UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 | ||
FORM 8‑K CURRENT REPORT | ||
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 | ||
Date of Report (Date of earliest event reported): February 28, 2017 | ||
NRG ENERGY, INC. (Exact name of Registrant as specified in its charter) | ||
Delaware (State or other jurisdiction of incorporation) | 001‑15891 (Commission File Number) | 41-1724239 (IRS Employer Identification No.) |
804 Carnegie Center, Princeton, New Jersey 08540 (Address of principal executive offices, including zip code) | ||
(609) 524‑4500 (Registrant’s telephone number, including area code) | ||
N/A (Former name or former address, if changed since last report) Check the appropriate box below if the Form 8‑K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions: [ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) [ ] Soliciting material pursuant to Rule 14a‑12 under the Exchange Act (17 CFR 240.14a‑12) [ ] Pre‑commencement communications pursuant to Rule 14d‑2(b) under the Exchange Act (17 CFR 240.14d‑2(b)) [ ] Pre‑commencement communications pursuant to Rule 13e‑4(c) under the Exchange Act (17 CFR 240.13e‑4(c)) | ||
Item 2.02 Results of Operations and Financial Condition
On February 28, 2017, NRG Energy, Inc. issued a press release announcing its financial results for the year ended December 31, 2016. A copy of the press release is furnished as Exhibit 99.1 to this report on Form 8-K and is hereby incorporated by reference.
Item 9.01 Financial Statements and Exhibits
(d) | Exhibits |
Exhibit Number | Document | |
99.1 | Press Release, dated February 28, 2017 | |
2
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 hereunto duly authorized.
NRG Energy, Inc. | ||
(Registrant) | ||
By: | /s/ Brian E. Curci | |
Brian E. Curci | ||
Corporate Secretary | ||
Dated: February 28, 2017 | ||
3
Exhibit Index
Exhibit Number | Document | |
99.1 | Press Release, dated February 28, 2017 | |
4
Exhibit 99.1
NRG Energy, Inc. Reports 2016 Results,
Reaffirms 2017 Financial Guidance
• | Delivered strong 2016 Adjusted EBITDA, cash from operations and Free Cash Flow before Growth (FCFbG) |
• | Reaffirming 2017 Adjusted EBITDA, Cash From Operations and FCFbG guidance |
• | Corporate debt reduction and preferred stock redemption throughout 2016 under the current program totaled $1.0 billion; approximately $100 million1 of recurring FCFbG |
• | Exceeded the targeted $400 million in cost reductions by over $100 million, ahead of the anticipated 2017 time frame |
• | Executed agreements with NRG Yield to drop down 311 net MWs of utility-scale solar assets for total cash consideration of $130 million2 and expanded Right of First Offer (ROFO) pipeline by 234 net MW; raised another $128 million3 through non-recourse financing at Agua Caliente |
• | 2.2 GW of coal-to-gas conversions and Petra Nova Project completed on time and on budget |
• | Recorded $1.2 billion non-cash asset and goodwill impairment charge |
PRINCETON, NJ - February 28, 2017 - NRG Energy, Inc. (NYSE: NRG) today reported full year 2016 net loss of $891 million, or $2.22 per diluted common share. The loss and resulting loss per share were driven by a $1.2 billion impairment of goodwill and fixed assets as forecasted gas and power prices continue to decline. Adjusted EBITDA for the full year 2016 was $3.3 billion, cash from operations was $2.1 billion and FCFbG was $1.2 billion. Additionally, NRG realized its second best safety year in company history with a full year top decile recordable rate of 0.624.
“Our business delivered a year of strong results, both EBITDA and Free Cash Flow, driven by Retail, which had a record 2016 adjusted EBITDA and its third consecutive year of EBITDA growth,” said Mauricio Gutierrez, NRG President and Chief Executive Officer. “Our focus on strategic priorities and strong execution in 2016 sets the foundation for 2017, allowing us to seize market opportunities while continuing to streamline the business, strengthen the balance sheet and deliver value to shareholders.”
Consolidated Financial Results
Three Months Ended | Twelve Months Ended | |||||||||||||||
($ in millions) | 12/31/16 | 12/31/15 | 12/31/16 | 12/31/15 | ||||||||||||
Net Loss | $ | (1,055 | ) | $ | (6,358 | ) | $ | (891 | ) | $ | (6,436 | ) | ||||
Cash From Operations | $ | 339 | $ | (83 | ) | $ | 2,072 | $ | 1,309 | |||||||
Adjusted EBITDAa | $ | 492 | $ | 582 | $ | 3,257 | $ | 3,166 | ||||||||
Free Cash Flow Before Growth (FCFbG) | $ | 78 | $ | (8 | ) | $ | 1,209 | $ | 1,127 | |||||||
a. | For comparability, 2015 results have been restated to include the negative contribution from Residential Solar of $43 million and $173 million for the three and twelve months ended December 31, 2015. |
1 $100 million savings driven by reduction of debt since 3rd quarter of 2015, preferred stock redemption and extension of maturities at lower interest rates
2 Subject to working capital and other adjustments
3 Net of financing fees
4 Excludes Goal Zero, NRG Home Services and Residential Solar
Segment Results
As part of its streamlining strategy, NRG has realigned its reporting segments to more clearly report Generation and Retail activities. Accordingly, customer-facing businesses will now reside in the Retail segment. The Company's Retail segment will now include Business Solutions which includes Commercial & Industrial (C&I) previously in Generation, and the Generation segment now includes BETM. The results of the Company have been recast to reflect these changes.
Table 1: Net (Loss)/Income
($ in millions) | Three Months Ended | Twelve Months Ended | ||||||||||||||
Segment | 12/31/16 | 12/31/15 | 12/31/16 | 12/31/15 | ||||||||||||
Generation | $ | (889 | ) | $ | (4,690 | ) | $ | (507 | ) | $ | (4,446 | ) | ||||
Retail | 316 | 161 | 1,045 | 624 | ||||||||||||
Renewables a | (204 | ) | (18 | ) | (306 | ) | (92 | ) | ||||||||
NRG Yield a | (126 | ) | 12 | (15 | ) | 65 | ||||||||||
Corporate b | (152 | ) | (1,823 | ) | (1,108 | ) | (2,587 | ) | ||||||||
Net Loss c | $ | (1,055 | ) | $ | (6,358 | ) | $ | (891 | ) | $ | (6,436 | ) | ||||
a. | In accordance with GAAP, 2015 results have been restated to include full impact of the assets in the NRG Yield Drop Down transactions which closed on November 3, 2015, and September 1, 2016. |
b. | Includes Residential Solar. |
c. | Includes mark-to-market gains and losses of economic hedges. |
The net loss for the twelve months of 2016 was driven by a $1.2 billion impairment of goodwill and fixed assets as forecasted gas and power prices continue to decline. The net loss for the twelve months of 2015 includes non-cash charges of $3.3 billion5 and $3.0 billion for asset impairments net of taxes and income tax valuation allowance expense, respectively.
Table 2: Adjusted EBITDA
($ in millions) | Three Months Ended | Twelve Months Ended | ||||||||||||||
Segment | 12/31/16 | 12/31/15 | 12/31/16 | 12/31/15 | ||||||||||||
Generation a | $ | 160 | $ | 300 | $ | 1,505 | $ | 1,759 | ||||||||
Retail | 134 | 149 | 811 | 793 | ||||||||||||
Renewables b | 26 | 27 | 187 | 158 | ||||||||||||
NRG Yield b | 207 | 189 | 899 | 758 | ||||||||||||
Corporate c | (35 | ) | (83 | ) | (145 | ) | (302 | ) | ||||||||
Adjusted EBITDA d | $ | 492 | $ | 582 | $ | 3,257 | $ | 3,166 | ||||||||
a. | See Appendices A-6 through A-9 for Generation regional Reg G results. |
b. | In accordance with GAAP, 2015 results have been restated to include full impact of the assets in the NRG Yield Drop Down transactions which closed on November 3, 2015, and September 1, 2016. |
c. | 2016 includes Residential Solar. 2015 results have been restated to include negative contribution of $43 million and $173 million for the three and twelve months ended December 31, 2015, respectively. |
d. | See Appendices A-1 through A-4 for Operating Segment Reg G results. |
Generation: Full year 2016 Adjusted EBITDA was $1.5 billion, $254 million lower than 2015 primarily driven by:
• | Gulf Coast Region: $93 million decrease due to lower average realized energy margins in Texas from the decline in power prices, offset by lower operating costs. |
• | East Region: $365 million decrease from lower dispatch and capacity prices, partially offset by the monetization of forward hedges and lower operating costs on decreased run times, deactivations and plant sales. |
• | West Region: $122 million increase due to gains from sale of real property at Potrero site, emission credit sales and lower operating costs, partially offset by lower capacity revenues. |
• | Other Generation: $82 million increase driven by favorable trading results at BETM. |
Fourth quarter Adjusted EBITDA was $160 million, $140 million lower than the fourth quarter 2015 primarily driven by:
• | Gulf Coast Region: $22 million decrease due to lower realized energy margins in Texas. |
• | East Region: $128 million lower due to lower realized energy margins and lower capacity prices. |
5 Total impairments of $5.1 billion net of taxes of $1.8 billion
2
• | West Region: $11 million increase due to higher capacity revenues and lower operating costs. |
Retail: Full year 2016 Adjusted EBITDA was $811 million, $18 million higher than 2015 driven by lower costs, increased retail margins and favorable settlement of a Texas sales tax audit, partially offset by unfavorable impacts from selling back excess supply due to milder weather conditions in 2016 as compared to 2015 and lower volumes driven by lower average customer usage.
Fourth quarter Adjusted EBITDA was $134 million, $15 million lower than the fourth quarter 2015 due primarily to an increase in spend associated with customer growth initiatives.
