Forward-looking statements speak only as of the date they were made, and the Company 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 the Company'sCompany’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.
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
See accompanying notes to consolidated financial statements.
See accompanying notes to consolidated financial statements.
CLEARWAY ENERGY LLC
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | |
(In millions) | June 30, 2023 | | December 31, 2022 |
ASSETS | (Unaudited) | | |
Current Assets | | | |
Cash and cash equivalents | $ | 547 | | | $ | 657 | |
| | | |
Restricted cash | 371 | | | 339 | |
Accounts receivable — trade | 215 | | | 153 | |
Accounts receivable — affiliates | 1 | | | — | |
Inventory | 51 | | | 47 | |
Derivative instruments | 34 | | | 26 | |
| | | |
Prepayments and other current assets | 64 | | | 54 | |
Total current assets | 1,283 | | | 1,276 | |
Property, plant and equipment, net | 7,748 | | | 7,421 | |
Other Assets | | | |
Equity investments in affiliates | 352 | | | 364 | |
Intangible assets for power purchase agreements, net | 2,397 | | | 2,488 | |
Other intangible assets, net | 74 | | | 77 | |
Derivative instruments | 83 | | | 63 | |
Right-of-use assets, net | 550 | | | 527 | |
Other non-current assets | 131 | | | 96 | |
Total other assets | 3,587 | | | 3,615 | |
Total Assets | $ | 12,618 | | | $ | 12,312 | |
LIABILITIES AND MEMBERS’ EQUITY | | | |
Current Liabilities | | | |
Current portion of long-term debt — external | $ | 330 | | | $ | 322 | |
Current portion of long-term debt — affiliate | 2 | | | 2 | |
Accounts payable — trade | 63 | | | 55 | |
Accounts payable — affiliates | 62 | | | 24 | |
Derivative instruments | 44 | | | 50 | |
Accrued interest expense | 54 | | | 54 | |
| | | |
Accrued expenses and other current liabilities | 54 | | | 95 | |
Total current liabilities | 609 | | | 602 | |
Other Liabilities | | | |
Long-term debt — external | 6,708 | | | 6,491 | |
Deferred income taxes | 4 | | | 4 | |
Derivative instruments | 259 | | | 303 | |
Long-term lease liabilities | 578 | | | 548 | |
Other non-current liabilities | 208 | | | 197 | |
Total other liabilities | 7,757 | | | 7,543 | |
Total Liabilities | 8,366 | | | 8,145 | |
Redeemable noncontrolling interest in subsidiaries | 15 | | | 7 | |
Commitments and Contingencies | | | |
Members’ Equity | | | |
Contributed capital | 1,275 | | | 1,308 | |
Retained earnings | 1,126 | | | 1,240 | |
Accumulated other comprehensive income | 21 | | | 21 | |
Noncontrolling interest | 1,815 | | | 1,591 | |
Total Members’ Equity | 4,237 | | | 4,160 | |
Total Liabilities and Members’ Equity | $ | 12,618 | | | $ | 12,312 | |
See accompanying notes to consolidated financial statements.
CLEARWAY ENERGY LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
| | | | | | | |
| Nine months ended September 30, |
| 2017 | | 2016(a) |
| (In millions) |
Cash Flows from Operating Activities | | | |
Net income | $ | 110 |
| | $ | 152 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | | |
Equity in earnings of unconsolidated affiliates | (63 | ) | | (34 | ) |
Distributions from unconsolidated affiliates | 52 |
| | 43 |
|
Depreciation and amortization | 241 |
| | 224 |
|
Amortization of financing costs | 7 |
| | 6 |
|
Amortization of intangibles and out-of-market contracts | 52 |
| | 57 |
|
Changes in derivative instruments | (2 | ) | | (5 | ) |
Loss on disposal of asset components | 8 |
| | 5 |
|
Changes in prepaid and accrued liabilities for tolling agreements | 5 |
| | 2 |
|
Changes in other working capital | (35 | ) | | (6 | ) |
Net Cash Provided by Operating Activities | 375 |
| | 444 |
|
Cash Flows from Investing Activities | | | |
Payments for the Drop Down Assets | (176 | ) | | (77 | ) |
Capital expenditures | (23 | ) | | (16 | ) |
Cash receipts from notes receivable | 11 |
| | 11 |
|
Return of investment from unconsolidated affiliates | 32 |
| | 16 |
|
Investments in unconsolidated affiliates | (48 | ) | | (69 | ) |
Net Cash Used in Investing Activities | (204 | ) | | (135 | ) |
Cash Flows from Financing Activities | | | |
Net contributions from noncontrolling interests | 13 |
| | 7 |
|
Net distributions and return of capital to NRG prior to the acquisition of Drop Down Assets | (49 | ) | | (126 | ) |
Proceeds from the issuance of Class C units | 33 |
| | — |
|
Payments of distributions | (149 | ) | | (127 | ) |
Payments of debt issuance costs | (4 | ) | | (6 | ) |
Proceeds from the revolving credit facility | — |
| | 60 |
|
Payments for the revolving credit facility | — |
| | (366 | ) |
Proceeds from the issuance of long-term debt — external | 41 |
| | 550 |
|
Payments for long-term debt | (224 | ) | | (204 | ) |
Net Cash Used in Financing Activities | (339 | ) | | (212 | ) |
Net Decrease in Cash, Cash Equivalents and Restricted Cash | (168 | ) | | 97 |
|
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 486 |
| | 241 |
|
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 318 |
| | $ | 338 |
|
(a) Retrospectively adjusted as discussed in Note 1, Nature of Business.
