the inclusion of consolidated partnerships, state tax expense and the expense for the change in valuation allowance.allowance partially offset by the generation of PTCs and ITCs from various wind and solar facilities, respectively and current state tax expense.
Uncertain Tax Benefits
As of September 30, 2017,March 31, 2018, NRG has recorded a non-current tax liability of $40$35 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the ninethree months ended September 30, 2017,March 31, 2018, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of September 30, 2017,March 31, 2018, NRG had cumulative interest and penalties related to these uncertain tax benefits of $43 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 notno longer subject to U.S. federal income tax examinations for years prior to 2015. The Company is no longer 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 1413 — Related Party Transactions
Services Agreement and Transition Services Agreement with GenOn
The Company provides GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn, or the Services Agreement. The initial term of the Services Agreement was through December 31, 2013, with an automatic renewal absent a request for termination. The fee charged was determined based on a fixed amount as described in the Services Agreement and was calculated based on historical GenOn expenses prior to the NRG Merger. The annual fees under the Services Agreement were approximately $193 million and management has concluded that this method of charging overhead costs is reasonable. As described in Note 3, Discontinued Operations Dispositions and AcquisitionsDispositions, in connection with the Restructuring Support Agreement, NRG agreed to provide shared services to GenOn under the Services Agreement for an adjusted annualized fee of $84 million throughmillion.
In December 2017, in conjunction with the pendencyconfirmation of the Chapter 11 Cases. Beginning on June 14, 2017, NRG records operating income for the amounts earned for shared services of approximately $5 million per month. Subsequent to the GenOn Entities' emergence from bankruptcy,plan of reorganization, the Services Agreement was terminated and replaced by the transition services agreement. Under the transition services agreement, NRG will continue to provide the shared services for two months at no charge; after which GenOn has an additional two, one-month options to provideand other separation services at an annualized feerate of $84 million.million, subject to certain credits and adjustments, until September 30, 2018, which GenOn can terminate earlier if NRG charges these fees on a monthly basis, less amounts incurred directly by GenOn.is provided 60 days' notice. NRG may provide additional separation services that are necessary for or reasonably related to the operation of GenOn's business after such date, subject to NRG's prior written consent, not to be unreasonably withheld. For the three and nine months ended September 30,March 31, 2018, NRG recorded approximately $21 million against selling, general and administrative expenses post-Chapter 11 Filing. For the three months ended March 31, 2017, NRG recorded other income - affiliate related to these services of $14 million and $104 million, respectively. For the three and nine months ended September 30, 2016, NRG recorded other income - affiliate related to these services of $48 million and $144 million, respectively.million.
In addition, as described in Note 3, Discontinued Operations Dispositions and Acquisitions,Dispositions, under the Restructuring Support Agreement, NRG has agreed to provide GenOn with a $28 million credit against amounts owed to NRG prior to the Petition Date under the current Services Agreement.transition services agreement. The credit wasis intended to reimburse GenOn for its payment of financing costs. In addition, the Restructuring Support Agreement provides thatAny unused amount can be paid in cash at GenOn's request, subject to the extent GenOn has paid for services during the bankruptcy proceedingsterms and the aforementioned credit has not been applied in full, NRG shall, upon request by GenOn, reimburse such payments in cash up to the amount of any unused portionconditions of the credit.
See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement and Services Agreement, based on which NRG recorded a reserve of $15 million against affiliate receivable balances as of September 30, 2017.transition services agreement.
Credit Agreement with GenOn
NRG and GenOn are party to a secured intercompany revolving credit agreement. The intercompany revolving credit agreement provided for a $500 million revolving credit facility, all of which was available for revolving loans and letters of credit. At September 30, 2017March 31, 2018 and December 31, 2016, $1032017, $86 million and $272$92 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of September 30,March 31, 2018 and December 31, 2017, there were $125 million of loans outstanding under the intercompany secured revolving credit facility. As of December 31, 2016, no loans were outstanding under this intercompany secured revolving credit facility.facility, which will be applied against the settlement cash consideration that will be paid to GenOn upon emergence from bankruptcy, as further discussed in Note 3 , Discontinued Operations and Dispositions. In addition, the intercompany secured revolving credit facility contains customary covenants and events of default. As of September 30, 2017,March 31, 2018, GenOn was in default under the secured intercompany revolving credit agreement due to the filing of the Chapter 11 Cases.
As a result of the Chapter 11 Cases, no additional revolving loans or letters of credit are available to GenOn. In addition, NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. The letter of credit facility provided availability of up to $330 million less amounts borrowed and letters of credit provided are required to be cash collateralized at 103% of the letter of credit amount. On July 27, 2017, this letter of credit facility was terminated as GenOn has obtained a separate letter of credit facility with a third party financial institution. Effective with completion of the reorganization, GenOn must repay NRG for all revolving loans outstanding, with such amount to be netted against the settlement payment owed from NRG to GenOn. Accordingly, the affiliate receivable is recorded net within accrued expenses and other current liabilities - affiliate on the consolidated balance sheet as of September 30, 2017.March 31, 2018, all of which is to be settled at emergence. Interest continues to accrue during the pendency of the Chapter 11 Cases and borrowings remain secured obligations.
Commercial Operations Agreement
NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. As of September 30, 2017,March 31, 2018, derivative assets and liabilities associated with these transactions are recorded within NRG's derivative instruments balances on the consolidated balance sheet, with related revenues and costs within operating revenues and cost of operations, respectively. Additionally, as of March 31, 2018 and December 31, 2017, the Company had $28 million and $32 million, respectively, of cash collateral posted in support of energy risk management activities by GenOn.
NRG will provide settlement cash consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility.
Note 1514 — Commitments and Contingencies
This footnote should be read in conjunction with the complete description under Note 22, Commitments and Contingencies, to the Company's 20162017 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 September 30, 2017,March 31, 2018, hedges under the first lienslien were out-of-the-moneyin-the-money for NRG on a counterparty aggregate basis.
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.
Energy Plus Holdings—On August 7, 2012, Energy Plus Holdings receivedMarch 27, 2018, ComEd filed a subpoena from the NYAG which generally sought information and business recordsMotion to Compel Payments of Claims seeking $61 million related to Energy Plus Holdings' sales, marketingasbestos liabilities. On April 25, 2018, NRG filed an Omnibus Objection to All Remaining Claims of ComEd 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. On August 28, 2017, the parties entered into an Assurance of Discontinuance resolving this matter.Exelon.
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 expectOn March 9, 2018, the resolutionConsent Decree which provides that Midwest Generation will be required to (x) pay $500,000 to each of this matter to have a material impact on the Company’s consolidated financial position, resultsState of operations or cash flows.Illinois and the Federal Government and (y) make and maintain certain operational improvements was lodged with the court.
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 June 22, 2017, plaintiffs in the California case filed a motion for leave to file a second amended complaint to substitute new plaintiffs. Defendants’Defendants filed an opposition to this motion on June 26, 2017. The court granted plaintiffs' motion to substitute new plaintiffs and on August 1, 2017, Defendantsdefendants filed an answer to the second amended complaint. On August 31, 2017, the court in the California case agreed that the litigation should be stayed pending final court approval of the New Jersey settlement. On July 12, 2017, the parties in the New Jersey action reached an agreement in principle to resolve the class allegations which was confirmed by a term sheet signed by the parties on July 28, 2017. On September 27, 2017, plaintiffs in the New Jersey case filed their motion for preliminary approval of the class settlement which was approved by the court on November 17, 2017. On May 1, 2018, the court granted plaintiffs' motion for final approval of the class action settlement.
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 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 demurrersobjections in response to the plaintiffs' complaint. The demurrersobjections 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 demurrersobjections to the amended complaints. On November 18, 2016, the court sustained the demurrersobjections 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 demurrersobjections without leave to amend. On July 14, 2017, CDWR filed a notice of appeal. On January 10, 2018, CDWR filed its appellate brief. Defendants filed their opposition brief on April 10, 2018.
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. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. The case is currently stayed by agreement of the parties. On October 26, 2017,May 2, 2018, the court approved the parties'a joint stipulation which provides theprovides: (i) plaintiffs' opposition brief is due on December 6, 2017 andor before July 30, 2018; (ii) defendants' reply brief is due on February 8,or before October 5, 2018; and (iii) a hearing on the motions is scheduled on October 30, 2018.
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. The court heard oral argument on defendants' motion to dismiss on June 20, 2017. On September 7, 2017, the court requested additional briefing which the parties provided on September 21, 2017.
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. On June 6, 2017, the defendants filed a motion to compel arbitration or dismiss the lawsuit. Plaintiffs filed their opposition on June 29, 2017. On July 14, 2017, the court denied NRG's motion to compel arbitration or dismiss the case. On July 25, 2017, NRG filed a motion for reconsideration of the appeal, which the courtwas denied. On August 22, 2017, NRG filed a notice of appeal. NRG’s appellate briefAfter fully briefing the appeal, oral argument was filedheard on October 25, 2017. Plaintiffs’ opposition is due on November 16, 2017.April 24, 2018.
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 GenOn's Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property. Plaintiffs filed an amended complaint on August 14, 2017. On October 20, 2017, NRG filed its answeranswers and affirmative defenses.
Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen — On June 28, 2017, plaintiffs Washington-St. Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against Louisiana Generating, L.L.C., or LaGen, in the United States District Court for the Middle District of Louisiana. The plaintiffs claim breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology. Plaintiffs seek damages for the alleged improper charges and a declaration as to which charges are proper under the contract. On September 14, 2017, the court issued a scheduling order setting this case for trial on October 21, 2019. LaGen filed a motion for a more definite statementits answer and affirmative defenses on September 18,November 17, 2017.
GenOn Chapter 11 Cases — On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under the Restructuring Support Agreement to which the GenOn Entities, NRG and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them has agreed to supportsupported the Bankruptcy CourtCourt's approval of the plan of reorganization. GenOn has a customary "fiduciary out" under the Restructuring Support Agreement. Moreover, the Bankruptcy Court may not approve the plan of reorganization. If the plan of reorganization is not approved,consummated, NRG may not be entitled to the benefits of the Settlement Agreement provided under the Restructuring Support Agreement and it will remain subject to any claims of GenOn and the noteholders, including claims relating to or arising out of any shared services and any other relationships or transactions between the companies. See Note 3, Discontinued Operations Dispositions and AcquisitionsDispositions, for additional information related to the Chapter 11 Cases.
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 the Services Agreement between NRG and GenOn. Plaintiffs generally seek return 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 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, among other things, generally seek return of all monies paid under the services agreement and any other damages that the court deems appropriate. Pursuant to the terms of the Restructuring Support Agreement, this matterOn December 14, 2017, a settlement agreement was executed between GenOn and NRG which should ultimately be resolved if the GenOn Entities' plan of reorganization is approved by the Bankruptcy Court.resolve this lawsuit.
Morgantown v. GenOn Mid-Atlantic — On June 8, 2017, Morgantown and Dickerson Owner Lessors filed a lawsuit against GenOn Mid-Atlantic, LLC, NRG North America LLC, GenOn Americas Generation, LLC, NRG Americas, Inc., GenOn Energy Holdings, Inc., GenOn Energy, Inc., and NRG Energy, Inc. in New York State Supreme Court. The plaintiffs allege that they were overcharged by defendants for certain services outlined in a Services Agreement and that defendants caused a Qualified Credit Support portion of a Participation Agreement, or QCS Agreement, to be violated by causing the transfer of certain money outside the allowable confines set forth in the QCS Agreement. In addition, plaintiffs claim that the transfers were unfairly executed and done so in an effort to defraud plaintiffs and hinder their ability to continue to do business. As such, plaintiffs seek, among other things, the return of certain transferred funds and service charges paid and to bar defendants from executing additional transfers on plaintiffs’ behalf. A claims estimation ruling on this matter byOn November 7, 2017, the Bankruptcy Court could occur as early as November 7, 2017.issued an order estimating the claims to be valued at $0. On December 14, 2017, a settlement agreement was executed between GenOn and NRG. On April 27, 2018, the parties executed a mutual release which in conjunction with the settlement agreement resolved this lawsuit.
BTEC v. NRG Texas Power — On July 18, 2017, BTEC New Albany LLC, or BTEC, filed a lawsuit against NRG Texas Power LLC, or NRG Texas Power, in the Harris County District Court in Texas. On January 15, 2013, the parties entered into a Membership Interest and Purchase Agreement, or MIPA, whereby BTEC agreed to dismantle, transport and rebuild an electric power generation facility at the former P.H. Robinson Electric Generating Station in Bacliff, Texas. The MIPA required BTEC to meet a Guaranteed Commercial Completion Date of May 31, 2016. But even a year later, BTEC had not satisfied all of the contractually-required acceptance criteria. As a result and given that the MIPA expiration date passed on May 31, 2017, NRG elected to terminate the contract in June 2017. BTEC claims that NRG Texas Power breached the MIPA by improperly terminating it, and seeks a declaratory judgment as to the rights and obligations of the parties. In addition, BTEC seeks damages, interest and attorney’s fees. On August 14, 2017, NRG Texas Power served its answer to the lawsuit. On September 7, 2017, NRG Texas Power filed a counterclaim seeking damages in excess of $48 million. On March 21, 2018, BTEC filed a Second Amended Petition in which they supplemented their previous claims and added a claim for specific performance.
GenOn Related Contingencies
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. On June 1, 2017, the Fifth Circuit affirmed the District Court's judgment. On June 12, 2017, MC Asset Recovery petitioned the Fifth Circuit for rehearing. The petition for rehearing was denied and a court order and judgment affirming the District Court's judgments was entered on July 17, 2017. On January 17, 2018, theThe bankruptcy court willis scheduled to hear a Motion for a Final Decree in the Mirant bankruptcy.bankruptcy on June 13, 2018.
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. On June 13, 2017, the Ninth Circuit granted plaintiffs' petition for interlocutory review. The appeal is fully briefed.
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. The appeal has been fully briefed bywas argued on February 16, 2018. On March 27, 2018, the parties.Ninth Circuit reversed the District Court's decision. On April 10, 2018, the defendants filed a petition for rehearing. 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.
On February 26, 2018, GenOn filed objections to the proofs of claim filed in the Chapter 11 Cases by all of the plaintiffs in each of the four cases. GenOn filed that same day a motion seeking a schedule for a series of hearings to resolve the objections and asking the Bankruptcy Court to estimate all of the proofs of claim at zero dollars. The plaintiffs have objected to the request for Bankruptcy Court to estimate the proofs of claim. The Bankruptcy Court ordered briefing as to whether it had authority to resolve these claims.
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 Potomac River LLC is currently reviewing the information provided by DOEE.
Natixis v. GenOn Mid-Atlantic—On February 16, 2018, Natixis Funding Corp. and Natixis, New York Branch filed a complaint in the Supreme Court of the State of New York against GenOn Mid-Atlantic, the owner lessors under GenOn Mid-Atlantic’s operating leases of the Dickerson and Morgantown coal generation units, and the lease indenture trustee under those leases. The plaintiffs’ allegations against GenOn Mid-Atlantic relate to a payment agreement between GenOn Mid-Atlantic and Natixis Funding Corp. to procure credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson. The plaintiffs seek approximately $34 million in damages arising from GenOn Mid-Atlantic’s purported breach of certain warranties in the payment agreement. On April 2, 2018, GenOn Mid-Atlantic removed the allegations against it to the U.S. District Court for the Southern District of New York. On April 11, 2018, the U.S. District Court for the Southern District of New York entered a briefing schedule on a forthcoming motion to remand by Natixis Funding Corp. and a forthcoming motion to transfer by GenOn Mid-Atlantic.
Note 1615 — Regulatory Matters
This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 20162017 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
Department of Energy Consideration of 202(c) and Defense Production Act —On March 29, 2018, FirstEnergy Solutions requested that the Department of Energy provide price supports for its coal and nuclear units by having the DOE issue an emergency must-run order under Section 202(c) of the Federal Power Act. A number of parties have filed comments with the DOE, including PJM, challenging the assertion that the FirstEnergy Solutions’ units are necessary for grid reliability. The DOE has not yet formally responded. Subsequently, Senator Manchin of West Virginia has requested that the Administration utilize the Defense Production Act to require coal and nuclear units to continue to operate. The assertion is that these plants are needed to maintain national security. No formal timeline for action on either proposal has been set by the Administration.
Zero-Emission Credits for Nuclear Plants in Illinois — In 2016, Illinois enacted 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. On July 14, 2017, Defendants' motions to dismiss were granted. On July 17, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Seventh Circuit. On July 18, 2017, the Court of Appeals issued an order setting an expedited briefing schedule for the matter. Briefing is underway.complete. Oral argument was held on January 3, 2018, with supplemental briefs filed on January 26, 2018. On February 21, 2018, the Seventh Circuit invited the U.S. to file an amicus brief in the proceeding.
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. On July 25, 2017, the defendants' motions to dismiss were granted. On August 24, 2017, NRG, along with other plaintiff companies, filed a notice of appeal to the U.S. Court of Appeals for the Second Circuit. On September 9, 2017, the Court of Appeals issued a briefing schedule. Briefing is underway.complete. Oral argument took place on March 12, 2018.
Department of Energy's Proposed Grid Resiliency Pricing Rule and Subsequent FERC Proceeding — — On September 29, 2017, the Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC to take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 2, 2017, FERC issued a notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to address. On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner compatible with robust competitive markets. On January 8, 2018, FERC terminated the proposed rulemaking and opened a new proceeding asking each ISO/RTO to address specific questions focused on grid resilience. On March 9, 2018, the ISOs/RTOs filed comments to the questions posed by FERC.
East/West
Montgomery County Station Power Tax—On December 20, 2013, NRG received a letter from Montgomery County, Maryland requesting payment of an energy tax for the consumption of station power at the Dickerson Facility over the previous three years. Montgomery County seeks payment in the amount of $22 million, which includes tax, interest and penalties. NRG disputed the applicability of the tax. On December 11, 2015, the Maryland Tax Court reversed Montgomery County's assessment. Montgomery County filed an appeal, and on February 2, 2017, the Montgomery County Circuit Court affirmed the decision of the tax court. On February 17, 2017, Montgomery County filed an appeal to the Court of Special Appeals of Maryland. On April 24, 2018, the Court of Special Appeals of Maryland affirmed the lower court's decision.
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months, which was granted on November 3, 2017. On April 20, 2018, NRG filed a motion requesting an additional extension of the suspension period to coincide with the CPUC’s final decision on SCE’s application seeking approval of resources procured through its Moorpark RFO, or until June 30, 2019, whichever is sooner.
Note 1716 — Environmental Matters
This footnote should be read in conjunction with the complete description under Note 24, Environmental Matters, to the Company's 20162017 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 current 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 current 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) SO2 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, or FGD, fly ash, bottom ash, and flue gas mercury control. In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines. On September 18, 2017, the EPA promulgated a final rule that (i) postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking and (ii) withdrew the April 2017 administrative stay. The legal challenges have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company has largely eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the rule is revised.
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. On September 13, 2017, the EPA granted the petition for reconsideration that the Utility Solid Waste Activities Group filed in May 2017. 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 September 30, 2017.March 31, 2018.
East RegionEast/West
Burton Island Old Ash LandfillNew Source Review — The EPA and various states have been investigating compliance of electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review,” or NSR. In January 2006, NRG's Indian River Power LLC was notified2007, Midwest Generation received an NOV from the EPA alleging that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill locatedpast work at Crawford, Fisk, Joliet, Powerton, Waukegan and Will County generating stations violated NSR and other regulations. These alleged violations are the subject of litigation described in Note 14, Commitments and Contingencies. Additionally, in April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at oil-fired combustion turbines 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 waterTorrington Terminal, Franklin, Branford 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. In the second quarter of 2017, the Company completed the remediation requirements in the remediation plan. The cost of completing the work required by the remediation plan was within amounts budgeted in early 2016. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in December 2016.Middletown generating stations violated regulations regarding NSR.
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 1817 — Condensed Consolidating Financial Information
As of September 30, 2017March 31, 2018, the Company had outstanding $5.4$4.8 billion of Senior Notes due from 20182022 to 2027,2028, as shown in Note 87, 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, 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 September 30, 2017March 31, 2018:
|
| | |
| Ace Energy, Inc. | New Genco GP, LLC | NRG Norwalk Harbor OperationsNortheast Affiliate Services Inc. |
| Allied Home Warranty GP LLC | Norwalk Power LLC | NRG Operating Services,Norwalk Harbor Operations Inc. |
| Allied Warranty LLC | NRG Advisory Services LLC | NRG Oswego Harbor Power OperationsOperating Services, Inc. |
| Arthur Kill Power LLC | NRG Affiliate Services Inc. | NRG PacGenOswego Harbor Power Operations Inc. |
| Astoria Gas Turbine Power LLC | NRG Arthur Kill Operations Inc. | NRG Portable Power LLCPacGen Inc. |
| Bayou Cove Peaking Power, LLC | NRG Astoria Gas Turbine Operations Inc. | NRG Portable Power Marketing LLC |
| BidURenergy, Inc. | NRG Bayou Cove LLC | NRG Reliability SolutionsPower Marketing LLC |
| Cabrillo Power I LLC | NRG Business Services LLC | NRG Renter's ProtectionReliability Solutions LLC |
| Cabrillo Power II LLC | NRG Cabrillo Power Operations Inc. | NRG RetailRenter's Protection LLC |
| Carbon Management Solutions LLC | NRG California Peaker Operations LLC | NRG Retail Northeast LLC |
| Cirro Group, Inc. | NRG Cedar Bayou Development Company, LLC | NRG Rockford AcquisitionRetail Northeast LLC |
| Cirro Energy Services, Inc. | NRG Connected Home LLC | NRG Saguaro Operations Inc.Rockford Acquisition LLC |
| Conemaugh Power LLC | NRG Connecticut Affiliate Services Inc. | NRG Security LLCSaguaro Operations Inc. |
| Connecticut Jet Power LLC | NRG Construction LLC | NRG Services CorporationSecurity LLC |
| Cottonwood Development LLC | NRG Curtailment Solutions, Inc | NRG SimplySmart Solutions LLCServices Corporation |
| Cottonwood Energy Company LP | NRG Development Company Inc. | NRG South Central Affiliate Services Inc.SimplySmart Solutions LLC |
| Cottonwood Generating Partners I LLC | NRG Devon Operations Inc. | NRG South Central Generating LLCAffiliate Services Inc. |
| Cottonwood Generating Partners II LLC | NRG Dispatch Services LLC | NRG South Central Operations Inc.Generating LLC |
| Cottonwood Generating Partners III LLC | NRG Distributed Energy Resources Holdings LLC | NRG South Texas LPCentral Operations Inc. |
| Cottonwood Technology Partners LP | NRG Distributed Generation PR LLC | NRG SPV #1 LLCSouth Texas LP |