Renewables: Full year 2016 Adjusted EBITDA was $187 million, $29 million higher than 2015 due mainly to increased generation at Ivanpah and Mountain Wind and lower operating expenses while fourth quarter Adjusted EBITDA was $1 million higher than the prior year due primarily to increased generation at Ivanpah.
NRG Yield: Full year 2016 Adjusted EBITDA was $899 million, $141 million higher than 2015 due primarily to increased wind production from Renewables, full year contributions from the acquisitions of Desert Sunlight and Spring Canyon which closed in 2015, and a receipt of insurance proceeds from a 2014 wind outage claim.
Fourth quarter Adjusted EBITDA was $207 million, $18 million higher than the fourth quarter 2015 due primarily to increased production in the Renewables segment and a receipt of insurance proceeds from a 2014 wind outage claim.
Corporate: Full year 2016 Adjusted EBITDA was $(145) million, $157 million better than 2015 due to reduced operating expenses at Residential Solar and other expense reductions, also driving the fourth quarter Adjusted EBITDA which was $48 million favorable to 2015.
Liquidity and Capital Resources
Table 3: Corporate Liquidity
($ in millions) | 12/31/16 | 12/31/15 | ||||||
Cash at NRG-Level a | $ | 570 | $ | 693 | ||||
Revolver | 1,217 | 1,373 | ||||||
NRG-Level Liquidity | $ | 1,787 | $ | 2,066 | ||||
Restricted cash | 446 | 414 | ||||||
Cash at Non-Guarantor Subsidiaries | 1,403 | 825 | ||||||
Total Liquidity | $ | 3,636 | $ | 3,305 | ||||
a. | December 31, 2016, balance includes $247 million of unrestricted cash held at Midwest Generation (a non-guarantor subsidiary) which can be distributed to NRG without limitation. |
NRG-Level cash as of December 31, 2016, was $570 million, a decrease of $123 million from the end of 2015, and $1.2 billion was available under the Company’s credit facilities at the end of 2016. Total liquidity was $3.6 billion, including restricted cash and cash at non-guarantor subsidiaries (primarily GenOn and NRG Yield).
NRG Strategic Developments
Drop Down Assets and Expanded ROFO Pipeline
In December 2016, NRG offered NRG Yield the opportunity to purchase the following assets: (i) the Minnesota Portfolio, a 40 MW portfolio of wind projects; (ii) the 30 MW Community wind projects; (iii) the 50 MW Jeffers wind projects; and (iv) a 16% interest in the 290 MW Agua Caliente solar facility, pursuant to the ROFO Agreement. In addition to these ROFO Assets, NRG also offered NRG Yield the opportunity to purchase NRG's 50% interests in seven utility-scale solar projects located in Utah, representing 265 net MW of capacity6.
On February 24, 2017, NRG entered into a definitive agreement with NRG Yield to drop down the Agua Caliente and Utah utility-scale solar projects (311 net MW) for cash consideration of $130 million, plus assumed non-recourse project debt of approximately $464 million7, excluding working capital and other adjustments. Details of the projects, which are expected to close in the second quarter of 2017, include:
• | A 16% interest (approximately 31% of NRG's 51% interest) in the Agua Caliente solar project, one of the ROFO Assets, representing ownership of approximately 46 net MW of capacity. Prior to the agreement, on February 17, 2017, NRG decreased its equity investment through an incremental $128 million non-recourse project-level note, after fees, all of which was distributed to NRG. |
6 Reflects NRG's net interest based on cash to be distributed in tax equity partnership with Dominion
7 Approximately $328 million on balance sheet and $136 million pro-rata share of unconsolidated debt
3
• | NRG's 50% interest in seven utility-scale solar projects located in Utah representing 265 net MW of capacity. NRG acquired the Utah assets in November 2016 for upfront cash consideration of $111 million and subsequent to closing reduced the effective cash consideration paid to $63 million as a result of additional non-recourse project-level financings of $48 million8 during the fourth quarter of 2016. |
NRG Yield elected not to pursue the acquisition of the Minnesota, Community and Jeffers wind projects at this time, but may continue its evaluation of the projects. NRG Yield has retained the right with NRG, pursuant to the ROFO Agreement, to participate in any third party process to the extent NRG elected to pursue a third party sale of these assets.
In connection with the execution of the definitive agreement, NRG and NRG Yield entered into an amendment to the ROFO Agreement 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 with a 25-year PPA with City of Georgetown |
• | The Hawaii Solar projects, which have a combined capacity of 80 net MW with an average PPA of 22 years with the Hawaiian Electric Company9 |
Fleet Optimizations
NRG achieved a significant milestone in its fleet optimization strategy, completing coal-to-gas projects at three generation facilities across its fleet. The modified units can generate approximately 2.2 GW. The three plants include the Joliet Generating Station (three units converted by fourth quarter 2016 for a total of 1,326 MW), the Shawville Generating Station (all four units are currently in final commissioning following modification for a total of 597 MW) and the New Castle Generating Station, (all three units have been modified by second quarter 2016 for a total of 325 MW).
Over 2016, NRG continued to grow renewables development opportunities with acquisitions of 1.7GW of wind and solar assets. As of December 2016, NRG held 543 MW of backlog in execution across the utility wind and solar, community solar and DG solar businesses. Over the fourth quarter 2016, NRG accelerated utility project origination across CAISO, ERCOT and ISO-NE, growing the project pipeline to approximately 3.3 GW, a 25% increase over the previous quarter. NRG successfully transitioned 2.7 GW of the combined NRG and NYLD fleet (approximately 26 wind and 7 solar projects) to self-perform operations in 2016, including Alta and CVSR.
On December 29, 2016, NRG completed, on time and on budget, construction and final acceptance of performance testing at the Petra Nova project, the world's largest post-combustion carbon capture system. During performance testing, the facility captured more than 90% of CO2 from a 240 MW equivalent slipstream of flue gas off an existing coal-fueled electrical generating unit at the WA Parish power plant in Fort Bend County, southwest of Houston. At this level of operation, Petra Nova can capture more than 5,000 tons of CO2 per day, which is the equivalent of taking more than 350,000 cars off the road.
In 2016, NRG completed the installation of environmental control upgrades at its 638 MW Avon Lake Unit 9 facility (COD June 2016) and its 1,538 MW Powerton coal facility (COD December 2016).
2017 Guidance
NRG is reaffirming its guidance range for 2017 with respect to Adjusted EBITDA, cash from operations and FCFbG as set forth below.
Table 4: 2017 Adjusted EBITDA and FCF before Growth Guidance
2017 | ||
($ in millions) | Guidance | |
Adjusted EBITDAa | $2,700 - $2,900 | |
Cash From Operations | $1,355 - $1,555 | |
Free Cash Flow - before Growth | $800 - $1,000 | |
a. | Non-GAAP financial measure; see Appendix Table A-11 for GAAP Reconciliation to Net Income that excludes fair value adjustments related to derivatives. The Company is unable to provide guidance for Net Income due to the impact of such fair value adjustments related to derivatives in a given year. |
8 Net of final construction costs and financing fees
9 61 of the 80 MWs have been contracted as of February 28, 2017
4
Capital Allocation Update
On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%. In 2016, NRG reduced corporate debt by $792 million10. Combined with the debt repurchases in 2015 and the extension of debt maturities at a lower average coupon rate, NRG has realized annual interest savings of approximately $87 million, plus an additional $10 million in dividend savings from the repurchase of 100% of its outstanding $345 million, 2.822% convertible perpetual preferred stock. NRG is also announcing $200 million of additional capital reserved for debt reduction bringing total 2017 allocation to discretionary debt reduction to $600 million.
On January 18, 2017, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable February 15, 2017, to stockholders of record as of February 1, 2017, representing $0.12 on an annualized basis.
The Company’s common stock dividend, corporate level debt reduction and share repurchases are subject to available capital, market conditions and compliance with associated laws and regulations.
Earnings Conference Call
On February 28, 2017, NRG will host a conference call at 8:00 a.m. Eastern to discuss these results. Investors, the news media and others may access the live webcast of the conference call and accompanying presentation materials by logging on to NRG’s website at http://www.nrg.com and clicking on “Investors.” The webcast will be archived on the site for those unable to listen in real time.
About NRG
NRG is the leading integrated power company in the U.S., built on the strength of the nation’s largest and most diverse competitive electric generation portfolio and leading retail electricity platform. A Fortune 200 company, NRG creates value through best in class operations, reliable and efficient electric generation, and a retail platform serving residential and commercial customers. Working with electricity customers, large and small, we continually innovate, embrace and implement sustainable solutions for producing and managing energy. We aim to be pioneers in developing smarter energy choices and delivering exceptional service as our retail electricity providers serve almost 3 million residential and commercial customers throughout the country. More information is available at www.nrg.com. Connect with NRG Energy on Facebook and follow us on Twitter @nrgenergy.
Safe Harbor Disclosure
In addition to historical information, the information presented in this communication includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. These statements involve estimates, expectations, projections, goals, assumptions, known and unknown risks and uncertainties and can typically be identified by terminology such as “may,” “should,” “could,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “expect,” “intend,” “seek,” “plan,” “think,” “anticipate,” “estimate,” “predict,” “target,” “potential” or “continue,” or the negative of these terms or other comparable terminology. Such forward-looking statements include, but are not limited to, statements about the Company’s future revenues, income, indebtedness, capital structure, plans, expectations, objectives, projected financial performance and/or business results and other future events, and views of economic and market conditions.