| | | | | | | | | | | |
| Six months ended June 30, |
(In millions) | 2023 | | 2022 |
Cash Flows from Operating Activities | | | |
Net Income | $ | 54 | | | $ | 1,278 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | |
Equity in earnings of unconsolidated affiliates | — | | | (14) | |
Distributions from unconsolidated affiliates | 11 | | | 17 | |
Depreciation, amortization and accretion | 256 | | | 250 | |
Amortization of financing costs and debt discounts | 6 | | | 7 | |
Amortization of intangibles | 94 | | | 82 | |
Loss on debt extinguishment | — | | | 2 | |
Gain on sale of business | — | | | (1,291) | |
Reduction in carrying amount of right-of-use assets | 8 | | | 7 | |
| | | |
| | | |
Changes in derivative instruments and amortization of accumulated OCI/OCL | (51) | | | 92 | |
| | | |
Cash used in changes in other working capital: | | | |
Changes in prepaid and accrued liabilities for tolling agreements | (56) | | | (74) | |
Changes in other working capital | (87) | | | (76) | |
Net Cash Provided by Operating Activities | 235 | | | 280 | |
Cash Flows from Investing Activities | | | |
| | | |
| | | |
Acquisition of Drop Down Assets, net of cash acquired | (7) | | | (51) | |
| | | |
| | | |
Capital expenditures | (109) | | | (81) | |
| | | |
| | | |
Return of investment from unconsolidated affiliates | 10 | | | 6 | |
Investments in unconsolidated affiliates | (10) | | | — | |
| | | |
Proceeds from sale of business | — | | | 1,457 | |
| | | |
| | | |
Net Cash (Used in) Provided by Investing Activities | (116) | | | 1,331 | |
Cash Flows from Financing Activities | | | |
Contributions from noncontrolling interests, net of distributions | 209 | | | 16 | |
Contributions from (distributions to) CEG, net | 66 | | | (23) | |
| | | |
| | | |
Payments of distributions | (153) | | | (141) | |
Tax-related distributions | (45) | | | — | |
Distributions to CEG of escrowed amounts | — | | | (64) | |
Proceeds from the revolving credit facility | — | | | 80 | |
Payments for the revolving credit facility | — | | | (325) | |
Proceeds from the issuance of long-term debt — external | 42 | | | 214 | |
| | | |
Payments of debt issuance costs | (8) | | | (4) | |
Payments for long-term debt — external | (306) | | | (722) | |
Payments for long-term debt — affiliate | — | | | (1) | |
Other | (2) | | | (7) | |
Net Cash Used in Financing Activities | (197) | | | (977) | |
| | | |
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash | (78) | | | 634 | |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 996 | | | 654 | |
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 918 | | | $ | 1,288 | |
See accompanying notes to consolidated financial statements.
CLEARWAY ENERGY LLC
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
For the Six Months Ended June 30, 2023
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(In millions) | Contributed Capital | | Retained Earnings | | Accumulated Other Comprehensive Income | | Noncontrolling Interest | | Total Members’ Equity |
Balances at December 31, 2022 | $ | 1,308 | | | $ | 1,240 | | | $ | 21 | | | $ | 1,591 | | | $ | 4,160 | |
Net loss | — | | | (22) | | | — | | | (33) | | | (55) | |
Unrealized loss on derivatives and changes in accumulated OCI | — | | | — | | | (3) | | | (1) | | | (4) | |
| | | | | | | | | |
Contributions from CEG, net of distributions, cash | 30 | | | — | | | — | | | | | 30 | |
Contributions from noncontrolling interests, net of distributions, cash | — | | | — | | | — | | | 215 | | | 215 | |
Transfers of assets under common control | (59) | | | — | | | — | | | 53 | | | (6) | |
| | | | | | | | | |
Distributions paid to Clearway, Inc. | — | | | (44) | | | — | | | — | | | (44) | |
Distributions paid to CEG Class B and Class D unit holders | — | | | (32) | | | — | | | — | | | (32) | |
Balances at March 31, 2023 | 1,279 | | | 1,142 | | | 18 | | | 1,825 | | | 4,264 | |
Net income (loss) | — | | | 106 | | | — | | | (6) | | | 100 | |
Unrealized gain on derivatives | — | | | — | | | 3 | | | 1 | | | 4 | |
| | | | | | | | | |
Distributions to CEG, cash | (4) | | | — | | | — | | | — | | | (4) | |
Distributions to noncontrolling interests, net of contributions, cash | — | | | — | | | — | | | (5) | | | (5) | |
Tax-related distributions | — | | | (45) | | | — | | | — | | | (45) | |
Distributions paid to Clearway, Inc. | — | | | (45) | | | — | | | — | | | (45) | |
Distributions paid to CEG Class B and Class D unit holders | — | | | (32) | | | — | | | — | | | (32) | |
Balances at June 30, 2023 | $ | 1,275 | | | $ | 1,126 | | | $ | 21 | | | $ | 1,815 | | | $ | 4,237 | |
See accompanying notes to consolidated financial statements.
CLEARWAY ENERGY LLC
CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY
For the Six Months Ended June 30, 2022
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(In millions) | Contributed Capital | | Retained Earnings (Accumulated Deficit) | | Accumulated Other Comprehensive(Loss) Income | | Noncontrolling Interest | | Total Members’ Equity |
Balances at December 31, 2021 | $ | 1,495 | | | $ | 43 | | | $ | (13) | | | $ | 1,692 | | | $ | 3,217 | |
Net loss | — | | | (58) | | | — | | | (42) | | | (100) | |
Unrealized gain on derivatives | — | | | — | | | 13 | | | 3 | | | 16 | |
Distributions to CEG, net of contributions, cash | (3) | | | — | | | — | | | — | | | (3) | |
| | | | | | | | | |
Contributions from noncontrolling interests, net of distributions, cash | — | | | — | | | — | | | 28 | | | 28 | |
Transfers of assets under common control | (46) | | | — | | | — | | | 9 | | | (37) | |
| | | | | | | | | |
Distributions paid to Clearway, Inc. | (40) | | | — | | | — | | | — | | | (40) | |
Distributions paid to CEG Class B and Class D unit holders | (5) | | | (25) | | | — | | | — | | | (30) | |
Balances at March 31, 2022 | 1,401 | | | (40) | | | — | | | 1,690 | | | 3,051 | |
Net income (loss) | — | | | 1,382 | | | — | | | (10) | | | 1,372 | |
Unrealized gain on derivatives | — | | | — | | | 6 | | | 1 | | | 7 | |
Contributions from (distributions to) CEG, cash | 11 | | | — | | | — | | | (31) | | | (20) | |
Distributions to noncontrolling interests, net of contributions, cash | — | | | — | | | — | | | (10) | | | (10) | |
Distributions paid to Clearway, Inc. | (41) | | | — | | | — | | | — | | | (41) | |
Distributions paid to CEG Class B and Class D unit holders | (30) | | | — | | | — | | | — | | | (30) | |
Balances at June 30, 2022 | $ | 1,341 | | | $ | 1,342 | | | $ | 6 | | | $ | 1,640 | | | $ | 4,329 | |
See accompanying notes to consolidated financial statements.