Devon Power��Power LLC | NRG Dunkirk Operations Inc. | NRG Texas C&I Supply LLC |
| Dunkirk Power LLC | NRG El Segundo Operations Inc. | NRG Texas Gregory LLC |
| Eastern Sierra Energy Company LLC | NRG Energy Efficiency-L LLC | NRG Texas Holding Inc. |
| El Segundo Power, LLC | NRG Energy Labor Services LLC | NRG Texas LLC |
| El Segundo Power II LLC | NRG ECOKAP Holdings LLC | NRG Texas Power LLC |
| Energy Alternatives Wholesale, LLC | NRG Energy Services Group LLC | NRG Warranty Services LLC |
| Energy Choice Solutions LLC | NRG Energy Services International Inc. | NRG West Coast LLC |
| Energy Plus Holdings LLC | NRG Energy Services LLC | NRG Western Affiliate Services Inc. |
| Energy Plus Natural Gas LLC | NRG Generation Holdings, Inc. | O'Brien Cogeneration, Inc. II |
| Energy Protection Insurance Company | NRG Greenco LLC | ONSITE Energy, Inc. |
| Everything Energy LLC | NRG Home & Business Solutions LLC | Oswego Harbor Power LLC |
| Forward Home Security, LLC | NRG Home Services LLC | Reliant Energy Northeast LLC |
| GCP Funding Company, LLC | NRG Home Solutions LLC | Reliant Energy Power Supply, LLC |
| Green Mountain Energy Company | NRG Home Solutions Product LLC | Reliant Energy Retail Holdings, LLC |
| Gregory Partners, LLC | NRG Homer City Services LLC | Reliant Energy Retail Services, LLC |
| Gregory Power Partners LLC | NRG Huntley Operations Inc. | RERH Holdings, LLC |
| Huntley Power LLC | NRG HQ DG LLC | Saguaro Power LLC |
| Independence Energy Alliance LLC | NRG Identity Protect LLC | Somerset Operations Inc. |
| Independence Energy Group LLC | NRG Ilion Limited Partnership | Somerset Power LLC |
| 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 Services, LP |
Langford Wind Power,Louisiana Generating LLC | NRG MidAtlantic Affiliate Services Inc. | US Retailers LLC |
Louisiana GeneratingMeriden Gas Turbines LLC | NRG Middletown Operations Inc. | Vienna Operations Inc. |
Meriden Gas TurbinesMiddletown Power LLC | NRG Montville Operations Inc. | Vienna Power LLC |
MiddletownMontville Power LLC | NRG New Roads Holdings LLC | WCP (Generation) Holdings LLC |
Montville Power LLCNEO Corporation | NRG North Central Operations Inc. | West Coast Power LLC |
NEO Corporation | NRG Northeast Affiliate Services 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 September 30, 2017March 31, 2018
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 2,160 |
| | $ | 1,021 |
| | $ | — |
| | $ | (132 | ) | | $ | 3,049 |
|
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 1,588 |
| | 682 |
| | 15 |
| | (129 | ) | | 2,156 |
|
| Depreciation and amortization | 104 |
| | 160 |
| | 8 |
| | — |
| | 272 |
|
| Impairment losses | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
| Selling, general and administrative | 97 |
| | 29 |
| | 88 |
| | (1 | ) | | 213 |
|
| Reorganization | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
| Development activity expenses | — |
| | 9 |
| | 5 |
| |
| | 14 |
|
| Total operating costs and expenses | 1,789 |
| | 894 |
| | 134 |
| | (130 | ) | | 2,687 |
|
| Other income - affiliate | — |
| | — |
| | 14 |
| | — |
| | 14 |
|
| Operating Income/(Loss) | 371 |
| | 127 |
| | (120 | ) | | (2 | ) | | 376 |
|
| Other Income/(Expense) | | | | | | | | | |
| Equity in losses of consolidated subsidiaries | (41 | ) | | (9 | ) | | (134 | ) | | 184 |
| | — |
|
| Equity in (losses)/earnings of unconsolidated affiliates | — |
| | (606 | ) | | 666 |
| | (33 | ) | | 27 |
|
| Other income | 7 |
| | 3 |
| | 5 |
| | — |
| | 15 |
|
| Loss on debt extinguishment | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) |
| Interest expense | (4 | ) | | (103 | ) | | (114 | ) | | — |
| | (221 | ) |
| Total other (expense)/income | (38 | ) | | (716 | ) | | 423 |
| | 151 |
| | (180 | ) |
| Income/(Loss) from Continuing Operations Before Income Taxes | 333 |
| | (589 | ) | | 303 |
| | 149 |
| | 196 |
|
| Income tax expense/(benefit) | 113 |
| | (209 | ) | | 102 |
| | — |
| | 6 |
|
| Income/(Loss) from Continuing Operations | 220 |
| | (380 | ) | | 201 |
| | 149 |
| | 190 |
|
| Loss from Discontinued Operations, net of income tax | — |
| | (27 | ) | | — |
| | — |
| | (27 | ) |
| Net Income/(Loss) | 220 |
| | (407 | ) | | 201 |
| | 149 |
| | 163 |
|
| Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests | — |
| | (3 | ) | | 30 |
| | (35 | ) | | (8 | ) |
Net Income/(Loss) Attributable to NRG Energy, Inc. | $ | 220 |
| | $ | (404 | ) | | $ | 171 |
| | $ | 184 |
| | $ | 171 |
|
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the nine months ended September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 5,517 |
|
| $ | 2,872 |
|
| $ | — |
|
| $ | (257 | ) |
| $ | 8,132 |
|
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 4,156 |
| | 1,904 |
| | 46 |
| | (254 | ) | | 5,852 |
|
| Depreciation and amortization | 307 |
| | 458 |
| | 24 |
| | — |
| | 789 |
|
| Impairment losses | 42 |
| | 35 |
| | — |
| | — |
| | 77 |
|
| Selling, general and administrative | 281 |
| | 115 |
| | 304 |
| | (3 | ) | | 697 |
|
| Reorganization | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
| Development activity expenses | — |
| | 34 |
| | 15 |
| | — |
| | 49 |
|
| Total operating costs and expenses | 4,786 |
| | 2,546 |
| | 407 |
| | (257 | ) | | 7,482 |
|
| Other income - affiliate | — |
| | — |
| | 104 |
| | — |
| | 104 |
|
| Gain on sale of assets | 4 |
| | — |
| | — |
| | — |
| | 4 |
|
| Operating Income/(Loss) | 735 |
| | 326 |
| | (303 | ) | | — |
| | 758 |
|
| Other Income/(Expense) | | | | | | | | | |
| Equity in losses of consolidated subsidiaries | (61 | ) | | (66 | ) | | (182 | ) | | 309 |
| | — |
|
| Equity in earnings/(losses) of unconsolidated affiliates | — |
| | 101 |
| | (3 | ) | | (69 | ) | | 29 |
|
| Other income | 8 |
| | 15 |
| | 10 |
| | — |
| | 33 |
|
| Loss on debt extinguishment | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) |
| Interest expense | (11 | ) | | (328 | ) | | (353 | ) | | — |
| | (692 | ) |
| Total other expense | (64 | ) | | (281 | ) | | (528 | ) | | 240 |
| | (633 | ) |
| Income/(Loss) from Continuing Operations Before Income Taxes | 671 |
| | 45 |
| | (831 | ) | | 240 |
| | 125 |
|
| Income tax expense/(benefit) | 244 |
| | 28 |
| | (267 | ) | | — |
| | 5 |
|
| Income/(Loss) from Continuing Operations | 427 |
| | 17 |
| | (564 | ) | | 240 |
| | 120 |
|
| Loss from Discontinued Operations, net of income tax | — |
| | (802 | ) | | — |
| | — |
| | (802 | ) |
| Net Income/(Loss) | 427 |
| | (785 | ) | | (564 | ) | | 240 |
| | (682 | ) |
| Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests | — |
| | (49 | ) | | 55 |
| | (69 | ) | | (63 | ) |
Net Income/(Loss) Attributable to
NRG Energy, Inc. | $ | 427 |
| | $ | (736 | ) | | $ | (619 | ) | | $ | 309 |
| | $ | (619 | ) |
| |
(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 September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Net Income/(Loss) | $ | 220 |
| | $ | (407 | ) | | $ | 201 |
| | $ | 149 |
| | $ | 163 |
|
| Other Comprehensive Income/(Loss), net of tax | | | | | | | | | |
| Unrealized gain on derivatives, net | — |
| | 7 |
| | 7 |
| | (7 | ) | | 7 |
|
| Foreign currency translation adjustments, net | 2 |
| | 2 |
| | 2 |
| | (4 | ) | | 2 |
|
| Available-for-sale securities, net | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Defined benefit plans, net | — |
| | — |
| | (2 | ) | | 1 |
| | (1 | ) |
| Other comprehensive income | 2 |
| | 9 |
| | 8 |
| | (10 | ) | | 9 |
|
| Comprehensive Income/(Loss) | 222 |
| | (398 | ) | | 209 |
| | 139 |
| | 172 |
|
| Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest | — |
| | — |
| | 30 |
| | (35 | ) | | (5 | ) |
| Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. | $ | 222 |
| | $ | (398 | ) | | $ | 179 |
| | $ | 174 |
| | $ | 177 |
|
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the nine months ended September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Net Income/(Loss) | $ | 427 |
| | $ | (785 | ) | | $ | (564 | ) | | $ | 240 |
| | $ | (682 | ) |
| Other Comprehensive Income/(Loss), net of tax | | | | | | | | | |
| Unrealized gain on derivatives, net | — |
| | 6 |
| | 7 |
| | (7 | ) | | 6 |
|
| Foreign currency translation adjustments, net | 7 |
| | 7 |
| | 9 |
| | (13 | ) | | 10 |
|
| Available-for-sale securities, net | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| Defined benefit plans, net | — |
| | 29 |
| | 25 |
| | (28 | ) | | 26 |
|
| Other comprehensive income | 7 |
| | 42 |
| | 43 |
| | (48 | ) | | 44 |
|
| Comprehensive Income/(Loss) | 434 |
| | (743 | ) | | (521 | ) | | 192 |
| | (638 | ) |
| Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest | — |
| | (47 | ) | | 55 |
| | (69 | ) | | (61 | ) |
| Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. | $ | 434 |
| | $ | (696 | ) | | $ | (576 | ) | | $ | 261 |
| | $ | (577 | ) |
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| ASSETS | (In millions) |
| Current Assets | | | | | | | | | |
| Cash and cash equivalents | $ | (20 | ) | | $ | 350 |
| | $ | 893 |
| | $ | — |
| | $ | 1,223 |
|
| Funds deposited by counterparties | 29 |
| | 2 |
| | — |
| | — |
| | 31 |
|
| Restricted cash | 14 |
| | 523 |
| | — |
| | — |
| | 537 |
|
| Accounts receivable - trade, net | 876 |
| | 395 |
| | 3 |
| | — |
| | 1,274 |
|
| Accounts receivable - affiliate | 222 |
| | 191 |
| | (22 | ) | | (337 | ) | | 54 |
|
| Inventory | 406 |
| | 224 |
| | — |
| | — |
| | 630 |
|
| Derivative instruments | 438 |
| | 106 |
| | 5 |
| | (74 | ) | | 475 |
|
| Cash collateral posted in support of energy risk management activities | 190 |
| | 13 |
| | — |
| | — |
| | 203 |
|
| Prepayments and other current assets | 108 |
| | 147 |
| | 45 |
| | — |
| | 300 |
|
| Current assets - held for sale | — |
| | 33 |
| | — |
| | — |
| | 33 |
|
| Total current assets | 2,263 |
| | 1,984 |
| | 924 |
|
| (411 | ) | | 4,760 |
|
| Net property, plant and equipment | 3,980 |
| | 11,142 |
| | 236 |
| | (26 | ) | | 15,332 |
|
| Other Assets | | | | | | | | | |
| Investment in subsidiaries | 1,098 |
| | 1,004 |
| | 9,409 |
| | (11,511 | ) | | — |
|
| Equity investments in affiliates | — |
| | 1,135 |
| | 3 |
| | — |
| | 1,138 |
|
| Notes receivable, less current portion | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Goodwill | 359 |
| | 303 |
| | — |
| | — |
| | 662 |
|
| Intangible assets, net | 520 |
| | 1,321 |
| | — |
| | (3 | ) | | 1,838 |
|
| Nuclear decommissioning trust fund | 670 |
| | — |
| | — |
| | — |
| | 670 |
|
| Derivative instruments | 187 |
| | 38 |
| | 27 |
| | (46 | ) | | 206 |
|
| Deferred income tax | (5 | ) | | (148 | ) | | 358 |
| | — |
| | 205 |
|
| Non-current assets held-for-sale | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Other non-current assets | 63 |
| | 520 |
| | 61 |
| | — |
| | 644 |
|
| Total other assets | 2,892 |
| | 4,188 |
| | 9,858 |
| | (11,560 | ) | | 5,378 |
|
| Total Assets | $ | 9,135 |
| | $ | 17,314 |
| | $ | 11,018 |
| | $ | (11,997 | ) | | $ | 25,470 |
|
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | | |
| Current Liabilities | | | | | | | | | |
| Current portion of long-term debt and capital leases | $ | — |
| | $ | 623 |
| | $ | 624 |
| | $ | — |
| | $ | 1,247 |
|
| Accounts payable | 599 |
| | 285 |
| | 31 |
| | — |
| | 915 |
|
| Accounts payable — affiliate | 528 |
| | (340 | ) | | 146 |
| | (338 | ) | | (4 | ) |
| Derivative instruments | 418 |
| | 178 |
| | — |
| | (74 | ) | | 522 |
|
| Cash collateral received in support of energy risk management activities | 29 |
| | 2 |
| | — |
| | — |
| | 31 |
|
| Accrued expenses and other current liabilities | 301 |
| | 57 |
| | 472 |
| | — |
| | 830 |
|
| Accrued expenses and other current liabilities-affiliate | — |
| | 164 |
| | — |
| | — |
| | 164 |
|
| Total current liabilities | 1,875 |
| | 969 |
| | 1,273 |
| | (412 | ) | | 3,705 |
|
| Other Liabilities | | | | | | | | | |
| Long-term debt and capital leases | 244 |
| | 8,644 |
| | 6,770 |
| | — |
| | 15,658 |
|
| Nuclear decommissioning reserve | 265 |
| | — |
| | — |
| | — |
| | 265 |
|
| Nuclear decommissioning trust liability | 397 |
| | — |
| | — |
| | — |
| | 397 |
|
| Deferred income taxes | 428 |
| | — |
| | (407 | ) | | — |
| | 21 |
|
| Derivative instruments | 194 |
| | 159 |
| | — |
| | (46 | ) | | 307 |
|
| Out-of-market contracts, net | 69 |
| | 144 |
| | — |
| | — |
| | 213 |
|
| Non-current liabilities held-for-sale | — |
| | 13 |
| | — |
| | — |
| | 13 |
|
| Other non-current liabilities | 377 |
| | 315 |
| | 424 |
| | — |
| | 1,116 |
|
| Total non-current liabilities | 1,974 |
| | 9,275 |
| | 6,787 |
| | (46 | ) | | 17,990 |
|
| Total liabilities | 3,849 |
| | 10,244 |
| | 8,060 |
| | (458 | ) | | 21,695 |
|
| Redeemable noncontrolling interest in subsidiaries | — |
| | 85 |
| | — |
| | — |
| | 85 |
|
| Stockholders’ Equity | 5,286 |
| | 6,985 |
| | 2,958 |
| | (11,539 | ) | | 3,690 |
|
| Total Liabilities and Stockholders’ Equity | $ | 9,135 |
| | $ | 17,314 |
| | $ | 11,018 |
| | $ | (11,997 | ) | | $ | 25,470 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 1,483 |
| | $ | 885 |
| | $ | — |
| | $ | 53 |
| | $ | 2,421 |
|
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 1,082 |
| | 409 |
| | 14 |
| | 53 |
| | 1,558 |
|
| Depreciation and amortization | 73 |
| | 154 |
| | 8 |
| | — |
| | 235 |
|
| Selling, general and administrative | 98 |
| | 32 |
| | 61 |
| | — |
| | 191 |
|
| Reorganization costs | 2 |
| | — |
| | 18 |
| | — |
| | 20 |
|
| Development costs | — |
| | 9 |
| | 4 |
| | — |
| | 13 |
|
| Total operating costs and expenses | 1,255 |
| | 604 |
| | 105 |
| | 53 |
| | 2,017 |
|
| Gain/(loss) on sale of assets | 3 |
| | (1 | ) | | — |
| | — |
| | 2 |
|
| Operating Income/(Loss) | 231 |
| | 280 |
| | (105 | ) | | — |
| | 406 |
|
| Other Income/(Expense) | | | | | | | | | |
| Equity in earnings of consolidated subsidiaries | 210 |
| | — |
| | 330 |
| | (540 | ) | | — |
|
| Equity in losses of unconsolidated affiliates | — |
| | (1 | ) | | (1 | ) | | — |
| | (2 | ) |
| Other income/(expense), net | 21 |
| | (11 | ) | | 3 |
| | (16 | ) | | (3 | ) |
| Loss on debt extinguishment, net | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
| Interest expense | (3 | ) | | (72 | ) | | (92 | ) | |
|
| | (167 | ) |
| Total other income/(expense) | 228 |
| | (84 | ) | | 238 |
| | (556 | ) | | (174 | ) |
| Income Before Income Taxes | 459 |
| | 196 |
| | 133 |
| | (556 | ) | | 232 |
|
| Income tax expense/(benefit) | 113 |
| | 48 |
| | (162 | ) | | — |
| | (1 | ) |
| Net Income | 346 |
| | 148 |
| | 295 |
| | (556 | ) | | 233 |
|
| Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests | — |
| | (46 | ) | | 16 |
| | (16 | ) | | (46 | ) |
Net Income Attributable to NRG Energy, Inc. | $ | 346 |
| | $ | 194 |
| | $ | 279 |
| | $ | (540 | ) | | $ | 279 |
|
| |
| (a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the nine months ended September 30, 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) | $ | 427 |
| | $ | (785 | ) | | $ | (564 | ) | | $ | 240 |
| | $ | (682 | ) |
| Loss from discontinued operations | — |
| | (802 | ) | | — |
| | — |
| | (802 | ) |
| Net income/(loss) from continuing operations | 427 |
| | 17 |
| | (564 | ) | | 240 |
| | 120 |
|
| Adjustments to reconcile net income/(loss) to net cash provided by operating activities: | | | | | | | | |
|
| Distributions from unconsolidated affiliates | — |
| | 60 |
| | — |
| | (7 | ) | | 53 |
|
| Equity in losses/(earnings) of unconsolidated affiliates | — |
| | (101 | ) | | 3 |
| | 69 |
| | (29 | ) |
| Depreciation and amortization | 307 |
| | 458 |
| | 24 |
| | — |
| | 789 |
|
| Provision for bad debts | 40 |
| | 2 |
| | 15 |
| | — |
| | 57 |
|
| Amortization of nuclear fuel | 37 |
| | — |
| | — |
| | — |
| | 37 |
|
| Amortization of financing costs and debt discount/premiums | — |
| | 31 |
| | 13 |
| | — |
| | 44 |
|
| Adjustment for debt extinguishment | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Amortization of intangibles and out-of-market contracts | 20 |
| | 59 |
| | — |
| | — |
| | 79 |
|
| Amortization of unearned equity compensation | — |
| | — |
| | 27 |
| | — |
| | 27 |
|
| Impairment losses | 42 |
| | 35 |
| | — |
| | — |
| | 77 |
|
| Changes in deferred income taxes and liability for uncertain tax benefits | 244 |
| | 28 |
| | (246 | ) | | — |
| | 26 |
|
| Changes in nuclear decommissioning trust liability | 20 |
| | — |
| | — |
|
| — |
| | 20 |
|
| Changes in derivative instruments | (11 | ) | | 32 |
| | 12 |
| | (8 | ) | | 25 |
|
| Changes in collateral deposits supporting energy risk management activities | (126 | ) | | 23 |
| | — |
| | — |
| | (103 | ) |
| Proceeds from sale of emission allowances | 21 |
| | — |
| | — |
| | — |
| | 21 |
|
| Gain on sale of assets | (22 | ) | | — |
| | — |
| | — |
| | (22 | ) |
| Cash (used)/provided by changes in other working capital | (958 | ) | | (523 | ) | | 1,395 |
| | (294 | ) | | (380 | ) |
| Cash provided by continuing operations | 41 |
| | 124 |
| | 679 |
| | — |
| | 844 |
|
| Cash used by discontinued operations | — |
| | (38 | ) | | — |
| | — |
| | (38 | ) |
| Net Cash Provided by Operating Activities | 41 |
| | 86 |
| | 679 |
| | — |
| | 806 |
|
| Cash Flows from Investing Activities | | | | | | | | | |
|
| Dividends from NRG Yield, Inc. | — |
| | — |
| | 69 |
| | (69 | ) | | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | (176 | ) | | — |
| | 176 |
| | — |
|
| Intercompany dividends | — |
| | — |
| | 129 |
| | (129 | ) | | — |
|
| Acquisition of business, net of cash acquired | — |
| | (36 | ) | | — |
| | — |
| | (36 | ) |
| Capital expenditures | (135 | ) | | (606 | ) | | (19 | ) | | — |
| | (760 | ) |
| Decrease in notes receivable | — |
| | 11 |
| | — |
| | — |
| | 11 |
|
| Purchases of emission allowances | (47 | ) | | — |
| | — |
| | — |
| | (47 | ) |
| Proceeds from sale of emission allowances | 105 |
| | — |
| | — |
| | — |
| | 105 |
|
| Investments in nuclear decommissioning trust fund securities | (402 | ) | | — |
| | — |
| | — |
| | (402 | ) |
| Proceeds from sales of nuclear decommissioning trust fund securities | 382 |
| | — |
| | — |
| | — |
| | 382 |
|
| Proceeds from renewable energy grants and state rebates | 8 |
| | — |
|
| — |
| | — |
| | 8 |
|
| Proceeds from sale of assets, net of cash disposed of | 36 |
| | — |
| | — |
| | — |
| | 36 |
|
| Investments in unconsolidated affiliates | — |
| | (31 | ) | | — |
| | — |
| | (31 | ) |
| Other | 22 |
| | — |
| | — |
| | — |
| | 22 |
|
| Cash (used)/provided by continuing operations | (31 | ) | | (838 | ) | | 179 |
| | (22 | ) | | (712 | ) |
| Cash used by discontinued operations | — |
| | (53 | ) | | — |
| | — |
| | (53 | ) |
| Net Cash (Used)/Provided by Investing Activities | (31 | ) | | (891 | ) | | 179 |
| | (22 | ) | | (765 | ) |
| Cash Flows from Financing Activities |
|
| | |
| | |
| | | | |
| Dividends from NRG Yield, Inc. | — |
| | (69 | ) | | — |
| | 69 |
| | — |
|
| Payments from/(for) intercompany loans | 9 |
| | 417 |
| | (426 | ) | | — |
| | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | — |
| | 176 |
| | (176 | ) | | — |
|
| Intercompany dividends | — |
| | (129 | ) | | — |
| | 129 |
| | — |
|
| Payment of dividends to common and preferred stockholders | — |
| | — |
| | (28 | ) | | — |
| | (28 | ) |
| Net receipts from settlement of acquired derivatives that include financing elements | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Proceeds from issuance of long-term debt | — |
| | 920 |
| | 214 |
| | — |
| | 1,134 |
|
| Payments for short and long-term debt | — |
| | (493 | ) | | (219 | ) | | — |
| | (712 | ) |
| Receivable from affiliate | — |
| | (125 | ) | | — |
| | — |
| | (125 | ) |
| Contributions from, net of distributions to, noncontrolling interest in subsidiaries | — |
| | 65 |
| | — |
| | — |
| | 65 |
|
| Payment of debt issuance costs | — |
| | (38 | ) | | (5 | ) | | — |
| | (43 | ) |
| Other - contingent consideration | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) |
| Cash provided/(used) by continuing operations | 9 |
| | 540 |
| | (288 | ) | | 22 |
| | 283 |
|
| Cash used by discontinued operations | — |
| | (224 | ) | | — |
| | — |
| | (224 | ) |
| Net Cash Provided/(Used) by Financing Activities | 9 |
| | 316 |
| | (288 | ) | | 22 |
| | 59 |
|
| Change in cash from discontinued operations | — |
| | (315 | ) | | — |
| | — |
| | (315 | ) |
| Effect of exchange rate changes on cash and cash equivalents | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) |
| Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties | 19 |
| | (184 | ) | | 570 |
| | — |
| | 405 |
|
| Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period | 4 |
| | 1,059 |
| | 323 |
| | — |
| | 1,386 |
|
| Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period | $ | 23 |
|
| $ | 875 |
|
| $ | 893 |
|
| $ | — |
| | $ | 1,791 |
|
(a) All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONSCOMPREHENSIVE INCOME
For the three months ended September 30, 2016March 31, 2018
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 2,424 |
| | $ | 1,090 |
| | $ | — |
| | $ | (93 | ) | | $ | 3,421 |
|
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 1,719 |
| | 804 |
| | 10 |
| | (93 | ) | | 2,440 |
|
| Depreciation and amortization | 147 |
| | 144 |
| | 7 |
| | — |
| | 298 |
|
| Impairment losses | 8 |
| | 1 |
| | — |
| | — |
| | 9 |
|
| Selling, general and administrative | 115 |
| | 50 |
| | 112 |
| | — |
| | 277 |
|
| Development activity expenses | — |
| | 10 |
| | 11 |
| | — |
| | 21 |
|
| Total operating costs and expenses | 1,989 |
| | 1,009 |
| | 140 |
| | (93 | ) | | 3,045 |
|
| Other income - affiliate | — |
| | — |
| | 48 |
| | — |
| | 48 |
|
| Gain on sale of assets | — |
| | — |
| | 4 |
| | — |
| | 4 |
|
| Operating Income/(Loss) | 435 |
| | 81 |
| | (88 | ) | | — |
| | 428 |
|
| Other Income/(Expense) | | | | | |
| | | | |
| Equity in (losses)/earnings of consolidated subsidiaries | (114 | ) | | (10 | ) | | 562 |
| | (438 | ) | | — |
|
| Equity in earnings/(losses) of unconsolidated affiliates | 2 |
| | 75 |
| | (12 | ) | | (49 | ) | | 16 |
|
| Loss on investment | — |
| | (8 | ) | | — |
| | — |
| | (8 | ) |
| Other income/(loss), net | 1 |
| | 6 |
| | �� |
| | — |
| | 7 |
|
| Loss on debt extinguishment | — |
| | — |
| | (50 | ) | | — |
| | (50 | ) |
| Interest expense | (4 | ) | | (104 | ) | | (129 | ) | | — |
| | (237 | ) |
| Total other expense | (115 | ) | | (41 | ) | | 371 |
| | (487 | ) | | (272 | ) |
| Income from Continuing Operations Before Income Taxes | 320 |
| | 40 |
| | 283 |
| | (487 | ) | | 156 |
|
| Income tax expense/(benefit) | 134 |
| | 45 |
| | (151 | ) | | — |
| | 28 |
|
| Income from Continuing Operations | 186 |
| | (5 | ) | | 434 |
| | (487 | ) | | 128 |
|
| Income from Discontinued Operations, net of income tax | — |
| | 263 |
| | 2 |
| | — |
| | 265 |
|
| Net Income | 186 |
| | 258 |
| | 436 |
| | (487 | ) | | 393 |
|
| Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest | — |
| | 6 |
| | 34 |
| | (49 | ) | | (9 | ) |
| Net Income Attributable to NRG Energy, Inc. | $ | 186 |
| | $ | 252 |
| | $ | 402 |
| | $ | (438 | ) | | $ | 402 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Net Income | $ | 346 |
| | $ | 148 |
| | $ | 295 |
| | $ | (556 | ) | | $ | 233 |
|
| Other Comprehensive (Loss)/Income, net of tax | | | | | | | | | |
| Unrealized gain on derivatives, net | — |
| | 16 |
| | 15 |
| | (17 | ) | | 14 |
|
| Foreign currency translation adjustments, net | (2 | ) | | (2 | ) | | (3 | ) | | 5 |
| | (2 | ) |
| Defined benefit plans, net | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Other comprehensive (loss)/income | (2 | ) | | 14 |
| | 11 |
| | (12 | ) | | 11 |
|
| Comprehensive Income | 344 |
| | 162 |
| | 306 |
| | (568 | ) | | 244 |
|
| Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest | — |
| | (46 | ) | | 24 |
| | (16 | ) | | (38 | ) |
| Comprehensive Income Attributable to NRG Energy, Inc. | $ | 344 |
| | $ | 208 |
| | $ | 282 |
| | $ | (552 | ) | | $ | 282 |
|
| |
| (a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the nine months ended September 30, 2016
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 6,079 |
| | $ | 2,400 |
| | $ | — |
| | $ | (151 | ) | | $ | 8,328 |
|
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 4,278 |
| | 1,558 |
| | 29 |
| | (154 | ) | | 5,711 |
|
| Depreciation and amortization | 372 |
| | 435 |
| | 19 |
| | — |
| | 826 |
|
| Impairment losses | 8 |
| | 57 |
| | — |
| | — |
| | 65 |
|
| Selling, general and administrative | 306 |
| | 144 |
| | 351 |
| | — |
| | 801 |
|
| Development activity expenses | — |
| | 42 |
| | 23 |
| | — |
| | 65 |
|
| Total operating costs and expenses | 4,964 |
| | 2,236 |
| | 422 |
| | (154 | ) | | 7,468 |
|
| Other income - affiliate | — |
| | — |
| | 144 |
| | — |
| | 144 |
|
| Loss on sale of assets | — |
| | — |
| | (79 | ) | | — |
| | (79 | ) |
| Operating Income/(Loss) | 1,115 |
| | 164 |
| | (357 | ) | | 3 |
| | 925 |
|
| Other Income/(Expense) | | | | | |
| | | | |
| Equity in (losses)/earnings of consolidated subsidiaries | (195 | ) | | (80 | ) | | 904 |
| | (629 | ) | | — |
|
| Equity in earnings/(losses) of unconsolidated affiliates | 5 |
| | 114 |
| | (2 | ) | | (104 | ) | | 13 |
|
| Impairment loss on investment | — |
| | (147 | ) | | — |
| | — |
| | (147 | ) |
| Other income, net | 3 |
| | 25 |
| | 2 |
| | (1 | ) | | 29 |
|
| Loss on debt extinguishment | — |
| | (4 | ) | | (115 | ) | | — |
| | (119 | ) |
| Interest expense | (11 | ) | | (312 | ) | | (395 | ) | |
|
| | (718 | ) |
| Total other (expense)/income | (198 | ) | | (404 | ) | | 394 |
| | (734 | ) | | (942 | ) |
| Income/(Loss) Before Income Taxes | 917 |
| | (240 | ) | | 37 |
| | (731 | ) | | (17 | ) |
| Income tax expense/(benefit) | 362 |
| | (49 | ) | | (238 | ) | | — |
| | 75 |
|
| Income/(Loss) from Continuing Operations | 555 |
| | (191 | ) | | 275 |
| | (731 | ) | | (92 | ) |
| Income from Discontinued Operations, net of income tax | — |
| | 248 |
| | 8 |
| | — |
| | 256 |
|
| Net Income | 555 |
| | 57 |
| | 283 |
| | (731 | ) | | 164 |
|
| Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest | — |
| | (17 | ) | | 70 |
| | (102 | ) | | (49 | ) |
| Net Income Attributable to NRG Energy, Inc. | $ | 555 |
| | $ | 74 |
| | $ | 213 |
| | $ | (629 | ) | | $ | 213 |
|
| |
(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 September 30, 2016
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Net Income | $ | 186 |
| | $ | 258 |
| | $ | 436 |
| | $ | (487 | ) | | $ | 393 |
|
| Other Comprehensive Income/(Loss), net of tax | | | | | | | | | |
| Unrealized income on derivatives, net | — |
| | 40 |
| | 26 |
| | (39 | ) | | 27 |
|
| Foreign currency translation adjustments, net | 2 |
| | 2 |
| | 4 |
| | (5 | ) | | 3 |
|
| Defined benefit plans, net | 54 |
| | — |
| | (43 | ) | | 20 |
| | 31 |
|
| Other comprehensive loss | 56 |
| | 42 |
| | (13 | ) | | (24 | ) | | 61 |
|
| Comprehensive Income | 242 |
| | 300 |
| | 423 |
| | (511 | ) | | 454 |
|
| Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest | — |
| | 13 |
| | 34 |
| | (49 | ) | | (2 | ) |
| Comprehensive Income Attributable to NRG Energy, Inc. | $ | 242 |
| | $ | 287 |
| | $ | 389 |
| | $ | (462 | ) | | $ | 456 |
|
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the nine months ended September 30, 2016
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Net Income | $ | 555 |
| | $ | 57 |
| | $ | 283 |
| | $ | (731 | ) | | $ | 164 |
|
| Other Comprehensive Income/(Loss), net of tax | | | | | | | | |
|
| Unrealized (loss)/gain on derivatives, net | — |
| | (15 | ) | | 46 |
| | (39 | ) | | (8 | ) |
| Foreign currency translation adjustments, net | 4 |
| | 4 |
| | 6 |
| | (8 | ) | | 6 |
|
| Available-for-sale securities, net | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Defined benefit plans, net | 55 |
| | — |
| | (43 | ) | | 20 |
| | 32 |
|
| Other comprehensive income/(loss) | 59 |
| | (11 | ) | | 10 |
| | (27 | ) | | 31 |
|
| Comprehensive Income | 614 |
| | 46 |
| | 293 |
| | (758 | ) | | 195 |
|
| Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest | — |
| | (38 | ) | | 70 |
| | (102 | ) | | (70 | ) |
| Comprehensive Income Attributable to NRG Energy, Inc. | 614 |
| | 84 |
| | 223 |
| | (656 | ) | | 265 |
|
| Dividends for preferred shares | — |
| | — |
| | 5 |
| | — |
| | 5 |
|
| Gain on redemption of preferred shares | — |
| | — |
| | (78 | ) | | — |
| | (78 | ) |
| Comprehensive Income Available for Common Stockholders | $ | 614 |
| | $ | 84 |
| | $ | 296 |
| | $ | (656 | ) | | $ | 338 |
|
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
DecemberMarch 31, 20162018
(Unaudited)
| | | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations (a) | | Consolidated | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| ASSETS | (In millions) | (In millions) |
| Current Assets | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | (9 | ) | | $ | 624 |
| | $ | 323 |
| | $ | — |
| | $ | 938 |
| $ | 43 |
| | $ | 371 |
| | $ | 350 |
| | $ | — |
| | $ | 764 |
|
| Funds deposited by counterparties | 2 |
| | — |
| | — |
| | — |
| | 2 |
| 241 |
| | — |
| | — |
| | — |
| | 241 |
|
| Restricted cash | 11 |
| | 435 |
| | — |
| | — |