Although NRG believes that its expectations are reasonable, it can give no assurance that these expectations will prove to be correct, and actual results may vary materially. Factors that could cause actual results to differ materially from those contemplated herein include, among others, general economic conditions, hazards customary in the power industry, weather conditions, including wind and solar performance, competition in wholesale power markets, the volatility of energy and fuel prices, failure of customers to perform under contracts, changes in the wholesale power markets, changes in government regulations, the condition of capital markets generally, our ability to access capital markets, unanticipated outages at our generation facilities, adverse results in current and future litigation, failure to identify, execute or successfully implement acquisitions, repowerings or asset sales, our ability to implement value enhancing improvements to plant operations and companywide processes, our ability to proceed with projects under development or the inability to complete the construction of such projects on schedule or within budget, risks related to project siting, financing, construction, permitting, government approvals and the negotiation of project development agreements, our ability to
10 Cash cost of $874 million, including $120 million of debt extinguishment fees; Additional 2015 corporate debt reduction of $246 MM (cash cost of $226 MM) completed in 2015 bringing total debt reduction under program to $1 billion
5
progress development pipeline projects, GenOn’s ability to continue as a going concern, our ability to obtain federal loan guarantees, the inability to maintain or create successful partnering relationships, our ability to operate our businesses efficiently including NRG Yield, our ability to retain retail customers, our ability to realize value through our commercial operations strategy and the creation of NRG Yield, the ability to successfully integrate businesses of acquired companies, our ability to realize anticipated benefits of transactions (including expected cost savings and other synergies) or the risk that anticipated benefits may take longer to realize than expected, our ability to close the Drop Down transactions with NRG Yield, and our ability to execute our Capital Allocation Plan. Debt and share repurchases may be made from time to time subject to market conditions and other factors, including as permitted by United States securities laws. Furthermore, any common stock dividend is subject to available capital and market conditions.
NRG undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. The adjusted EBITDA and free cash flow guidance are estimates as of February 28, 2017. These estimates are based on assumptions the company believed to be reasonable as of that date. NRG disclaims any current intention to update such guidance, except as required by law. The foregoing review of factors that could cause NRG’s actual results to differ materially from those contemplated in the forward-looking statements included in this Earnings press release should be considered in connection with information regarding risks and uncertainties that may affect NRG’s future results included in NRG’s filings with the Securities and Exchange Commission at www.sec.gov.
###
Contacts:
Media: | Investors: | ||
Marijke Shugrue | Kevin L. Cole, CFA | ||
609.524.5262 | 609.524.4526 | ||
Lindsey Puchyr | |||
609.524.4527 | |||
6
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Year Ended December 31, | |||||||||||
(In millions, except per share amounts) | 2016 | 2015 | 2014 | ||||||||
Operating Revenues | |||||||||||
Total operating revenues | $ | 12,351 | $ | 14,674 | $ | 15,868 | |||||
Operating Costs and Expenses | |||||||||||
Cost of operations | 8,555 | 10,784 | 11,808 | ||||||||
Depreciation and amortization | 1,367 | 1,566 | 1,523 | ||||||||
Impairment losses | 918 | 5,030 | 97 | ||||||||
Selling, general and administrative | 1,101 | 1,199 | 1,016 | ||||||||
Acquisition-related transaction and integration costs | 8 | 10 | 84 | ||||||||
Development costs | 90 | 146 | 88 | ||||||||
Total operating costs and expenses | 12,039 | 18,735 | 14,616 | ||||||||
Gain on sale of assets | 215 | — | 19 | ||||||||
Gain on postretirement benefits curtailment | — | 21 | — | ||||||||
Operating Income/(Loss) | 527 | (4,040 | ) | 1,271 | |||||||
Other Income/(Expense) | |||||||||||
Equity in earnings of unconsolidated affiliates | 27 | 36 | 38 | ||||||||
Impairment losses on investments | (268 | ) | (56 | ) | — | ||||||
Other income, net | 42 | 33 | 22 | ||||||||
(Loss)/gain on sale of equity method investment | — | (14 | ) | 18 | |||||||
Net (loss)/gain on debt extinguishment | (142 | ) | 75 | (95 | ) | ||||||
Interest expense | (1,061 | ) | (1,128 | ) | (1,119 | ) | |||||
Total other expense | (1,402 | ) | (1,054 | ) | (1,136 | ) | |||||
(Loss)/Income Before Income Taxes | (875 | ) | (5,094 | ) | 135 | ||||||
Income tax expense | 16 | 1,342 | 3 | ||||||||
Net (Loss)/Income | (891 | ) | (6,436 | ) | 132 | ||||||
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests | (117 | ) | (54 | ) | (2 | ) | |||||
Net (Loss)/Income Attributable to NRG Energy, Inc. | (774 | ) | (6,382 | ) | 134 | ||||||
Dividends for preferred shares | 5 | 20 | 56 | ||||||||
Gain on redemption of preferred shares | (78 | ) | — | — | |||||||
(Loss)/Income Available for Common Stockholders | $ | (701 | ) | $ | (6,402 | ) | $ | 78 | |||
(Loss)/Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders | |||||||||||
Weighted average number of common shares outstanding — basic | 316 | 329 | 334 | ||||||||
Net (Loss)/Income per Weighted Average Common Share — Basic | $ | (2.22 | ) | $ | (19.46 | ) | $ | 0.23 | |||
Weighted average number of common shares outstanding — diluted | 316 | 329 | 339 | ||||||||
Net (Loss)/Income per Weighted Average Common Share — Diluted | $ | (2.22 | ) | $ | (19.46 | ) | $ | 0.23 | |||
Dividends Per Common Share | $ | 0.24 | $ | 0.58 | $ | 0.54 | |||||
7
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
For the Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In millions) | |||||||||||
Net (Loss)/Income | $ | (891 | ) | $ | (6,436 | ) | $ | 132 | |||
Other Comprehensive Income/(Loss), net of tax | |||||||||||
Unrealized gain/(loss) on derivatives, net of income tax expense/(benefit) of $1, $19, and $(21) | 35 | (15 | ) | (45 | ) | ||||||
Foreign currency translation adjustments, net of income tax benefit of $0, $0, and $5 | (1 | ) | (11 | ) | (8 | ) | |||||
Available-for-sale securities, net of income tax benefit of $0, $3, and $2 | 1 | 17 | (7 | ) | |||||||
Defined benefit plan, net of income tax expense/(benefit) of $0, $69, and $(88) | 3 | 10 | (129 | ) | |||||||
Other comprehensive income/(loss) | 38 | 1 | (189 | ) | |||||||
Comprehensive Loss | (853 | ) | (6,435 | ) | (57 | ) | |||||
Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests | (117 | ) | (73 | ) | 8 | ||||||
Comprehensive Loss Attributable to NRG Energy, Inc. | (736 | ) | (6,362 | ) | (65 | ) | |||||
Dividends for preferred shares | 5 | 20 | 56 | ||||||||
Gain on redemption of preferred shares | (78 | ) | — | — | |||||||
Comprehensive Loss Available for Common Stockholders | $ | (663 | ) | $ | (6,382 | ) | $ | (121 | ) | ||
8
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31, | |||||||
2016 | 2015 | ||||||
(In millions) | |||||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | $ | 1,973 | $ | 1,518 | |||
Funds deposited by counterparties | 2 | 106 | |||||
Restricted cash | 446 | 414 | |||||
Accounts receivable — trade | 1,166 | 1,157 | |||||
Inventory | 1,111 | 1,252 | |||||
Derivative instruments | 1,062 | 1,915 | |||||
Cash collateral posted in support of energy risk management activities | 203 | 568 | |||||
Current assets held-for-sale | 9 | 6 | |||||
Prepayments and other current assets | 423 | 455 | |||||
Total current assets | 6,395 | 7,391 | |||||
Property, plant and equipment, net | 17,912 | 18,732 | |||||
Other Assets | |||||||
Equity investments in affiliates | 1,120 | 1,045 | |||||
Notes receivable, less current portion | 17 | 53 | |||||
Goodwill | 662 | 999 | |||||
Intangible assets, net | 2,036 | 2,310 | |||||
Nuclear decommissioning trust fund | 610 | 561 | |||||
Derivative instruments | 189 | 305 | |||||
Deferred income taxes | 225 | 167 | |||||
Non-current assets held-for-sale | 10 | 105 | |||||
Other non-current assets | 1,179 | 1,214 | |||||
Total other assets | 6,048 | 6,759 | |||||
Total Assets | $ | 30,355 | $ | 32,882 | |||
9
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued)
As of December 31, | |||||||