CLEARWAY ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 — Nature of Business
NRG YieldClearway Energy LLC, together with its consolidated subsidiaries, or the Company, was formed by NRG asis an energy infrastructure investor with a Delaware limited liability companyfocus on March 5, 2013, to serve as the primary vehicle through which NRG owns, operatesinvestments in clean energy and acquiresowner of modern, sustainable and long-term contracted renewable and conventional generation and thermal infrastructure assets. NRG owns 100% of NRG Yield LLC's Class B units and Class D units and receives distributions through its ownership of these units. Yield, Inc. owns 100% of NRG Yield LLC's Class A units and Class C units.
assets across North America. The Company ownsis sponsored by GIP and TotalEnergies through the portfolio company, Clearway Energy Group LLC, or CEG, which is equally owned by GIP and TotalEnergies. GIP is an independent infrastructure fund manager that makes equity and debt investments in infrastructure assets and businesses. TotalEnergies is a diversified portfolioglobal multi-energy company.
The Company is one of contractedthe largest renewable and conventional generation and thermal infrastructure assetsenergy owners in the U.S. with over 5,500 net MW of installed wind and solar generation projects. The Company’s contracted generation portfolio collectively represents 5,080over 8,000 net MW as of September 30, 2017. Eachassets also includes approximately 2,500 net MW of these assets sells substantially all ofenvironmentally-sound, highly efficient natural gas-fired generation facilities. Through this environmentally-sound, diversified and primarily contracted portfolio, the Company endeavors to increase distributions to its output pursuant to long-term offtake agreements with creditworthy counterparties.unit holders. The weighted average remaining contract duration of these offtake agreements was approximately 16 years as of September 30, 2017 based on CAFD. The Company also owns thermal infrastructure assets with an aggregate steam and chilled water capacity of 1,319 net MWt and electric generation capacity of 123 net MW. These thermal infrastructure assets provide steam, hot and/or chilled water, and, in some instances, electricity to commercial businesses, universities, hospitals and governmental units in multiple locations, principally through long-term contracts or pursuant to rates regulated by state utility commissions.
The following table represents the structuremajority of the Company as of September 30, 2017:
On July 12, 2017, NRG announced that it had adopted and initiated a three-year, three-part improvement plan, or the NRG Transformation Plan. As part of the NRG Transformation Plan, NRG announced that it is exploring strategic alternatives for its renewables platform and its interest in Yield, Inc. NRG, through its holdings of Class B common stock and Class D common stock, has a 55.1% voting interest in Yield, Inc. and receives distributionsCompany’s revenues are derived from the Company through its ownership of Class B units and Class D units. NRG stated that the strategic alternatives span a variety of ownership structures and partnership types, including the potential partial or full monetization of NRG's renewables platform and NRG's interest in Yield, Inc. NRG is Yield, Inc.'s controlling stockholder and the Company has been highly dependent on NRG for, among other things, growth opportunities and management and administration services. See Part I, Item 1A, Risk Factors in the Company's 2016 Form 10-K, as well as Part II, Item 1A, Risk Factors in the Company's Form 10-Q for the quarter ended June 30, 2017, for risks related to the NRG Transformation Plan and the Company's relationship with NRG.
As of September 30, 2017, the Company's operating assets are comprised of the following projects:
|
| | | | | | | | | | |
Projects | | Percentage Ownership | | Net Capacity (MW)(a) | | Offtake Counterparty | | Expiration |
Conventional | | | | | | | | |
El Segundo | | 100 | % | | 550 |
| | Southern California Edison | | 2023 |
GenConn Devon | | 50 | % | | 95 |
| | Connecticut Light & Power | | 2040 |
GenConn Middletown | | 50 | % | | 95 |
| | Connecticut Light & Power | | 2041 |
Marsh Landing | | 100 | % | | 720 |
| | Pacific Gas and Electric | | 2023 |
Walnut Creek | | 100 | % | | 485 |
| | Southern California Edison | | 2023 |
| | | | 1,945 |
| | | | |
Utility Scale Solar | | | | | | | | |
Agua Caliente | | 16 | % | | 46 |
| | Pacific Gas and Electric | | 2039 |
Alpine | | 100 | % | | 66 |
| | Pacific Gas and Electric | | 2033 |
Avenal | | 50 | % | | 23 |
| | Pacific Gas and Electric | | 2031 |
Avra Valley | | 100 | % | | 26 |
| | Tucson Electric Power | | 2032 |
Blythe | | 100 | % | | 21 |
| | Southern California Edison | | 2029 |
Borrego | | 100 | % | | 26 |
| | San Diego Gas and Electric | | 2038 |
CVSR | | 100 | % | | 250 |
| | Pacific Gas and Electric | | 2038 |
Desert Sunlight 250 | | 25 | % | | 63 |
| | Southern California Edison | | 2035 |
Desert Sunlight 300 | | 25 | % | | 75 |
| | Pacific Gas and Electric | | 2040 |
Kansas South | | 100 | % | | 20 |
| | Pacific Gas and Electric | | 2033 |
Roadrunner | | 100 | % | | 20 |
| | El Paso Electric | | 2031 |
TA High Desert | | 100 | % | | 20 |
| | Southern California Edison | | 2033 |
Utah Solar Portfolio (b) (e) | | 50 | % | | 265 |
| | PacifiCorp | | 2036 |
| | | | 921 |
| | | | |
Distributed Solar | | | | | | | | |
Apple I LLC Projects | | 100 | % | | 9 |
| | Various | | 2032 |
AZ DG Solar Projects | | 100 | % | | 5 |
| | Various | | 2025 - 2033 |
| | | | 14 |
| | | | |
Wind | | | | | | | | |
Alta I | | 100 | % | | 150 |
| | Southern California Edison | | 2035 |
Alta II | | 100 | % | | 150 |
| | Southern California Edison | | 2035 |
Alta III | | 100 | % | | 150 |
| | Southern California Edison | | 2035 |
Alta IV | | 100 | % | | 102 |
| | Southern California Edison | | 2035 |
Alta V | | 100 | % | | 168 |
| | Southern California Edison | | 2035 |
Alta X (b) | | 100 | % | | 137 |
| | Southern California Edison | | 2038 |
Alta XI (b) | | 100 | % | | 90 |
| | Southern California Edison | | 2038 |
Buffalo Bear | | 100 | % | | 19 |
| | Western Farmers Electric Co-operative | | 2033 |
Crosswinds (b) (f) | | 99 | % | | 21 |
| | Corn Belt Power Cooperative | | 2027 |
Elbow Creek (b) (f) | | 100 | % | | 122 |
| | NRG Power Marketing LLC | | 2022 |
Elkhorn Ridge (b) (f) | | 66.7 | % | | 54 |
| | Nebraska Public Power District | | 2029 |
Forward (b) (f) | | 100 | % | | 29 |
| | Constellation NewEnergy, Inc. | | 2017 |
Goat Wind (b) (f) | | 100 | % | | 150 |
| | Dow Pipeline Company | | 2025 |