| | 446 |
| 8 |
| | 399 |
| | — |
| | — |
| | 407 |
|
| Accounts receivable - trade, net | 734 |
| | 321 |
| | 3 |
| | — |
| | 1,058 |
| |
| Accounts receivable - affiliate | 307 |
| | (254 | ) | | 200 |
| | (139 | ) | | 114 |
| |
| Accounts receivable, net | | 610 |
| | 290 |
| | 3 |
| | — |
| | 903 |
|
| Inventory | 482 |
| | 239 |
| | — |
| | — |
| | 721 |
| 323 |
| | 205 |
| | — |
| | — |
| | 528 |
|
| Derivative instruments | 962 |
| | 196 |
| | 1 |
| | (92 | ) | | 1,067 |
| 932 |
| | 207 |
| | 12 |
| | (136 | ) | | 1,015 |
|
| Cash collateral posted in support of energy risk management activities | 116 |
| | 34 |
| | — |
| | — |
| | 150 |
| |
| Current assets held-for-sale | — |
| | 9 |
| | — |
| | — |
| | 9 |
| |
| Cash collateral paid in support of energy risk management activities | | 211 |
| | — |
| | — |
| | — |
| | 211 |
|
| Accounts receivable - affiliate | | 509 |
| | 141 |
| | 491 |
| | (1,068 | ) | | 73 |
|
| Current assets - held for sale | | — |
| | 89 |
| | — |
| | — |
| | 89 |
|
| Prepayments and other current assets | 76 |
| | 152 |
| | 62 |
| | — |
| | 290 |
| 154 |
| | 134 |
| | 38 |
| | — |
| | 326 |
|
| Current assets - discontinued operations | — |
| | 1,919 |
| | — |
| | — |
| | 1,919 |
| |
| Total current assets | 2,681 |
| | 3,675 |
| | 589 |
| | (231 | ) | | 6,714 |
| 3,031 |
| | 1,836 |
| | 894 |
|
| (1,204 | ) | | 4,557 |
|
| Net Property, Plant and Equipment | 4,219 |
| | 10,926 |
| | 251 |
| | (27 | ) | | 15,369 |
| |
| Property, plant and equipment, net | | 2,500 |
| | 11,196 |
| | 240 |
| | (25 | ) | | 13,911 |
|
| Other Assets | | | | | | | | | | | | | | | | | | |
| Investment in subsidiaries | 1,090 |
| | 1,054 |
| | 10,128 |
| | (12,272 | ) | | — |
| 511 |
| | 1 |
| | 7,374 |
| | (7,886 | ) | | — |
|
| Equity investments in affiliates | (13 | ) | | 1,128 |
| | 5 |
| | — |
| | 1,120 |
| — |
| | 1,010 |
| | 1 |
| | — |
| | 1,011 |
|
| Notes receivable, less current portion | — |
| | 16 |
| | — |
| | — |
| | 16 |
| |
| Goodwill | 359 |
| | 303 |
| | — |
| | — |
| | 662 |
| 360 |
| | 179 |
| | — |
| | — |
| | 539 |
|
| Intangible assets, net | 592 |
| | 1,384 |
| | — |
| | (3 | ) | | 1,973 |
| 439 |
| | 1,290 |
| | — |
| | (3 | ) | | 1,726 |
|
| Nuclear decommissioning trust fund | 610 |
| | — |
| | — |
| | — |
| | 610 |
| 680 |
| | — |
| | — |
| | — |
| | 680 |
|
| Derivative instruments | 144 |
| | 44 |
| | 36 |
| | (43 | ) | | 181 |
| 245 |
| | 118 |
| | 38 |
| | (47 | ) | | 354 |
|
| Deferred income taxes | 3 |
| | — |
| | 222 |
| | — |
| | 225 |
| |
| Non-current assets held for sale | — |
| | 10 |
| | — |
| | — |
| | 10 |
| |
| Deferred income tax | | 264 |
| | (34 | ) | | (94 | ) | | — |
| | 136 |
|
| Non-current assets held-for-sale | | — |
| | 157 |
| | — |
| | — |
| | 157 |
|
| Other non-current assets | 67 |
| | 446 |
| | 328 |
| | — |
| | 841 |
| 73 |
| | 489 |
| | 119 |
| | — |
| | 681 |
|
| Non-current assets - discontinued operations | — |
| | 2,961 |
| | — |
| | — |
| | 2,961 |
| |
| Total other assets | 2,852 |
| | 7,346 |
| | 10,719 |
| | (12,318 | ) | | 8,599 |
| 2,572 |
| | 3,210 |
| | 7,438 |
| | (7,936 | ) | | 5,284 |
|
| Total Assets | $ | 9,752 |
| | $ | 21,947 |
| | $ | 11,559 |
| | $ | (12,576 | ) | | $ | 30,682 |
| $ | 8,103 |
| | $ | 16,242 |
| | $ | 8,572 |
| | $ | (9,165 | ) | | $ | 23,752 |
|
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | | | | | | | | | | | |
| Current Liabilities | | | | | | | | | | | | | | | | | | |
| Current portion of long-term debt and capital leases | $ | — |
| | $ | 498 |
| | $ | 18 |
| | $ | — |
| | $ | 516 |
| $ | — |
| | $ | 935 |
| | $ | 21 |
| | $ | — |
| | $ | 956 |
|
| Accounts payable | 501 |
| | 247 |
| | 34 |
| | — |
| | 782 |
| 510 |
| | 241 |
| | 36 |
| | — |
| | 787 |
|
| Accounts payable — affiliate | 744 |
| | (452 | ) | | (122 | ) | | (139 | ) | | 31 |
| 1,662 |
| | (121 | ) | | (441 | ) | | (1,068 | ) | | 32 |
|
| Derivative instruments | 947 |
| | 237 |
| | — |
| | (92 | ) | | 1,092 |
| 857 |
| | 69 |
| | — |
| | (136 | ) | | 790 |
|
| Cash collateral received in support of energy risk management activities | 81 |
| | — |
| | — |
| | — |
| | 81 |
| 240 |
| | — |
| | — |
| | — |
| | 240 |
|
| Current liabilities held-for-sale | | — |
| | 80 |
| | — |
| | — |
| | 80 |
|
| Accrued expenses and other current liabilities | 316 |
| | 209 |
| | 465 |
| | — |
| | 990 |
| 236 |
| | 146 |
| | 280 |
| | — |
| | 662 |
|
| Current liabilities - discontinued operations | — |
| | 1,210 |
| | — |
| | — |
| | 1,210 |
| |
| Accrued expenses and other current liabilities-affiliate | | — |
| | — |
| | 161 |
| | — |
| | 161 |
|
| Total current liabilities | 2,589 |
| | 1,949 |
| | 395 |
| | (231 | ) | | 4,702 |
| 3,505 |
| | 1,350 |
| | 57 |
| | (1,204 | ) | | 3,708 |
|
| Other Liabilities | | | | | | | | | | | | | | | | | | |
| Long-term debt and capital leases | 244 |
| | 8,252 |
| | 7,461 |
| | — |
| | 15,957 |
| 244 |
| | 8,387 |
| | 6,775 |
| | — |
| | 15,406 |
|
| Nuclear decommissioning reserve | 287 |
| | — |
| | — |
| | — |
| | 287 |
| 272 |
| | — |
| | — |
| | — |
| | 272 |
|
| Nuclear decommissioning trust liability | 339 |
| | — |
| | — |
| | — |
| | 339 |
| 400 |
| | — |
| | — |
| | — |
| | 400 |
|
| Deferred income taxes | 186 |
| | 125 |
| | (291 | ) | | — |
| | 20 |
| 112 |
| | 64 |
| | (156 | ) | | — |
| | 20 |
|
| Derivative instruments | 157 |
| | 170 |
| | — |
| | (43 | ) | | 284 |
| 224 |
| | 87 |
| | — |
| | (47 | ) | | 264 |
|
| Out-of-market contracts, net | 80 |
| | 150 |
| | — |
| | — |
| | 230 |
| 62 |
| | 139 |
| | — |
| | — |
| | 201 |
|
| Non-current liabilities held-for-sale | — |
| | 11 |
| | — |
| | — |
| | 11 |
| — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Other non-current liabilities | 396 |
| | 456 |
| | 324 |
| | — |
| | 1,176 |
| 419 |
| | 324 |
| | 393 |
| | — |
| | 1,136 |
|
| Non-current liabilities - discontinued operations | — |
| | 3,184 |
| | — |
| | — |
| | 3,184 |
| |
| Total non-current liabilities | 1,689 |
| | 12,348 |
| | 7,494 |
| | (43 | ) | | 21,488 |
| 1,733 |
| | 9,008 |
| | 7,012 |
| | (47 | ) | | 17,706 |
|
| Total Liabilities | 4,278 |
| | 14,297 |
| | 7,889 |
| | (274 | ) | | 26,190 |
| |
| Total liabilities | | 5,238 |
| | 10,358 |
| | 7,069 |
| | (1,251 | ) | | 21,414 |
|
| Redeemable noncontrolling interest in subsidiaries | — |
| | 46 |
| | — |
| | — |
| | 46 |
| — |
| | 80 |
| | — |
| | — |
| | 80 |
|
| Stockholders’ Equity | 5,474 |
| | 7,604 |
| | 3,670 |
| | (12,302 | ) | | 4,446 |
| 2,865 |
| | 5,804 |
| | 1,503 |
| | (7,914 | ) | | 2,258 |
|
| Total Liabilities and Stockholders’ Equity | $ | 9,752 |
| | $ | 21,947 |
| | $ | 11,559 |
|
| $ | (12,576 | ) | | $ | 30,682 |
| $ | 8,103 |
| | $ | 16,242 |
| | $ | 8,572 |
| | $ | (9,165 | ) | | $ | 23,752 |
|
| |
| (a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the ninethree months ended September 30, 2016 March 31, 2018
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Cash Flows from Operating Activities | | | | | | | | | |
| Net Income | $ | 555 |
| | $ | 57 |
| | $ | 283 |
| | $ | (731 | ) | | $ | 164 |
|
| Less: Income from discontinued operations | — |
| | 248 |
| | 8 |
| | — |
| | 256 |
|
| Net income/(loss) from continuing operations | 555 |
| | (191 | ) | | 275 |
| | (731 | ) | | (92 | ) |
| Adjustments to reconcile net income/(loss) to net cash provided by operating activities: | | | | | | | | | |
| Distributions from unconsolidated affiliates | — |
| | 65 |
| | — |
| | (8 | ) | | 57 |
|
| Equity in (earnings)/losses of unconsolidated affiliates | (5 | ) | | (20 | ) | | 2 |
| | 10 |
| | (13 | ) |
| Depreciation and amortization | 372 |
| | 435 |
| | 19 |
| | — |
| | 826 |
|
| Provision for bad debts | 31 |
| | 5 |
| | — |
| | — |
| | 36 |
|
| Amortization of nuclear fuel | 39 |
| | — |
| | — |
| | — |
| | 39 |
|
| Amortization of financing costs and debt discount/premiums | — |
| | 25 |
| | 17 |
| | — |
| | 42 |
|
| Adjustment for debt extinguishment | — |
| | 102 |
| | 17 |
| | — |
| | 119 |
|
| Amortization of intangibles and out-of-market contracts | 32 |
| | 99 |
| | — |
| | — |
| | 131 |
|
| Amortization of unearned equity compensation | — |
| | — |
| | 23 |
| | — |
| | 23 |
|
| Impairment losses | 8 |
| | 203 |
| | — |
| | — |
| | 211 |
|
| Changes in deferred income taxes and liability for uncertain tax benefits | (134 | ) | | (90 | ) | | 253 |
| | — |
| | 29 |
|
| Changes in nuclear decommissioning trust liability | 24 |
| | — |
| | — |
| | — |
| | 24 |
|
| Changes in derivative instruments | (173 | ) | | 206 |
| | (3 | ) | | — |
| | 30 |
|
| Changes in collateral posted supporting energy risk management activities | 268 |
| | (7 | ) | | — |
| | — |
| | 261 |
|
| Proceeds from sale of emission allowances | 11 |
| | — |
| | — |
| | — |
| | 11 |
|
| Loss on sale of assets | — |
| | — |
| | 70 |
| | — |
| | 70 |
|
| Cash (used)/provided by changes in other working capital | (827 | ) | | 168 |
| | (200 | ) | | 729 |
| | (130 | ) |
| Net cash provided by continuing operations | 201 |
| | 1,000 |
|
| 473 |
|
| — |
| | 1,674 |
|
| Cash provided by discontinued operations | — |
| | 67 |
| | — |
| | — |
| | 67 |
|
| Net Cash Provided by Operating Activities | 201 |
| | 1,067 |
| | 473 |
| | — |
| | 1,741 |
|
| Cash Flows from Investing Activities | | | | | | | | | |
| Dividends from NRG Yield, Inc. | — |
| | — |
| | 59 |
| | (59 | ) | | — |
|
| Acquisition of September 2016 Drop Down assets, net of cash acquired | — |
| | (77 | ) | | — |
| | 77 |
| | — |
|
| Intercompany dividends | — |
| | — |
| | 12 |
| | (12 | ) | | — |
|
| Acquisition of businesses, net of cash acquired | — |
| | (18 | ) | | — |
| | — |
| | (18 | ) |
| Capital expenditures | (145 | ) | | (474 | ) | | (40 | ) | | — |
| | (659 | ) |
| Increase in notes receivable | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Purchases of emission allowances | (32 | ) | | — |
| | — |
| | — |
| | (32 | ) |
| Proceeds from sale of emission allowances | 47 |
| | — |
| | — |
| | — |
| | 47 |
|
| Investments in nuclear decommissioning trust fund securities | (378 | ) | | — |
| | — |
| | — |
| | (378 | ) |
| Proceeds from sales of nuclear decommissioning trust fund securities | 354 |
| | — |
| | — |
| | — |
| | 354 |
|
| Proceeds from renewable energy grants and state rebates | — |
| | 11 |
| | — |
| | — |
| | 11 |
|
| Proceeds from sale of assets, net of cash disposed of | — |
| | 67 |
| | 17 |
| | — |
| | 84 |
|
| Investments in unconsolidated affiliates | 2 |
| | (25 | ) | | — |
| | — |
| | (23 | ) |
| Other | 27 |
| | (4 | ) | | 8 |
| | — |
| | 31 |
|
| Net cash (used)/provided by continuing operations | (125 | ) | | (518 | ) | | 56 |
|
| 6 |
| | (581 | ) |
| Cash provided by discontinued operations | — |
| | 326 |
| | — |
| | — |
| | 326 |
|
| Net Cash (Used)/Provided by Investing Activities | (125 | ) | | (192 | ) | | 56 |
| | 6 |
| | (255 | ) |
| Cash Flows from Financing Activities | | | | | | | | | |
| Dividends from NRG Yield, Inc. | — |
| | (59 | ) | | — |
| | 59 |
| | — |
|
| Payments (for)/from intercompany loans | (2 | ) | | (134 | ) | | 136 |
| | — |
| | — |
|
| Acquisition of September 2016 Drop Down assets, net of cash acquired | — |
| | — |
| | 77 |
| | (77 | ) | | — |
|
| Intercompany dividends | (52 | ) | | 40 |
| | — |
| | 12 |
| | — |
|
| Payment of dividends to common and preferred stockholders | — |
| | — |
| | (66 | ) | | — |
| | (66 | ) |
| Payment for preferred shares | — |
| | — |
| | (226 | ) | | — |
| | (226 | ) |
| Net receipts for settlement of acquired derivatives that include financing elements | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Proceeds from issuance of long-term debt | — |
| | 1,097 |
| | 4,140 |
| | — |
| | 5,237 |
|
| Payments for short and long-term debt | (2 | ) | | (811 | ) | | (4,540 | ) | | — |
| | (5,353 | ) |
| Payments for debt extinguishment costs | — |
| | (98 | ) | | — |
| | — |
| | (98 | ) |
| Distributions from, net of contributions to, noncontrolling interest in subsidiaries | — |
| | (127 | ) | | — |
| | — |
| | (127 | ) |
| Proceeds from issuance of common stock | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Payment of debt issuance costs | — |
| | (17 | ) | | (53 | ) | | — |
| | (70 | ) |
| Other | (3 | ) | | (7 | ) | | — |
| | — |
| | (10 | ) |
| Net cash used by continuing operations | (59 | ) | | (110 | ) | | (531 | ) | | (6 | ) | | (706 | ) |
| Cash provided by discontinued operations | — |
| | 119 |
| | — |
| | — |
| | 119 |
|
| Net Cash (Used)/Provided by Financing Activities | (59 | ) | | 9 |
| | (531 | ) | | (6 | ) | | (587 | ) |
| Change in cash from discontinued operations | — |
| | 512 |
| | — |
| | — |
| | 512 |
|
| Effect of exchange rate changes on cash and cash equivalents | — |
| | (6 | ) | | — |
| | — |
| | (6 | ) |
| Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties | 17 |
| | 366 |
| | (2 | ) | | — |
| | 381 |
|
| Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period | — |
| | 629 |
| | 693 |
| | — |
| | 1,322 |
|
| Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period | $ | 17 |
| | $ | 995 |
| | $ | 691 |
| | $ | — |
| | $ | 1,703 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Cash Flows from Operating Activities | | | | | | | | | |
| Net income | $ | 346 |
| | $ | 148 |
| | $ | 295 |
| | $ | (556 | ) | | $ | 233 |
|
| Adjustments to reconcile net income to net cash provided/(used) by operating activities: | | | | | | | | |
|
| Distributions from unconsolidated affiliates | — |
| | 13 |
| | — |
| | (3 | ) | | 10 |
|
| Equity in losses of unconsolidated affiliates | — |
| | 1 |
| | 1 |
| | — |
| | 2 |
|
| Depreciation and amortization | 73 |
| | 154 |
| | 8 |
| | — |
| | 235 |
|
| Provision for bad debts | 17 |
| | (2 | ) | | — |
| | — |
| | 15 |
|
| Amortization of nuclear fuel | 13 |
| | — |
| | — |
| | — |
| | 13 |
|
| Amortization of financing costs and debt discount/premiums | — |
| | 10 |
| | 4 |
| | — |
| | 14 |
|
| Adjustment for debt extinguishment | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| Amortization of intangibles and out-of-market contracts | 3 |
| | 19 |
| | — |
| | — |
| | 22 |
|
| Amortization of unearned equity compensation | — |
| | — |
| | 13 |
| | — |
| | 13 |
|
| Changes in deferred income taxes and liability for uncertain tax benefits | 114 |
| | 27 |
| | (144 | ) | | — |
| | (3 | ) |
| Changes in nuclear decommissioning trust liability | 34 |
| | — |
| | — |
| | — |
| | 34 |
|
| Changes in derivative instruments | 5 |
| | (220 | ) | | (14 | ) | | (18 | ) | | (247 | ) |
| Changes in collateral deposits in support of energy risk management activities | 162 |
| | 1 |
| | — |
| | — |
| | 163 |
|
| Gain on sale of emission allowances | (8 | ) | | — |
| | — |
| | — |
| | (8 | ) |
| (Gain)/loss on sale of assets | (3 | ) | | 1 |
| | — |
| | — |
| | (2 | ) |
| Changes in other working capital | (442 | ) | | 22 |
| | (296 | ) | | 577 |
| | (139 | ) |
| Net Cash Provided/(Used) by Operating Activities | 314 |
| | 174 |
| | (131 | ) | | — |
| | 357 |
|
| Cash Flows from Investing Activities | | | | | | | | | |
|
| Dividends from NRG Yield, Inc. | — |
| | — |
| | 25 |
| | (25 | ) | | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | (42 | ) | | — |
| | 42 |
| | — |
|
| Acquisition of business, net of cash acquired | (2 | ) | | (60 | ) | | — |
| | — |
| | (62 | ) |
| Capital expenditures | (61 | ) | | (276 | ) | | (21 | ) | | — |
| | (358 | ) |
| Decrease in notes receivable | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Purchases of emission allowances | (17 | ) | | — |
| | — |
| | — |
| | (17 | ) |
| Proceeds from sale of emission allowances | 23 |
| | — |
| | — |
| | — |
| | 23 |
|
| Investments in nuclear decommissioning trust fund securities | (216 | ) | | — |
| | — |
| | — |
| | (216 | ) |
| Proceeds from the sale of nuclear decommissioning trust fund securities | 182 |
| | — |
| | — |
| | — |
| | 182 |
|
| Proceeds from sale of assets, net of cash disposed of | 10 |
| | 1 |
| | — |
| | — |
| | 11 |
|
| Change in investments in unconsolidated affiliates | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Net Cash (Used)/Provided by Investing Activities | (81 | ) | | (372 | ) | | 4 |
| | 17 |
| | (432 | ) |
| Cash Flows from Financing Activities |
|
| | |
| | |
| | | | |
| Dividends from NRG Yield, Inc. | — |
| | (25 | ) | | — |
| | 25 |
| | — |
|
| Payment from/(for) intercompany loans | 18 |
| | 80 |
| | (98 | ) | | — |
| | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | — |
| | 42 |
| | (42 | ) | | — |
|
| Payment of dividends to common and preferred stockholders | — |
| | — |
| | (10 | ) | | — |
| | (10 | ) |
| Payment for treasury stock | — |
| | — |
| | (93 | ) | | — |
| | (93 | ) |
| Proceeds from issuance of long-term debt | — |
| | 179 |
| | — |
| | — |
| | 179 |
|
| Payments for short and long-term debt | — |
| | (222 | ) | | (6 | ) | | — |
| | (228 | ) |
| Contributions from, net of distributions to noncontrolling interests in subsidiaries | — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| Payment of debt issuance costs | — |
| | (6 | ) | | (1 | ) | | — |
| | (7 | ) |
| Net Cash Provided/(Used) by Financing Activities | 18 |
| | 116 |
| | (166 | ) | | (17 | ) | | (49 | ) |
| Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | 251 |
| | (82 | ) | | (293 | ) | | — |
| | (124 | ) |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 41 |
| | 852 |
| | 643 |
| | — |
| | 1,536 |
|
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 292 |
|
| $ | 770 |
|
| $ | 350 |
|
| $ | — |
| | $ | 1,412 |
|
| |
| (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, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated |
| | (In millions) |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 1,599 |
| | $ | 867 |
| | $ | — |
| | $ | (84 | ) | | $ | 2,382 |
|
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 1,260 |
| | 664 |
| | 18 |
| | (80 | ) | | 1,862 |
|
| Depreciation and amortization | 99 |
| | 150 |
| | 8 |
| | — |
| | 257 |
|
| Selling, general and administrative | 96 |
| | 46 |
| | 118 |
| | — |
| | 260 |
|
| Development costs | — |
| | 12 |
| | 5 |
| | — |
| | 17 |
|
| Total operating costs and expenses | 1,455 |
| | 872 |
| | 149 |
| | (80 | ) | | 2,396 |
|
| Other income - affiliate | — |
| | — |
| | 48 |
| | — |
| | 48 |
|
| Gain on sale of assets | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
| Operating Income/(Loss) | 146 |
| | (5 | ) | | (101 | ) | | (4 | ) | | 36 |
|
| Other (Expense)/Income | | | | | |
| | | | |
| Equity in (losses)/earnings of consolidated subsidiaries | (42 | ) | | 1 |
| | 68 |
| | (27 | ) | | — |
|
| Equity in (losses)/earnings of unconsolidated affiliates | (1 | ) | | 7 |
| | (1 | ) | | — |
| | 5 |
|
| Other (expense)/income, net | (2 | ) | | 5 |
| | 7 |
| | 3 |
| | 13 |
|
| Loss on debt extinguishment, net | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) |
| Interest expense | (4 | ) | | (104 | ) | | (117 | ) | | — |
| | (225 | ) |
| Total other expense | (49 | ) | | (93 | ) | | (43 | ) | | (24 | ) | | (209 | ) |
| Income/(Loss) from Continuing Operations Before Income Taxes | 97 |
| | (98 | ) | | (144 | ) | | (28 | ) | | (173 | ) |
| Income tax expense/(benefit) | 19 |
| | (46 | ) | | 25 |
| | (2 | ) | | (4 | ) |
| Income/(Loss) from Continuing Operations | 78 |
| | (52 | ) | | (169 | ) | | (26 | ) | | (169 | ) |
| (Loss)/income from discontinued operations, net of income tax | — |
| | (37 | ) | | 3 |
| | — |
| | (34 | ) |
| Net Income/(Loss) | 78 |
| | (89 | ) | | (166 | ) | | (26 | ) | | (203 | ) |
| Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest | — |
| | (38 | ) | | (3 | ) | | 1 |
| | (40 | ) |
| Net Income/(Loss) Attributable to NRG Energy, Inc. | $ | 78 |
| | $ | (51 | ) | | $ | (163 | ) | | $ | (27 | ) | | $ | (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) | $ | 78 |
| | $ | (89 | ) | | $ | (166 | ) | | $ | (26 | ) | | $ | (203 | ) |
| Other Comprehensive Income, 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) | 83 |
| | (79 | ) | | (156 | ) | | (40 | ) | | (192 | ) |
| Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest | — |
| | (37 | ) | | (3 | ) | | 1 |
| | (39 | ) |
| Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. | $ | 83 |
| | $ | (42 | ) | | $ | (153 | ) | | $ | (41 | ) | | $ | (153 | ) |
| |
| (a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2017
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations (a) | | Consolidated |
| ASSETS | (In millions) |
| Current Assets | | | | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | 348 |
| | $ | 643 |
| | $ | — |
| | $ | 991 |
|
| Funds deposited by counterparties | 37 |
| | — |
| | — |
| | — |
| | 37 |
|
| Restricted cash | 4 |
| | 504 |
| | — |
| | — |
| | 508 |
|
| Accounts receivable, net | 768 |
| | 307 |
| | 4 |
| | — |
| | 1,079 |
|
| Inventory | 338 |
| | 194 |
| | — |
| | — |
| | 532 |
|
| Derivative instruments | 625 |
| | 81 |
| | 9 |
| | (89 | ) | | 626 |
|
| Cash collateral paid in support of energy risk management activities | 170 |
| | 1 |
| | — |
| | — |
| | 171 |
|
| Accounts receivable - affiliate | 709 |
| | 213 |
| | (129 | ) | | (698 | ) | | 95 |
|
| Current assets held-for-sale | 8 |
| | 107 |
| | — |
| | — |
| | 115 |
|
| Prepayments and other current assets | 116 |
| | 118 |
| | 27 |
| | — |
| | 261 |
|
| Total current assets | 2,775 |
| | 1,873 |
| | 554 |
| | (787 | ) | | 4,415 |
|
| Property, plant and equipment, net | 2,502 |
| | 11,194 |
| | 238 |
| | (26 | ) | | 13,908 |
|
| Other Assets | | | | | | | | | |
| Investment in subsidiaries | 305 |
| | — |
| | 7,581 |
| | (7,886 | ) | | — |
|
| Equity investments in affiliates | — |
| | 1,036 |
| | 2 |
| | — |
| | 1,038 |
|
| Goodwill | 360 |
| | 179 |
| | — |
| | — |
| | 539 |
|
| Intangible assets, net | 454 |
| | 1,295 |
| | — |
| | (3 | ) | | 1,746 |
|
| Nuclear decommissioning trust fund | 692 |
| | — |
| | — |
| | — |
| | 692 |
|
| Derivative instruments | 121 |
| | 40 |
| | 31 |
| | (20 | ) | | 172 |
|
| Deferred income taxes | 377 |
| | (7 | ) | | (236 | ) | | — |
| | 134 |
|
| Non-current assets held for sale | — |
| | 43 |
| | — |
| | — |
| | 43 |
|
| Other non-current assets | 50 |
| | 461 |
| | 158 |
| | (38 | ) | | 631 |
|
| Total other assets | 2,359 |
| | 3,047 |
| | 7,536 |
| | (7,947 | ) | | 4,995 |
|
| Total Assets | $ | 7,636 |
| | $ | 16,114 |
| | $ | 8,328 |
| | $ | (8,760 | ) | | $ | 23,318 |
|
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | | |
| Current Liabilities | | | | | | | | | |
| Current portion of long-term debt and capital leases | $ | — |
| | $ | 667 |
| | $ | 59 |
| | $ | (38 | ) | | $ | 688 |
|
| Accounts payable | 545 |
| | 281 |
| | 55 |
| | — |
| | 881 |
|
| Accounts payable — affiliate | 751 |
| | (201 | ) | | 181 |
| | (698 | ) | | 33 |
|
| Derivative instruments | 535 |
| | 108 |
| | — |
| | (88 | ) | | 555 |
|
| Cash collateral received in support of energy risk management activities | 37 |
| | — |
| | — |
| | — |
| | 37 |
|
| Current liabilities held-for-sale | — |
| | 72 |
| | — |
| | — |
| | 72 |
|
| Accrued expenses and other current liabilities | 290 |
| | 175 |
| | 425 |
| | — |
| | 890 |
|
| Accrued expenses and other current liabilities - affiliate | — |
| | — |
| | 161 |
| | — |
| | 161 |
|
| Total current liabilities | 2,158 |
| | 1,102 |
| | 881 |
| | (824 | ) | | 3,317 |
|
| Other Liabilities | | | | | | | | | |
| Long-term debt and capital leases | 244 |
| | 8,733 |
| | 6,739 |
| | — |
| | 15,716 |
|
| Nuclear decommissioning reserve | 269 |
| | — |
| | — |
| | — |
| | 269 |
|
| Nuclear decommissioning trust liability | 415 |
| | — |
| | — |
| | — |
| | 415 |
|
| Deferred income taxes | 112 |
| | 64 |
| | (155 | ) | | — |
| | 21 |
|
| Derivative instruments | 110 |
| | 107 |
| | — |
| | (20 | ) | | 197 |
|
| Out-of-market contracts, net | 66 |
| | 141 |
| | — |
| | — |
| | 207 |
|
| Non-current liabilities held-for-sale | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Other non-current liabilities | 410 |
| | 321 |
| | 391 |
| | — |
| | 1,122 |
|
| Total non-current liabilities | 1,626 |
| | 9,374 |
| | 6,975 |
| | (20 | ) | | 17,955 |
|
| Total Liabilities | 3,784 |
| | 10,476 |
| | 7,856 |
| | (844 | ) | | 21,272 |
|
| Redeemable noncontrolling interest in subsidiaries | — |
| | 78 |
| | — |
| | — |
| | 78 |
|
| Stockholders’ Equity | 3,852 |
| | 5,560 |
| | 472 |
| | (7,916 | ) | | 1,968 |
|
| Total Liabilities and Stockholders’ Equity | $ | 7,636 |
| | $ | 16,114 |
| | $ | 8,328 |
|
| $ | (8,760 | ) | | $ | 23,318 |
|
| |
| (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) | $ | 78 |
| | $ | (89 | ) | | $ | (166 | ) | | $ | (26 | ) | | $ | (203 | ) |
| (Loss)/income from discontinued operations | — |
| | (37 | ) | | 3 |
| | — |
| | (34 | ) |
| Net income/(loss) from continuing operations | 78 |
| | (52 | ) | | (169 | ) | | (26 | ) | | (169 | ) |
| Adjustments to reconcile net income/(loss) to net cash (used)/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 | 99 |
| | 150 |
| | 8 |
| | — |
| | 257 |
|
| Provision for bad debts | 8 |
| | 1 |
| | — |
| | — |
| | 9 |
|
| Amortization of nuclear fuel | 12 |
| | — |
| | — |
| | — |
| | 12 |
|
| Amortization of financing costs and debt discount/premiums | — |
| | 11 |
| | 4 |
| | — |
| | 15 |
|
| Amortization of intangibles and out-of-market contracts | 6 |
| | 24 |
| | — |
| | — |
| | 30 |
|
| 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 | ) | | 43 |
| | (1 | ) | | — |
| | 38 |
|
| Changes in collateral deposits in support of energy risk management activities | (136 | ) | | 9 |
| | — |
| | — |
| | (127 | ) |
| Gain on sale of assets | (2 | ) | | — |
| | — |
| | — |
| | (2 | ) |
| Changes in other working capital | (118 | ) | | 458 |
| | (601 | ) | | 63 |
| | (198 | ) |
| Net cash (used)/provided by continuing operations | (1 | ) | | 609 |
|
| (722 | ) |
| 32 |
| | (82 | ) |
| Cash provided by discontinued operations | — |
| | 15 |
| | — |
| | — |
| | 15 |
|
| Net Cash (Used)/Provided by Operating Activities | (1 | ) | | 624 |
| | (722 | ) | | 32 |
| | (67 | ) |
| Cash Flows from Investing Activities | | | | | | | | | |
| Dividends from NRG Yield, Inc. | — |
| | — |
| | 22 |
| | (22 | ) | | — |
|
| Intercompany dividends | — |
| | — |
| | 129 |
| | (129 | ) | | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | (131 | ) | | — |
| | 131 |
| | — |
|
| Acquisition of businesses, net of cash acquired | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) |
| Capital expenditures | (64 | ) | | (168 | ) | | (4 | ) | | — |
| | (236 | ) |
| 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 the sale of nuclear decommissioning trust fund securities | 117 |
| | — |
| | — |
| | — |
| | 117 |
|
| Proceeds from sale of assets, net of cash disposed of | 11 |
| | 3 |
| | — |
| | — |
| | 14 |
|
| Change in investments in unconsolidated affiliates | — |
| | (12 | ) | | — |
| | — |
| | (12 | ) |
| Other | 18 |
| | — |
| | — |
| | — |
| | 18 |
|
| Net cash (used)/provided by continuing operations | (69 | ) | | (307 | ) | | 147 |
|
| (20 | ) | | (249 | ) |
| Cash used by discontinued operations | — |
| | (32 | ) | | — |
| | — |
| | (32 | ) |
| Net Cash (Used)/Provided by Investing Activities | (69 | ) | | (339 | ) | | 147 |
| | (20 | ) | | (281 | ) |
| Cash Flows from Financing Activities | | | | | | | | | |
| Dividends from NRG Yield, Inc. | — |
| | (22 | ) | | — |
| | 22 |
| | — |
|
| Payments (for)/from 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 | — |
| | 167 |
| | 26 |
| | — |
| | 193 |
|
| Payments for short and long-term debt | — |
| | (146 | ) | | (31 | ) | | — |
| | (177 | ) |
| Distributions to, net of contributions from, noncontrolling interests in subsidiaries | — |
| | (5 | ) | | — |
| | — |
| | (5 | ) |
| Payment of debt issuance costs | — |
| | (10 | ) | | (4 | ) | | — |
| | (14 | ) |
| Other - contingent consideration | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) |
| Net cash provided/(used) by continuing operations | 65 |
| | (582 | ) | | 508 |
| | (12 | ) | | (21 | ) |
| Cash used by discontinued operations | — |
| | (132 | ) | | — |
| | — |
| | (132 | ) |
| Net Cash Provided/(Used) by Financing Activities | 65 |
| | (714 | ) | | 508 |
| | (12 | ) | | (153 | ) |
| Effect of exchange rate changes on cash and cash equivalents | — |
| | (7 | ) | | — |
| | — |
| | (7 | ) |
| Change in cash from discontinued operations | — |
| | (149 | ) | | — |
| | — |
| | (149 | ) |
| Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | (5 | ) | | (287 | ) | | (67 | ) | | — |
| | (359 | ) |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 13 |
| | 1,050 |
| | 323 |
| | — |
| | 1,386 |
|
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 8 |
| | $ | 763 |
| | $ | 256 |
| | $ | — |
| | $ | 1,027 |
|
| |
| (a) | All significant intercompany transactions have been eliminated in consolidation. |
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, 2017March 31, 2018 and 20162017. Also refer to NRG's 20162017 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: Introduction and Overview section; NRG's Business Strategy section; Business section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.