2016 | 2015 | ||||||
(In millions, except share data) | |||||||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current Liabilities | |||||||
Current portion of long-term debt and capital leases | $ | 1,220 | $ | 481 | |||
Accounts payable | 895 | 869 | |||||
Derivative instruments | 1,084 | 1,721 | |||||
Cash collateral received in support of energy risk management activities | 2 | 106 | |||||
Accrued interest expense | 220 | 242 | |||||
Other accrued expenses | 543 | 568 | |||||
Current liabilities held-for-sale | — | 2 | |||||
Other current liabilities | 418 | 386 | |||||
Total current liabilities | 4,382 | 4,375 | |||||
Other Liabilities | |||||||
Long-term debt and capital leases | 18,006 | 18,983 | |||||
Nuclear decommissioning reserve | 287 | 326 | |||||
Nuclear decommissioning trust liability | 339 | 283 | |||||
Postretirement and other benefit obligations | 553 | 588 | |||||
Deferred income taxes | 20 | 19 | |||||
Derivative instruments | 294 | 493 | |||||
Out-of-market contracts, net | 1,040 | 1,146 | |||||
Non-current liabilities held-for-sale | 12 | 4 | |||||
Other non-current liabilities | 930 | 900 | |||||
Total non-current liabilities | 21,481 | 22,742 | |||||
Total Liabilities | 25,863 | 27,117 | |||||
2.822% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding at December 31, 2015 | — | 302 | |||||
Redeemable noncontrolling interest in subsidiaries | 46 | 29 | |||||
Commitments and Contingencies | |||||||
Stockholders' Equity | |||||||
Common stock; $0.01 par value; 500,000,000 shares authorized; 417,583,825 and 416,939,950 shares issued; and 315,443,011 and 314,190,042 shares outstanding at December 31, 2016 and 2015 | 4 | 4 | |||||
Additional paid-in capital | 8,358 | 8,296 | |||||
Accumulated deficit | (3,787 | ) | (3,007 | ) | |||
Treasury stock, at cost; 102,140,814 and 102,749,908 shares at December 31, 2016 and 2015 | (2,399 | ) | (2,413 | ) | |||
Accumulated other comprehensive loss | (135 | ) | (173 | ) | |||
Noncontrolling interest | 2,405 | 2,727 | |||||
Total Stockholders' Equity | 4,446 | 5,434 | |||||
Total Liabilities and Stockholders' Equity | $ | 30,355 | $ | 32,882 | |||
10
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In millions) | |||||||||||
Cash Flows from Operating Activities | |||||||||||
Net (loss)/income | $ | (891 | ) | $ | (6,436 | ) | 132 | ||||
Adjustments to reconcile net income/(loss) to net cash provided by operating activities: | |||||||||||
Equity in earnings and distribution of unconsolidated affiliates | 54 | 37 | 49 | ||||||||
Depreciation and amortization | 1,367 | 1,566 | 1,523 | ||||||||
Provision for bad debts | 48 | 64 | 64 | ||||||||
Amortization of nuclear fuel | 49 | 45 | 46 | ||||||||
Amortization of financing costs and debt discount/premiums | 3 | (11 | ) | (12 | ) | ||||||
Adjustment to loss/(gain) on debt extinguishment | 21 | (75 | ) | 25 | |||||||
Amortization of intangibles and out-of-market contracts | 91 | 81 | 64 | ||||||||
Amortization of unearned equity compensation | 10 | 41 | 42 | ||||||||
Net (gain)/loss on sale of assets and equity method investments | (224 | ) | 14 | (4 | ) | ||||||
Gain on post retirement benefits curtailment | — | (21 | ) | — | |||||||
Impairment losses | 1,186 | 5,086 | 97 | ||||||||
Changes in derivative instruments | 23 | 233 | (61 | ) | |||||||
Changes in deferred income taxes and liability for uncertain tax benefits | (43 | ) | 1,326 | (154 | ) | ||||||
Changes in collateral deposits in support of risk management activities | 365 | (381 | ) | 146 | |||||||
Proceeds from sale of emission allowances | 47 | — | — | ||||||||
Changes in nuclear decommissioning trust liability | 41 | (2 | ) | 19 | |||||||
Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects: | |||||||||||
Accounts receivable - trade | (12 | ) | 136 | (2 | ) | ||||||
Inventory | 134 | (26 | ) | (245 | ) | ||||||
Prepayments and other current assets | (39 | ) | 8 | 36 | |||||||
Accounts payable | (27 | ) | (218 | ) | (12 | ) | |||||
Accrued expenses and other current liabilities | (39 | ) | (9 | ) | (26 | ) | |||||
Other assets and liabilities | (92 | ) | (149 | ) | (217 | ) | |||||
Net Cash Provided by Operating Activities | 2,072 | 1,309 | 1,510 | ||||||||
Cash Flows from Investing Activities | |||||||||||
Acquisition of businesses, net of cash acquired | (209 | ) | (31 | ) | (2,936 | ) | |||||
Capital expenditures | (1,244 | ) | (1,283 | ) | (909 | ) | |||||
(Increase)/decrease in restricted cash, net | (29 | ) | 8 | 57 | |||||||
(Increase)/decrease in restricted cash to support equity requirements for U.S. DOE funded projects | (3 | ) | 35 | (206 | ) | ||||||
Net cash proceeds from notes receivable | 17 | 18 | 25 | ||||||||
Proceeds from renewable energy grants | 36 | 82 | 916 | ||||||||
Purchases of emission allowances, net of proceeds | (1 | ) | 41 | (16 | ) | ||||||
Investments in nuclear decommissioning trust fund securities | (551 | ) | (629 | ) | (619 | ) | |||||
Proceeds from sales of nuclear decommissioning trust fund securities | 510 | 631 | 600 | ||||||||
Proceeds from sale of assets, net | 636 | 27 | 203 | ||||||||
Investments in unconsolidated affiliates | (34 | ) | (395 | ) | (103 | ) | |||||
Other | 48 | 11 | 85 | ||||||||
Net Cash Used by Investing Activities | (824 | ) | (1,485 | ) | (2,903 | ) | |||||
Cash Flows from Financing Activities | |||||||||||
Payments of dividends to preferred and common stockholders | (76 | ) | (201 | ) | (196 | ) | |||||
Net receipts from settlement of acquired derivatives that include financing elements | 151 | 196 | 9 | ||||||||
Payments for treasury stock | — | (437 | ) | (39 | ) | ||||||
Payments for preferred shares | (226 | ) | — | — | |||||||
Distributions from, net of contributions to, noncontrolling interests in subsidiaries | (156 | ) | 47 | 189 | |||||||
Proceeds from sale of noncontrolling interests in subsidiaries | — | 600 | 630 | ||||||||
Proceeds from issuance of common stock | 1 | 1 | 21 | ||||||||
Proceeds from issuance of long-term debt | 5,527 | 1,004 | 4,563 | ||||||||
Payments of debt issuance and hedging costs | (89 | ) | (21 | ) | (67 | ) | |||||
Payments for short and long-term debt | (5,913 | ) | (1,599 | ) | (3,827 | ) | |||||
Other | (13 | ) | (22 | ) | (18 | ) | |||||
Net Cash (Used)/Provided by Financing Activities | (794 | ) | (432 | ) | 1,265 | ||||||
Effect of exchange rate changes on cash and cash equivalents | 1 | 10 | (10 | ) | |||||||
Net Increase/(Decrease) in Cash and Cash Equivalents | 455 | (598 | ) | (138 | ) | ||||||
Cash and Cash Equivalents at Beginning of Period | 1,518 | 2,116 | 2,254 | ||||||||
Cash and Cash Equivalents at End of Period | $ | 1,973 | $ | 1,518 | $ | 2,116 | |||||
11
Appendix Table A-1: Fourth Quarter 2016 Adjusted EBITDA Reconciliation by Operating Segment
The following table summarizes the calculation of Adj. EBITDA and provides a reconciliation to net (loss)/income:
($ in millions) | Generation | Retail | Renewables | NRG Yield | Corp/Elim | Total | ||||||
Net (loss)/income | (889 | ) | 316 | (204 | ) | (126 | ) | (152 | ) | (1,055 | ) | |
Plus: | ||||||||||||
Interest expense, net | 9 | — | 22 | 61 | 124 | 216 | ||||||
Income tax | 1 | — | (6 | ) | (26 | ) | (48 | ) | (79 | ) | ||
Loss on debt extinguishment | — | — | — | — | 23 | 23 | ||||||
Depreciation and amortization | 224 | 28 | 47 | 73 | 16 | 388 | ||||||
ARO expense | 13 | — | 1 | 1 | 1 | 16 | ||||||
Amortization of contracts | (4 | ) | 1 | — | 17 | — | 14 | |||||
Amortization of leases | (12 | ) | — | — | — | — | (12 | ) | ||||
EBITDA | (658 | ) | 345 | (140 | ) | — | (36 | ) | (489 | ) | ||
Adjustment to reflect NRG share of adjusted EBITDA in unconsolidated affiliates | 6 | — | 23 | 21 | (36 | ) | 14 | |||||
Reorganization costs | — | — | — | — | 3 | 3 | ||||||
Deactivation costs | 4 | — | — | — | 1 | 5 | ||||||
Other non recurring charges | 1 | 2 | 1 | 3 | (1 | ) | 6 | |||||
Impairment losses | 561 | 1 | 30 | 183 | 20 | 795 | ||||||
Impairment losses on investments | — | — | 106 | — | 15 | 121 | ||||||
Mark-to-market (MtM) losses/(gains) on economic hedges | 246 | (214 | ) | 6 | — | (1 | ) | 37 | ||||
Adjusted EBITDA | 160 | 134 | 26 | 207 | (35 | ) | 492 | |||||
Fourth Quarter 2016 condensed financial information by Operating Segment:
($ in millions) | Generation | Retail | Renewables | NRG Yield | Corp/Elim | Total | ||||||
Operating revenues | 1,304 | 1,417 | 88 | 249 | (239 | ) | 2,819 | |||||
Cost of sales | 593 | 1,053 | 11 | 13 | (238 | ) | 1,432 | |||||
Economic gross margin | 711 | 364 | 77 | 236 | (1 | ) | 1,387 | |||||
Operations & maintenance and other cost of operationsa | 450 | 91 | 30 | 70 | (28 | ) | 613 | |||||