Hardin (b) (f) | | 99 | % | | 15 |
| | Interstate Power and Light Company | | 2027 |
Laredo Ridge | | 100 | % | | 80 |
| | Nebraska Public Power District | | 2031 |
Lookout (b) (f) | | 100 | % | | 38 |
| | Southern Maryland Electric Cooperative | | 2030 |
|
| | | | | | | | | | |
Projects | | Percentage Ownership | | Net Capacity (MW)(a) | | Offtake Counterparty | | Expiration |
Odin (b) (f) | | 99.9 | % | | 20 |
| | Missouri River Energy Services | | 2028 |
Pinnacle | | 100 | % | | 55 |
| | Maryland Department of General Services and University System of Maryland | | 2031 |
San Juan Mesa (b) (f) | | 75 | % | | 90 |
| | Southwestern Public Service Company | | 2025 |
Sleeping Bear (b) (f) | | 100 | % | | 95 |
| | Public Service Company of Oklahoma | | 2032 |
South Trent | | 100 | % | | 101 |
| | AEP Energy Partners | | 2029 |
Spanish Fork (b) (f) | | 100 | % | | 19 |
| | PacifiCorp | | 2028 |
Spring Canyon II (b) | | 90.1 | % | | 29 |
| | Platte River Power Authority | | 2039 |
Spring Canyon III (b) | | 90.1 | % | | 25 |
| | Platte River Power Authority | | 2039 |
Taloga | | 100 | % | | 130 |
| | Oklahoma Gas & Electric | | 2031 |
Wildorado (b) (f) | | 100 | % | | 161 |
| | Southwestern Public Service Company | | 2027 |
| | | | 2,200 |
| | | | |
Thermal | | | | | | | | |
NRG Dover Energy Center LLC | | 100 | % | | 103 |
| | NRG Power Marketing LLC | | 2018 |
Thermal generation | | 100 | % | | 20 |
| | Various | | Various |
| | | | 123 |
| | | | |
Total net generation capacity(c) | | | | 5,203 |
| | | | |
| | | | | | | | |
Thermal equivalent MWt (d) | | 100 | % | | 1,319 |
| | Various | | Various |
(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of September 30, 2017.
(b) Projects are part of tax equity arrangements.
(c) The Company's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. The Company's generation capacity including this noncontrolling interest was 5,209 MWs.
(d) For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.
(e) Represents interests in Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC, all acquired as part of the March 2017 Drop Down Assets (ownership percentage is based upon cash to be distributed).
(f)Projects are part of NRG Wind TE Holdco portfolio.
In addition to the facilities owned or leased in the table above, the Company entered into partnerships to own or purchase solar power generation projects, as well as other ancillary related assets from a related party via intermediate funds. The Company does not consolidate these partnerships and accounts for them as equity method investments. The Company's net interest in these projects is 226 MW based on cash to be distributed as of September 30, 2017. For further discussions, refer to Note 4, Investments Accounted for by the Equity Method and Variable Interest Entities of this Form 10-Q and Note 5, Investments Accounted for by the Equity Method and Variable Interest Entities to the consolidated financial statements for the year ended December 31, 2016 included in the Company's May 9, 2017 Form 8-K.
Substantially all of the Company's generation assets are under long-term contractual arrangements for the output or capacity from these assets. The thermal assets are comprised
Clearway Energy, Inc., or Clearway, Inc., consolidates the results of district energy systems and combined heat and power plants that produce steam, hot water and/or chilled water and, in some instances, electricity at a central plant. Certain district energy systems are subject to rate regulation by state public utility commissions (although they may negotiate certain rates) while the other district energy systems have rates determined by negotiated bilateral contracts.
As described in Note 3, Business Acquisitions, on August 1, 2017, the Company acquired the remaining 25%through its controlling interest, in NRG Wind TE Holdco, a portfolio of 12 wind projects, referred towith CEG’s interest shown as the August 2017 Drop Down Assets, from NRG for total cash consideration of $44 million, including workingcontributed capital adjustment of $3 million. The purchase agreement also included potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027, which were estimated and accrued as contingent consideration in the amountCompany’s consolidated financial statements. The holders of $8 millionClearway, Inc.’s outstanding shares of Class A and Class C common stock are entitled to dividends as declared. CEG receives its distributions from the Company through its ownership of the Company’s Class B and Class D units.
As of June 30, 2023, Clearway, Inc. owned 57.90% of the economic interests of the Company, with CEG owning 42.10% of the economic interests of the Company.
The following table represents a summarized structure of the Company as of SeptemberJune 30, 2017. On March 27, 2017, the Company acquired the following interests from NRG, referred to as the March 2017 Drop Down Assets: (i) Agua Caliente Borrower 2 LLC, which owns a 16% interest in the Agua Caliente solar farm, one2023:
Basis of the ROFO assets and (ii) NRG's interests in seven utility-scale solar farms located in Utah that were part of NRG's November 2, 2016 acquisition of projects from SunEdison, or the Utah Solar Portfolio. The Company paid total cash consideration of $130 million, plus a $2 million working capital adjustment, and assumed non-recourse debt of $328 million, which is consolidated, as well as its pro-rata share of non-recourse project-level debt of $135 million. The acquisition was funded with cash on hand.
The acquisitions of the August 2017 Drop Down Assets and March 2017 Drop Down Assets were accounted for as transfers of entities under common control. The accounting guidance requires retrospective combination of the entities for all periods presented as if the combinations had been in effect from the beginning of the financial statement period or from the date the entities were under common control (if later than the beginning of the financial statement period).Presentation
The accompanying unaudited interim 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 GAAP 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 for the year ended December 31, 2016 included in the Company's May 9, 2017Company’s 2022 Form 8-K.10-K. Interim results are not necessarily indicative of results for a full year.
In the opinion of management, the accompanying unaudited interim consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company'sCompany’s consolidated financial position as of SeptemberJune 30, 2017,2023, and the results of operations, comprehensive income (loss) and cash flows for the three and ninesix months ended SeptemberJune 30, 20172023 and 2016.2022.