The discussion and analysis below has been organized as follows:
Executive summary, including introduction and overview, business strategy, and changes to the business environment during the period, including environmental and regulatory matters;
Results of operations;
Financial condition, addressing liquidity position, sources and uses of liquidity, capital resources and requirements, commitments, and off-balance sheet arrangements; and
Known trends that may affect NRG's results of operations and financial condition in the future.
Executive Summary
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, is a leadingcustomer-driven integrated power company built on the strengtha portfolio of a diverse competitive electric generation portfolio and leading retail electricity platform.brands and diverse generation assets. NRG is continuously focused on excellence in operating performance of its existing assets and optimal hedging of generation assets and retail load operations, as well as serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels. The Company owns and operates approximately 30,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and Company:
directly sells energy services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant"“Reliant” and other retail brand names owned by NRG. NRG;
owns and operates approximately 30,000 MW of generation;
engages in the trading of wholesale energy, capacity and related products; and
transacts in and trades fuel and transportation services.
NRG was incorporated as a Delaware corporation on May 29, 1992.
The following table summarizes NRG's global generation portfolio as of September 30, 2017,March 31, 2018, by operating segment:
| | | | | Global Generation Portfolio(a)(b) | | Global Generation Portfolio(a) |
| | | (In MW) | | (In MW) |
| | | Generation | | | | | | | | | | Generation | | | | | | | | |
| Generation Type | | Gulf Coast | | East/West (c) | | Renewables(d) | | NRG Yield(e) | | Other(f) | | Total Global | | Gulf Coast(f)(i) | | East/West(b) | | Renewables(c)(g)(j) | | NRG Yield(d)(j) | | Other(e)(j) | | Total Global |
Natural gas(g)(f) | | 7,464 |
| | 4,939 |
| | — |
| | 1,878 |
| | — |
| | 14,281 |
| | 7,464 |
| | 4,878 |
| | — |
| | 1,878 |
| | — |
| | 14,220 |
|
| Coal | | 5,114 |
| | 3,869 |
| | — |
| | — |
| | — |
| | 8,983 |
| | 5,114 |
| | 3,871 |
| | — |
| | — |
| | — |
| | 8,985 |
|
| Oil | | — |
| | 3,642 |
| | — |
| | 190 |
| | — |
| | 3,832 |
| | — |
| | 3,641 |
| | — |
| | 190 |
| | — |
| | 3,831 |
|
| Nuclear | | 1,136 |
| | — |
| | — |
| | — |
| | — |
| | 1,136 |
| | 1,136 |
| | — |
| | — |
| | — |
| | — |
| | 1,136 |
|
Wind | | — |
| | — |
| | 743 |
| | 2,206 |
| | — |
| | 2,949 |
| | — |
| | — |
| | 739 |
| | 2,200 |
| | — |
| | 2,939 |
|
| Utility Scale Solar | | — |
| | — |
| | 742 |
| | 921 |
| | — |
| | 1,663 |
| | — |
| | — |
| | 738 |
| | 921 |
| | — |
| | 1,659 |
|
| Distributed Solar | | — |
| | — |
| | 175 |
| | 14 |
| | 114 |
| | 303 |
| | — |
| | — |
| | 182 |
| | 52 |
| | 114 |
| | 348 |
|
Total generation capacity(g)(h) | | 13,714 |
| | 12,450 |
| | 1,660 |
| | 5,209 |
| | 114 |
| | 33,147 |
| | 13,714 |
| | 12,390 |
| | 1,659 |
| | 5,241 |
| | 114 |
| | 33,118 |
|
Capacity attributable to noncontrolling interest(h) | | — |
| | — |
| | (684 | ) | | (2,342 | ) | | — |
| | (3,026 | ) | | — |
| | — |
| | (776 | ) | | (2,353 | ) | | — |
| | (3,129 | ) |
| Total net generation capacity | | 13,714 |
| | 12,450 |
| | 976 |
| | 2,867 |
| | 114 |
| | 30,121 |
| | 13,714 |
| | 12,390 |
| | 883 |
| | 2,888 |
| | 114 |
| | 29,989 |
|
(a) All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.
| |
(b) | GenOn, which represented 16,423 MW of global generation at December 31, 2016, was deconsolidated from NRG on June 14, 2017. |
(c) Includes International and BETM.
(d)(c) Includes Distributed Solar capacity from assets held by DGPV Holdco 1, DGPV Holdco 2, and DGPV Holdco 2.3.
(e)(d) Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.
(f)(e) The Distributed Solar figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco.
(g)(f) Natural gas generation does not include 51371 MW related to the Miramar and El Cajon sites which were part of the San Diego Combustion Turbines and retired on January 1, 2017, and 106 MW related to Encina Unit 1Greens Bayou 5 which was deactivated on March 31, 2017.retired in January 2018.
| |
| (g) | During the first quarter of 2018, NRG sold 10 MW to third parties related to the Minnesota wind assets. |
| |
| (h) | NRG Yield's total generation capacity includes 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's total generation capacity net of this noncontrolling interest was 5,203 MWs.5,247 MW. |
| |
| (i) | Includes the South Central business, which owns and operates a 3,555 MW portfolio of generation assets in Gulf Coast, and which the Company expects to sell as announced on February 6, 2018. NRG will lease back the 1,263 MW Cottonwood facility. |
| |
| (j) | Includes net MW for NRG Yield, Inc. of 2,888 MW and the Renewables operating and development platform of 467 MW, which the Company expects to sell as announced on February 6, 2018. |
GenOnStrategy
On June 14, 2017, GenOn, GenOn Americas GenerationNRG's strategy is to maximize stockholder value through the safe production and certainsale of their directly and indirectly-owned subsidiaries, all of which are subsidiaries of NRG, filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Codereliable power to its customers in the United States Bankruptcy Courtmarkets served by the Company, while positioning the Company to provide fully integrated solutions to the end-use energy consumer. This strategy is intended to enable the Company to create and maintain growth at reasonable margins while de-risking the Company in terms of reduced and mitigated exposure to cyclical commodity price risk. At the same time, the Company's relentless commitment to safety for the Southern District of Texas, Houston Division. As a result of the bankruptcy filingsits employees, customers and beginning on June 14, 2017, GenOn and its subsidiaries, representing approximately 15,000 MW, were deconsolidated from NRG’s consolidated financial statements.partners continues unabated.
To effectuate the Company’s strategy, NRG is focused on: (i) excellence in operating performance of its existing assets including repowering its power generation assets at premium sites and optimal hedging of generation assets and retail load operations; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) deploying innovative and renewable energy solutions for consumers within its retail businesses; and (iv) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management, including reducing consolidated debt and pursuing selective acquisitions, joint ventures, divestitures and investments.
Transformation Plan
On July 12, 2017, NRG announcedis in the process of executing its Transformation Plan, which is designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The Company expects to fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018. The three-part, three-year plan is comprised of the following targets:targets, and the Company's first quarter achievements towards such targets are as follows:
Operations and cost excellence — Cost savings and margin enhancement of $1,065 million recurring, which consists of $590 million of annualcumulative cost savings, a $215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales.
Portfolio optimization — Targeting up to $4.0$3.2 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG Yield, Inc. and its renewables platform.
In 2017, NRG executed asset sales of 322 MW for aggregate cash of $150 million, which includes sales to NRG Yield, Inc. and the sale of Minnesota wind projects to third parties.
On February 6, 2018, NRG announced agreements to sell (i) NRG's full ownership interest in NRG Yield, Inc. and NRG's renewables platform, a 3,440 MW portfolio, for cash of $1.375 billion, subject to certain adjustments; and (ii) NRG's South Central business, a 3,555 MW portfolio of generation assets, for cash of $1.0 billion, subject to certain adjustments. The transactions are subject to customary closing conditions and are expected to close in the second half of 2018.
On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of the membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, a 527-MW natural gas-fired project in Carlsbad, CA, pursuant to the ROFO Agreement. The purchase price for the transaction is $365 million in cash consideration, subject to customary working capital and other adjustments.
On February 23, 2018, NRG entered into an agreement to sell BETM for $70 million. The transaction is subject to customary closing conditions and is expected to close in the second half of 2018.
On March 30, 2018, the Company completed the sale of 100% of its ownership interest in Buckthorn Solar to NRG Yield, Inc. for cash consideration of approximately $42 million.
Capital structure and allocation enhancements — A prioritized capital allocation strategy that targets a reduction in consolidated debt from approximately $19.5 billion ($18 billion net debt) to approximately $6.5 billion ($6 billion net debt). Following the completion of the contemplated asset sales, the Company expects $4.8-$6.3 billion in excess cash to be available for allocation through 2020, after achievingachieve its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio.
Expected reduction in non-recourse debt related to the sale of NRG's ownership in NRG Yield, Inc. and the NRG renewables platform and the sales of Carlsbad Energy Center and Buckthorn Solar.
The Company expectsWorking Capital and Costs to fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018. Achieve —The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and (ii) approximately $290 million, one-time costs to achieve.
Since the inception of the Transformation Plan, NRG has realized $242 million of non-recurring working capital improvements and $83 million of one-time costs to achieve.
Regulatory Matters
The Company’s regulatory matters are described in the Company’s 20162017 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 16,15, Regulatory Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q as found in Item 1.
As owners of power plants and participants in wholesale and retail energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC, and the PUCT, as well as other public utility commissions in certain states where NRG's generating, thermal, or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.
NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to NRG's ownership interest in STP.
Federal Energy Regulation
Department of Energy's Proposed Grid Resiliency Pricing Rule and Subsequent FERC Proceeding — On September 29, 2017, the Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking proposed that FERC take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner compatible with robust competitive markets. On January 8, 2018, FERC terminated the proposed rulemaking and opened a new proceeding asking each ISO/RTO to address specific questions focused on grid resilience. On March 9, 2018, the ISOs/RTOs filed comments to the questions posed by FERC.
East RegionState Energy Regulation
State Out-Of-Market Subsidy Proposals — On April 12, 2018, the New Jersey State Legislature passed a bill to provide out-of-market subsidies to the state’s nuclear plants. The bill has not yet been signed by the New Jersey Governor. In addition, Certain other states in the areas of the country in which NRG operates, including Ohio and Pennsylvania, have considered but have not enacted proposals to provide out-of-market subsidy payments to potentially uneconomic nuclear and fossil generating units. NRG has opposed efforts to provide out-of-market subsidies, and intends to continue opposing them in the future.
Regional Regulatory Developments
NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 15, Regulatory Matters, to the Consolidated Financial Statements.
Gulf Coast
MISO
Revisions to MISO Capacity Construct — On February 28, 2018, FERC issued two orders on MISO’s capacity market design, which together, re-affirm MISO’s existing capacity market structure. FERC also held that, even though there was a period of time between where MISO’s capacity market structure may not have just and reasonable, that FERC exercised its remedial authority not to rerun past auctions. On March 30, 2018, the Company filed a motion for rehearing with FERC. The eventual outcome of this proceeding will affect capacity prices in MISO and the incentive for generators in MISO to sell capacity into neighboring markets.
East/West
PJM
Minimum Offer Price Rule Exemption AppealCapacity Market Reforms Filing — On July 7, 2017,April 9, 2018, PJM filed with FERC two capacity market reform proposals in one filing attempting to address market impacts created by out-of-market subsidies.PJM proposed a capacity re-pricing proposal as its preferred option to accommodate state subsidies in the D.C. Circuit vacated a FERC order from 2013 relatedwholesale market. In the alternative, PJM proposes extending its MOPR to existing resources, along with other changes. The outcome of this proceeding will potentially affect future capacity market prices.
PJM Seasonal Capacity Proceeding — On November 17, 2016, PJM proposed to allow winter- and summer-peaking capacity resources to “aggregate” their seasonal capacity into an exemptionannual capacity product eligible to participate as Capacity Performance resources. NRG filed comments specifically supporting PJM’s proposal to modify the Minimum Offer Price Rule, or MOPR,aggregation rules to allow seasonal capacity resources to aggregate across LDAs and remandedto allow aggregations through RPM auctions, but opposing the issue backmove to FERC.seasonal capacity. On OctoberJanuary 23, 2017, PJM re-filedamended its initial 2012 MOPR. FERC's rulingproposal to address questions from FERC. On March 21, 2017, FERC issued a decision accepting PJM's seasonal capacity aggregation filing pursuant to FERC staff's delegated authority, since FERC did not have a quorum at the time. On February 23, 2018, FERC re-affirmed its prior order. On February 23, 2018, FERC accepted PJM's filing and dismissed the requests for clarification. The outcome of this proceeding could have a material impact on PJM's renewed proposal could affect how generators participate in thefuture PJM Base Residual Auction.capacity prices.
2020/2021 PJM Auction ResultsComplaints Related to Extension of Base Capacity — On May 23, 2017, PJM announcedIn 2015, FERC approved changes to PJM’s capacity market, which included moving from the results of its 2020/2021 base residual auction. NRG, excluding GenOn, cleared approximately 3,992 MW ofBase Capacity product to the higher performance Capacity Performance product. NRG’s expected capacity revenues, excluding GenOn, fromproduct over the base residual auctioncourse of a five year transition. Under this transition, as of the May 2017 BRA, the Base Capacity product will no longer be available. Several parties have filed complaints at FERC seeking to maintain the RPM Base Capacity product for the 2020/2021at least one more delivery year are approximately $268 million. For results of the 2019/2020or until such time as PJM base residual auction, referdevelops a model for seasonal resources to Item 1 - Business of the 2016 Form 10-K.
The table below providesparticipate. On February 23, 2018, FERC issued an Order scheduling a detailed description of NRG’s 2020/2021 base residual auction result:
|
| | | |
| | Capacity Performance Product |
| Zone | Cleared Capacity (MW)(a) | | Price ($/MW-day) |
| COMED | 3,315 | | $188.12 |
| EMAAC | 519 | | $187.87 |
| MAAC | 158 | | $86.04 |
| Total | 3,992 | | |
(a) Includes imports. Does not include capacity sold by NRG Curtailment Specialists.technical conference. Multiple parties filed for rehearing. On March 16, 2018, FERC issued a notice for technical conference that took place on April 24, 2018.
New England
2020/2021 Massachusetts Attorney General Report on the Retail Electric Market — On March 29, 2018, Massachusetts Attorney General Maura Healey released a study of the retail electric market titled “Are Consumers Benefitting from Competition: An Analysis of the Individual Residential Electricity Supply Market in Massachusetts.” The report compared retail electric supply prices with Basic Service rates charged by local distribution companies over a two year period from July 2015 to July 2017 and concluded that customers taking supply from the retail market paid more than if they remained on Basic Service. The Massachusetts Legislature is currently considering the Attorney General's report.
ISO-NE Auction ResultsRetention of Mystic Units — ISO-NE recently announced that it had denied delist bids submitted by two of the three Mystic generating units attached to the DistriGas LNG terminal outside of Boston, citing local reliability concerns. Subsequently, ISO-NE announced its intent to retain the Mystic units in future auctions through an out-of-market payment, citing “fuel security” concerns. On May 1, 2018, ISO-NE filed with FERC to allow it to retain the Mystic units. ISO-NE has also stated that it intends to start a new stakeholder process to consider the pricing impacts of the units retained for fuel security at a later date. Retention of resources through out-of-market mechanisms will suppress future prices in the Forward Capacity Market.
Competitive Auctions with Sponsored Resources Proposal (CASPR) —On January 8, 2018, ISO-NE filed the CASPR proposal which attempts to accommodate state sponsored resources while maintaining competitive market pricing. On January 29, 2018, NRG protested certain aspects of the proposal and also supported ISO-NE’s beginning attempts to address state sponsored resources entering the capacity market. On March 9, 2018, FERC accepted ISO-NE's proposal. On April 9, 2018, NRG joined another generator in filing a request for rehearing. The rehearing is pending at FERC. The outcome of this proceeding will potentially affect future capacity market prices.
Renewable Technology Resource (RTR) Exemption —In 2014, FERC approved a package of revisions that included a renewables exemption called the RTR Exemption. After FERC denied rehearing, the case was appealed to the D.C. Circuit. After a voluntary remand motion, the Court remanded the case back to FERC. In 2016, FERC issued an order reaffirming its decision. In 2017, a group of generators, including NRG, filed a petition for review with the D.C. Circuit. Briefing is complete. The D.C. Circuit heard oral argument on April 13, 2018.
Northern Pass Siting Application — On February 6, 2017, ISO-NE announced1, 2018, the results of its 2020/2021 forward capacity auction. NRG cleared 2,641 MW at $5.297 KW per month providing expected annual capacity revenues of $167.9 million. The 333 MWs at Canal Unit 3, which previously clearedNew Hampshire Site Evaluation Committee denied the tenth forward capacity auctionapplication for Northern Pass Transmission to cross the state with a seven year price lock at160-mile transmission line from Quebec into southern New Hampshire. The Northern Pass transmission line project had previously been awarded a pricecontract by the State of $7.03 KW per monthMassachusetts, which is now in doubt. The addition of 1,000 MW of additional Canadian hydropower associated with Northern Pass would have affected energy and capacity prices. On February 28, 2018, Northern Pass Transmission filed a motion for rehearing. On March 13, 2018, the 2020/2021 deliverability year, are excluded from these results.New Hampshire Site Evaluation Committee suspended the request for rehearing pending a written decision on the project's full application.
Peak Energy Rent Adjustment Complaint — On September 30, 2016, the New England Power Generators Association, or NEPGA, filed a complaint against ISO-NE asking FERC to find the Peak Energy Rent, or PER, unjust and unreasonable. The PER adjustment reduces capacity payments on days where energy prices exceed a pre-defined level, known as the "PER strike price." On January 9, 2017, FERC granted NEPGA’s complaint requiring a change to the methodology used to calculate the PER strike price. FERC also directed the parties to determine any refunds for PER paid between September 30, 2016 and May 31, 2018. On July 26, 2017, NEPGA filed settlement documents at FERC, which NRG supported. TheOn February 20, 2018, FERC accepted the settlement is pending at FERC. The outcome of this matter will determine the amount of refunds that the NRG fleet may receive asand directed ISO-NE to submit a result of negotiatingcompliance filing setting out the PER strike price methodology.calculation. On March 22, 2018, ISO-NE submitted its compliance filing.
New York
Independent Power Producers of New York (IPPNY) Complaint — On January 9, 2017, EPSA requested FERC to promptly direct the NYISO to file tariff provisions to address pending market concerns related to out-of-market payments to existing generation in the NYISO. This request was prompted by the ZEC program initiated by the NYSPSC. This request follows IPPNY’s complaint at FERC against the NYISO on May 10, 2013, as amended on March 25, 2014. On April 5, 2018, EPSA filed a motion for renewed request for expedited action on the MOPR. The generators asked FERC to direct the NYISO to require that capacity from existing generation resources that would have exited the market but for out-of-market payments be mitigated. Failure to implement buyer-side mitigation measures could result in uneconomic entry, which artificially decreases capacity prices below competitive market levels.
New York Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued what it refers to as its “Retail Reset” order, or Reset Order, in docketDocket 12-M-0476 et al.al. Among other things, the Reset Order placed a price cap on energy supply offers and required many retail providers to seek affirmative consent from certain retail customers. Various parties have challenged the NYPSC’s abilityauthority to regulate ratesprices charged by competitive suppliers in New York state court. On March 29, 2018, the New York State Court of Appeals granted a motion by the Retail Energy Supply Association and National Energy Marketers Association for leave to appeal an earlier adverse Appellate Division ruling. In conjunction with the court challenges, the NYPSC is scheduled to commencenoticed both an evidentiary proceeding onand a collaborative track to address the functioning of the competitive retail marketsmarkets. An administrative hearing on November 29, 2017.the evidentiary track concluded on December 12, 2017 after 10 days of testimony and is now in the post-hearing brief phase. The outcome of thisthe evidentiary and collaborative process,processes, combined with the outcome of the appeal of the Appellate Division order,Reset Order, could affect the viability of the New York retail energy market.
General
State Out-Of-Market Subsidy Proposals — Certain states including Connecticut, New Jersey, Ohio and Pennsylvania have considered but have not enacted proposals to provide out-of-market subsidy payments to potentially uneconomic nuclear and fossil generating units. NRG has opposed those efforts to provide out of market subsidies, and intends to continue opposing them in the future.
West Region
CAISO
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months. A hearingmonths, which was granted on theNovember 3, 2017. On April 20, 2018, NRG filed a motion was held on October 31, 2017, after which the CEC took the matter under submission subject to a written decision to be issued atrequesting an unspecified later date. If the CEC Commissioners accept the recommendation, and formally deny a permit for the Puente Power Project, then the project will not move forward.
Nuclear Operations
Decommissioning Trusts — Upon expirationadditional extension of the operating licenses forsuspension period to coincide with the two generating units at STP, recently extendedCPUC’s final decision on SCE’s application seeking approval of resources procured through its Moorpark RFO, or until 2047 and 2048, respectively, the co-owners of STP are required under federal law to decontaminate and decommission the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioning obligations unless itJune 30, 2019, whichever is a rate-regulated utility, or a state or municipal entity that sets its own rates, or has the benefit of a state-mandated non-bypassable charge available to periodically fund the decommissioning trust such that the trust, plus allowable earnings, will equal the estimated decommissioning obligations by the time the decommissioning is expected to begin.sooner.
Environmental Matters
NRG is subject to a wide range ofnumerous 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 maintained during operation of power plants. NRG is also subject toFederal and state environmental laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. Requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered specieshistorically have been put in place in recent years. However, under the current U.S. presidential administration, some of these rules are being reconsidered and reviewed.become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on theour operations, of the Company's facilities, which could have a material effect onaffect the Company's operations. Complying with environmental laws often involves significant capital and operating expenses.expenses, as well as occasionally curtailing operations. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.
A number of regulations with the potential tothat may affect the Company and its facilities have been recently promulgatedare under review by the EPA, but are being reconsidered, including ESPS/NSPSESPS for GHGs, ash disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. NRG is evaluatingwill evaluate the potential outcomes and any resulting impactsimpact of recently promulgatedthese regulations that the EPA is now reconsidering andas they are revised but cannot fully predict such impactsthe impact of each until administrative reconsiderations andanticipated legal challenges are resolved. 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 current U.S. presidential administration. The Company’s environmental matters are described in the Company’s 20162017 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Item 1 — Note 17,16, Environmental Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q and as follows.
National
Air
The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO2, ozone, and PM2.5.PM2.5. Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have historically become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent NAAQSair regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economical. Significant changes to air regulatory programs affecting the Company are described below.economic.
Ozone NAAQS — On October 26, 2015, the EPA promulgated a rule that reduces the ozone NAAQS to 0.070 ppm. Challenges to this rule have been stayed at the request of the EPA so that it can evaluate the rule. If the rule is not altered by the EPA and survives legal challenges, this more stringent NAAQS will obligate the states to develop plans to reduce NOx (an ozone precursor), which could affect some of the Company's units.
Clean Power Plan — The attention in recent years on GHG emissions has resulted in federal regulations and state legislative and regulatory action. In October 2015, the EPA finalized the Clean Power Plan, or CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. The D.C. Circuit heard oral argument on the legal challenges to the CPP in September 2016. At the EPA's request, the D.C. Circuit agreed on April 28, 2017 to hold the case in abeyance. On October 16, 2017, the EPA proposed a rule to repeal the CPP. Accordingly, the Company believes the CPP is not likely to survive.
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. On September 13, 2017, the EPA granted the petition for reconsideration that the Utility Solid Waste Activities Group filed in May 2017. 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 September 30, 2017.March 31, 2018.
Water
Nuclear WasteClean Water Act —The Company is required under the CWA to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations have become more stringent and imposed new requirements.
Once Through Cooling Regulation — The federal government's programIn August 2014, EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998,address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the U.S. DOE has been in defaultnext 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, or FGD, fly ash, bottom ash, and flue gas mercury control. In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the federal government's obligationsdeadlines. On September 18, 2017, the EPA promulgated a final rule that (i) postpones the compliance dates to begin accepting spent nuclear fuel, or SNF,preserve the status quo for FGD wastewater and high-level radioactive waste, or HLW, underbottom ash transport water by two years to November 2020 until the U.S. Nuclear Waste Policy ActEPA completes its next rulemaking and (ii) withdrew the April 2017 administrative stay. The legal challenges have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company has largely eliminated its estimate of 1982, or the Nuclear Waste Policy Act. Owners of nuclear plants, including the owners of STP, hadenvironmental capital expenditures that would have been required to enter into contracts setting outcomply with permits incorporating the obligations ofrevised guidelines. The Company will revisit these estimates after the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services to license a spent fuel repository. Effective May 16, 2014, the U.S. DOE stopped collecting the fees.