Selling, marketing, general and administrativeb | 100 | 135 | 17 | 6 | 38 | 296 | ||||||
Development costs | 5 | 2 | 15 | — | 1 | 23 | ||||||
Other (income)/expense | (4 | ) | 2 | (11 | ) | (47 | ) | 23 | (37 | ) | ||
Adjusted EBITDA | 160 | 134 | 26 | 207 | (35 | ) | 492 | |||||
a. | Excludes deactivation costs of $5 million, ARO expense of $16 million and lease amortization of $12 million. |
b. | Excludes reorganization costs of $3 million. |
The following table reconciles the condensed financial information to Adjusted EBITDA:
($ in millions) | Condensed financial information | Interest, tax, depr., amort. | MtM | Deactivation | Other adj. | Adjusted EBITDA | ||||||
Operating revenues | 2,532 | 14 | 273 | — | — | 2,819 | ||||||
Cost of operations | 1,195 | 1 | 236 | — | — | 1,432 | ||||||
Gross margin | 1,337 | 13 | 37 | — | — | 1,387 | ||||||
Operations & maintenance and other cost of operations | 622 | (4 | ) | — | (5 | ) | — | 613 | ||||
Selling, marketing, general & administrative a | 299 | — | — | — | (3 | ) | 296 | |||||
Development costs | 23 | — | — | — | — | 23 | ||||||
Other expense/(income) b | 1,448 | (161 | ) | — | — | (1,324 | ) | (37 | ) | |||
Net loss | (1,055 | ) | 178 | 37 | 5 | 1,327 | 492 | |||||
a. | Other adj. includes reorganization costs of $3 million. |
b. | Other adj. includes impairments. |
12
Appendix Table A-2: Fourth Quarter 2015 Adjusted EBITDA Reconciliation by Operating Segment
The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net (loss)/income:
($ in millions) | Generation | Retail | Renewables | NRG Yield | Corp/Elim | Total | ||||||
Net (loss)/income | (4,690 | ) | 161 | (18 | ) | 12 | (1,823 | ) | (6,358 | ) | ||
Plus: | ||||||||||||
Interest expense, net | 17 | — | 19 | 63 | 171 | 270 | ||||||
Income tax | (3 | ) | — | (5 | ) | 4 | 1,389 | 1,385 | ||||
Loss on debt extinguishment | — | — | — | — | (84 | ) | (84 | ) | ||||
Depreciation and amortization | 223 | 33 | 46 | 75 | 16 | 393 | ||||||
ARO expense | 7 | — | — | — | 1 | 8 | ||||||
Amortization of contracts | (4 | ) | 2 | — | 14 | — | 12 | |||||
Amortization of leases | (12 | ) | — | — | — | — | (12 | ) | ||||
EBITDA | (4,462 | ) | 196 | 42 | 168 | (330 | ) | (4,386 | ) | |||
Adjustment to reflect NRG share of adjusted EBITDA in unconsolidated affiliates | 4 | — | (32 | ) | 15 | 38 | 25 | |||||
Acquisition-related transaction & integration costs | — | — | — | — | 2 | 2 | ||||||
Reorganization costs | 3 | 3 | 6 | — | 6 | 18 | ||||||
Deactivation costs | 3 | — | — | — | — | 3 | ||||||
Other non recurring charges | 4 | (1 | ) | 2 | 3 | 5 | 13 | |||||
Impairment losses | 4,605 | — | 8 | — | 154 | 4,767 | ||||||
Impairment losses on investments | 14 | — | — | — | 42 | 56 | ||||||
MtM losses/(gains) on economic hedges | 129 | (49 | ) | 1 | 3 | — | 84 | |||||
Adjusted EBITDA | 300 | 149 | 27 | 189 | (83 | ) | 582 | |||||
Fourth Quarter 2015 condensed financial information by Operating Segment:
($ in millions) | Generation | Retail | Renewables | NRG Yield | Corp/Elim | Total | ||||||
Operating revenues | 1,538 | 1,423 | 89 | 241 | (189 | ) | 3,102 | |||||
Cost of sales | 670 | 1,064 | 10 | 13 | (193 | ) | 1,564 | |||||
Economic gross margin | 868 | 359 | 79 | 228 | 4 | 1,538 | ||||||
Operations & maintenance and other cost of operations a | 483 | 95 | 3 | 77 | 7 | 665 | ||||||
Selling, marketing, general & administrative b | 93 | 127 | 10 | 3 | 70 | 303 | ||||||
Development costs | 6 | — | 17 | — | 14 | 37 | ||||||
Other expense/(income) c | (14 | ) | (12 | ) | 22 | (41 | ) | (4 | ) | (49 | ) | |
Adjusted EBITDA | 300 | 149 | 27 | 189 | (83 | ) | 582 | |||||
a. | Excludes deactivation costs of $3 million, ARO expense of $8 million and lease amortization of $12 million. |
b. | Excludes reorganization costs of $18 million. |
c. | Excludes acquisition-related transaction & integration costs of $2 million. |
The following table reconciles the condensed financial information to Adjusted EBITDA:
($ in millions) | Condensed financial information | Interest, tax, depr., amort. | MtM | Deactivation | Other adj. | Adjusted EBITDA | ||||||
Operating revenues | 3,011 | 12 | 79 | — | — | 3,102 | ||||||
Cost of operations | 1,569 | — | (5 | ) | — | — | 1,564 | |||||
Gross margin | 1,442 | 12 | 84 | — | — | 1,538 | ||||||
Operations & maintenance and other cost of operations | 664 | 4 | — | (3 | ) | — | 665 | |||||
Selling, marketing, general & administrative a | 321 | — | — | — | (18 | ) | 303 | |||||
Development costs | 37 | — | — | — | — | 37 | ||||||
Other expense/(income) b | 6,778 | (436 | ) | — | — | (6,391 | ) | (49 | ) | |||
Net loss | (6,358 | ) | 444 | 84 | 3 | 6,409 | 582 | |||||
a. | Other adj. includes reorganization costs of $18 million. |
b. | Other adj. includes impairments and acquisition-related transaction & integration costs. |
13
Appendix Table A-3: Full Year 2016 Adjusted EBITDA Reconciliation by Operating Segment
The following table summarizes the calculation of Adj. EBITDA and provides a reconciliation to net (loss)/income:
($ in millions) | Generation | Retail | Renewables | NRG Yield | Corp/Elim | Total | ||||||
Net (loss)/income | (507 | ) | 1,045 | (306 | ) | (15 | ) | (1,108 | ) | (891 | ) | |
Plus: | ||||||||||||
Interest expense, net | 65 | — | 107 | 273 | 601 | 1,046 | ||||||
Income tax | (1 | ) | 1 | (20 | ) | (1 | ) | 37 | 16 | |||
Loss on debt extinguishment | — | — | — | — | 142 | 142 | ||||||
Depreciation and amortization | 702 | 115 | 190 | 297 | 63 | 1,367 | ||||||
ARO expense | 35 | — | 2 | 3 | 2 | 42 | ||||||
Amortization of contracts | (18 | ) | 7 | 1 | 74 | (4 | ) | 60 | ||||
Amortization of leases | (49 | ) | — | — | — | — | (49 | ) | ||||
EBITDA | 227 | 1,168 | (26 | ) | 631 | (267 | ) | 1,733 | ||||
Adjustment to reflect NRG share of adjusted EBITDA in unconsolidated affiliates | 30 | — | 42 | 79 | (45 | ) | 106 | |||||
Acquisition-related transaction & integration costs | — | — | — | — | 7 | 7 | ||||||
Reorganization costs | — | 5 | 3 | — | 21 | 29 | ||||||
Deactivation costs | 19 | — | — | — | 2 | 21 | ||||||
(Gain)/loss on sale of business | (223 | ) | — | — | — | 79 | (144 | ) | ||||
Other non recurring charges | 21 | 1 | 1 | 6 | 5 | 34 | ||||||
Impairment losses | 645 | 1 | 56 | 183 | 33 | 918 | ||||||
Impairment losses on investments | 142 | — | 105 | — | 21 | 268 | ||||||
Mark-to-market (MtM) losses/(gains) on economic hedges | 644 | (364 | ) | 6 | — | (1 | ) | 285 | ||||
Adjusted EBITDA | 1,505 | 811 | 187 | 899 | (145 | ) | 3,257 | |||||
Full Year 2016 condensed financial information by Operating Segment:
($ in millions) | Generation | Retail | Renewables | NRG Yield | Corp/Elim | Total | ||||||
Operating revenues | 6,451 | 6,338 | 424 | 1,089 | (1,031 | ) | 13,271 | |||||
Cost of sales | 2,835 | 4,688 | 14 | 61 | (1,034 | ) | 6,564 | |||||
Economic gross margin | 3,616 | 1,650 | 410 | 1,028 | 3 | 6,707 | ||||||
Operations & maintenance and other cost of operations a | 1,856 | 341 | 139 | 236 | (20 | ) | 2,552 | |||||
Selling, marketing, general & administrative b | 372 | 492 | 57 | 16 | 135 | 1,072 | ||||||
Development costs | 21 | 4 | 40 | — | 21 | 86 | ||||||
Other (income)/expense c | (138 | ) | 2 | (13 | ) | (123 | ) | 12 | (260 | ) | ||
Adjusted EBITDA | 1,505 | 811 | 187 | 899 | (145 | ) | 3,257 | |||||
a. | Excludes deactivation costs of $21 million, ARO expense of $42 million and lease amortization of $49 million. |
b. | Excludes reorganization costs of $29 million. |
c. | Excludes acquisition-related transaction & integration costs of $7 million. |
The following table reconciles the condensed financial information to Adjusted EBITDA:
($ in millions) | Condensed financial information | Interest, tax, depr., amort. | MtM | Deactivation | Other adj. | Adjusted EBITDA | ||||||
Operating revenues | 12,351 | 55 | 865 | — | — | 13,271 | ||||||
Cost of operations | 5,989 | (5 | ) | 580 | — | — | 6,564 | |||||
Gross margin | 6,362 | 60 | 285 | — | — | 6,707 | ||||||
Operations & maintenance and other cost of operations | 2,566 | 7 | — | (21 | ) | — | 2,552 | |||||
Selling, marketing, general & administrative a | 1,101 | — | — | — | (29 | ) | 1,072 | |||||
Development costs | 90 | — | — | — | (4 | ) | 86 | |||||
Other expense/(income) b | 3,496 | (1,205 | ) | — | — | (2,551 | ) | (260 | ) | |||
Net loss | (891 | ) | 1,258 | 285 | 21 | 2,584 | 3,257 | |||||
a. | Other adj. includes reorganization costs of $29 million. |
b. | Other adj. includes impairments, gain/(loss) on sale of business and acquisition-related transaction & integration costs. |
14
Appendix Table A-4: Full Year 2015 Adjusted EBITDA Reconciliation by Operating Segment
The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net (loss)/income:
($ in millions) | Generation | Retail | Renewables | NRG Yield | Corp/Elim | Total | ||||||
Net (loss)/income | (4,446 | ) | 624 | (92 | ) | 65 | (2,587 | ) | (6,436 | ) | ||
Plus: | ||||||||||||
Interest expense, net | 68 | 1 | 80 | 262 | 704 | 1,115 | ||||||
Income tax | — | 1 | (18 | ) | 12 | 1,347 | 1,342 | |||||
Loss/(gain) on debt extinguishment | — | — | — | 9 | (84 | ) | (75 | ) | ||||
Depreciation and amortization | 896 | 133 | 181 | 297 | 59 | 1,566 | ||||||
ARO expense | 32 | — | — | 2 | 1 | 35 | ||||||
Amortization of contracts | (10 | ) | 6 | 1 | 54 | — | 51 | |||||
Amortization of leases | (50 | ) | — | — | — | — | (50 | ) | ||||
EBITDA | (3,510 | ) | 765 | 152 | 701 | (560 | ) | (2,452 | ) | |||
Adjustment to reflect NRG share of adjusted EBITDA in unconsolidated affiliates | 27 | — | (20 | ) | 49 | 34 | 90 | |||||
Acquisition-related transaction & integration costs | — | 1 | — | 3 | 6 | 10 | ||||||
Reorganization costs | 3 | 3 | 6 | — | 6 | 18 | ||||||
Deactivation costs | 11 | — | — | — | — | 11 | ||||||
Gain on sale of business | — | — | (3 | ) | — | — | (3 | ) | ||||
Other non recurring charges | 20 | (12 | ) | 7 | 3 | 16 | 34 | |||||
Impairment losses | 4,827 | 36 | 13 | — | 154 | 5,030 | ||||||
Impairment losses on investments | 14 | — | — | — | 42 | 56 | ||||||
MtM losses on economic hedges | 367 | — | 3 | 2 | — | 372 | ||||||
Adjusted EBITDA | 1,759 | 793 | 158 | 758 | (302 | ) | 3,166 | |||||
Full Year 2015 condensed financial information by Operating Segment:
($ in millions) | Generation | Retail | Renewables | NRG Yield | Corp/Elim | Total | ||||||
Operating revenues | 7,785 | 6,910 | 396 | 1,009 | (1,142 | ) | 14,958 | |||||
Cost of sales | 3,649 | 5,244 | 16 | 71 | (1,134 | ) | 7,846 | |||||
Economic gross margin | 4,136 | 1,666 | 380 | 938 | (8 | ) | 7,112 | |||||
Operations & maintenance and other cost of operations a | 2,058 | 366 | 115 | 248 | 16 | 2,803 | ||||||
Selling, marketing, general & administrative b | 390 | 491 | 47 | 12 | 241 | 1,181 | ||||||
Development costs | 20 | 4 | 61 | — | 61 | 146 | ||||||
Other (income)/expense c | (91 | ) | 12 | (1 | ) | (80 | ) | (24 | ) | (184 | ) | |
Adjusted EBITDA | 1,759 | 793 | 158 | 758 | (302 | ) | 3,166 | |||||
a. | Excludes deactivation costs of $11 million, ARO expense of $35 million and lease amortization of $50 million. |
b. | Excludes reorganization costs of $18 million. |
c. | Excludes acquisition-related transaction & integration costs of $10 million. |
The following table reconciles the condensed financial information to Adjusted EBITDA:
($ in millions) | Condensed financial information | Interest, tax, depr., amort. | MtM | Deactivation | Other adj. | Adjusted EBITDA | ||||||
Operating revenues | 14,674 | 40 | 244 | — | — | 14,958 | ||||||
Cost of operations | 7,985 | (11 | ) | (128 | ) | — | — | 7,846 | ||||
Gross margin | 6,689 | 51 | 372 | — | — | 7,112 | ||||||
Operations & maintenance and other cost of operations | 2,799 | 15 | — | (11 | ) | — | 2,803 | |||||
Selling, marketing, general & administrative | 1,199 | — | — | — | (18 | ) | 1,181 | |||||
Development costs | 146 | — | — | — | — | 146 | ||||||
Other expense/(income) a | 8,981 | (2,382 | ) | — | — | (6,783 | ) | (184 | ) | |||
Net loss | (6,436 | ) | 2,418 | 372 | 11 | 6,801 | 3,166 | |||||
a. | Other adj. includes impairments and acquisition-related transaction & integration costs. |
15
Appendix Table A-5: 2016 and 2015 Three Months Ended December 31 and Full Year Adjusted Cash Flow from Operations Reconciliations
The following table summarizes the calculation of adjusted cash flow operating activities providing a reconciliation to net cash provided by operating activities:
Three Months Ended | ||||||
($ in millions) | December 31, 2016 | December 31, 2015 | ||||
Net Cash Provided by Operating Activities | 339 | (83 | ) | |||
Reclassifying of net receipts for settlement of acquired derivatives that include financing elements | 22 | 58 | ||||
Sale of Potrero Land | — | — | ||||
Merger, integration and cost-to-achieve expenses a | (7 | ) | 3 | |||
Return of capital from equity investments | 11 | 38 | ||||
Adjustment for change in collateral | (134 | ) | 201 | |||
Adjusted Cash Flow from Operating Activities | 231 | 217 | ||||
Maintenance CapEx, net b | (58 | ) | (99 | ) | ||
Environmental CapEx, net | (48 | ) | (80 | ) | ||
Preferred dividends | — | (3 | ) | |||
Distributions to non-controlling interests | (47 | ) | (43 | ) | ||
Free Cash Flow - before Growth | 78 | (8 | ) | |||
a. | Cost-to-achieve expenses associated with the $150 million savings announced on September 2015 call. |
b. | Includes insurance proceeds of $4 million in 2016; excludes merger and integration capex of $2 million in 2015. |
Twelve Months Ended | ||||||
($ in millions) | December 31, 2016 | December 31, 2015 | ||||
Net Cash Provided by Operating Activities | 2,072 | 1,309 | ||||
Reclassifying of net receipts for settlement of acquired derivatives that include financing elements | 151 | 196 | ||||
Sale of Potrero Land | 74 | — | ||||
Merger, integration and cost-to-achieve expenses a | 40 | 21 | ||||
Return of capital from equity investments | 17 | 38 | ||||
Adjustment for change in collateral | (365 | ) | 381 | |||
Adjusted Cash Flow from Operating Activities | 1,989 | 1,945 | ||||
Maintenance CapEx, net b | (330 | ) | (413 | ) | ||
Environmental CapEx, net | (285 | ) | (237 | ) | ||
Preferred dividends | (2 | ) | (10 | ) | ||
Distributions to non-controlling interests | (163 | ) | (158 | ) | ||
Free Cash Flow - before Growth | 1,209 | 1,127 | ||||
a. | Cost-to-achieve expenses associated with the $150 million savings announced on September 2015 call. |
b. | Includes insurance proceeds of $37 million in 2016; excludes merger and integration capex of $11 million in 2015. |
16
Appendix Table A-6: Fourth Quarter 2016 Regional Adjusted EBITDA Reconciliation for Generation
The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net loss:
($ in millions) | East | Gulf Coast | West | Other | Total | |||||
Net loss | (123 | ) | (662 | ) | (92 | ) | (12 | ) | (889 | ) |
Plus: | ||||||||||
Interest expense, net | 9 | — | — | — | 9 | |||||
Income tax | — | — | — | 1 | 1 | |||||
Depreciation and amortization | 56 | 157 | 11 | — | 224 | |||||
ARO expense | 2 | 3 | 8 | — | 13 | |||||
Amortization of contracts | (5 | ) | 2 | (1 | ) | — | (4 | ) | ||
Amortization of leases | (11 | ) | (1 | ) | — | — | (12 | ) | ||
EBITDA | (72 | ) | (501 | ) | (74 | ) | (11 | ) | (658 | ) |
Adjustment to reflect NRG share of adjusted EBITDA in unconsolidated affiliates | — | (2 | ) | 4 | 4 | 6 | ||||
Deactivation costs | 3 | — | 1 | — | 4 | |||||
Other non recurring charges | 3 | 1 | (1 | ) | (2 | ) | 1 | |||
Impairment losses | 118 | 358 | 85 | — | 561 | |||||
Mark-to-market (MtM) losses on economic hedges | 5 | 236 | 5 | — | 246 | |||||
Adjusted EBITDA | 57 | 92 | 20 | (9 | ) | 160 | ||||
Fourth Quarter 2016 condensed financial information for Generation:
($ in millions) | East | Gulf Coast | West | Other | Elims. | Total | ||||||
Operating revenues | 579 | 616 | 100 | (9 | ) | 18 | 1,304 | |||||
Cost of sales | 230 | 304 | 38 | — | 21 | 593 | ||||||
Economic gross margin | 349 | 312 | 62 | (9 | ) | (3 | ) | 711 | ||||
Operations & maintenance and other cost of operationsa | 249 | 185 | 32 | (1 | ) | (15 | ) | 450 | ||||
Selling, marketing, general & administrative | 50 | 37 | 7 | 6 | — | 100 | ||||||
Development costs | 1 | 1 | 3 | — | — | 5 | ||||||
Other (income)/expense | (8 | ) | (3 | ) | — | (5 | ) | 12 | (4 | ) | ||
Adjusted EBITDA | 57 | 92 | 20 | (9 | ) | — | 160 | |||||
a. | Excludes deactivation costs of $4 million, ARO expense of $13 million and lease amortization of $12 million. |
The following table reconciles the condensed financial information to Adjusted EBITDA:
($ in millions) | Condensed financial information | Interest, tax, depr., amort. | MtM | Deactivation | Other adj. | Adjusted EBITDA | ||||||
Operating revenues | 1,064 | (4 | ) | 244 | — | — | 1,304 | |||||
Cost of operations | 593 | 2 | (2 | ) | — | — | 593 | |||||
Gross margin | 471 | (6 | ) | 246 | — | — | 711 | |||||
Operations & maintenance and other cost of operations | 455 | (1 | ) | — | (4 | ) | — | 450 | ||||
Selling, marketing, general & administrative | 100 | — | — | — | — | 100 | ||||||
Development costs | 5 | — | — | — | — | 5 | ||||||
Other expense/(income) a | 800 | (12 | ) | — | — | (792 | ) | (4 | ) | |||
Net loss | (889 | ) | 7 | 246 | 4 | 792 | 160 | |||||
a. | Other adj. includes impairments. |
17
Appendix Table A-7: Fourth Quarter 2015 Regional Adjusted EBITDA Reconciliation for Generation
The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net loss:
($ in millions) | East | Gulf Coast | West | Other | Total | |||||
Net loss | (164 | ) | (4,488 | ) | (25 | ) | (13 | ) | (4,690 | ) |
Plus: | ||||||||||
Interest expense, net | 16 | — | — | 1 | 17 | |||||
Income tax | — | — | — | (3 | ) | (3 | ) | |||
Depreciation and amortization | 92 | 119 | 11 | 1 | 223 | |||||
ARO expense | 4 | 1 | 2 | — | 7 | |||||
Amortization of contracts | (6 | ) | — | 2 | — | (4 | ) | |||
Amortization of leases | (12 | ) | (1 | ) | — | 1 | (12 | ) | ||
EBITDA | (70 | ) | (4,369 | ) | (10 | ) | (13 | ) | (4,462 | ) |
Adjustment to reflect NRG share of adjusted EBITDA in unconsolidated affiliates | — | (1 | ) | 2 | 3 | 4 | ||||
Reorganization costs | — | 3 | — | — | 3 | |||||
Deactivation costs | 3 | — | — | — | 3 | |||||
Other non recurring charges | 15 | (19 | ) | 6 | 2 | 4 | ||||
Impairment losses | 214 | 4,383 | 8 | — | 4,605 | |||||
Impairment losses on investments | — | 14 | — | — | 14 | |||||
MtM losses on economic hedges | 23 | 103 | 3 | — | 129 | |||||
Adjusted EBITDA | 185 | 114 | 9 | (8 | ) | 300 | ||||
Fourth Quarter 2015 condensed financial information for Generation:
($ in millions) | East | Gulf Coast | West | Other | Elims. | Total | ||||||
Operating revenues | 773 | 668 | 109 | (8 | ) | (4 | ) | 1,538 | ||||
Cost of sales | 290 | 330 | 50 | — | — | 670 | ||||||
Economic gross margin | 483 | 338 | 59 | (8 | ) | (4 | ) | 868 | ||||
Operations & maintenance and other cost of operationsa | 263 | 197 | 38 | (1 | ) | (14 | ) | 483 | ||||
Selling, marketing, general & administrative b | 29 | 33 | 14 | 17 | — | 93 | ||||||
Development costs | 2 | 1 | 3 | — | — | 6 | ||||||
Other expense/(income) | 4 | (7 | ) | (5 | ) | (16 | ) | 10 | (14 | ) | ||
Adjusted EBITDA | 185 | 114 | 9 | (8 | ) | — | 300 | |||||
a. | Excludes deactivation costs of $3 million. ARO expense of $7 million and lease amortization of $12 million. |
b. | Excludes reorganization costs of $3 million. |
The following table reconciles the condensed financial information to Adjusted EBITDA:
($ in millions) | Condensed financial information | Interest, tax, depr., amort. | MtM | Deactivation | Other adj. | Adjusted EBITDA | ||||||
Operating revenues | 1,404 | (3 | ) | 137 | — | — | 1,538 | |||||
Cost of operations | 661 | (1 | ) | 10 | — | — | 670 | |||||
Gross margin | 743 | (2 | ) | 127 | — | — | 868 | |||||
Operations & maintenance and other cost of operations | 481 | 5 | — | (3 | ) | — | 483 | |||||
Selling, marketing, general & administrative a | 96 | — | — | — | (3 | ) | 93 | |||||
Development costs | 6 | — | — | — | — | 6 | ||||||
Other expense/(income) b | 4,850 | (12 | ) | — | — | (4,852 | ) | (14 | ) | |||
Net loss | (4,690 | ) | 5 | 127 | 3 | 4,855 | 300 | |||||
a. | Other adj. includes reorganization costs of $3 million. |
b. | Other adj. includes impairments. |
18
Appendix Table A-8: Full Year 2016 Regional Adjusted EBITDA Reconciliation for Generation
The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net income/(loss)
($ in millions) | East | Gulf Coast | West | Other | Total | |||||
Net income/(loss) | 373 | (911 | ) | (19 | ) | 50 | (507 | ) | ||
Plus: | ||||||||||
Interest expense, net | 65 | 1 | — | (1 | ) | 65 | ||||
Income tax | — | (2 | ) | — | 1 | (1 | ) | |||
Depreciation and amortization | 212 | 432 | 57 | 1 | 702 | |||||
ARO expense | 7 | 11 | 17 | — | 35 | |||||
Amortization of contracts | (22 | ) | 6 | (4 | ) | 2 | (18 | ) | ||
Amortization of leases | (47 | ) | (2 | ) | — | — | (49 | ) | ||
EBITDA | 588 | (465 | ) | 51 | 53 | 227 | ||||
Adjustment to reflect NRG share of adjusted EBITDA in unconsolidated affiliates | — | 3 | 11 | 16 | 30 | |||||
Deactivation costs | 18 | — | 1 | — | 19 | |||||
Gain on sale of assets | (217 | ) | — | (6 | ) | — | (223 | ) | ||
Other non recurring charges | 7 | 16 | (1 | ) | (1 | ) | 21 | |||
Impairments | 135 | 367 | 143 | — | 645 | |||||
Impairment losses on investments | — | 142 | — | — | 142 | |||||
Mark-to-market (MtM) losses on economic hedges | 180 | 444 | 20 | — | 644 | |||||
Adjusted EBITDA | 711 | 507 | 219 | 68 | 1,505 | |||||
Full Year 2016 condensed financial information for Generation:
($ in millions) | East | Gulf Coast | West | Other | Elims. | Total | ||||||
Operating revenues | 3,241 | 2,705 | 458 | 62 | (15 | ) | 6,451 | |||||
Cost of sales | 1,300 | 1,386 | 149 | — | — | 2,835 | ||||||
Economic gross margin | 1,941 | 1,319 | 309 | 62 | (15 | ) | 3,616 | |||||
Operations & maintenance and other cost of operations a | 1,048 | 684 | 138 | 1 | (15 | ) | 1,856 | |||||
Selling, marketing, general & administrative | 183 | 135 | 31 | 23 | — | 372 | ||||||
Development costs | 4 | 3 | 14 | — | — | 21 | ||||||
Other (income)/expense | (5 | ) | (10 | ) | (93 | ) | (30 | ) | — | (138 | ) | |
Adjusted EBITDA | 711 | 507 | 219 | 68 | — | 1,505 | ||||||
a. | Excludes deactivation costs of $19 million, ARO expense of $35 million and lease amortization of $49 million. |
The following table reconciles the condensed financial information to Adjusted EBITDA:
($ in millions) | Condensed financial information | Interest, tax, depr., amort. | MtM | Deactivation | Other adj. | Adjusted EBITDA | ||||||
Operating revenues | 5,679 | (15 | ) | 787 | — | — | 6,451 | |||||
Cost of operations | 2,689 | 3 | 143 | — | — | 2,835 | ||||||
Gross Margin | 2,990 | (18 | ) | 644 | — | — | 3,616 | |||||
Operations & maintenance and other cost of operations | 1,861 | 14 | — | (19 | ) | — | 1,856 | |||||
Selling, marketing, general & administrative | 372 | — | — | — | — | 372 | ||||||
Development costs | 22 | — | — | — | (1 | ) | 21 | |||||
Other expense/(income) a | 1,242 | (64 | ) | — | — | (1,316 | ) | (138 | ) | |||
Net loss | (507 | ) | 32 | 644 | 19 | 1,317 | 1,505 | |||||
a. | Other adj. includes impairments. |
19
Appendix Table A-9: Full Year 2015 Regional Adjusted EBITDA Reconciliation for Generation
The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net income/(loss)
($ in millions) | East | Gulf Coast | West | Other | Total | |||||
Net income/(loss) | 17 | (4,439 | ) | 5 | (29 | ) | (4,446 | ) | ||
Plus: | ||||||||||
Interest expense, net | 68 | — | 1 | (1 | ) | 68 | ||||
Depreciation and amortization | 299 | 546 | 51 | — | 896 | |||||
ARO expense | 14 | 6 | 12 | — | 32 | |||||
Amortization of contracts | (19 | ) | 5 | 2 | 2 | (10 | ) | |||
Amortization of leases | (47 | ) | (3 | ) | — | — | (50 | ) | ||
EBITDA | 332 | (3,885 | ) | 71 | (28 | ) | (3,510 | ) | ||
Adjustment to reflect NRG share of adjusted EBITDA in unconsolidated affiliates | — | 3 | 8 | 16 | 27 | |||||
Reorganization costs | — | 3 | — | — | 3 | |||||
Deactivation costs | 8 | — | 3 | — | 11 | |||||
Other non recurring charges | 24 | (1 | ) | (1 | ) | (2 | ) | 20 | ||
Impairment losses | 436 | 4,383 | 8 | — | 4,827 | |||||
Impairment losses on investments | — | 14 | — | — | 14 | |||||
MtM losses on economic hedges | 276 | 83 | 8 | — | 367 | |||||
Adjusted EBITDA | 1,076 | 600 | 97 | (14 | ) | 1,759 | ||||
Full Year 2015 condensed financial information for Generation:
($ in millions) | East | Gulf Coast | West | Other | Elims. | Total | ||||||
Operating revenues | 4,291 | 3,054 | 475 | (21 | ) | (14 | ) | 7,785 | ||||
Cost of sales | 1,891 | 1,566 | 192 | — | — | 3,649 | ||||||
Economic gross margin | 2,400 | 1,488 | 283 | (21 | ) | (14 | ) | 4,136 | ||||
Operations & maintenance and other cost of operations a | 1,162 | 756 | 153 | 1 | (14 | ) | 2,058 | |||||
Selling, marketing, general & administrative b | 170 | 147 | 44 | 29 | — | 390 | ||||||
Development costs | 3 | 9 | 8 | — | — | 20 | ||||||
Other (income)/expense | (11 | ) | (24 | ) | (19 | ) | (37 | ) | — | (91 | ) | |
Adjusted EBITDA | 1,076 | 600 | 97 | (14 | ) | — | 1,759 | |||||
a. | Excludes deactivation costs of $11 million, ARO expense of $32 million and lease amortization of $50 million. |
b. | Excludes reorganization cost of $3 million. |
The following table reconciles the condensed financial information to Adjusted EBITDA:
($ in millions) | Condensed financial information | Interest, tax, depr., amort. | MtM | Deactivation | Other adj. | Adjusted EBITDA | ||||||
Operating revenues | 7,546 | (15 | ) | 254 | — | — | 7,785 | |||||
Cost of operations | 3,767 | (5 | ) | (113 | ) | — | — | 3,649 | ||||
Gross margin | 3,779 | (10 | ) | 367 | — | — | 4,136 | |||||
Operations & maintenance and other cost of operations | 2,051 | 18 | — | (11 | ) | — | 2,058 | |||||
Selling, marketing, general & administrative | 393 | — | — | — | (3 | ) | 390 | |||||
Development costs | 20 | — | — | — | — | 20 | ||||||
Other expense/(income) a | 5,761 | (68 | ) | — | — | (5,784 | ) | (91 | ) | |||
Net loss | (4,446 | ) | 40 | 367 | 11 | 5,787 | 1,759 | |||||