Note 2 — Summary of Significant Accounting Policies
Use of Estimates
The preparation of consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions. These estimates and assumptions impact the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the consolidated financial statements, andstatements. They also impact the reported amounts of revenues and expensesnet earnings during the reporting period.periods. Actual results could be different from these estimates.
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase. Cash and cash equivalents held at project subsidiaries was $134 million and $121 million as of June 30, 2023 and December 31, 2022, respectively.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets that sum to the total of the same such amounts shown in the consolidated statements of cash flows:
| | | | | | | | | | | |
| June 30, 2023 | | December 31, 2022 |
| (In millions) |
Cash and cash equivalents | $ | 547 | | | $ | 657 | |
Restricted cash | 371 | | | 339 | |
Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows | $ | 918 | | | $ | 996 | |
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. As of June 30, 2023, these restricted funds were comprised of $104 million designated to fund operating expenses, $168 million designated for current debt service payments and $85 million restricted for reserves including debt service, performance obligations and other reserves as well as capital expenditures. The remaining $14 million is held in distributions reserve accounts.
Accumulated Depreciation and Accumulated Amortization
The following table presents the accumulated depreciation included in the property, plant and equipment, net, and accumulated amortization included in intangible assets, net, respectively, as of September 30, 2017 and December 31, 2016:net:
|
| | | | | | | |
| September 30, 2017 | | December 31, 2016 |
| (In millions) |
Property, Plant and Equipment Accumulated Depreciation | $ | 1,189 |
| | $ | 951 |
|
Intangible Assets Accumulated Amortization | 216 |
| | 163 |
|
Noncontrolling Interests
The following table reflects the changes in the Company's noncontrolling interest balance:
|
| | | |
| (In millions) |
Balance as of December 31, 2016 as reported | $ | 313 |
|
Less: Adjustment for August 2017 Drop Down Assets | (87 | ) |
Balance as of December 31, 2016 as recast | 226 |
|
Capital contributions from tax equity investors, net of distributions | 11 |
|
Comprehensive loss | (56 | ) |
Balance as of September 30, 2017 | $ | 181 |
|
| | | | | | | | | | | |
| June 30, 2023 | | December 31, 2022 |
| (In millions) |
Property, Plant and Equipment Accumulated Depreciation | $ | 3,232 | | | $ | 3,024 | |
Intangible Assets Accumulated Amortization | 972 | | | 877 | |
Distributions
The following table lists the distributions paid on NRG Yield LLC'sthe Company's Class A, B, C and D units during the ninesix months ended SeptemberJune 30, 2017:2023:
|
| | | | | | | | | | | |
| Third Quarter 2017 | | Second Quarter 2017 | | First Quarter 2017 |
Distributions per Class A, B, C and D unit | $ | 0.28 |
| | $ | 0.27 |
| | $ | 0.26 |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | Second Quarter 2023 | | First Quarter 2023 |
Distributions per Class A, B, C and D unit | | | | | | $ | 0.3818 | | | $ | 0.3745 | |
On October 31, 2017,August 7, 2023, the Company declared a distribution on its Class A, Class B, Class C and Class D units of $0.288$0.3891 per unit payable on DecemberSeptember 15, 20172023 to unit holders of record as of DecemberSeptember 1, 2017.2023.
Changes in Capital Structure
At-the-Market Equity Offering Program, or the ATM Program
NRG Yield, Inc. is party to an equity distribution agreement with Barclays Capital Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC, as sales agents. PursuantIn addition to the termsquarterly distributions, the Company paid $45 million in additional distributions, $26 million of which was distributed to Clearway, Inc. and $19 million of which was distributed to CEG, during the second quarter of 2023 in order for Clearway, Inc. to make certain additional tax payments primarily associated with the sale of the Thermal Business.
Redeemable Noncontrolling Interests
To the extent that a third party has the right to redeem their interests for cash or other assets, the Company has included the noncontrolling interest attributable to the third party as a component of temporary equity distribution agreement, NRG Yield, Inc. may offer and sell shares of its Class C common stock par value $0.01 per share, from time to time throughin the sales agents up to an aggregate sales price of $150 million through an at-the-market equity offering program, or the ATM Program. NRG Yield, Inc. may also sell shares of its Class C common stock to anymezzanine section of the sales agents, as principalsconsolidated balance sheet. The following table reflects the changes in the Company’s redeemable noncontrolling interest balance:
| | | | | | | | |
| | (In millions) |
Balance at December 31, 2022 | | $ | 7 | |
Cash distributions to redeemable noncontrolling interests | | (1) | |
Comprehensive income attributable to redeemable noncontrolling interests | | 9 | |
Balance at June 30, 2023 | | $ | 15 | |
Revenue Recognition
Disaggregated Revenues
The following tables represent the Company’s disaggregation of revenue from contracts with customers along with the reportable segment for its own account, ateach category:
| | | | | | | | | | | | | | | | | | | | | |
| Three months ended June 30, 2023 |
(In millions) | Conventional Generation | | Renewables | | | | | | Total |
Energy revenue (a) | $ | 3 | | | $ | 275 | | | | | | | $ | 278 | |
Capacity revenue (a) | 96 | | | 5 | | | | | | | 101 | |
Other revenue (a) | 21 | | | 27 | | | | | | | 48 | |
Contract amortization | (5) | | | (42) | | | | | | | (47) | |
Mark-to-market for economic hedges | — | | | 26 | | | | | | | 26 | |
Total operating revenues | 115 | | | 291 | | | | | | | 406 | |
Less: Mark-to-market for economic hedges | — | | | (26) | | | | | | | (26) | |
Less: Lease revenue | (104) | | | (237) | | | | | | | (341) | |
Less: Contract amortization | 5 | | | 42 | | | | | | | 47 | |
Total revenue from contracts with customers | $ | 16 | | | $ | 70 | | | | | | | $ | 86 | |
| | | | | | | | | |
(a) The following amounts of energy, capacity and other revenue relate to leases and are accounted for under ASC 842:
| | | | | | | | | | | | | | | | | |
(In millions) | Conventional Generation | | Renewables | | Total |
Energy revenue | $ | 1 | | | $ | 233 | | | $ | 234 | |
Capacity revenue | 82 | | | 4 | | | 86 | |
Other revenue (b) | 21 | | | — | | | 21 | |
Total | $ | 104 | | | $ | 237 | | | $ | 341 | |