On February 5, 2013, STPNOC entered into a settlement agreement with the U.S. DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and HLW under the Nuclear Waste Policy Act through December 31, 2013, which was extended through an addendum dated January 24, 2014, to December 31, 2016. On December 12, 2016, STPNOC received the federal government's offer of another three-year extension of payment for continued failure to accept SNF and HLW. The proposal has been reviewed for adequacy and, with advice of counsel, was accepted. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the U.S., nor has the NRC licensed any such facilities. STPNOC currently stores all SNF generated by its nuclear generating facilities in on-site storage pools. Since STPNOC's SNF storage pools do not have sufficient storage capacity for the life of the units, STPNOCrule is proceeding to construct dry cask storage capability on-site. STPNOC plans to continue to assert claims against the U.S. DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW.
Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. STP's warehouse capacity is adequate for on-site storage until a site in Andrews County, Texas becomes fully operational.revised.
Regional Environmental Developments
Gulf Coast Region
Texas Regional Haze — On October 17, 2017, the EPA promulgated a final rule creating a Texas-only SO2 cap-and-trade program to address regional haze. The program is scheduled to begin on January 1, 2019. Several of the Company's units in Texas will be affected by this rule.
East Region
Massachusetts Global Warming Solutions Act Proposed Regulation - In May 2016, the Massachusetts Supreme Judicial Court held that the Massachusetts DEP had not complied with the 2008 Global Warming Solutions Act, which requires establishing limits for sources of GHGs. The Court held that participation in RGGI was not sufficient. In August 2017, the Massachusetts DEP finalized a regulation that, if it survives legal challenges, would limit GHG emissions, and may limit operations, from electric generating facilities located in Massachusetts. The final regulationrule has been challenged by several environmental groups in The Commonwealththe Fifth Circuit of Massachusetts Superiorthe U.S. Court of Suffolk County.Appeals, which litigation has been stayed pending resolution of administrative petitions for reconsideration.
Significant Events
The following significant events have occurred during 2017,2018, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:
NRG Transformation Plan
On July 12, 2017, NRG announcedAs described above, the Company has continued to execute on its Transformation Plan. The three-part, three-year plan is comprised of targets in the areas of operational and cost excellence, portfolio optimization, and capital structure and allocation enhancement.
GenOn Chapter 11 Bankruptcy FilingRetail Acquisition
On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings and beginning on the Petition Date, NRG no longer consolidates GenOn for financial reporting purposes, as discussed in more detail in Note 1, Basis of Presentation, Note 3, Discontinued Operations, Dispositions and Acquisitions and Note 14, Related Party Transactionsof this Form 10-Q.
Transfers of Assets Under Common Control
On March 27, 2017,2018, the Company entered into an agreement to acquire XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for approximately $204 million in cash, plus estimated transaction costs of $6 million. The acquisition is expected to close in the second half of 2018.
Canal 3 Sale
On March 22, 2018, NRG completedagreed to sell Canal 3 to Stonepeak Kestrel Holdings II LLC in conjunction with GenOn's sale of Canal Units 1 and 2 to Stonepeak Kestrel Holdings LLC. The final purchase price for the Canal 3 sale will be determined based on a formula including capital reimbursement, return on capital and a development fee. Upon closing the sale of Canal 3, NRG also expects to reimburse GenOn for $13.5 million of the following projects$15 million one-time payment GenOn made in December 2017 to NRG Yield, Inc.: (i)as compensation for being granted a 16% interestpurchase option and a rejection option with respect to the Canal 3 project. The Canal 3 sale is expected to enhance 2018 capital allocation by approximately $130 million early in the Agua Caliente solar project, and (ii) NRG's interests in seven utility-scale solar projects located in Utah, which have reached commercial operations, for $130 million cash consideration, as discussed in more detail in Note 3, Discontinued Operations, Dispositions and Acquisitionsthird quarter of this Form 10-Q.2018.
On August 1, 2017, NRG closed on the sale of its remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million, including working capital adjustments. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027.
On October 17, 2017, the Company offered NRG Yield, Inc. the opportunity to purchase 100% of its ownership interest in Buckthorn Solar pursuant to the ROFO Agreement.
On November 1, 2017, NRG completed the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.
Financing Activities
On May 26, 2017, Carlsbad Energy Holdings, LLC entered intoMarch 21, 2018, the Company repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 1.75% and reducing the LIBOR floor to 0.00%. As a note payable agreement with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038, as discussed in more detail in Note 8, Debt and Capital Leases.
On June 12, 2017, NRG repaid $125 million on the Revolving Credit Facility. As of September 30, 2017, there were no cash borrowings outstanding on the revolver.
On October 16, 2017, NRG redeemed all of its outstanding 7.625% Senior Notes due 2018 and all of its outstanding 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest.
Operational Matters
Extreme Weather Events
In late August 2017, Hurricane Harvey made landfall on the Texas coast. During the third quarter of 2017, the Company’s Retail business was impacted by Hurricane Harvey by approximately $20 million.
In addition, during August 2017, NRG's Cottonwood generating station was damaged when the Sabine River Authority opened the floodgatesresult of the Toledo Bend reservoir, which resulted in downstream flooding of the Sabine River. The generating station was returned to service during the fourth quarter of 2017. NRG is continuing to work with insurers on potential property insurance recovery and does not anticipate recovery from business interruption insurance due to the short period of the outage. The Company estimates the impact of the Cottonwood damage and Hurricane Harvey on Gulf Coast Generation to be approximately $20 million.
Carlsbad Energy Center Power Purchase Tolling Agreement
As of May 1, 2017, NRG’s subsidiary, Carlsbad Energy Center LLC, achieved the Conditions Precedent, or CP, Satisfaction Date under its power purchase tolling agreement with San Diego Gas & Electric Company for the Carlsbad Energy Center. The CP Satisfaction Date is the date on which specified conditions precedent under the power purchase tolling agreement have either been satisfied or waived.
Bacliff Project
On June 16, 2017, the Company provided notice to BTEC New Albany, LLC that NRG Texas Power LLC was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.
Will County Unit 4
In May 2017, NRG's Will County Unit 4 suffered an equipment failure that is projected to result in an extended outage. At this time,repricing, the Company expects approximately $47 million in interest savings over the remaining life of the loan.
Share Repurchases
In February 2018, the Company's board of directors authorized the Company to complete repairs and returnrepurchase $1 billion of its common stock, with the unit to service in by early 2018.first $500 million program beginning as soon as permitted. In March 2018, the Company repurchased 3,114,748 shares of NRG common stock for approximately $93 million at an average cost of $29.75 per share.
Trends Affecting Results of Operations and Future Business Performance
In addition to below, theThe Company’s trends are described in the Company’s 20162017 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Trends Affecting Results of Operations and Future Business Performance,.and below.
ERCOT RetirementsPricing — A number of announced retirement notices of coal generating facilities in Texas could lower reserve margins in ERCOT. This trend of retirement notices couldERCOT forward prices for July and August 2018 are significantly higher than where previous summers have settled. These elevated pricing levels mean that deviations from expected demand and/or generation availability may have an effectexaggerated and material impact on the Company’s results of operations and future business performance, particularly in the ERCOT market.actual results.
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, to the Condensed Consolidated Financial Statements of this Form 10-Q, for a discussion of recent accounting developments.
Consolidated Results of Operations
The following table provides selected financial information for the Company:
| | | | Three months ended September 30, | | Nine months ended September 30, | Three months ended March 31, |
| (In millions except otherwise noted) | 2017 | | 2016 | | Change | | 2017 | | 2016 | | Change | 2018 | | 2017 | | Change |
| Operating Revenues | | | | | | | | | | | | | | | | |
| Retail revenue | | $ | 1,486 |
| | $ | 1,341 |
| | $ | 145 |
|
Energy revenue (a) | $ | 665 |
| | $ | 933 |
| | $ | (268 | ) | | $ | 1,908 |
| | $ | 2,478 |
| | $ | (570 | ) | 619 |
| | 587 |
| | 32 |
|
Capacity revenue (a) | 335 |
| | 303 |
| | 32 |
| | 894 |
| | 937 |
| | (43 | ) | 288 |
| | 262 |
| | 26 |
|
| Retail revenue | 1,934 |
|
| 2,015 |
| | (81 | ) | | 4,880 |
| | 4,931 |
| | (51 | ) | |
| Mark-to-market for economic hedging activities | 26 |
|
| 62 |
| | (36 | ) | | 185 |
| | (360 | ) | | 545 |
| (106 | ) |
| 118 |
| | (224 | ) |
| Contract amortization | (12 | ) | | (12 | ) | | — |
| | (41 | ) | | (41 | ) | | — |
| (14 | ) | | (15 | ) | | 1 |
|
Other revenues (b) | 101 |
| | 120 |
| | (19 | ) | | 306 |
| | 383 |
| | (77 | ) | 148 |
| | 89 |
| | 59 |
|
| Total operating revenues | 3,049 |
| | 3,421 |
| | (372 | ) | | 8,132 |
| | 8,328 |
| | (196 | ) | 2,421 |
| | 2,382 |
| | 39 |
|
| Operating Costs and Expenses | | | | | | | | | | | | | | | | |
Cost of sales (c) | 1,679 |
| | 1,847 |
| | 168 |
| | 4,362 |
| | 4,526 |
| | 164 |
| 1,391 |
| | 1,259 |
| | (132 | ) |
| Mark-to-market for economic hedging activities | 50 |
| | 149 |
| | 99 |
| | 168 |
| | (301 | ) | | (469 | ) | (302 | ) | | 137 |
| | 439 |
|
Contract and emissions credit amortization (c) | 8 |
| | 11 |
| | 3 |
| | 24 |
| | 34 |
| | 10 |
| 6 |
| | 7 |
| | 1 |
|
| Operations and maintenance | 326 |
| | 354 |
| | 28 |
| | 1,038 |
| | 1,196 |
| | 158 |
| 370 |
| | 371 |
| | 1 |
|
| Other cost of operations | 93 |
| | 79 |
| | (14 | ) | | 260 |
| | 256 |
| | (4 | ) | 93 |
| | 88 |
| | (5 | ) |
| Total cost of operations | 2,156 |
| | 2,440 |
| | 284 |
| | 5,852 |
| | 5,711 |
| | 141 |
| 1,558 |
| | 1,862 |
| | 304 |
|
| Depreciation and amortization | 272 |
| | 298 |
| | 26 |
| | 789 |
| | 826 |
| | 37 |
| 235 |
| | 257 |
| | 22 |
|
| Impairment losses | 14 |
| | 9 |
| | (5 | ) | | 77 |
| | 65 |
| | (12 | ) | |
| Selling, general and administrative | 213 |
| | 277 |
| | 64 |
| | 697 |
| | 801 |
| | 104 |
| 191 |
| | 260 |
| | 69 |
|
| Reorganization | 18 |
| | — |
| | (18 | ) | | 18 |
| | — |
| | (18 | ) | |
| Reorganization costs | | 20 |
| | — |
| | (20 | ) |
| Development costs | 14 |
| | 21 |
| | 7 |
| | 49 |
| | 65 |
| | 16 |
| 13 |
| | 17 |
| | 4 |
|
| Total operating costs and expenses | 2,687 |
| | 3,045 |
| | 358 |
| | 7,482 |
|
| 7,468 |
| | (14 | ) | 2,017 |
| | 2,396 |
| | 379 |
|
| Other income - affiliate | 14 |
| | 48 |
| | (34 | ) | | 104 |
| | 144 |
| | (40 | ) | — |
| | 48 |
| | (48 | ) |
| Gain/(loss) on sale of assets | — |
| | 4 |
| | (4 | ) | | 4 |
| | (79 | ) | | 83 |
| |
| Gain on sale of assets | | 2 |
| | 2 |
| | — |
|
| Operating Income | 376 |
| | 428 |
| | (52 | ) | | 758 |
| | 925 |
| | (167 | ) | 406 |
| | 36 |
| | 370 |
|
| Other Income/(Expense) | | | | | | | | | | | | | | | | |
| Equity in earnings of unconsolidated affiliates | 27 |
| | 16 |
| | 11 |
| | 29 |
| | 13 |
| | 16 |
| |
| Impairment loss on investment | — |
| | (8 | ) | | 8 |
| | — |
| | (147 | ) | | 147 |
| |
| Equity in (losses)/earnings of unconsolidated affiliates | | (2 | ) | | 5 |
| | (7 | ) |
| Other income, net | 15 |
| | 7 |
| | 8 |
| | 33 |
| | 29 |
| | 4 |
| (3 | ) | | 13 |
| | (16 | ) |
| Loss on debt extinguishment, net | (1 | ) | | (50 | ) | | 49 |
| | (3 | ) | | (119 | ) | | 116 |
| (2 | ) | | (2 | ) | | — |
|
| Interest expense | (221 | ) | | (237 | ) | | 16 |
| | (692 | ) | | (718 | ) | | 26 |
| (167 | ) | | (225 | ) | | 58 |
|
| Total other expense | (180 | ) | | (272 | ) | | 92 |
| | (633 | ) | | (942 | ) | | 309 |
| (174 | ) | | (209 | ) | | 35 |
|
| Income/(Loss) from Continuing Operations before Income Taxes | 196 |
| | 156 |
| | 40 |
| | 125 |
|
| (17 | ) | | 142 |
| 232 |
| | (173 | ) | | 405 |
|
| Income tax expense | 6 |
| | 28 |
| | (22 | ) | | 5 |
| | 75 |
| | (70 | ) | |
| Income tax benefit | | (1 | ) | | (4 | ) | | 3 |
|
| Income/(Loss) from Continuing Operations | 190 |
| | 128 |
| | 62 |
| | 120 |
| | (92 | ) | | 212 |
| 233 |
| | (169 | ) | | 402 |
|
| (Loss)/Income from discontinued operations, net of income tax | (27 | ) | | 265 |
| | (292 | ) | | (802 | ) | | 256 |
| | (1,058 | ) | |
| Loss from discontinued operations, net of income tax | | — |
| | (34 | ) | | 34 |
|
| Net Income/(Loss) | 163 |
| | 393 |
| | (230 | ) | | (682 | ) | | 164 |
| | (846 | ) | 233 |
| | (203 | ) | | 436 |
|
| Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest | (8 | ) | | (9 | ) | | 1 |
| | (63 | ) | | (49 | ) | | (14 | ) | (46 | ) | | (40 | ) | | (6 | ) |
| Net Income/(Loss) Attributable to NRG Energy, Inc. | $ | 171 |
| | $ | 402 |
| | $ | (231 | ) | | $ | (619 | ) | | $ | 213 |
| | $ | (832 | ) | $ | 279 |
| | $ | (163 | ) | | $ | 442 |
|
| Business Metrics | | | | |
|
| | | | | | | | | | |
|
|
| Average natural gas price — Henry Hub ($/MMBtu) | $ | 3.00 |
| | $ | 2.81 |
| | 7 | % | | $ | 3.17 |
| | $ | 2.29 |
| | 38 | % | $ | 3.00 |
| | $ | 3.32 |
| | (10 | )% |
(a) Includes realized gains and losses from financially settled transactions.
(b) Includes unrealized trading gains and losses.
(c) Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits.
Management’s discussion of the results of operations for the three months ended September 30,March 31, 2018 and 2017 and 2016
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended September 30, 2017March 31, 2018 and 2016.2017. The average on-peak power prices have generally decreasedincreased primarily due to the increase in natural gas prices for the three months ended September 30, 2017March 31, 2018 as compared to the same period in 2016.2017.
| | | | Average on Peak Power Price ($/MWh) | Average on Peak Power Price ($/MWh) |
| | Three months ended September 30, | Three months ended March 31, |
| Region | 2017 | | 2016 | | Change % | 2018 | | 2017 | | Change % |
Gulf Coast (a) | | | | | | | | | | |
ERCOT - Houston (b) | $ | 33.09 |
| | $ | 33.12 |
| | — | % | $ | 33.15 |
| | $ | 27.70 |
| | 20 | % |
ERCOT - North(b) | 29.35 |
| | 30.47 |
| | (4 | )% | 31.67 |
| | 22.76 |
| | 39 | % |
MISO - Louisiana Hub(c) | 39.56 |
| | 39.83 |
| | (1 | )% | 46.24 |
| | 44.66 |
| | 4 | % |
| East/West | | | | |
| | | | | |
NY J/NYC(c) | 37.42 |
| | 42.50 |
| | (12 | )% | 61.97 |
| | 35.61 |
| | 74 | % |
NEPOOL(c) | 31.94 |
| | 42.33 |
| | (25 | )% | 65.86 |
| | 33.81 |
| | 95 | % |
PEPCO (PJM)(c) | 38.81 |
| | 42.57 |
| | (9 | )% | |
COMED (PJM)(c) | | 33.21 |
| | 30.39 |
| | 9 | % |
PJM West Hub(c) | 35.10 |
| | 38.84 |
| | (10 | )% | 47.43 |
| | 32.02 |
| | 48 | % |
CAISO - NP15(c) | 46.69 |
| | 38.13 |
| | 22 | % | 32.73 |
| | 26.47 |
| | 24 | % |
CAISO - SP15(c) | 46.54 |
| | 40.24 |
| | 16 | % | 35.44 |
| | 23.01 |
| | 54 | % |
(a) Gulf Coast region also transacts in PJM - West Hub.
(b) Average on peak power prices based on real time settlement prices as published by the respective ISOs.
(c) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs.
The following table summarizes average realized power prices for each region in which NRG operates for the three months ended September 30,March 31, 2018 and 2017, and 2016, which reflects the impact of settled hedges.
| | | | Average Realized Power Price ($/MWh) | Average Realized Power Price ($/MWh) |
| | Three months ended September 30, | Three months ended March 31, |
| Region | 2017 | | 2016 | | Change % | 2018 | | 2017 | | Change % |
| Gulf Coast | $ | 34.69 |
| | $ | 39.68 |
| | (13 | )% | $ | 36.42 |
| | $ | 35.83 |
| | 2 | % |
| East/West | 38.19 |
| | 40.44 |
| | (6 | )% | 85.12 |
| | 74.58 |
| | 14 | % |
Though the average on peak power prices have decreasedincreased on average by 5%40%, average realized prices by region for the Company have generally fluctuated at a slower rate year-over-year due to the Company's multi-year hedging program.
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales.
Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.
The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2017March 31, 2018 and 2016:2017:
| | | | Three months ended September 30, 2017 | Three months ended March 31, 2018 |
| | Generation | | | | | | | | | | | | | Generation | | | | | | | | |
| (In millions) | Gulf Coast | | East/West(a) | | Subtotal | | Retail | | Renewables | | NRG Yield | | Corporate/Eliminations | | Total | Retail | | Gulf Coast | | East/West(a) | | Subtotal | | Renewables | | NRG Yield | | Corporate/Eliminations | | Total |
| Energy revenue | $ | 540 |
| | $ | 243 |
| | $ | 783 |
| | $ | — |
| | $ | 119 |
| | $ | 146 |
| | $ | (383 | ) | | $ | 665 |
| $ | — |
|
| $ | 371 |
|
| $ | 218 |
|
| $ | 589 |
|
| $ | 77 |
|
| $ | 114 |
|
| $ | (161 | ) |
| $ | 619 |
|
| Capacity revenue | 74 |
| | 172 |
| | 246 |
| | — |
| | 1 |
| | 92 |
| | (4 | ) | | 335 |
| — |
|
| 67 |
|
| 140 |
|
| 207 |
|
| — |
|
| 82 |
|
| (1 | ) |
| 288 |
|
| Retail revenue | — |
| | — |
| | — |
| | 1,936 |
| | — |
| | — |
| | (2 | ) | | 1,934 |
| 1,487 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| (1 | ) |
| 1,486 |
|
| Mark-to-market for economic hedging activities | 133 |
| | — |
| | 133 |
| | — |
| | 5 |
| | — |
| | (112 | ) | | 26 |
| (6 | ) |
| (564 | ) |
| (10 | ) |
| (574 | ) |
| (10 | ) |
| — |
|
| 484 |
|
| (106 | ) |
| Contract amortization | 5 |
| | — |
| | 5 |
| | 1 |
| | (1 | ) | | (18 | ) | | 1 |
| | (12 | ) | — |
|
| 3 |
|
| — |
|
| 3 |
|
| — |
|
| (17 | ) |
| — |
|
| (14 | ) |
Other revenue (b) | 41 |
| | 16 |
| | 57 |
| | — |
| | 20 |
| | 44 |
| | (20 | ) | | 101 |
| — |
|
| 86 |
|
| 16 |
|
| 102 |
|
| 19 |
|
| 46 |
|
| (19 | ) |
| 148 |
|
| Operating revenue | 793 |
| | 431 |
| | 1,224 |
| | 1,937 |
| | 144 |
| | 264 |
| | (520 | ) | | 3,049 |
| 1,481 |
|
| (37 | ) |
| 364 |
|
| 327 |
|
| 86 |
|
| 225 |
|
| 302 |
|
| 2,421 |
|
| Cost of fuel | (292 | ) | | (123 | ) | | (415 | ) | | (1 | ) | | (1 | ) | | (6 | ) | | 17 |
| | (406 | ) | (8 | ) |
| (193 | ) |
| (83 | ) |
| (276 | ) |
| (1 | ) |
| (15 | ) |
| (63 | ) |
| (363 | ) |
Other cost of sales(c) | (102 | ) | | (79 | ) | | (181 | ) | | (1,457 | ) | | (3 | ) | | (9 | ) | | 377 |
| | (1,273 | ) | (1,100 | ) |
| (79 | ) |
| (73 | ) |
| (152 | ) |
| (1 | ) |
| (5 | ) |
| 230 |
|
| (1,028 | ) |
| Mark-to-market for economic hedging activities | 2 |
| | 10 |
| | 12 |
| | (174 | ) | | — |
| | — |
| | 112 |
| | (50 | ) | 792 |
|
| (3 | ) |
| (3 | ) |
| (6 | ) |
| — |
|
| — |
|
| (484 | ) |
| 302 |
|
| Contract and emission credit amortization | (7 | ) | | (1 | ) | | (8 | ) | | — |
| | — |
| | — |
| | — |
| | (8 | ) | — |
|
| (6 | ) |
| — |
|
| (6 | ) |
| — |
|
| — |
|
| — |
|
| (6 | ) |
| Gross margin | $ | 394 |
| | $ | 238 |
| | $ | 632 |
| | $ | 305 |
| | $ | 140 |
| | $ | 249 |
| | $ | (14 | ) | | $ | 1,312 |
| $ | 1,165 |
|
| $ | (318 | ) |
| $ | 205 |
|
| $ | (113 | ) |
| $ | 84 |
|
| $ | 205 |
|
| $ | (15 | ) |
| $ | 1,326 |
|
| Less: Mark-to-market for economic hedging activities, net | 135 |
|
| 10 |
|
| 145 |
| | (174 | ) |
| 5 |
|
| — |
|
| — |
| | (24 | ) | 786 |
|
| (567 | ) |
| (13 | ) |
| (580 | ) |
| (10 | ) |
| — |
|
| — |
|
| 196 |
|
| Less: Contract and emission credit amortization, net | (2 | ) |
| (1 | ) |
| (3 | ) | | 1 |
|
| (1 | ) |
| (18 | ) |
| 1 |
| | (20 | ) | — |
|
| (3 | ) |
| — |
|
| (3 | ) |
| — |
|
| (17 | ) |
| — |
|
| (20 | ) |
| Economic gross margin | $ | 261 |
| | $ | 229 |
|
| $ | 490 |
|
| $ | 478 |
|
| $ | 136 |
|
| $ | 267 |
|
| $ | (15 | ) |
| $ | 1,356 |
| $ | 379 |
|
| $ | 252 |
|
| $ | 218 |
|
| $ | 470 |
|
| $ | 94 |
|
| $ | 222 |
|
| $ | (15 | ) |
| $ | 1,150 |
|
| Business Metrics | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
MWh sold (thousands)(d)(e) | 15,568 |
| | 6,363 |
| | | | | | 928 |
| | 1,544 |
| | | | | | | 11,238 |
| | 4,494 |
| | | | 1,015 |
| | 1,616 |
| | | | |
MWh generated (thousands) (f) | 14,185 |
| | 4,106 |
| | | | | | 928 |
| | 2,261 |
| | | | | | | 10,186 |
| | 2,561 |
| | | | 1,015 |
| | 1,616 |
| | | | |
(a) Includes International, BETM and Generation eliminations | | (b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield. | |
| (b) Renewables other revenue includes $13 million of intercompany revenue to NRG Yield. | | (b) Renewables other revenue includes $13 million of intercompany revenue to NRG Yield. |
(c) Includes purchased energy, capacity and emissions credits | (d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements. | | (e) Does not include thermal MWh of 9 thousand or MWt of 463 thousand for thermal sold by NRG Yield. | |
| (f) Does not include thermal MWh of 44 thousand or MWt of 463 thousand for thermal generated by NRG Yield. | |
| (e) Does not include thermal MWh of 9 thousand or MWt of 617 thousand for thermal sold by NRG Yield. | | (e) Does not include thermal MWh of 9 thousand or MWt of 617 thousand for thermal sold by NRG Yield. |
| (f) Does not include thermal MWh of 19 thousand or MWt of 617 thousand for thermal generated by NRG Yield. | | (f) Does not include thermal MWh of 19 thousand or MWt of 617 thousand for thermal generated by NRG Yield. |
| | | | Three months ended September 30, 2016 | Three months ended March 31, 2017 |
| | Generation | | | | | | | | | | | | | Generation | | | | | | | | |
| (In millions) | Gulf Coast | | East/West(a) | | Subtotal | | Retail | | Renewables | | NRG Yield | | Corporate/Eliminations | | Total | Retail | | Gulf Coast | | East/West(a) | | Subtotal | | Renewables | | NRG Yield | | Corporate/Eliminations | | Total |
| Energy revenue | $ | 650 |
| | $ | 362 |
| | $ | 1,012 |
| | $ | — |
| | $ | 127 |
| | $ | 158 |
|
| $ | (364 | ) | | $ | 933 |
| $ | — |
|
| $ | 383 |
|
| $ | 225 |
|
| $ | 608 |
|
| $ | 70 |
|
| $ | 116 |
|
| $ | (207 | ) |
| $ | 587 |
|
| Capacity revenue | 72 |
| | 148 |
| | 220 |
| | — |
| | — |
| | 86 |
| | (3 | ) | | 303 |
| — |
|
| 66 |
|
| 121 |
|
| 187 |
|
| — |
|
| 79 |
|
| (4 | ) |
| 262 |
|
| Retail revenue | — |
| | — |
| | — |
| | 2,009 |
| | — |
| | — |
| | 6 |
| | 2,015 |
| 1,334 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 7 |
|
| 1,341 |
|
| Mark-to-market for economic hedging activities | 179 |
| | 57 |
| | 236 |
| | 2 |
| | 1 |
| | — |
| | (177 | ) | | 62 |
| 2 |
|
| 131 |
|
| (9 | ) |
| 122 |
|
| 6 |
|
| — |
|
| (12 | ) |
| 118 |
|
| Contract amortization | 4 |
| | — |
| | 4 |
| | 1 |
| | (1 | ) | | (17 | ) | | 1 |
| | (12 | ) | (1 | ) |
| 3 |
|
| — |
|
| 3 |
|
| — |
|
| (17 | ) |
| — |
|
| (15 | ) |
Other revenue (b) | 51 |
| | 13 |
| | 64 |
| | — |
| | 12 |
| | 45 |
| | (1 | ) | | 120 |
| — |
|
| 46 |
|
| (1 | ) |
| 45 |
|
| 19 |
|
| 43 |
|
| (18 | ) |
| 89 |
|
| Operating revenue | 956 |
| | 580 |
| | 1,536 |
| | 2,012 |
| | 139 |
| | 272 |
| | (538 | ) | | 3,421 |
| 1,335 |
|
| 629 |
|
| 336 |
|
| 965 |
|
| 95 |
|
| 221 |
|
| (234 | ) |
| 2,382 |
|
| Cost of fuel | (317 | ) | | (190 | ) | | (507 | ) | | (1 | ) | | (2 | ) | | (7 | ) | | 18 |
| | (499 | ) | (5 | ) |
| (214 | ) |
| (87 | ) |
| (301 | ) |
| (1 | ) |
| (12 | ) |
| 26 |
|
| (293 | ) |
Other cost of sales(c) | (114 | ) | | (83 | ) | | (197 | ) | | (1,484 | ) | | (1 | ) | | (11 | ) | | 345 |
| | (1,348 | ) | (992 | ) |
| (78 | ) |
| (74 | ) |
| (152 | ) |
| (3 | ) |
| (4 | ) |
| 185 |
|
| (966 | ) |
| Mark-to-market for economic hedging activities | 27 |
| | 7 |
| | 34 |
| | (360 | ) | | — |
| | — |
| | 177 |
| | (149 | ) | (139 | ) |
| (10 | ) |
| — |
|
| (10 | ) |
| — |
|
| — |
|
| 12 |
|
| (137 | ) |
| Contract and emission credit amortization | (9 | ) | | — |
| | (9 | ) | | (2 | ) | | — |
| | — |
| | — |
| | (11 | ) | — |
|
| (6 | ) |
| (1 | ) |
| (7 | ) |
| — |
|
| — |
|
| — |
|
| (7 | ) |
| Gross margin | $ | 543 |
| | $ | 314 |
| | $ | 857 |
| | $ | 165 |
| | $ | 136 |
| | $ | 254 |
| | $ | 2 |
| | $ | 1,414 |
| $ | 199 |
|
| $ | 321 |
|
| $ | 174 |
|
| $ | 495 |
|
| $ | 91 |
|
| $ | 205 |
|
| $ | (11 | ) |
| $ | 979 |
|
| Less: Mark-to-market for economic hedging activities, net | 206 |
|
| 64 |
|
| 270 |
| | (358 | ) |
| 1 |
|
| — |
|
| — |
| | (87 | ) | (137 | ) |
| 121 |
|
| (9 | ) |
| 112 |
|
| 6 |
|
| — |
|
| — |
|
| (19 | ) |
| Less: Contract and emission credit amortization, net | (5 | ) |
| — |
|
| (5 | ) | | (1 | ) |
| (1 | ) |
| (17 | ) |
| 1 |
| | (23 | ) | (1 | ) |
| (3 | ) |
| (1 | ) |
| (4 | ) |
| — |
|
| (17 | ) |
| — |
|
| (22 | ) |
| Economic gross margin | $ | 342 |
| | $ | 250 |
| | $ | 592 |
| | $ | 524 |
| | $ | 136 |
| | $ | 271 |
| | $ | 1 |
| | $ | 1,524 |
| $ | 337 |
|
| $ | 203 |
|
| $ | 184 |
|
| $ | 387 |
|
| $ | 85 |
|
| $ | 222 |
|
| $ | (11 | ) |
| $ | 1,020 |
|
| Business Metrics | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
MWh sold (thousands)(d)(e) | 16,380 |
| | 8,951 |
| | | | | | 977 |
| | 1,744 |
| | | | | | | 11,383 |
| | 5,178 |
| | | | 915 |
| | 1,677 |
| | | | |
MWh generated (thousands) (f) | 14,927 |
| | 6,426 |
| | | | | | 977 |
| | 2,372 |
| | | | | | | 10,689 |
| | 3,017 |
| | | | 915 |
| | 1,677 |
| | | | |
(a) Includes International, BETM and Generation eliminations. | | (b) Renewables other revenue includes $5 million of intercompany revenue to NRG Yield. | |
| (b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield. | | (b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield. |
(c) Includes purchased energy, capacity and emissions credits | (d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements. | | (e) Does not include thermal MWh of 12 thousand or MWt of 496 thousand for thermal sold by NRG Yield. | |
| (f) Does not include thermal MWh of 125 thousand or MWt of 496 thousand for thermal generated by NRG Yield. | |
| (e) Does not include thermal MWh of 9 thousand or MWt of 569 thousand for thermal sold by NRG Yield. | | (e) Does not include thermal MWh of 9 thousand or MWt of 569 thousand for thermal sold by NRG Yield. |
| (f) Does not include thermal MWh of 32 thousand or MWt of 569 thousand for thermal generated by NRG Yield. | | (f) Does not include thermal MWh of 32 thousand or MWt of 569 thousand for thermal generated by NRG Yield. |
The table below represents the weather metrics for the three months ended September 30, 2017March 31, 2018 and 2016:2017: | | | | Three months ended September 30, | | Three months ended March 31, |
| Weather Metrics | Gulf Coast | | East/West | | Gulf Coast | | East/West |
| 2017 | | | | | | |
| 2018 | | | | |
CDDs (a) | 1,528 |
| | 770 |
| | 133 |
| | 18 |
|
HDDs (a) | 1 |
| | 34 |
| | | 1,034 |
| | 1,728 |
|
| 2016 | | | | | |
| 2017 | | | | |
| CDDs | 1,655 |
| | 806 |
| | | 204 |
| | 20 |
|
| HDDs | — |
| | 23 |
| | 1,086 |
| | 1,799 |
|
| 10 year average | | | | | | | | |
| CDDs | 1,617 |
| | 705 |
| | 93 |
| | 17 |
|
| HDDs | 6 |
| | 40 |
| | | 1,036 |
| | 1,776 |
|
| |
| (a) | National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Retail gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail.