a. | Other adj. includes impairments and acquisition-related transaction & integration costs. |
20
Appendix Table A-10: Full Year 2016 Sources and Uses of Liquidity
The following table summarizes the sources and uses of liquidity for the full year 2016:
($ in millions) | Twelve Months Ended December 31, 2016 | |
Sources: | ||
Adjusted cash flow from operations | 1,989 | |
Asset sales | 562 | |
Issuance of NRG Yield Senior Notes due 2026 | 350 | |
Monetization of capacity revenues at Midwest Gen, net of payments | 253 | |
Collateral | 365 | |
Issuance of CVSR HoldCo debt | 200 | |
Issuance of NYLD 3.55% Series D notes (NRG Energy Center Minneapolis) | 125 | |
Capistrano debt proceeds, net of debt repayment | 108 | |
Tax Equity Proceeds | 11 | |
Uses: | ||
Debt repayments, net of proceeds (corporate-level) | (774 | ) |
Maintenance and environmental capex, net a | (615 | ) |
Growth investments and acquisitions, net | (564 | ) |
Debt repayments, non-discretionary | (399 | ) |
Proceeds from NRG Yield revolver, net of payments | (306 | ) |
Redemption of convertible preferred stock | (226 | ) |
Distributions to non-controlling interests | (163 | ) |
Decrease in credit facility availability | (156 | ) |
Capistrano distribution of debt proceeds to non-controlling interests | (87 | ) |
Debt Issuance Costs | (89 | ) |
Debt Repayment, Peaker Finco | (76 | ) |
Common and Preferred Stock Dividends | (76 | ) |
Merger, integration and cost-to-achieve expenses b | (40 | ) |
Other Investing and Financing | (61 | ) |
Change in Total Liquidity | 331 | |
a. | Includes insurance proceeds of $37 million. |
b. | Cost-to-achieve expenses associated with the $150 million savings announced on September 2015 call. |
21
Appendix Table A-11: 2017 Adjusted EBITDA Guidance Reconciliation
The following table summarizes the calculation of Adjusted EBITDA providing reconciliation to net income:
2017 Adjusted EBITDA | ||||||||
($ in millions) | Low | High | ||||||
GAAP Net Income a | 60 | 260 | ||||||
Income Tax | 80 | 80 | ||||||
Interest Expense & Debt Extinguishment Costs | 1,155 | 1,155 | ||||||
Depreciation, Amortization, Contract Amortization and ARO Expense | 1,235 | 1,235 | ||||||
Adjustment to reflect NRG share of adjusted EBITDA in unconsolidated affiliates | 110 | 110 | ||||||
Other Costs b | 60 | 60 | ||||||
Adjusted EBITDA | 2,700 | 2,900 | ||||||
a. | For purposes of guidance, fair value adjustments related to derivatives are assumed to be zero. |
b. | Includes deactivation costs, gain on sale of businesses, reorganization costs, asset write-offs, impairments and other non-recurring charges |
22
Appendix Table A-12: 2017 FCFbG Guidance Reconciliation
The following table summarizes the calculation of Free Cash Flow before Growth providing reconciliation to Cash from Operations:
2017 | |||
($ in millions) | Guidance | ||
Adjusted EBITDA | $2,700 - $2,900 | ||
Cash Interest payments | (1,065) | ||
Debt Extinguishment Cash Cost | 0 | ||
Cash Income tax | (40) | ||
Collateral / working capital / other | (240) | ||
Cash From Operations | $1,355 - $1,555 | ||
Adjustments: Acquired Derivatives, Cost-to-Achieve, Return of Capital Dividends, Collateral and Other | 0 | ||
Adjusted Cash flow from operations | $1,355 - $1,555 | ||
Maintenance capital expenditures, net | (310) - (340) | ||
Environmental capital expenditures, net | (10) - (30) | ||
Preferred dividends | 0 | ||
Distributions to non-controlling interests | (185) - (205) | ||
Free Cash Flow - before Growth | $800 - $1,000 | ||
EBITDA and Adjusted EBITDA are non-GAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance. The presentation of Adjusted EBITDA should not be construed as an inference that NRG’s future results will be unaffected by unusual or non-recurring items.
EBITDA represents net income before interest (including loss on debt extinguishment), taxes, depreciation and amortization. EBITDA is presented because NRG considers it an important supplemental measure of its performance and believes debt-holders frequently use EBITDA to analyze operating performance and debt service capacity. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are:
• | EBITDA does not reflect cash expenditures, or future requirements for capital expenditures, or contractual commitments; |
• | EBITDA does not reflect changes in, or cash requirements for, working capital needs; |
• | EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments; |
• | Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and |
• | Other companies in this industry may calculate EBITDA differently than NRG does, limiting its usefulness as a comparative measure. |
Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to use to invest in the growth of NRG’s business. NRG compensates for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only supplementally. See the statements of cash flow included in the financial statements that are a part of this news release.
Adjusted EBITDA is presented as a further supplemental measure of operating performance. As NRG defines it, Adjusted EBITDA represents EBITDA excluding impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the non-controlling interest, gains or losses on the repurchase, modification or extinguishment of debt, the impact of restructuring and any extraordinary, unusual or non-recurring items plus
23
adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. As an analytical tool, Adjusted EBITDA is subject to all of the limitations applicable to EBITDA. In addition, in evaluating Adjusted EBITDA, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release.
Management believes Adjusted EBITDA is useful to investors and other users of NRG's financial statements in evaluating its operating performance because it provides an additional tool to compare business performance across companies and across periods and adjusts for items that we do not consider indicative of NRG’s future operating performance. This measure is widely used by debt-holders to analyze operating performance and debt service capacity and by equity investors to measure our operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations, and for evaluating actual results against such expectations, and in communications with NRG's Board of Directors, shareholders, creditors, analysts and investors concerning its financial performance.
Adjusted cash flow from operating activities is a non-GAAP measure NRG provides to show cash from operations with the reclassification of net payments of derivative contracts acquired in business combinations from financing to operating cash flow, as well as the add back of merger, integration and related restructuring costs. The Company provides the reader with this alternative view of operating cash flow because the cash settlement of these derivative contracts materially impact operating revenues and cost of sales, while GAAP requires NRG to treat them as if there was a financing activity associated with the contracts as of the acquisition dates. The Company adds back merger, integration related restructuring costs as they are one time and unique in nature and do not reflect ongoing cash from operations and they are fully disclosed to investors.
Free cash flow (before Growth) is adjusted cash flow from operations less maintenance and environmental capital expenditures, net of funding, preferred stock dividends and distributions to non-controlling interests and is used by NRG predominantly as a forecasting tool to estimate cash available for debt reduction and other capital allocation alternatives. The reader is encouraged to evaluate each of these adjustments and the reasons NRG considers them appropriate for supplemental analysis. Because we have mandatory debt service requirements (and other non-discretionary expenditures) investors should not rely on free cash flow before Growth as a measure of cash available for discretionary expenditures.
Free Cash Flow before Growth is utilized by Management in making decisions regarding the allocation of capital. Free Cash Flow before Growth is presented because the Company believes it is a useful tool for assessing the financial performance in the current period. In addition, NRG’s peers evaluate cash available for allocation in a similar manner and accordingly, it is a meaningful indicator for investors to benchmark NRG's performance against its peers. Free Cash Flow before Growth is a performance measure and is not intended to represent net income (loss), cash from operations (the most directly comparable U.S. GAAP measure), or liquidity and is not necessarily comparable to similarly titled measures reported by other companies.
24