(b) On May 31, 2023, the Marsh Landing Black Start addition reached commercial operations and the Company will receive an annual fixed fee over a price agreed upon at the time of sale. During the first nine months of 2017, Yield, Inc. issued 1,921,866 shares of Class C common stockfive-year term under the ATM Programrelated agreement. The agreement was determined to be a sales-type lease resulting in the Company recording a lease receivable of $21 million included in total operating revenues, offset by net investment costs of $13 million included in cost of operations, resulting in a net pre-tax profit of $8 million.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended June 30, 2022 |
(In millions) | Conventional Generation | | Renewables | | Thermal | | | | | | Total |
Energy revenue (a) | $ | 3 | | | $ | 306 | | | $ | 11 | | | | | | | $ | 320 | |
Capacity revenue (a) | 106 | | | 1 | | | 4 | | | | | | | 111 | |
Other revenue | — | | | 27 | | | 3 | | | | | | | 30 | |
Contract amortization | (6) | | | (35) | | | — | | | | | | | (41) | |
Mark-to-market for economic hedges | — | | | (52) | | | — | | | | | | | (52) | |
Total operating revenues | 103 | | | 247 | | | 18 | | | | | | | 368 | |
Less: Mark-to-market for economic hedges | — | | | 52 | | | — | | | | | | | 52 | |
Less: Lease revenue | (109) | | | (268) | | | — | | | | | | | (377) | |
Less: Contract amortization | 6 | | | 35 | | | — | | | | | | | 41 | |
Total revenue from contracts with customers | $ | — | | | $ | 66 | | | $ | 18 | | | | | | | $ | 84 | |
(a) The following amounts of energy and capacity revenue relate to leases and are accounted for gross proceedsunder ASC 842:
| | | | | | | | | | | | | | | | | | | |
(In millions) | Conventional Generation | | Renewables | | | | Total |
Energy revenue | $ | 3 | | | $ | 268 | | | | | $ | 271 | |
Capacity revenue | 106 | | | — | | | | | 106 | |
Total | $ | 109 | | | $ | 268 | | | | | $ | 377 | |
| | | | | | | | | | | | | | | | | | | | | |
| Six months ended June 30, 2023 | | | | |
(In millions) | Conventional Generation | | Renewables | | Total | | | | |
Energy revenue (a) | $ | 4 | | | $ | 473 | | | $ | 477 | | | | | |
Capacity revenue (a) | 196 | | | 10 | | | 206 | | | | | |
Other revenue (a) | 21 | | | 39 | | | 60 | | | | | |
Contract amortization | (11) | | | (83) | | | (94) | | | | | |
Mark-to-market for economic hedges | — | | | 45 | | | 45 | | | | | |
Total operating revenues | 210 | | | 484 | | | 694 | | | | | |
Less: Mark-to-market for economic hedges | — | | | (45) | | | (45) | | | | | |
Less: Lease revenue | (205) | | | (393) | | | (598) | | | | | |
Less: Contract amortization | 11 | | | 83 | | | 94 | | | | | |
Total revenue from contracts with customers | $ | 16 | | | $ | 129 | | | $ | 145 | | | | | |
| | | | | | | | | |
(a) The following amounts of $35 million, with commission feesenergy, capacity and other revenue relate to leases and are accounted for under ASC 842:
| | | | | | | | | | | | | | | | | |
(In millions) | Conventional Generation | | Renewables | | Total |
Energy revenue | $ | 2 | | | $ | 385 | | | $ | 387 | |
Capacity revenue | 182 | | | 8 | | | 190 | |
Other revenue (b) | 21 | | | $ | — | | | 21 | |
Total | $ | 205 | | | $ | 393 | | | $ | 598 | |
(b) Includes revenue recognized for the Marsh Landing Black Start addition that reached commercial operations on May 31, 2023, as described above.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six months ended June 30, 2022 | | | | |
(In millions) | Conventional Generation | | Renewables | | Thermal | | Total | | | | |
Energy revenue (a) | $ | 3 | | | $ | 501 | | | $ | 48 | | | $ | 552 | | | | | |
Capacity revenue (a) | 220 | | | 1 | | | 18 | | | 239 | | | | | |
Other revenue | — | | | 41 | | | 11 | | | 52 | | | | | |
Contract amortization | (12) | | | (71) | | | — | | | (83) | | | | | |
Mark-to-market for economic hedges | — | | | (178) | | | — | | | (178) | | | | | |
Total operating revenues | 211 | | | 294 | | | 77 | | | 582 | | | | | |
Less: Mark-to-market for economic hedges | — | | | 178 | | | — | | | 178 | | | | | |
Less: Lease revenue | (223) | | | (430) | | | (1) | | | (654) | | | | | |
Less: Contract amortization | 12 | | | 71 | | | — | | | 83 | | | | | |
Total revenue from contracts with customers | $ | — | | | $ | 113 | | | $ | 76 | | | $ | 189 | | | | | |
| | | | | | | | | | | |
(a) The following amounts of $346 thousand. Yield, Inc. usedenergy and capacity revenue relate to leases and are accounted for under ASC 842:
| | | | | | | | | | | | | | | | | | | | | | | |
(In millions) | Conventional Generation | | Renewables | | Thermal | | Total |
Energy revenue | $ | 3 | | | $ | 430 | | | $ | 1 | | | $ | 434 | |
Capacity revenue | 220 | | | — | | | — | | | 220 | |
Total | $ | 223 | | | $ | 430 | | | $ | 1 | | | $ | 654 | |
Contract Balances
The following table reflects the net proceeds to acquire 1,921,866 Class C units fromcontract assets and liabilities included on the Company. At September 30, 2017, approximately $115 million remains available for issuance under the ATM Program.Company’s consolidated balance sheets:
Reclassifications | | | | | | | | | | | |
| June 30, 2023 | | December 31, 2022 |
| (In millions) |
Accounts receivable, net - Contracts with customers | $ | 62 | | | $ | 37 | |
Accounts receivable, net - Leases | 153 | | | 116 | |
Total accounts receivable, net | $ | 215 | | | $ | 153 | |
Certain prior-year amounts have been reclassified for comparative purposes.Recently Adopted Accounting Standards
Recent Accounting Developments
ASU 2017-12 — In August 2017,March 2020, the FASB issued ASU No. 2017-12, Derivatives2020-4, Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The amendments provide for optional expedients and Hedging (Topic 815), Targeted Improvementsexceptions for applying GAAP to Accountingcontracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. These amendments apply only to contracts that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform, which affects certain of the Company’s debt and interest rate swap agreements. The guidance is effective for Hedging Activities, orall entities as of March 20, 2020 through December 31, 2022. In December 2022, the FASB issued ASU No. 2017-12. ASU No. 2017-12 amends ASU No. 2016-15. The amendments2022-6, Deferral of ASU No. 2016-15 were issuedthe Sunset Date of Reference Rate Reform, to simplifyextend the applicationend of hedge accounting guidancethe transition period to December 31, 2024. As of July 14, 2023, the Company has amended all of the applicable contracts that previously used LIBOR as a reference rate and more closely aligning 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 limitedelected to alignment of risk management activities and financial reporting, risk component hedging, accounting forapply the hedged item in fair value hedges ofpractical expedient to certain modified cash flow interest rate risk, recognitionswap and presentation of the effects of hedging instruments, amounts excluded from the assessment of hedge effectiveness, and other simplifications of hedge accounting guidance.debt agreements. 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 doesdid not expect that the adoption of ASU No. 2017-12 will have a material impact on our consolidated results of operations, cash flows, and statement of financial position.