|
| | | | | | | |
| | Three months ended March 31, |
| (In millions except otherwise noted) | 2018 | | 2017 |
| Retail revenue | $ | 1,446 |
| | $ | 1,295 |
|
| Supply management revenue | 33 |
| | 33 |
|
| Capacity revenue | 8 |
| | 6 |
|
| Customer mark-to-market | (6 | ) | | 2 |
|
| Contract amortization | — |
| | (1 | ) |
Operating revenue (a) | 1,481 |
| | 1,335 |
|
Cost of sales (b) | (1,108 | ) | | (997 | ) |
| Mark-to-market for economic hedging activities | 792 |
| | (139 | ) |
| Gross Margin | $ | 1,165 |
| | $ | 199 |
|
| Less: Mark-to-market for economic hedging activities, net | 786 |
| | (137 | ) |
| Less: Contract amortization, net | — |
| | (1 | ) |
| Economic Gross Margin | $ | 379 |
| | $ | 337 |
|
| | | | |
| Business Metrics | | | |
| Mass electricity sales volume — GWh - Gulf Coast | 7,943 |
| | 6,984 |
|
| Mass electricity sales volume — GWh - All other regions | 1,718 |
| | 1,641 |
|
| C&I electricity sales volume — GWh - All regions | 5,027 |
| | 4,833 |
|
| Natural gas sales volumes (MDth) | 2,175 |
| | 1,262 |
|
Average Retail Mass customer count (in thousands) | 2,878 |
| | 2,826 |
|
| Ending Retail Mass customer count (in thousands) | 2,878 |
| | 2,832 |
|
| |
| (a) | Includes intercompany sales of $1 million and $1 million in 2018 and 2017, respectively, representing sales from Retail to the Gulf Coast region. |
| |
| (b) | Includes intercompany purchases of $164 million and $209 million in 2018 and 2017, respectively. |
Retail gross margin increased $966 million and economic gross margin increased $42 million for the three months ended March 31, 2018, compared to the same period in 2017, due to:
|
| | | | |
| | | (In millions) |
| Higher gross margin due to higher revenue of $37 million, driven by customer product, term, and mix, offset by higher supply costs of $14 million driven primarily by an increase in power prices | | $ | 23 |
|
| Higher gross margin of $19 million due to an increase in load of 706,000 MWh driven by colder weather conditions in 2018 compared to 2017 | | 19 |
|
| Increase in economic gross margin | | $ | 42 |
|
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | | 923 |
|
| Increase in contract amortization | | 1 |
|
| Increase in gross margin | | $ | 966 |
|
Generation gross margin and economic gross margin
Generation gross margin decreased $225$608 million and economic gross margin decreased $102increased $83 million, both of which include intercompany sales, during the three months ended September 30, 2017,March 31, 2018, compared to the same period in 2016:2017:
The table below describes the decrease in Generation gross margin and the increase in economic gross margin:
Gulf Coast Region
|
| | | |
| | (In millions) |
| Lower gross margin due to a 12% decrease in average realized prices primarily in Texas due to lower hedged power prices | $ | (76 | ) |
| Lower energy margin due to increased supply cost on load contracts | (13 | ) |
| Lower capacity margin on contract expirations and lower demand | (9 | ) |
| Higher gross margin due to increased generation primarily due to lower unplanned outages | 16 |
|
| Other | 1 |
|
| Decrease in economic gross margin | $ | (81 | ) |
| Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | (71 | ) |
| Increase in contract and emission credit amortization | 3 |
|
| Decrease in gross margin | $ | (149 | ) |
East/West
|
| | | |
| | (In millions) |
| Lower gross margin due to a 37% decrease in generation driven by lower economic generation due to milder weather conditions and the Will County outage | $ | (28 | ) |
| Lower gross margin from commercial optimization activities | (8 | ) |
| Higher gross margin due to a 38% increase in PJM capacity volumes coupled with a 140% increase in NY/NE realized capacity prices | 21 |
|
| Higher gross margin due to a 12% increase in average realized energy prices due to extreme heat in California and increased pricing during high demand periods in the East | 10 |
|
| Lower gross margin by BETM due to higher gains in 2016 on over the counter strategies, offset in small part by higher gains in 2017 on congestion strategies | (16 | ) |
| Decrease in economic gross margin | $ | (21 | ) |
| Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | (54 | ) |
| Decrease in contract and emission credit amortization | (1 | ) |
| Decrease in gross margin | $ | (76 | ) |
Retail gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail.
|
| | | | | | | |
| | Three months ended September 30, |
| (In millions except otherwise noted) | 2017 | | 2016 |
| Retail revenue | $ | 1,845 |
| | $ | 1,911 |
|
| Supply management revenue | 63 |
| | 53 |
|
| Capacity revenue | 28 |
| | 45 |
|
| Customer mark-to-market | — |
| | 2 |
|
| Contract amortization | 1 |
| | 1 |
|
Operating revenue (a) | 1,937 |
| | 2,012 |
|
Cost of sales (b) | (1,458 | ) | | (1,485 | ) |
| Mark-to-market for economic hedging activities | (174 | ) | | (360 | ) |
| Contract amortization | — |
| | (2 | ) |
| Gross Margin | $ | 305 |
| | $ | 165 |
|
| Less: Mark-to-market for economic hedging activities, net | (174 | ) | | (358 | ) |
| Less: Contract and emission credit amortization, net | 1 |
| | (1 | ) |
| Economic Gross Margin | $ | 478 |
| | $ | 524 |
|
| | | | |
| Business Metrics | | | |
| Mass electricity sales volume - GWh - Gulf Coast | 11,935 |
| | 11,996 |
|
| Mass electricity sales volume - GWh - All other regions | 1,724 |
| | 1,986 |
|
| C&I electricity sales volume — GWh - All regions | 5,087 |
| | 5,146 |
|
| Natural gas sales volumes (MDth) | 241 |
| | 172 |
|
Average Retail Mass customer count (in thousands) | 2,884 |
| | 2,786 |
|
| Ending Retail Mass customer count (in thousands) | 2,880 |
| | 2,797 |
|
| |
(a) | Includes intercompany sales of $2 million and $1 million in 2017 and 2016, respectively, representing sales from Retail to the Gulf Coast region. |
| |
(b) | Includes intercompany purchases of $365 million and $340 million in 2017 and 2016, respectively. |
Retail gross margin increased $140 million and economic gross margin decreased $46 million for the three months ended September 30, 2017, compared to the same period in 2016, due to:
|
| | | |
| | (In millions) |
| Lower gross margin due to lower rates to customers driven by customer product, term, and mix of $26 million or approximately $1.25 per MWh and higher supply costs of $10 million or approximately $0.50 per MWh driven primarily by an increase in power prices at the time of procurement | $ | (36 | ) |
| Lower gross margin of $15 million due to a reduction in load of 477,000 MWh partially offset by $4 million in higher margin due to the lower unfavorable impacts of selling back excess supply due to milder weather conditions in 2017 as compared to 2016 | (11 | ) |
| Lower gross margin of $9 million due to a reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7 million of customer relief related to the impact of Hurricane Harvey in 2017 | (16 | ) |
| Higher gross margin due to higher volumes driven by higher average customer usage and mix | 17 |
|
| Decrease in economic gross margin | $ | (46 | ) |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 184 |
|
| Increase in contract and emission credit amortization | 2 |
|
| Increase in gross margin | $ | 140 |
|
Mark-to-market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results increased by $63 million during the three months ended September 30, 2017, compared to the same period in 2016.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended September 30, 2017 |
| | Generation | | | | | | | | |
| | Gulf Coast | | East/West | | Retail | | Renewables | | Eliminations(a) | | Total |
| | (In millions) |
| Mark-to-market results in operating revenues | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 121 |
| | $ | 5 |
| | $ | — |
| | $ | 1 |
| | $ | (68 | ) | | $ | 59 |
|
| Net unrealized gains/(losses) on open positions related to economic hedges | 12 |
| | (5 | ) | | — |
| | 4 |
| | (44 | ) | | (33 | ) |
| Total mark-to-market gains/(losses) in operating revenues | $ | 133 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| | $ | (112 | ) | | $ | 26 |
|
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (5 | ) | | $ | (1 | ) | | $ | (127 | ) | | $ | — |
| | $ | 68 |
| | $ | (65 | ) |
| Reversal of acquired gain positions related to economic hedges | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) |
| Net unrealized gains/(losses) on open positions related to economic hedges | 7 |
| | 11 |
| | (45 | ) | | — |
| | 44 |
| | 17 |
|
| Total mark-to-market gains/(losses) in operating costs and expenses | $ | 2 |
| | $ | 10 |
| | $ | (174 | ) | | $ | — |
| | $ | 112 |
| | $ | (50 | ) |
| |
(a) | Represents the elimination of the intercompany activity between Retail and Generation. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended September 30, 2016 |
| | Generation | | | | | | | | |
| | Gulf Coast | | East/West | | Retail | | Renewables | | Eliminations(a) | | Total |
| | (In millions) |
| Mark-to-market results in operating revenues | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 8 |
| | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (77 | ) | | $ | (70 | ) |
| Net unrealized gains/(losses) on open positions related to economic hedges | 171 |
| | 58 |
| | 2 |
| | 1 |
| | (100 | ) | | 132 |
|
| Total mark-to-market gains/(losses) in operating revenues | $ | 179 |
| | $ | 57 |
| | $ | 2 |
| | $ | 1 |
| | $ | (177 | ) | | $ | 62 |
|
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 7 |
| | $ | 2 |
| | $ | (46 | ) | | $ | — |
| | $ | 77 |
| | $ | 40 |
|
| Reversal of acquired gain positions related to economic hedges | — |
| | (5 | ) | | (2 | ) | | — |
| | — |
| | (7 | ) |
| Net unrealized gains/(losses) on open positions related to economic hedges | 20 |
| | 10 |
| | (312 | ) | | — |
| | 100 |
| | (182 | ) |
| Total mark-to-market gains/(losses) in operating costs and expenses | $ | 27 |
| | $ | 7 |
| | $ | (360 | ) | | $ | — |
| | $ | 177 |
| | $ | (149 | ) |
| |
(a) | Represents the elimination of the intercompany activity between Retail and Generation. |
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.
For the three months ended September 30, 2017, the $26 million gain in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, partially offset by a decrease in value of open positions as a result of an increase in natural gas prices. The $50 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in value of open positions as a result of an increase in coal prices.
For the three months ended September 30, 2016, the $62 million gain in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of decreases in gas and electricity prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $149 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in value of open positions as a result of decreases in natural gas and ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 30, 2017 and 2016. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.
|
| | | | | | | |
| | Three months ended September 30, |
| (In millions) | 2017 | | 2016 |
| Trading (losses)/gains | | | |
| Realized | $ | (10 | ) | | $ | 20 |
|
| Unrealized | (5 | ) | | (5 | ) |
| Total trading (losses)/gains | $ | (15 | ) | | $ | 15 |
|
Operations and Maintenance Expense
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | Retail | | Renewables | | NRG Yield | | Corporate | | Eliminations | Total |
| | Gulf Coast | | East/West(a) | | | | | |
| | (In millions) |
| Three months ended September 30, 2017 | $ | 120 |
| | $ | 85 |
| | $ | 56 |
| | $ | 28 |
| | $ | 46 |
| | $ | 3 |
| | $ | (12 | ) | $ | 326 |
|
| Three months ended September 30, 2016 | 139 |
| | 97 |
| | 58 |
| | 19 |
| | 41 |
| | 7 |
| | (7 | ) | 354 |
|
| |
(a) | Includes International, BETM and generation eliminations of $2 million in 2017 and $1 million in 2016. |
Operations and maintenance expense decreased by $28 million for the three months ended September 30, 2017, compared to the same period in 2016, due to the following:
|
| | | |
| | (In millions) |
| Decrease in operation and maintenance expenses due to a reduction in normal maintenance at various gas and coal facilities in Texas | $ | (18 | ) |
| Decrease in operation and maintenance expenses primarily due to major maintenance activities and environmental work at Midwest Generation in 2016 | (11 | ) |
| Other | 1 |
|
| | $ | (28 | ) |
Selling, General and Administrative
Selling, general and administrative expenses are comprised of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Retail | | Renewables | | NRG Yield | | Corporate | | Total |
| | (In millions) |
| Three months ended September 30, 2017 | $ | 42 |
| | $ | 112 |
| | $ | 14 |
| | $ | 4 |
| | $ | 41 |
| | $ | 213 |
|
| Three months ended September 30, 2016 | 64 |
| | 137 |
| | 12 |
| | 4 |
| | 60 |
| | 277 |
|
Selling, general and administrative expenses decreased by $64 million for the three months ended September 30, 2017, compared to the same period in 2016. The decrease in year over year expenses is due primarily to a reduction in personnel costs and selling and marketing activities as the Company continues to focus on cost management.
Reorganization
Reorganization expenses of $18 million were incurred during the third quarter of 2017 related to the Transformation Plan announced on July 12, 2017.
Loss on Debt Extinguishment
A loss on debt extinguishment of $50 million was recorded for the three months ended September 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.
Interest Expense
NRG's interest expense decreased by $16 million for the three months ended September 30, 2017, compared to the same period in 2016 due to the following:
|
| | | |
| | (In millions) |
| Decrease due to the repurchase of Senior Notes in 2016 of $25 million, partly offset by Senior Notes issued in 2016 of $7 million | $ | (18 | ) |
| Decrease due to termination of swaps related to 2016 Capistrano debt refinancing | (16 | ) |
| Increase due to the issuance of Carlsbad Energy Project debt during 2017, and Utah Portfolio debt, due 2022, during 2016 | 8 |
|
| Increase in derivative interest expense from changes in fair value of interest rate swaps | 4 |
|
| Increase due to the issuance of Yield Operating Senior Notes, due 2026 | 3 |
|
| Other | 3 |
|
| | $ | (16 | ) |
Income Tax Expense
For the three months ended September 30, 2017, NRG recorded income tax expense of $6 million on pre-tax income of $196 million. For the same period in 2016, NRG recorded income tax expense of $28 million on pre-tax income of $156 million. The effective tax rate was 3.1% and 17.9% for the three months ended September 30, 2017 and 2016, respectively.
For the three months ended September 30, 2017, NRG's overall effective tax rate was different then the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.
For the three months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance, partially offset by amortization of indefinite lived assets, inclusion of consolidated partnerships and state tax expense.
(Loss)/Income from Discontinued Operations, Net of Income Tax Expense/(Benefit)
For the three months ended September 30, 2017, NRG recorded loss from discontinued operations, net of income tax expense/(benefit) of $27 million.
For the three months ended September 30, 2016, NRG recorded income from discontinued operations, net of income tax expense/(benefit) of $265 million.
Management’s discussion of the results of operations for the nine months ended September 30, 2017, and 2016
Electricity Prices
The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the nine months ended September 30, 2017, and 2016. Average on-peak power prices increased primarily due to the increase in natural gas prices for the nine months ended September 30, 2017 as compared to the same period in 2016.
|
| | | | | | | | | | |
| | Average on Peak Power Price ($/MWh) |
| | Nine months ended September 30, |
| Region | 2017 |
| 2016 | | Change % |
Gulf Coast (a) | | | | | |
ERCOT - Houston (b) | $ | 35.61 |
| | $ | 25.97 |
| | 37 | % |
ERCOT - North(b) | 26.64 |
| | 24.14 |
| | 10 | % |
MISO - Louisiana Hub(c) | 42.33 |
| | 33.47 |
| | 26 | % |
| East/West | | | | |
|
NY J/NYC(c) | 37.46 |
| | 35.04 |
| | 7 | % |
NEPOOL(c) | 33.11 |
| | 33.80 |
| | (2 | )% |
PEPCO (PJM)(c) | 35.65 |
| | 38.15 |
| | (7 | )% |
PJM West Hub(c) | 33.30 |
| | 33.95 |
| | (2 | )% |
CAISO - NP15(c) | 33.82 |
| | 29.38 |
| | 15 | % |
CAISO - SP15(c) | 33.42 |
| | 30.22 |
| | 11 | % |
(a) Gulf Coast region also transacts in PJM - West Hub.
(b) Average on peak power prices based on real time settlement prices as published by the respective ISOs.
(c) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs.
The following table summarizes average realized power prices for each region in which NRG operates for the nine months ended September 30, 2017, and 2016, which reflects the impact of settled hedges.
|
| | | | | | | | | | |
| | Average Realized Power Price ($/MWh) |
| | Nine months ended September 30, |
| Region | 2017 | | 2016 | | Change % |
| Gulf Coast | $ | 34.42 |
| | $ | 39.52 |
| | (13 | )% |
| East/West | 40.33 |
| | 42.38 |
| | (5 | )% |
Though the average on peak power prices have increased on average by 7%, average realized prices by region for the Company have generally fluctuated at a slower rate year-over-year due to the Company's multi-year hedging program.
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales.
Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.
The below tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2017 and 2016:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine months ended September 30, 2017 |
| | Generation | | | | | | | | | | |
| (In millions) | Gulf Coast | | East/West(a) | | Subtotal | | Retail | | Renewables | | NRG Yield | | Corporate/Eliminations | | Total |
| Energy revenue | $ | 1,408 |
| | $ | 651 |
| | $ | 2,059 |
| | $ | — |
| | $ | 298 |
| | $ | 436 |
| | $ | (885 | ) | | $ | 1,908 |
|
| Capacity revenue | 207 |
| | 438 |
| | 645 |
| | — |
| | 1 |
| | 256 |
| | (8 | ) | | 894 |
|
| Retail revenue | — |
| | — |
| | — |
| | 4,875 |
| | — |
| | — |
| | 5 |
| | 4,880 |
|
| Mark-to-market for economic hedging activities | 174 |
| | 4 |
| | 178 |
| | — |
| | 8 |
| | — |
| | (1 | ) | | 185 |
|
| Contract amortization | 11 |
| | — |
| | 11 |
| | — |
| | (1 | ) | | (52 | ) | | 1 |
| | (41 | ) |
Other revenue (b) | 143 |
| | 36 |
| | 179 |
| | — |
| | 58 |
| | 127 |
| | (58 | ) | | 306 |
|
| Operating revenue | 1,943 |
| | 1,129 |
| | 3,072 |
| | 4,875 |
| | 364 |
| | 767 |
| | (946 | ) | | 8,132 |
|
| Cost of fuel | (790 | ) | | (293 | ) | | (1,083 | ) | | (8 | ) | | (3 | ) | | (24 | ) | | 48 |
| | (1,070 | ) |
Other cost of sales(c) | (259 | ) | | (203 | ) | | (462 | ) | | (3,661 | ) | | (8 | ) | | (21 | ) | | 860 |
| | (3,292 | ) |
| Mark-to-market for economic hedging activities | (22 | ) | | 7 |
| | (15 | ) | | (154 | ) | | — |
| |
|
| | 1 |
| | (168 | ) |
| Contract and emission credit amortization | (21 | ) | | (3 | ) | | (24 | ) | | — |
| | — |
| | | | — |
| | (24 | ) |
| Gross margin | $ | 851 |
| | $ | 637 |
| | $ | 1,488 |
| | $ | 1,052 |
| | $ | 353 |
| | $ | 722 |
| | $ | (37 | ) | | $ | 3,578 |
|
| Less: Mark-to-market for economic hedging activities, net | 152 |
| | 11 |
| | 163 |
| | (154 | ) | | 8 |
| | — |
| | — |
| | 17 |
|
| Less: Contract and emission credit amortization, net | (10 | ) | | (3 | ) | | (13 | ) | | — |
| | (1 | ) | | (52 | ) | | 1 |
| | (65 | ) |
| Economic gross margin | $ | 709 |
| | $ | 629 |
| | $ | 1,338 |
| | $ | 1,206 |
| | $ | 346 |
| | $ | 774 |
| | $ | (38 | ) | | $ | 3,626 |
|
| Business Metrics | | | | | | | | | | | | | | | |
MWh sold (thousands)(d)(e) | 40,908 |
| | 16,140 |
| | | | | | 2,940 |
| | 5,295 |
| | | | |
MWh generated (thousands) (f) | 37,975 |
| | 10,202 |
| | | | | | 2,940 |
| | 6,467 |
| | | | |
| (a) Includes International, BETM and Generation eliminations. |
| (b) Renewables other revenue includes $21 million of intercompany revenue to NRG Yield. |
| (c) Includes purchased energy, capacity and emissions credits. |
| (d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements. |
| (e) Does not include thermal MWh of 27 thousand or MWt of 1,450 thousand for thermal sold by NRG Yield. |
| (f) Does not include thermal MWh of 80 thousand or MWt of 1,450 thousand for thermal generated by NRG Yield. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine months ended September 30, 2016 |
| | Generation | | | | | | | | | | |
| (In millions) | Gulf Coast | | East/West(a) | | Subtotal | | Retail | | Renewables | | NRG Yield | | Corporate/Eliminations | | Total |
| Energy revenue | $ | 1,598 |
| | $ | 896 |
| | $ | 2,494 |
| | $ | — |
| | $ | 303 |
| | $ | 459 |
| | $ | (778 | ) | | $ | 2,478 |
|
| Capacity revenue | 222 |
| | 468 |
| | 690 |
| | — |
| | — |
| | 256 |
| | (9 | ) | | 937 |
|
| Retail revenue | — |
| | — |
| | — |
| | 4,918 |
| | — |
| | — |
| | 13 |
| | 4,931 |
|
| Mark-to-market for economic hedging activities | (270 | ) | | (9 | ) | | (279 | ) | | — |
| | — |
| | — |
| | (81 | ) | | (360 | ) |
| Contract amortization | 11 |
| | — |
| | 11 |
| | — |
| | (1 | ) | | (51 | ) | | — |
| | (41 | ) |
Other revenue (b) | 182 |
| | 75 |
| | 257 |
| | — |
| | 34 |
| | 125 |
| | (33 | ) | | 383 |
|
| Operating revenue | 1,743 |
| | 1,430 |
| | 3,173 |
| | 4,918 |
| | 336 |
| | 789 |
| | (888 | ) | | 8,328 |
|
| Cost of fuel | (718 | ) | | (371 | ) | | (1,089 | ) | | (5 | ) | | (3 | ) | | (25 | ) | | 114 |
| | (1,008 | ) |
Other cost of sales(c) | (309 | ) | | (245 | ) | | (554 | ) | | (3,628 | ) | | (9 | ) | | (23 | ) | | 696 |
| | (3,518 | ) |
| Mark-to-market for economic hedging activities | 62 |
| | 8 |
| | 70 |
| | 150 |
| | — |
| | — |
| | 81 |
| | 301 |
|
| Contract and emission credit amortization | (22 | ) | | (4 | ) | | (26 | ) | | (5 | ) | | — |
| | (6 | ) | | 3 |
| | (34 | ) |
| Gross margin | $ | 756 |
| | $ | 818 |
| | $ | 1,574 |
| | $ | 1,430 |
| | $ | 324 |
| | $ | 735 |
| | $ | 6 |
| | $ | 4,069 |
|
| Less: Mark-to-market for economic hedging activities, net | (208 | ) | | (1 | ) | | (209 | ) | | 150 |
| | — |
| | — |
| | — |
| | (59 | ) |
| Less: Contract and emission credit amortization, net | (11 | ) | | (4 | ) | | (15 | ) | | (5 | ) | | (1 | ) | | (57 | ) | | 3 |
| | (75 | ) |
| Economic gross margin | $ | 975 |
| | $ | 823 |
| | $ | 1,798 |
| | $ | 1,285 |
| | $ | 325 |
| | $ | 792 |
| | $ | 3 |
| | $ | 4,203 |
|
| Business Metrics | | | | | | | | | | | | | | | |
MWh sold (thousands)(d)(e) | 40,433 |
| | 21,141 |
| | | | | | 2,968 |
| | 5,563 |
| | | | |
MWh generated (thousands) (f) | 36,427 |
| | 13,732 |
| | | | | | 2,968 |
| | 6,828 |
| | | | |
| (a) Includes International, BETM and Generation eliminations. |
| (b) Renewables other revenue includes $13 million of intercompany revenue to NRG Yield. |
| (c) Includes purchased energy, capacity and emissions credits |
| (d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements. |
| (e) Does not include thermal MWh of 61 thousand or MWt of 1,497 thousand for thermal sold by NRG Yield. |
| (f) Does not include thermal MWh of 248 thousand or MWt of 1,497 thousand for thermal generated by NRG Yield. |
The table below represents the weather metrics for the nine months ended September 30, 2017 and 2016: |
| | | | | | | | | | | | | | | |
| | Nine months ended September 30, | | | | | | | | | |
| Weather Metrics | Gulf Coast | | East/West | | | | | | | | | | |
| 2017 | | | | | | | | | | | | | |
CDDs (a) | 2,653 |
| | 1,071 |
| | | | | | | | | | |
HDDs (a) | 674 |
| | 2,041 |
| | | | | | | | | | |
| 2016 | | | | | | | | | | | | | |
| CDDs | 2,605 |
| | 1,098 |
| | | | | | | | | | |
| HDDs | 984 |
| | 2,046 |
| | | | | | | | | | |
| 10 year average | | | | | | | | | | | | | |
| CDDs | 2,656 |
| | 976 |
| | | | | | | | | | |
| HDDs | 1,167 |
| | 2,277 |
| | | | | | | | | | |
| |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Generation gross margin and economic gross margin
Generation gross margin decreased $86 million and economic gross margin decreased $460 million, both of which include intercompany sales, during the nine months ended September 30, 2017, compared to the same period in 2016:
The tables below describe the decrease in Generation gross margin and economic gross margin:
Gulf Coast Region
|
| | | |
| | (In millions) |
| Lower gross margin due to a 12% decrease in average realized prices primarily in Texas due to lower hedged power prices | $ | (225 | ) |
| Lower energy margin due to increased supply costs on load contracts | (39 | ) |
| Lower capacity margin on contract expirations and lower demand | (29 | ) |
| Lower gross margin due to a 42% decrease in ISO capacity prices and a 58% decrease in volume | (18 | ) |
| Lower gross margin from a 7% decrease in nuclear generation driven by the timing of planned outages | (17 | ) |
| Higher gross margin primarily due to 19% higher coal generation mainly in Texas driven by timing of planned outages | 59 |
|
| Other | 3 |
|
| Decrease in economic gross margin | $ | (266 | ) |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 360 |
|
| Increase in contract and emission credit amortization | 1 |
|
| Increase in gross margin | $ | 95 |
|
|
| | | |
| | (In millions) |
| Higher gross margin from sales of NOx emission credits | $ | 35 |
|
| Higher gross margin due to a 17% increase in average realized prices in South Central and a 3% increase in average realized prices in Texas | 20 |
|
| Higher capacity margins due to an 18% increase in demand in the South Central business | 15 |
|
| Higher gross margin from commercial optimization activities | 10 |
|
| Lower energy margin due to a 33% increase in supply cost on load contracts | (27 | ) |
| Other | (4 | ) |
| Increase in economic gross margin | $ | 49 |
|
| Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | (688 | ) |
| Decrease in gross margin | $ | (639 | ) |
East/West
|
| | | |
| | (In millions) |
| Lower gross margin due to a 14% decrease in generation driven by lower economic generation due to milder weather conditions and the Will County outage | $ | (60 | ) |
| Lower gross margin by BETM due to higher gains in 2016 on over the counter strategies, offset in small part by higher gains in 2017 on congestion strategies | (45 | ) |
| Lower gross margin from commercial optimization activities | (39 | ) |
| Lower gross margin due to lower load contracted prices coupled with slightly lower volumes | (26 | ) |
| Lower gross margin due to a 16% decrease in capacity pricing in New York of $10 million coupled with decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration and unit retirements in California | (23 | ) |
| Other | (1 | ) |
| Decrease in economic gross margin | $ | (194 | ) |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 12 |
|
| Increase in contract and emission credit amortization | 1 |
|
| Decrease in gross margin | $ | (181 | ) |
|
| | | |
| | (In millions) |
| Higher gross margin due to a 108% increase in New England cleared capacity pricing | $ | 20 |
|
| Higher gross margin due to a 20% increase in PJM cleared capacity pricing | 14 |
|
| Higher gross margin from commercial optimization activities | 16 |
|
| Lower gross margin due to a 31% decrease in capacity pricing in New York of $12 million coupled with decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration and unit retirements in California | (18 | ) |
| Lower gross margin due to lower load contracted prices coupled with lower contracted volumes | (12 | ) |
| Higher gross margin by BETM due to higher gains in congestion strategies | 14 |
|
| Increase in economic gross margin | $ | 34 |
|
| Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | (4 | ) |
| Increase in contract and emission credit amortization | 1 |
|
| Increase in gross margin | $ | 31 |
|
Retail gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail.
|
| | | | | | | |
| | Nine months ended September 30, |
| (In millions except otherwise noted) | 2017 | | 2016 |
| Retail revenue | $ | 4,658 |
| | $ | 4,727 |
|
| Supply management revenue | 147 |
| | 117 |
|
| Capacity revenue | 70 |
| | 74 |
|
Operating revenue (a) | 4,875 |
| | 4,918 |
|
Cost of sales (b) | (3,669 | ) | | (3,633 | ) |
| Mark-to-market for economic hedging activities | (154 | ) | | 150 |
|
| Contract amortization | — |
| | (5 | ) |
| Gross Margin | $ | 1,052 |
| | $ | 1,430 |
|
| Less: Mark-to-market for economic hedging activities, net | (154 | ) | | 150 |
|
| Less: Contract and emission credit amortization, net | — |
| | (5 | ) |
| Economic Gross Margin | $ | 1,206 |
| | $ | 1,285 |
|
| | | | |
| Business Metrics | | | |
| Mass electricity sales volume - GWh - Gulf Coast | 28,153 |
| | 27,382 |
|
| Mass electricity sales volume - GWh - All other regions | 4,722 |
| | 5,264 |
|
C&I electricity sales volume — GWh - All regions (c) | 15,228 |
| | 14,357 |
|
| Natural gas sales volumes (MDth) | 1,941 |
| | 1,423 |
|
| Average Retail Mass customer count (in thousands) | 2,857 |
| | 2,770 |
|
| Ending Retail Mass customer count (in thousands) | 2,880 |
| | 2,797 |
|
| |
(a) | Includes intercompany sales of $4 million and $3 million in 2017 and 2016, respectively, representing sales from Retail to the Gulf Coast region. |
| |
(b) | Includes intercompany purchases of $830 million and $655 million in 2017 and 2016. |
| |
(c) | Includes volumes for 2017 for one customer that self-supplied their volumes during the first six months of 2016. |
Retail gross margin decreased $378 million and economic gross margin decreased $79 million for the nine months ended September 30, 2017, compared to the same period in 2016, due to:
|
| | | |
| | (In millions) |
| Lower gross margin due to lower rates to customers driven by customer product, term, and mix of $95 million or approximately $2 per MWh, partially offset by lower supply costs of $5 million or approximately $0.10 per MWh driven primarily by a decrease in power prices at the time of procurement | $ | (90 | ) |
| Lower gross margin of $9 million due to a reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7 million of customer relief related to the impact of Hurricane Harvey in 2017 | (16 | ) |
| Lower gross margin of $13 million due to a reduction in load of 420,000 MWh and $2 million in lower margin due to the unfavorable impacts of selling back excess supply due to milder weather conditions in 2017 as compared to 2016 | (15 | ) |
| Higher gross margin due to higher volumes driven by higher average customer usage and mix | 42 |
|
| Decrease in economic gross margin | $ | (79 | ) |
| Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | (304 | ) |
| Increase in contract and emission credit amortization | 5 |
|
| Decrease in gross margin | $ | (378 | ) |
Renewables gross margin and economic gross margin
Renewables gross margin increased $29decreased $7 million and economic gross margin increased $21$9 million for the ninethree months ended September 30, 2017,March 31, 2018, compared to the same period in 2016,2017. The increase in economic gross margin was primarily driven by newadditional distributed generation solar projects placedfacilities reaching commercial operations in service, increased margin2017 and early 2018. The decrease in operations and maintenance agreements and receipt of insurance proceeds offsetting lower volume at the Ivanpah solar plant.
NRG Yield gross margin and economic gross margin
NRG Yield gross margin decreased $13 million and economic gross margin decreasedwas primarily driven by $19 million during the nine months ended September 30, 2017, compared to the same period in 2016, due to a 4% decrease in volume generated atunrealized losses on wind projects, primarily in connection with lower wind resources at the Alta Wind and NRG Wind TE Holdco projects, as well as 5% decrease in solar generation, primarily at CVSR in connection with lower insolation.hedges.
Mark-to-market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results increased by $76$215 million during the ninethree months ended September 30, 2017,March 31, 2018, compared to the same period in 2016.2017.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows: |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended March 31, 2018 |
| | | | Generation | | | | | | |
| | Retail | | Gulf Coast | | East/West | | Renewables | | Eliminations(a) | | Total |
| | (In millions) |
| Mark-to-market results in operating revenues | | | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (1 | ) | | $ | (34 | ) | | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | (32 | ) |
| Net unrealized (losses)/gains on open positions related to economic hedges | (5 | ) | | (530 | ) | | (10 | ) | | (10 | ) | | 481 |
| | (74 | ) |
| Total mark-to-market (losses)/gains in operating revenues | $ | (6 | ) | | $ | (564 | ) | | $ | (10 | ) | | $ | (10 | ) | | $ | 484 |
| | $ | (106 | ) |
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 42 |
| | $ | (1 | ) | | $ | (4 | ) | | $ | — |
| | $ | (3 | ) | | $ | 34 |
|
| Net unrealized gains/(losses) on open positions related to economic hedges | 750 |
| | (2 | ) | | 1 |
| | — |
| | (481 | ) | | 268 |
|
| Total mark-to-market gains/(losses) in operating costs and expenses | $ | 792 |
| | $ | (3 | ) | | $ | (3 | ) | | $ | — |
| | $ | (484 | ) | | $ | 302 |
|
| |
(a) | Represents the elimination of the intercompany activity between Retail and Generation. |
| | | | Nine months ended September 30, 2017 | Three months ended March 31, 2017 |
| | Generation | | | | | | | | | | | Generation | | | | | | |
| | Gulf Coast | | East/West | | Retail | | Renewables | | Eliminations(a) | | Total | Retail | | Gulf Coast | | East/West | | Renewables | | Eliminations(a) | | Total |
| | (In millions) | (In millions) |
| Mark-to-market results in operating revenues | | | | | | | | | | | | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 113 |
| | $ | (32 | ) | | $ | (1 | ) | | $ | 1 |
| | $ | 21 |
| | $ | 102 |
| |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | | $ | — |
| | $ | (1 | ) | | $ | (26 | ) | | $ | — |
| | $ | 39 |
| | $ | 12 |
|
| Net unrealized gains/(losses) on open positions related to economic hedges | 61 |
| | 36 |
| | 1 |
| | 7 |
| | (22 | ) | | 83 |
| 2 |
| | 132 |
| | 17 |
| | 6 |
| | (51 | ) | | 106 |
|
| Total mark-to-market gains/(losses) in operating revenues | $ | 174 |
| | $ | 4 |
| | $ | — |
| | $ | 8 |
| | $ | (1 | ) | | $ | 185 |
| $ | 2 |
| | $ | 131 |
| | $ | (9 | ) | | $ | 6 |
| | $ | (12 | ) | | $ | 118 |
|
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | | | | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (12 | ) | | $ | 1 |
| | $ | (51 | ) | | $ | — |
| | $ | (21 | ) | | $ | (83 | ) | |
| Reversal of acquired gain positions related to economic hedges | — |
| | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | | $ | 31 |
| | $ | (3 | ) | | $ | 2 |
| | $ | — |
| | $ | (39 | ) | | $ | (9 | ) |
| Net unrealized (losses)/gains on open positions related to economic hedges | (10 | ) | | 6 |
| | (102 | ) | | — |
| | 22 |
| | (84 | ) | (170 | ) | | (7 | ) | | (2 | ) | | — |
| | 51 |
| | (128 | ) |
| Total mark-to-market (losses)/gains in operating costs and expenses | $ | (22 | ) | | $ | 7 |
| | $ | (154 | ) | | $ | — |
| | $ | 1 |
| | $ | (168 | ) | $ | (139 | ) | | $ | (10 | ) | | $ | — |
| | $ | — |
| | $ | 12 |
| | $ | (137 | ) |
| |
| (a) | Represents the elimination of the intercompany activity between Retail and Generation. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Nine months ended September 30, 2016 |
| | Generation | | | | | | | |
| | Gulf Coast | | East/West | | Retail | | Renewables | | Eliminations(a) | | Total |
| | (In millions) |
| Mark-to-market results in operating revenues | | | | | | | | | | | |
| Reversal of previously recognized unrealized gains on settled positions related to economic hedges | $ | (260 | ) | | $ | (68 | ) | | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (329 | ) |
| Net unrealized (losses)/gains on open positions related to economic hedges | (10 | ) | | 59 |
| | 1 |
| | — |
| | (81 | ) | | (31 | ) |
| Total mark-to-market losses in operating revenues | $ | (270 | ) | | $ | (9 | ) | | $ | — |
| | $ | — |
| | $ | (81 | ) | | $ | (360 | ) |
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses on settled positions related to economic hedges | $ | 26 |
| | $ | 10 |
| | $ | 218 |
| | $ | — |
| | $ | — |
| | $ | 254 |
|
| Reversal of acquired gain positions related to economic hedges | — |
| | (10 | ) | | (1 | ) | | — |
| | — |
| | (11 | ) |
| Net unrealized gains/(losses) on open positions related to economic hedges | 36 |
| | 8 |
| | (67 | ) | | — |
| | 81 |
| | 58 |
|
| Total mark-to-market gains in operating costs and expenses | $ | 62 |
| | $ | 8 |
| | $ | 150 |
| | $ | — |
| | $ | 81 |
| | $ | 301 |
|
| |
(a) | Represents the elimination of the intercompany activity between Retail and Generation. |
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.
For the ninethree months ended September 30, 2017,March 31, 2018, the $185$106 million gainloss in operating revenues from economic hedge positions was driven primarily by a decrease in the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as an increase in value of open positions as a result of decreasesERCOT heat rate expansion and increases in PJM power prices, New York capacity prices, and natural gas prices. The $168 million loss in operating costs and expenses from economic hedge positions was driven primarily by the decrease in value of open positions as a result of decreases in coal, natural gas, and ERCOT powerelectricity prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.
For the nine months ended September 30, 2016, the $360 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $301$302 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in value of open positions as a result of ERCOT heat rate expansion and increases in ERCOT electricity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period, as well asperiod.
For the three months ended March 31, 2017, the $118 million gain in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of increasesdecreases in natural gas prices.and ERCOT electricity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period. The $137 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in value of open positions as a result of decreases in natural gas, coal, and ERCOT electricity prices, in addition to the reversal of previously recognized unrealized gains on contracts that settled during the period.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the ninethree months ended September 30, 2017,March 31, 2018 and 2016.2017. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.
| | | | Nine months ended September 30, | Three months ended March 31, |
| (In millions) | 2017 | | 2016 | 2018 | | 2017 |
| Trading gains/(losses) | | | | | | |
| Realized | $ | 18 |
| | $ | 67 |
| $ | 15 |
| | $ | 14 |
|
| Unrealized | (7 | ) | | 27 |
| 8 |
| | (14 | ) |
| Total trading gains | $ | 11 |
| | $ | 94 |
| $ | 23 |
| | $ | — |
|
Operations and Maintenance Expense
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | Retail | | Renewables | | NRG Yield | | Corporate | | Eliminations | Total |
| | Gulf Coast | | East/West(a) | | | | | |
| | (In millions) | |
| Nine months ended September 30, 2017 | $ | 370 |
| | $ | 284 |
| | $ | 170 |
| | $ | 91 |
| | $ | 143 |
| | $ | 12 |
| | $ | (32 | ) | $ | 1,038 |
|
| Nine months ended September 30, 2016 | 419 |
| | 374 |
| | 178 |
| | 93 |
| | 134 |
| | 19 |
| | (21 | ) | 1,196 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Retail | | Generation | Renewables | | NRG Yield | | Corporate | | Eliminations | Total |
| | | Gulf Coast | | East/West(a) | | | | |
| | | | (In millions) |
| Three months ended March 31, 2018 | $ | 47 |
|
| $ | 151 |
|
| $ | 105 |
|
| $ | 28 |
|
| $ | 52 |
|
| $ | 1 |
|
| $ | (14 | ) | $ | 370 |
|
| Three months ended March 31, 2017 | $ | 59 |
|
| $ | 143 |
|
| $ | 96 |
|
| $ | 28 |
|
| $ | 52 |
|
| $ | 4 |
|
| $ | (11 | ) | $ | 371 |
|
| |
(a) | Includes International, BETM and generation eliminations of $3 million in 2017 and $4 million in 2016. |
(a) Includes International, BETM and generation eliminations of $1 million in 2018 and $1 million in 2017.
Operations and maintenance expense decreased by $158$1 million for the ninethree months ended September 30, 2017,March 31, 2018, compared to the same period in 2016,2017, due to the following:
|
| | | |
| | (In millions) |
| Decrease in operation and maintenance expenses due to major maintenance activities and environmental control work at Midwest Generation in 2016 | $ | (68 | ) |
| Decrease in operation and maintenance expenses due to lower expenses at Big Cajun II in 2017 | (26 | ) |
| Decrease in operation and maintenance expenses due to the deactivation of the Huntley and Dunkirk facilities in 2016 | (16 | ) |
| Decrease in operation and maintenance expenses due to a reduction in normal maintenance at various gas and coal facilities in Texas | (15 | ) |
| Decrease in Retail operation and maintenance expenses due to reduced headcount | (8 | ) |
| Decrease in operations and maintenance expenses related to outage work at Arthur Kill in 2016 | (6 | ) |
| Decrease in operations and maintenance expenses due to a reduction in headcount related to the sale of the Engine Services business | (4 | ) |
| Other | (15 | ) |
| | $ | (158 | ) |
|
| | | |
| | (In millions) |
| Decrease in Retail operation and maintenance expenses due to reduced headcount | $ | (12 | ) |
| Increase in operation and maintenance expenses due to planned outages primarily at Midwest Generation | 9 |
|
| Increase in operation and maintenance expenses primarily due to timing of outages at W.A Parish, offset by a decrease in personnel costs due to the sale of the engine services business | 8 |
|
| Other | (6 | ) |
| | $ | (1 | ) |
Selling, General and Administrative
Selling, general and administrative expenses are comprised of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Retail | | Renewables | | NRG Yield | | Corporate | | Total |
| | (In millions) |
| Nine months ended September 30, 2017 | $ | 155 |
| | $ | 337 |
| | $ | 43 |
| | $ | 16 |
| | $ | 146 |
| | $ | 697 |
|
| Nine months ended September 30, 2016 | 195 |
| | 362 |
| | 43 |
| | 10 |
| | 191 |
| | 801 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Retail | | Generation | | Renewables | | NRG Yield | | Corporate | | Total |
| | | | (In millions) |
| Three months ended March 31 2018 | $ | 115 |
|
| $ | 50 |
|
| $ | 10 |
|
| $ | 6 |
|
| $ | 10 |
|
| $ | 191 |
|
| Three months ended March 31, 2017 | 119 |
|
| 61 |
|
| 14 |
|
| 4 |
|
| 62 |
|
| 260 |
|
Selling, general and administrative expenses decreased by $104$69 million for the ninethree months ended September 30, 2017,March 31, 2018 compared to the same period in 2016.2017. The decrease in year over year expenses is due primarily to a $18 million reduction in personnel costsgeneral and administrative expenses and an $11 million reduction in selling and marketing activities as the Company continues to focus on cost management.
Reorganization
Reorganization In addition, there was a reduction to general and administrative expenses of $18$25 million were incurred during the third quarter of 2017 related to the Transformation Plan announced on July 12, 2017.
Loss on Saleprior year consulting costs incurred of Assets
During the nine months ended September 30, 2016,which $14 million related to advisors engaged to assist the Company sold a majority interest in its EVgo businessstrategic review and $11 million in connection with advisors and other consultants engaged to Vision Ridge Partners, as described in Note 3, Discontinued Operations, Dispositions and Acquisitions, of this Form 10-Q, which resulted in a loss on sale of $79 million .
Impairment Losses on Investments
For the nine months ended September 30, 2016,assist the Company recorded other-than-temporary impairment losses of $147 million, which is primarily duewith GenOn's ability to its 50% interest in Petra Nova Parish Holdings,continue as further described in Note 7, Impairments, of this Form 10-Q.a going concern.
Reorganization Costs
Loss on Debt ExtinguishmentReorganization costs of $20 million, primarily related to employee costs, were incurred as part of the Transformation Plan.
A loss on debt extinguishmentOther Income - Affiliate
Other income - affiliate represents the services fees charged to GenOn for shared services under the Services Agreement through June 14, 2017, the date of $119 million was recorded for the nine months ended September 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.deconsolidation.
Interest Expense
NRG's interest expense decreased by $26$58 million for the ninethree months ended September 30, 2017,March 31, 2018, compared to the same period in 20162017 due to the following:
|
| | | |
| | (In millions) |
| Decrease due to the repurchase of Senior Notes in 2016 of $127 million, partly offset by Senior Notes issued in 2016 of $78 million | $ | (49 | ) |
| Decrease due to termination of swaps related to 2016 Capistrano debt refinancing | (16 | ) |
| Increase due to the issuance of Utah Portfolio debt, due 2022 and CVSR Holdco Notes, due 2037 during 2016 | 16 |
|
| Increase due to the issuance of Carlsbad Energy Project debt and Agua Caliente HoldCo, due 2038 during 2017 | 10 |
|
| Increase in derivative interest expense from changes in fair value of interest rate swaps | 9 |
|
| Increase due to the issuance of Yield Operating Senior Notes, due 2026, partially offset by repayment of the Yield Revolving Credit Facility, due 2019 during 2016 | 8 |
|
| Other | (4 | ) |
| | $ | (26 | ) |
|
| | | |
| | (In millions) |
| Decrease in derivative interest expense from changes in fair value of interest rate swaps | $ | (45 | ) |
| Decrease due to repurchases of Senior Notes | (20 | ) |
| Other, primarily related to the issuance of project-level debt | 7 |
|
| | $ | (58 | ) |
Income Tax Expense
For the ninethree months ended September 30, 2017,March 31, 2018, NRG recorded an income tax expensebenefit of $5$1 million on a pre-tax income of $125$232 million. For the same period in 2016,2017, NRG recorded an income tax expensebenefit of $75$4 million on a pre-tax loss of $17$173 million. The effective tax rate was 4.0%(0.4)% and (441.2)%2.3% for the ninethree months ended September 30,March 31, 2018 and 2017, and 2016, respectively.
For the ninethree months ended September 30,March 31, 2018, NRG's overall effective tax rate was different than the statutory rate of 21% primarily due to the tax benefit for the change in valuation allowance, the generation of PTCs from various wind facilities and the inclusion of consolidated partnerships partially offset by current state tax expense.
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 tax benefit for the change in valuation allowance andpartially offset by the generation of PTCs and ITCs from various wind and solar facilities, respectively partially offset by the inclusion of consolidated partnerships and current state tax expense.
For the nine months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due the amortization of indefinite lived assets, the inclusion of consolidated partnerships, state tax expense and the expense for the change in valuation allowance.
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
For the ninethree months ended September 30,March 31, 2018 and 2017, and 2016, net loss attributable to noncontrolling interests and redeemable noncontrolling interests primarily reflects net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method, partially offset by NRG Yield, Inc.'s share of net income.
(Loss)/Income from Discontinued Operations, Net of Income Tax (Benefit)/Expense
For the nine months ended September 30, 2017, NRG recorded loss from discontinued operations, net of income tax (benefit)/expense of $802 million.
For the nine months ended September 30, 2016, NRG recorded income from discontinued operations, net of income tax (benefit)/expense of $256 million.
Liquidity and Capital Resources
Liquidity Position
As of September 30, 2017March 31, 2018 and December 31, 20162017, NRG's liquidity, excluding collateral received, was approximately $3.4$2.8 billion and $2.43.2 billion, respectively, comprised of the following:
| | | (In millions) | September 30, 2017 | | December 31, 2016 | March 31, 2018 | | December 31, 2017 |
| Cash and cash equivalents: | | | | | | |
| NRG excluding NRG Yield | $ | 1,044 |
| | $ | 621 |
| $ | 591 |
| | $ | 843 |
|
| NRG Yield and subsidiaries | 179 |
| | 317 |
| 173 |
| | 148 |
|
| Restricted cash - operating | 124 |
| | 56 |
| 77 |
| | 71 |
|
Restricted cash - reserves (a) | 413 |
| | 390 |
| 330 |
| | 437 |
|
| Total | 1,760 |
| | 1,384 |
| 1,171 |
| | 1,499 |
|
| Total credit facility availability | 1,604 |
|
| 989 |
| 1,614 |
| | 1,711 |
|
| Total liquidity, excluding collateral received | $ | 3,364 |
| | $ | 2,373 |
| $ | 2,785 |
| | $ | 3,210 |
|
(a) Includes reserves primarily for debt service, performance obligations, and capital expenditures.
For the ninethree months ended September 30, 2017March 31, 2018, total liquidity, excluding collateral funds deposited by counterparties, increaseddecreased by $1 billion.$425 million. Changes in cash and cash equivalentsequivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at September 30, 2017March 31, 2018, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.
Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common stockholders, and to fund other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.
On July 12, 2017, NRG announced its Transformation Plan, which is described further in Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Summary.
Credit Ratings
The following table summarizes the Company's credit ratings as of September 30, 2017: |
| | | |
| S&P | | Moody's |
NRG Energy, Inc. | BB- Stable | | Ba3 Stable |
7.625% Senior Notes, due 2018 | BB- | | B1 |
7.875% Senior Notes, due 2021 | BB- | | B1 |
6.25% Senior Notes, due 2022 | BB- | | B1 |
6.625% Senior Notes, due 2023 | BB- | | B1 |
6.25% Senior Notes, due 2024 | BB- | | B1 |
7.25% Senior Notes, due 2026 | BB- | | B1 |
6.625% Senior Notes, due 2027 | BB- | | B1 |
Term Loan Facility, due 2023 | BB+ | | Baa3 |
NRG Yield, Inc. | BB | | Ba2 |
5.375% NRG Yield Operating LLC Senior Notes, due 2024 | BB | | Ba2 |
5.00% NRG Yield Operating LLC Senior Notes, due 2026 | BB | | Ba2 |
On October 6, 2017, Moody's upgraded the NRG rating outlook to positive from stable and affirmed NRG's Ba3 Corporate Family Rating.
Sources of Liquidity
The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand, cash flows from operations, and cash proceeds from future sales of assets, including sales to NRG Yield, Inc. Asand under the Transformation Plan, and financing arrangements, as described in Note 8,7, Debt and Capital Leases, to this Form 10-Q and Note 12,, Debt and Capital Leases,, to the Company's 2016 Form 10-K, the2017 10-K. The Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes, the NRG Yield 2019 Convertible Notes, the NRG Yield 2020 Convertible Notes, the NRG Yield Operating LLC senior unsecured notes, the NRG Yield, Inc. revolving credit facility, and project-related financings.
Carlsbad Project FinancingSale of Ownership in NRG Yield, Inc. and Renewables Platform
On May 26, 2017, Carlsbad Energy Holdings, LLCFebruary 6, 2018, NRG and Global Infrastructure Partners, or GIP, entered into a note payablepurchase and sale agreement for GIP to purchase NRG's ownership in NRG Yield, Inc. and NRG's renewables platform for cash of $1.375 billion, subject to certain adjustments. The purchase and sale agreement includes the sale of all of NRG's ownership in NRG Yield, Inc., NRG's renewable energy development and operations platforms and NRG's renewable energy non-ROFO backlog and pipeline.
In connection with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038. As of September 30, 2017, all $407 million of these notes were outstanding.
Also on May 26, 2017, Carlsbad Energy Holdings, LLCtransaction, the Company entered into a credit agreement, or the Carlsbad FinancingConsent and Indemnity Agreement with NRG Yield, Inc. and GIP setting forth key terms and conditions of NRG Yield, Inc.'s consent to the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completiontransaction. As part of the project. Consent and Indemnity Agreement, NRG has agreed to indemnify GIP and NRG Yield, Inc. and its project companies for any increase in property taxes at the California-based solar projects resulting from the transaction.
The Carlsbad Financing Agreement also includes a letterstransaction is expected to close in the second half of credit facility not2018 and is subject to exceed aggregate amountvarious customary closing conditions, approvals and consents. Upon the closing of $83 million, and a working capital loan facility with an aggregate principle amount not to exceed $4 million.the transaction, NRG’s Ivanpah asset will no longer be part of the NRG Yield ROFO assets.
ROFO Agreement Expansion and OfferSale of South Central Business
On February 24, 2017,6, 2018, NRG and Cleco Energy LLC, or Cleco, entered into a purchase and sale agreement for Cleco to purchase NRG's South Central business for cash of $1.0 billion, subject to certain adjustments. The transaction is expected to close in the second half of 2018 and is subject to various customary closing conditions, approvals and consents. The South Central business owns and operates a 3,555 MW portfolio of generation assets in the Gulf Coast region. Upon the closing of the transaction, NRG will enter into a sale leaseback agreement for the Cottonwood plant through May 2025.
Sale of BETM
On February 23, 2018, the Company amendedentered into an agreement to sell BETM to a third party for $70 million. The transaction is expected to close in the second half of 2018 and restated the ROFO Agreementis subject to expand the ROFO assets pipeline with the addition of 234 net MW of utility-scale solar projects. These assets include Buckthorn Solar, a 154 net MW facility located in Texas,various customary closing conditions, approvals and the Hawaii Solar projects, which have a combined capacity of 80 net MW.
On October 17, 2017, the Company offered NRG Yield, Inc. the opportunity to purchase 100% of its ownership interest in Buckthorn Solar pursuant to the ROFO Agreement.consents.
Sale of Assets to NRG Yield, Inc.
On November 1, 2017, NRGMarch 30, 2018, as part of the Transformation Plan, the Company completed the sale of a 38 MW solar portfolio primarily comprised100% of assets from SPP funds,its ownership interest in addition to other projects developed by NRG,Buckthorn Solar to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.approximately $42 million.
On August 1, 2017, NRG closed on its sale ofFebruary 6, 2018, the remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, toCompany entered into an agreement with NRG Yield, Inc. for total cash considerationto sell 100% of $44 million. The transaction also includes potential additional payments to NRG dependent on actual energy prices for merchant periods beginning in 2027.
On May 23, 2017, NRG offered NRG Yield, Inc. the opportunity to form a new distributed solar investment partnership enabling up to $50 million in investment by NRG Yield, Inc. In addition, on July 31, 2017, NRG offered NRG Yield, Inc. equitymembership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, a 38527 MW portfolio of distributed and small utility-scale solar assets primarily comprised of assets from NRG's Solar Power Partners, or SPP, fundsnatural gas fired project in additionCarlsbad, CA, pursuant to other projects developed since the acquisition of SPP. These equity interests are not part of the ROFO Agreement. BothThe purchase price for the distributed solar investment partnership and the distributed and small utility-scale solar acquisitions aretransaction is $365 million in cash consideration, subject to negotiationcustomary working capital and approval by NRG Yield, Inc.'s independent directors. Asother adjustments. The transaction is expected to close during the fourth quarter of September 30, 2017, NRG Yield, Inc has invested $41 million in distributed solar investment partnerships with NRG.2018.