ASU 2016-18 — In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230), Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require an entity to include amounts generally described as restricted cash and restricted cash equivalents 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 early adopted ASU No. 2016-18 during the second quarter of 2017. Net cash flows used in investing activities for the nine months ended September 30, 2016 decreased by $7 million. The sum of Company's cash and cash equivalents and restricted cash reported within the consolidated balance sheet as of December 31, 2016 equals the beginning balances of cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows for the nine months ended September 30, 2017. The sum of Company's cash and cash equivalents and restricted cash reported within the consolidated balance sheet as of September 30, 2017 equals to the ending balances of cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows for the nine months ended September 30, 2017.
ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company expects to adopt the standard effective January 1, 2019 utilizing the required modified retrospective approach for the earliest period presented. The Company expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. The Company is currently working through an adoption plan and evaluating the anticipated impact on the Company's results of operations, cash flows and financial position. 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, the Company believes the adoption of Topic 842 may be material to its financial statements.
ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09, which was further amended through various updates issued by the FASB thereafter. The amendments of ASU No. 2014-09 completed the joint effort between the FASB and the IASB, to develop a common revenue standard for GAAP and IFRS, and to improve financial reporting. The guidance under Topic 606 provides that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for the goods or services provided and establishes a five step model to be applied by an entity in evaluating its contracts with customers. The Company expects to adopt the standard effective January 1, 2018 and apply the guidance retrospectively to contracts at the date of adoption. The Company will recognize the cumulative effect of applying Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method. The Company also expects to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance completed to date by the entity. The majority of the Company's revenues are obtained through PPAs, which are currently accounted for as operating leases. In connection with the implementation of Topic 842, as described above, the Company expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. As leases are excluded from the scope of Topic 606, the Company expects the standard to have an immaterial impact on the Company's results of operations, cash flows and financial position.
Note 3 — Business Acquisitions and Dispositions
2017 Acquisitions
November 2017Daggett 3 Drop Down Assets — On November 1, 2017,February 17, 2023, the Company, through its indirect subsidiary, Daggett Solar Investment LLC, acquired the Class A membership interests in Daggett TargetCo LLC, the indirect owner of the Daggett 3 solar project, a 38300 MW solar portfolio primarily comprisedproject with matching storage capacity that is currently under construction, located in San Bernardino, California, from Clearway Renew, a subsidiary of assets from NRG's Solar Power Partners (SPP) funds and other projects developed by NRG,CEG, for cash consideration of $71 million, excluding working capital adjustments, plus assumed non-recourse debt$21 million. Simultaneously, a cash equity investor acquired the Class B membership interests in Daggett TargetCo LLC from Clearway Renew for cash consideration of $26$129 million. AsThe Company and the cash equity investor then contributed their Class A and B membership interests, respectively, into Daggett Renewable Holdco LLC, a partnership between the Company and the cash equity investor, which consolidates Daggett TargetCo LLC. Daggett TargetCo LLC consolidates, as the indirect owner of September 30, 2017, the November 2017 Drop Down Assets' debt was $33 million,primary beneficiary, a tax equity fund, Daggett TE Holdco LLC, which owns the Daggett 3 solar project, as further described in Note 4, Investments Accounted for by the Equity Method and Variable Interest Entities. Daggett 3 has PPAs with investment-grade counterparties that have a 15-year weighted average contract duration that commence when the underlying operating assets reach commercial operations, which is expected to occur in the second half of which $7 million was paid by NRG2023. The Daggett 3 operations are reflected in October 2017.
The purchase price for the November 2017 Drop Down AssetsCompany’s Renewables segment and the acquisition was funded with cashexisting sources of liquidity. The acquisition was determined to be an asset acquisition and the Company consolidates Daggett 3 on hand.a prospective basis in its financial statements. The assets and liabilities transferred to the Company relate to interests under common control by NRG and were recorded at historical cost in accordance with ASC 805-50, Business Combinations - Related Issues. The difference between the cash paid of $21 million and the historical valuecost of the entities' equityCompany’s net assets acquired of $15 million was recorded as an adjustment to CEG’s contributed capital. Becausecapital balance. In addition, the transaction constituted a transfer of net assets under common control, the guidance requires retrospective combinationCompany reflected $21 million of the entities for all periods presented as ifCompany’s purchase price, which was contributed back to the combination has beenCompany by CEG to pay down the acquired long-term debt, in effect since the inceptionline item contributions from CEG, net of common control.
distributions in the consolidated statements of members’ equity.
The following is a summary of assets and liabilities transferred in connection with the acquisition of the November 2017 Drop Down Assets as of September 30, 2017:
|
| | | |
| (In millions) |
Assets: | |
Current assets | $ | 11 |
|
Property, plant and equipment | 84 |
|
Non-current assets | 32 |
|
Total assets | 127 |
|
Liabilities: | |
Debt (Current and non-current) (a) | 31 |
|
Other current and non-current liabilities | 3 |
|
Total liabilities assumed | 34 |
|
Net assets acquired | $ | 93 |
|
| | | | | | | | |
(In millions) | | Daggett 3 |
Restricted cash | | $ | 14 | |
Property, plant and equipment | | 534 | |
Right-of-use-assets, net | | 31 | |
Derivative assets | | 27 | |
| | |
Total assets acquired | | 606 | |
| | |
Long-term debt (a) | | 480 | |
Long-term lease liabilities | | 33 | |
Other current and non-current liabilities (b) | | 78 | |
Total liabilities assumed | | 591 | |
Net assets acquired | | $ | 15 | |
(a)NetIncludes a $181 million construction loan, $75 million sponsor equity bridge loan and $229 million tax equity bridge loan, offset by $5 million in unamortized debt issuance costs. See Note 7, Long-term Debt, for further discussion of $2the long-term debt assumed in the acquisition.