Sale of Canal 3
On March 27,22, 2018, NRG agreed to sell Canal 3 to Stonepeak Kestrel Holdings II LLC in conjunction with GenOn's sale of Canal Units 1 and 2 to Stonepeak Kestrel Holdings LLC. The final purchase price for the Canal 3 sale will be determined based on a formula including capital reimbursement, return on capital and a development fee. Upon closing the sale of Canal 3, NRG also expects to reimburse GenOn for $13.5 million of the $15 million one-time payment GenOn made in December 2017 to NRG as compensation for being granted a purchase option and a rejection option with respect to the Company sold (i) a 16% interestCanal 3 project. The Canal 3 sale is expected to enhance 2018 capital allocation by approximately $130 million early in the Agua Caliente solar project, representing ownershipthird quarter 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 to NRG Yield, Inc. NRG Yield Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse project debt of approximately $328 million.2018.
2023 Term Loan Facility
On January 24, 2017,March 21, 2018, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%,1.75% and reducing the LIBOR floor remains 0.75%to 0.00%. As a result of the repricing, the Company expects interest savings of approximately $9 million in 2017 and approximately $60$47 million in interest savings over the remaining life of the loan.
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility
On April 30, 2018, NRG Yield LLC and NRG Yield Operating LLC refinanced the revolving credit facility, which extended the maturity of the facility to April 28, 2023, and decreased the overall cost of borrowing from L+ 2.50% to L+1.75%.
First Lien Structure
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired throughin the GenOn and EME (including Midwest Generation), acquisitions, assets held by NRG Yield, Inc., and NRG's assets that have project-level financing. NRG uses the first lien structure 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 gas used as a proxy for power. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have claim under the first lien program. The first lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure as the lien counterparty’s exposure to NRG is positively correlated to the value of the specified generation assets.exposure. Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity, and 10% of its other assets, with these counterparties for the first 60 months and then declining thereafter. These volumetric limits, exclude Midwest Generation's coal capacity.Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.
The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of September 30, 2017March 31, 2018, all hedges under the first liens were out-of-the-moneyin-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of September 30, 2017March 31, 2018:
| | Equivalent Net Sales Secured by First Lien Structure (a) | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | 2018 | | 2019 | | 2020 | | 2021 | | 2022 |
| In MW | 1,458 |
| | 1,093 |
| | — |
| | — |
| | — |
| 454 |
| | — |
| | — |
| | — |
| | — |
|
As a percentage of total net coal and nuclear capacity (b) | 27 | % | | 20 | % | | — | % | | — | % | | — | % | 10 | % | | — | % | | — | % | | — | % | | — | % |
| |
| (a) | Equivalent net salesNet Sales include natural gas swaps converted using a weighted average heat rate by region. |
| |
| (b) | Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien which excludes coal assets acquired in the EME (Midwest(including Midwest Generation) acquisition, assets in NRG Yield, Inc. and NRG's assets that have project level financing. |
Uses of Liquidity
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures, including repowering and renewable development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases, return of capital and dividend payments to stockholders.
Senior Note Redemptions
On October 16, 2017,stockholders; and (v) costs necessary to execute the Company redeemed $398 million of its 7.625% Senior Notes due 2018 and $206 million of its 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest. As a result of the senior note redemptions a $12 million loss on debt extinguishment will be recorded in the fourth quarter of 2017. In addition, the Company expects to save approximately $47 million in annualized interest.Transformation Plan.
Restructuring Support Agreement
As described in Note 3, Discontinued Operations, Dispositions and Acquisitions, NRG, the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes entered into a Restructuring Support Agreement, that provides for a restructuring and recapitalization of GenOn through a prearranged plan of reorganization. Certain principal terms of the Restructuring Support Agreement include that NRG will provide settlement consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of June 30, 2017, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, to be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit facility was terminated, as GenOn has obtained a separate letter of credit facility with a third party financial institution. In addition, NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of September 30, 2017 was approximately $106 million. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement, which includes the retention of the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million, recorded as a liability as of September 30, 2017.
Revolving Credit Facility
As of September 30, 2017, there were no cash borrowings outstanding on the revolver.
Commercial Operations
NRG'sThe Company's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of September 30, 2017March 31, 2018, commercial operations had total cash collateral outstanding of $274$211 million and $606$607 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of September 30, 2017March 31, 2018, total collateral held from counterparties was $31$241 million in cash and $17$47 million inof letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on NRG'sthe Company's credit ratings and general perception of its creditworthiness.
Capital Expenditures
The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental, and growth investments for the ninethree months ended September 30, 2017,March 31, 2018, and the currently estimated capital expenditure and growth investments forecast for the remainder of 2017. 2018.
|
| | | | | | | | | | | | | | | |
| | Maintenance | | Environmental | | Growth Investments | | Total |
| | (In millions) |
| Generation | | | | | | | |
| Gulf Coast | $ | 73 |
| | $ | 1 |
| | $ | 3 |
| | $ | 77 |
|
| East/West | 17 |
| | 24 |
| | 240 |
| | 281 |
|
| Retail | 22 |
| | — |
| | 33 |
| | 55 |
|
| Renewables | 3 |
| | — |
| | 309 |
| | 312 |
|
| NRG Yield | 21 |
| | — |
| | 2 |
| | 23 |
|
Corporate | 11 |
| | — |
| | 1 |
| | 12 |
|
| Total cash capital expenditures for the nine months ended September 30, 2017 | 147 |
| | 25 |
| | 588 |
| | 760 |
|
| Funding from third party equity partners, cash grants and debt financing, net of fees | — |
| | — |
| | (815 | ) | | (815 | ) |
Other investments (a) | — |
| | — |
| | 95 |
| | 95 |
|
| Total capital expenditures and investments, net of financings | 147 |
| | 25 |
| | (132 | ) | | 40 |
|
| | | | | | | | |
| Estimated capital expenditures for the remainder of 2017 | 76 |
| | 10 |
| | 430 |
| | 516 |
|
| Funding from third party equity partners, cash grants and debt financing, net of fees | — |
| | — |
| | (211 | ) | | (211 | ) |
| NRG estimated capital expenditures for the remainder of 2017, net of financings | $ | 76 |
| | $ | 10 |
| | $ | 219 |
| | $ | 305 |
|
| |
(a) | Other investments include restricted cash activity. |
|
| | | | | | | | | | | | | | | |
| | Maintenance | | Environmental | | Growth Investments (b) | | Total |
| | (In millions) |
| Retail | $ | 4 |
| | $ | — |
| | $ | 16 |
| | $ | 20 |
|
| Generation | | | | | | | |
| Gulf Coast | 38 |
| | — |
| | — |
| | 38 |
|
East/West (a) | 9 |
| | — |
| | 109 |
| | 118 |
|
| Renewables | 1 |
| | — |
| | 142 |
| | 143 |
|
| NRG Yield | 8 |
| | — |
| | 10 |
| | 18 |
|
Corporate | 4 |
| | — |
| | 17 |
| | 21 |
|
| Total cash capital expenditures for the three months ended March 31, 2018 | 64 |
| | — |
| | 294 |
| | 358 |
|
| Funding from third party equity partners, cash grants and debt financing, net of fees | — |
| | — |
| | (169 | ) | | (169 | ) |
Other investments (c) | — |
| | — |
| | 62 |
| | 62 |
|
| Total capital expenditures and investments, net of financings | 64 |
| | — |
| | 187 |
| | 251 |
|
| | | | | | | | |
| Estimated capital expenditures for the remainder of 2018 | 157 |
| | 3 |
| | 206 |
| | 366 |
|
| Funding from third party equity partners, cash grants and debt financing, net of fees | — |
| | — |
| | (222 | ) | | (222 | ) |
Other investments (c) | — |
| | — |
| | 234 |
| | 234 |
|
NRG estimated capital expenditures for the remainder of 2018, net of financings (d) | $ | 157 |
| | $ | 3 |
| | $ | 218 |
| | $ | 378 |
|
(a) Includes International and BETM
Environmental(b) Total cash capital expenditures — For includes $17 million of cost-to-achieve spend associated with the nine months ended September 30, 2017, the Company's environmentalTransformation Plan
(c) Other investments include restricted cash activity and acquisitions
(d) Maintenance capital expenditures included DSI/ESP upgrades at the Powerton facility and the Joliet gas conversionincludes approximately $66 million for assets to satisfy CPS.be sold
Growth Investments capital expenditures — For the ninethree months ended September 30, 2017,March 31, 2018, the Company's growth investment capital expenditures included $245$152 million for solarrenewable projects, $241$114 million for repowering projects $65 million for wind projects and $37$28 million for the Company's other growth projects.
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 20172018 through 20212022 required to comply with environmental laws will be approximately $60$79 million, which includes $16$14 million for Midwest Generation. The increase from last quarter is driven primarily by the addition of the anticipated costs of adding NOx control equipment at certain of the Company's units in Connecticut.
Common Stock Dividends
The following table lists the dividends paid during the ninethree months ended September 30, 2017:March 31, 2018:
|
| | | | | | | | | | | |
| | Third Quarter 2017 | | Second Quarter 2017 | | First Quarter 2017 |
| Dividends per Common Share | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
|
|
| | | |
| | First Quarter 2018 |
| Dividends per Common Share | $ | 0.030 |
|
On October 18, 2017,April 19, 2018, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable NovemberMay 15, 2017,2018, to stockholders of record as of NovemberMay 1, 20172018 representing $0.12 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.regulations. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.
Share Repurchases
In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock, with the first $500 million program beginning as soon as permitted. In March 2018, the Company repurchased 3,114,748 shares of NRG common stock for approximately $93 million at an average cost of $29.75 per share.
Xoom Energy Acquisition
On March 27, 2018, the Company entered into an agreement to acquire XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for approximately $204 million in cash, plus estimated transaction costs of $6 million. The acquisition is expected to close in the second half of 2018.
Fuel Repowerings
Carlsbad — The table below lists the Company'sCompany is currently projected repowering and conversion projects. With respect to facilities that are currently operating, the timingoverseeing construction of the projects listed below could adversely impactCarlsbad project, which when completed will consist of approximately 527 MWs of net generation capacity. On February 6, 2018, the Company's operating revenues, gross margin and other operating costsCompany entered into an agreement with NRG Yield, Inc. to sell the Carlsbad project pursuant to the ROFO Agreement. The transaction is expected to close during the period priorfourth quarter of 2018.
Canal 3 — The Company is currently overseeing construction of the Canal 3 project, a dual-fueled peaking facility, which when completed will consist of approximately 333 MWs of net generating capacity. In January 2018, Final Notice To Proceed was issued, and construction commenced with an anticipated COD by summer 2019. On March 22, 2018, NRG agreed to the targeted COD.
|
| | | | | | | | |
Facility | Net Generation Capacity (MW) (b)
| | Project Type | | Fuel Type | | Targeted COD |
Repowerings | | | | | | | |
Carlsbad Peakers (formerly Encina) Units 1, 2, 3, 4, 5 and GT | 527 |
| | Growth | | Natural Gas | | Q4 2018 |
Puente (formerly Mandalay) Units 1 and 2(a)
| 262 |
| | Growth | | Natural Gas | | Q2 2020 |
Total Fuel Repowerings | 789 |
| | | | | | |
(a) See Regulatory Matterssell Canal 3 to Stonepeak Kestrel Holdings II LLC. The sale is expected to close early in the Management's Discussion and Analysis to this Form 10-Qthird quarter of 2018.
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for recent developments inpermitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that may impact the viability ofwould deny a permit for the Puente project.
(bPower Project. On JuneOctober 16, 2017, NRG Texas Power LLC provided noticefiled a motion to BTEC New Albany, LLC that itsuspend the permitting proceeding for at least six months, which was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31,granted on November 3, 2017. On July 14, 2017,April 20, 2018, NRG filed a motion requesting an additional extension of the Company gave noticesuspension period to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million undercoincide with the terminated MIPA, consistingCPUC’s final decision on SCE’s application seeking approval of $38 million in purchaser incurred costs and $10 million in liquidated damages.
resources procured through its Moorpark RFO, or until June 30, 2019, whichever is sooner.
Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative ninethree month periods:
|
| | | | | | | | | | | |
| | Nine months ended September 30, | | |
| | 2017 | | 2016 | | Change |
| | (In millions) |
| Net cash used by operating activities | $ | 806 |
| | $ | 1,741 |
| | $ | (935 | ) |
| Net cash used by investing activities | (765 | ) | | (255 | ) | | (510 | ) |
| Net cash provided by financing activities | 59 |
| | (587 | ) | | 646 |
|
|
| | | | | | | | | | | |
| | Three months ended March 31, | | |
| | 2018 | | 2017 | | Change |
| | (In millions) |
| Net cash provided/(used) by operating activities | $ | 357 |
| | $ | (67 | ) | | $ | 424 |
|
| Net cash used by investing activities | (432 | ) | | (281 | ) | | (151 | ) |
| Net cash used by financing activities | (49 | ) | | (153 | ) | | 104 |
|
Net Cash UsedProvided By Operating Activities
Changes to net cash usedprovided by operating activities were driven by:
|
| | | |
| | (In millions) |
| Changes in cash collateral in support of risk management activities due to changes in commodity prices | $ | (364 | ) |
| Decrease in operating income adjusted for non-cash items | (216 | ) |
| Decrease in other assets and liabilities | (127 | ) |
| Cash used by discontinued operations | (105 | ) |
| Decrease in accounts payable due to lower expenses and the timing of payments in 2017 compared to 2016. | (68 | ) |
| Increase in inventory due to lower generation in 2017, combined with earlier inventory purchases in the fourth quarter of 2015 for anticipated 2016 generation requirements | (64 | ) |
| Other | (35 | ) |
| Decrease in accounts receivable due to the timing of cash receipts in 2017 compared to 2016 | 44 |
|
| | $ | (935 | ) |
|
| | | |
| | (In millions) |
| Changes in cash collateral in support of risk management activities due to changes in commodity prices | $ | 290 |
|
| Increase in operating income adjusted for non-cash items | 87 |
|
| Other changes in working capital | 85 |
|
| Decrease in accounts receivable due to timing of cash receipts | 27 |
|
| Decrease in inventory as a result of initiatives related to the Transformation Plan | 13 |
|
| Change in cash from discontinued operations | (15 | ) |
| Decrease in accounts payable due to lower expenses in 2018 | (63 | ) |
| | $ | 424 |
|
Net Cash Used By Investing Activities
Changes to net cash used by investing activities were driven by:
|
| | | |
| | (In millions) |
| Cash used by discontinued operations | $ | (379 | ) |
| Decrease in maintenance and environmental capital expenditures, offset by an increase in growth capital expenditures | (101 | ) |
| Proceeds from sale of assets in 2016 compared to 2017 | (48 | ) |
| Increase in cash paid for acquisitions in 2017 compared to 2016 | (18 | ) |
| Other | (7 | ) |
| Net increase in emissions allowances activity | 43 |
|
| | $ | (510 | ) |
|
| | | |
| | (In millions) |
| Increase in capital expenditures for growth investments of $119 million primarily for solar and repowering projects | $ | (122 | ) |
| Increase in cash paid for acquisitions in 2018 compared to 2017 | (59 | ) |
| Decrease in insurance proceeds | (18 | ) |
| Other | (2 | ) |
| Increase in sales of emissions, net of purchases | 4 |
|
| Decrease in investments in unconsolidated affiliates | 14 |
|
| Change in cash from discontinued operations related to capital expenditures in 2017 | 32 |
|
| | $ | (151 | ) |
Net Cash Provided By Financing Activities
Changes to net cash provided by financing activities were driven by:
|
| | | |
| | (In millions) |
| Increase in borrowings, primarily related to Agua Caliente Borrower 1 & 2, 2038 Senior Notes and the Carlsbad Project Financing as well as reduced payments due to repurchases of Senior Notes in 2016 | $ | 538 |
|
| Increase due to purchase of preferred stock in 2016 | 226 |
|
| Increase in cash contributions, net of distributions from non-controlling interest in 2017 | 192 |
|
| Decrease in debt extinguishment cost | 98 |
|
| Decrease in payment of dividends, primarily related to reduction of NRG dividend rate in the first quarter of 2016 | 38 |
|
| Decrease in deferred debt issuance cost | 27 |
|
| Decrease in financing element related to acquired derivatives | (5 | ) |
| Payment for affiliate receivable | (125 | ) |
| Cash used by discontinued operations | (343 | ) |
| | $ | 646 |
|
|
| | | |
| | (In millions) |
| Change in cash from discontinued operations related to long term deposits in 2017 | $ | 132 |
|
| Increase in cash contributions, net of distributions from non-controlling interest in 2018, primarily related to tax equity financing | 115 |
|
| Other | 15 |
|
| Increase in debt payments of $51 million as well as a $14 million reduction in borrowings in 2018 | (65 | ) |
| Repurchase of common stock in 2018 | (93 | ) |
| | $ | 104 |
|
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the ninethree months ended September 30, 2017,March 31, 2018, the Company had a total domestic pre-tax book income of $112$233 million and a foreign pre-tax book incomeloss of $13$1 million. As of December 31, 2016,2017, the Company had cumulative domestic Federal NOL carryforwards of $3.4$2.8 billion, of which $1.2 billion is from GenOn Energy, Inc. and subsidiaries which will begin expiring in 2026 and cumulative state NOL carryforwards of $4.9$2.2 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $196$224 million, which do not have an expiration date. Contingent upon GenOn's emergence from bankruptcy, the Company will recognize an estimated $7.8$9.5 billion worthless stock deduction for tax purposes. The NOL balances of $1.2 billion will remain with the GenOn group of companies upon emergence from bankruptcy.
In addition to these amounts, the Company has $36$35 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily to state and local jurisdictions, of up to $25$20 million in 2017.2018.
The Company has recorded a non-current tax liability of $40$35 million until final resolution with the related taxing authority. The $40$35 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.
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 notno longer 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 prior to 2010. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior tobefore 2010.
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.
Retained or Contingent Interests
NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in equity investments — As of September 30, 2017March 31, 2018, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Several of these investments are variable interest entities for which NRG is not the primary beneficiary. See also Note 98, Variable Interest Entities, or VIEs, to this Form 10-Q.
NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $616$594 million as of September 30, 2017March 31, 2018. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 20162017 Form 10-K.
Contractual Obligations and Commercial Commitments
NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 20162017 Form 10-K. See also Note 87, Debt and Capital Leases, and Note 1514, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the three and nine months ended September 30, 2017March 31, 2018.
Fair Value of Derivative Instruments
NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities or retail load obligations. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG enters into interest rate swap agreements. The following disclosures about fair value of derivative instruments provide an update to, and should be read in conjunction with, Fair Value of Derivative Instruments in Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's 20162017 Form 10‑K.
The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at September 30, 2017March 31, 2018, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2017March 31, 2018.
|
| | | |
| Derivative Activity (Losses)/Gains | (In millions) |
| Fair Value of Contracts as of December 31, 2016 | $ | (128 | ) |
| Contracts realized or otherwise settled during the period | 21 |
|
| Changes in fair value | (41 | ) |
| Fair Value of Contracts as of September 30, 2017 | $ | (148 | ) |
|
| | | |
| Derivative Activity Gains | (In millions) |
| Fair Value of Contracts as of December 31, 2017 | $ | 46 |
|
| Contracts realized or otherwise settled during the period | 3 |
|
| Changes in fair value | 266 |
|
| Fair Value of Contracts as of March 31, 2018 | $ | 315 |
|
| | | | Fair Value of Contracts as of September 30, 2017 | Fair Value of Contracts as of March 31, 2018 |
| | Maturity | Maturity |
| Fair value hierarchy (Losses)/Gains | 1 Year or Less | | Greater than 1 Year to 3 Years | | Greater than 3 Years to 5 Years | | Greater than 5 Years | | Total Fair Value | 1 Year or Less | | Greater than 1 Year to 3 Years | | Greater than 3 Years to 5 Years | | Greater than 5 Years | | Total Fair Value |
| | (In millions) | (In millions) |
| Level 1 | $ | (34 | ) | | $ | (30 | ) | | $ | (5 | ) | | $ | — |
| | $ | (69 | ) | $ | (13 | ) | | $ | (39 | ) | | $ | (3 | ) | | $ | (1 | ) | | $ | (56 | ) |
| Level 2 | 11 |
| | (28 | ) | | (14 | ) | | — |
| | (31 | ) | 223 |
| | 139 |
| | 19 |
| | 12 |
| | 393 |
|
| Level 3 | (24 | ) | | (11 | ) | | (5 | ) | | (8 | ) | | (48 | ) | 15 |
| | (13 | ) | | (7 | ) | | (17 | ) | | (22 | ) |
| Total | $ | (47 | ) | | $ | (69 | ) | | $ | (24 | ) | | $ | (8 | ) | | $ | (148 | ) | $ | 225 |
| | $ | 87 |
| | $ | 9 |
| | $ | (6 | ) | | $ | 315 |
|
The Company has elected to present derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3 - Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of September 30, 2017,March 31, 2018, NRG's net derivative liabilityasset was $148$315 million, a decreasean increase to total fair value of $20$269 million as compared to December 31, 2016.2017. This decreaseincrease was driven by lossesgains in fair value largely offset byand the roll-off of trades that settled during the period.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $39$6 million in the net value of derivatives as of September 30, 2017.March 31, 2018. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in a decrease of approximately $62$11 million in the net value of derivatives as of September 30, 2017.March 31, 2018.
Critical Accounting Policies and Estimates
NRG's discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.
On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.
The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. NRG's critical accounting policies include derivative instruments, income taxes and valuation allowance for deferred tax assets, impairment of long lived assets and investments, goodwill and other intangible assets, and contingencies.
The Company performs its annual test of goodwill impairment during the fourth quarter. The Company tests its long-lived assets for impairment whenever indicators of impairment exist. The Company’sCompany's annual budget is utilized to determine the cash flows associated with the Company’sCompany's long-lived assets, which incorporates various assumptions, including the Company’sCompany's long-term view of natural gas prices and its impact on merchant power prices and fuel costs. The Company’sCompany's annual budget process is finalized and approved by the Board of Directors in the fourth quarter. It is reasonably possible that the updated long term cash flows will not support the carrying value of certain assets, and the Company will be required to test such assets for impairment. This could also have a negative impact on the fair value of the reporting units that have goodwill balances. This decrease in power prices could also result in an adverse change in the manner that long-livedlong-live assets are used, or result in the Company selling an asset before the end of its previously estimated useful life, at a price that is lower than its carrying amount. During the preparation of the budget, the Company noted that management’s view of long term merchant power prices has decreased, and accordingly,Accordingly, if these decreases continue, it is reasonably possible that certain of the Company's goodwill and/or long-lived assets will be significantly impaired during the fourth quarter of 2017.
impaired.
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A — Quantitative and Qualitative Disclosures About Market Risk, of the Company's 20162017 Form 10-K.
Commodity Price Risk
Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities and correlations between various commodities, such as natural gas, electricity, coal, oil and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of its energy assets and liabilities, which includes generation assets, load obligations and bilateral physical and financial transactions.
The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions, calculated using the VaR model for the three and nine months endedending September 30, 2017March 31, 2018 and 20162017:
| | | (In millions) | 2017 | | 2016 | 2018 | | 2017 |
| VaR as of September 30, | $ | 40 |
| | $ | 40 |
| |
| Three months ended September 30, | | | | |
| VaR as of March 31, | | $ | 58 |
| | $ | 60 |
|
| Three months ended March 31, | | | | |
| Average | $ | 30 |
| | $ | 59 |
| $ | 58 |
| | $ | 52 |
|
| Maximum | 40 |
| | 72 |
| 69 |
| | 60 |
|
| Minimum | 25 |
| | 40 |
| 48 |
| | 41 |
|
| Nine months ended September 30, | | | | |
| Average | $ | 27 |
| | $ | 58 |
| |
| Maximum | 40 |
| | 72 |
| |
| Minimum | 20 |
| | 40 |
| |
In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of September 30, 2017March 31, 2018, for the entire term of these instruments entered into for both asset management and trading was $17$19 million, primarily driven by asset-backed transactions.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.
The Company's project subsidiaries enter into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. See Note 12, Debt and Capital Leases, of the Company's 20162017 Form 10-K for more information on the Company's interest rate swaps.
If all of the above swaps had been discontinued on September 30, 2017March 31, 2018, the Company would have owed the counterparties $4364 million. Based on the credit ratings of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.
NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of September 30, 2017March 31, 2018, a 1% change in variable interest rates would result in a $13.814.5 million change in interest expense on a rolling twelve month basis.
As of September 30, 2017March 31, 2018, the fair value and related carrying value of the Company's debt was $17.4$16.7 billion and $17.1$16.6 billion respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $984$930 million.
Liquidity Risk
Liquidity risk arises from the general funding needs of NRG's activities and in the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.
Based on a sensitivity analysis for power and gas positions under marginable contracts, a $0.50 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $16454 million as of September 30, 2017March 31, 2018, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $14937 million as of September 30, 2017March 31, 2018. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2017March 31, 2018.
Credit Risk
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. See Note 4, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 6, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.
Currency Exchange Risk
NRG's foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not hedge. As these earnings and investments are not material to NRG's consolidated results, the Company's foreign currency exposure is limited.
ITEM 4 — CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.
Changes in Internal Control over Financial Reporting
Effective January 1, 2018, NRG adopted ASC 606, Revenue from Contracts with Customers. Changes were made to relevant business processes and related control activities in order to monitor and maintain controls over financial reporting. There were no other changes in NRG’sNRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred induring the third quarter of 2017ended March 31, 2018, that materially affected, or are reasonably likely to materially affect, NRG’sNRG's internal control over financial reporting.
PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through September 30, 2017March 31, 2018, see Note 1514, Commitments and Contingencies, to this Form 10-Q.
ITEM 1A — RISK FACTORS
Information regarding risk factors appears in Part I, Item 1A, Risk Factors Related to NRG Energy, Inc., in the Company's 20162017 Form 10-K, and Part II, Item 1A of the Company's Form 10-Q for the quarter ended June 30, 2017.10-K. There have been no material changes in the Company's risk factors since those reported in its 20162017 Form 10‑K and its Form 10-Q for the quarter ended June 30, 2017.K.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock, with the first $500 million program beginning as soon as permitted. The authorization did not specify an expiration date.
The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act), of NRG's common stock during the quarter ended March 31, 2018.
|
| | | | | | | | | | | | | | |
| For the three months ended March 31, 2018 | | Total Number of Shares Purchased | | Average Price Paid per Share(a) | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(b) |
| Month #1 | | | | | | | | |
| (January 1, 2018 to January 31, 2018) | | — |
| | $ | — |
| | — |
| | $ | — |
|
| Month #2 | | | | | | | | |
| (February 1, 2018 to February 28, 2018) | | — |
| | $ | — |
| | — |
| | $ | — |
|
| Month #3 | | | | | | | | |
| (March 1, 2018 to March 31, 2018) | | 3,114,748 |
| | $ | 29.75 |
| | 3,114,748 |
| | $ | 907,314,521 |
|
| Total | | 3,114,748 |
| | | | 3,114,748 |
| | |
(a) The average price paid per share excludes commissions of $0.01 per share paid in connection with the share repurchases.
(b) Includes commissions of $0.01 per share paid in connection with the share repurchases.
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
See Note 3, Discontinued Operations Dispositions and AcquisitionsDispositions, to the Condensed Consolidated Financial Statements of thisthe Company's 2017 Form 10-Q,10-K, for a description of events of default by GenOn and GenOn Americas Generation under the GenOn Senior Notes and the GenOn Americas Generation Senior Notes.
ITEM 4 — MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5 — OTHER INFORMATION
None.
ITEM 6 — EXHIBITS
|
| | | | |
| Number | | Description | | Method of Filing |
| 10.1 | | Amended and Restated Backstop Commitment Letter,Second Amendment Agreement, dated as of October 2, 2017,March 21, 2018, by and among GenOnNRG Energy, Inc., GenOn Americas Generation, LLC, the guarantors partylenders from time to time parties thereto and backstop parties thereto.Citicorp North America, Inc., as administrative agent and collateral agent. | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on October 6, 2017. |
10.2 | | First Amendment, dated as of October 2, 2017, to the Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, NRG Energy, Inc. and the consenting noteholders party thereto. | | Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on October 6, 2017. |
10.3 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 1, 2017.March 22, 2018. |
| 31.1 | | | | Filed herewith. |
| 31.2 | | | | Filed herewith. |
| 31.3 | | | | Filed herewith. |
| 32 | | | | Furnished herewith. |
| 101 INS | | XBRL Instance Document. | | Filed herewith. |
| 101 SCH | | XBRL Taxonomy Extension Schema. | | Filed herewith. |
| 101 CAL | | XBRL Taxonomy Extension Calculation Linkbase. | | Filed herewith. |
| 101 DEF | | XBRL Taxonomy Extension Definition Linkbase. | | Filed herewith. |
| 101 LAB | | XBRL Taxonomy Extension Label Linkbase. | | Filed herewith. |
| 101 PRE | | XBRL Taxonomy Extension Presentation Linkbase. | | Filed herewith. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
| | | | |
| | NRG ENERGY, INC. (Registrant) | |
| | | |
| | /s/ MAURICIO GUTIERREZ | |
| | Mauricio Gutierrez | |
| | Chief Executive Officer (Principal Executive Officer) | |
| |
| | | |
| | /s/ KIRKLAND B. ANDREWS | |
| | Kirkland B. Andrews | |
| | Chief Financial Officer (Principal Financial Officer) | |
| |
| | | |
| | /s/ DAVID CALLEN | |
| | David Callen | |
Date: November 2, 2017May 3, 2018 | Chief Accounting Officer (Principal Accounting Officer) | |
| |