(b) Includes $32 million of net debt issuanceproject costs that were subsequently funded by CEG. Subsequent to the acquisition date, CEG funded an additional $11 million in project costs.
Supplemental Pro Forma Information
As described above, The combined $43 million funded by CEG will be repaid with the Company's acquisition ofproceeds received when the November 2017 Drop Down Assets was accounted for as a transfer of entities under common control. The following unaudited supplemental pro forma information represents the consolidated results of operations as if the Company acquired the November 2017 Drop Down Assets on January 1, 2016, including the impact of acquisition accounting with respectproject reaches substantial completion, which is expected to NRG's acquisition of the projects.
|
| | | | | | | | | | | | | | | |
| For the three months ended | | For the nine months ended |
| September 30, 2017 | | September 30, 2016 | | September 30, 2017 | | September 30, 2016 |
| | | | | | | |
Total operating revenues | $ | 269 |
| | $ | 275 |
| | $ | 777 |
| | $ | 798 |
|
Net income | 30 |
| | 69 |
| | 90 |
| | 155 |
|
August 2017 Drop Down Assets — On August 1, 2017, the Company acquired the remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, from NRG for total cash consideration of $44 million, including working capital adjustment of $3 million. The purchase agreement also included potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027, which were estimated and accrued as contingent considerationoccur in the amountsecond half of $8 million as of September 30, 2017.2023.
The Company originally acquired 75% of NRG Wind TE Holdco on November 3, 2015, or November 2015 Drop Down Assets, which were consolidated with 25% of the net assets recorded as noncontrolling interest. The assets and liabilities transferred to the Company related to interests under common control by NRG and were recorded at historical cost in accordance with ASC 805-50, Business Combination - Related Issues. The difference between the cash paid of $44 million, net of the contingent consideration of $8 million, and the historical value of the remaining 25% of $87 million as of July 31, 2017, was recorded as an adjustment to NRG's contributed capital. Since the transaction constituted a transfer of entities under common control, the accounting guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect from the beginning of the financial statement period or from the date the entities were under common control (if later than the beginning of the financial statement period).
March 2017 Drop Down Assets — On March 27, 2017, the Company acquired the following interests from NRG: (i) Agua Caliente Borrower 2 LLC, which owns a 16% interest (approximately 31% of NRG's 51% interest) in the Agua Caliente solar farm, one of the ROFO Assets, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in the Utah Solar Portfolio. Agua Caliente is located in Yuma County, AZ and sells power subject to a 25-year PPA with Pacific Gas and Electric, with 22 years remaining on that contract. The seven utility-scale solar farms in the Utah Solar Portfolio are owned by the following entities: Four Brothers Capital, LLC, Iron Springs Capital, LLC, and Granite Mountain Capital, LLC. These utility-scale solar farms achieved commercial operations in 2016, sell power subject to 20-year PPAs with PacifiCorp, a subsidiary of Berkshire Hathaway and are part of a tax equity structure with Dominion Solar Projects III, Inc., or Dominion, through which the Company is entitled to receive 50% of cash to be distributed, as further described below. The Company paid cash consideration of $130 million, plus $2 million of working capital paid through September 30, 2017. The acquisition of the March 2017 Drop
Down Assets was funded with cash on hand. The Company recorded the acquired interests as equity method investments. The Company also assumed non-recourse debt of $41 million and $287 million on Agua Caliente Borrower 2 LLC and the Utah Solar Portfolio, respectively, as further described in Note 7, Long-term Debt, as well as its pro-rata share of non-recourse project-level debt of Agua Caliente Solar LLC, as further described in Note 4 — Investments Accounted for by the Equity Method and Variable Interest Entities.
Entities that are not Consolidated
The assets and liabilities transferred to the Company relate to interests under common control by NRG and were recorded at historical cost in accordance with ASC 805-50, Business Combination - Related Issues. The difference between the cash paid and the historical value of the entities' equity of $8 million was recorded ashas an adjustment to contributed capital. Since the transaction constituted a transfer of entities under common control, the accounting guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect from the beginning of the financial statement period or from the date the entities were under common control (if later than the beginning of the financial statement period). Accordingly, in connection with the retrospective adjustment of prior periods, the Company adjusted its financial statements to reflect its results of operations, financial position and cash flows as if it recorded its interests in the Agua Caliente Borrower 2 LLC on January 1, 2016, and its interests in the Utah Solar Portfolio on November 2, 2016.
The following is a summary of assets and liabilities transferred in connection with the acquisition of the March 2017 Drop Down Assets as of March 27, 2017:
|
| | | |
| (In millions) |
Assets: | |
Cash | $ | 6 |
|
Equity investment in projects | 456 |
|
Total assets acquired | 462 |
|
Liabilities: | |
Debt (Current and non-current) (a) | 320 |
|
Other current and non-current liabilities | 3 |
|
Total liabilities assumed | 323 |
|
Net assets acquired | $ | 139 |
|
(a)Net of $8 million of debt issuance costs.
The following tables present a summary of the Company's historical information combining the financial information for the March 2017 Drop Down Assets and August 2017 Drop Down Assets transferred in connection with the acquisition:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended September 30, 2016 | | Nine months ended September 30, 2016 |
| As Previously Reported | | March 2017 Drop Down Assets | | August 2017 Drop Down Assets | | As Currently Reported | | As Previously Reported | | March 2017 Drop Down Assets | | August 2017 Drop Down Assets | | As Currently Reported |
(In millions) | | | | | | | | | | | | | | | |
Total operating revenues | $ | 272 |
| | $ | — |
| | $ | — |
| | $ | 272 |
| | $ | 789 |
| | $ | — |
| | $ | — |
| | $ | 789 |
|
Operating income | 118 |
| | — |
| | — |
| | 118 |
| | 319 |
| | — |
| | — |
| | 319 |
|
Net income | 64 |
| | 3 |
| | — |
| | 67 |
| | 147 |
| | 5 |
| | — |
| | 152 |
|
Net income attributable to Yield LLC | 100 |
| | 3 |
| | 2 |
| | 105 |
| | 209 |
| | 5 |
| | 5 |
| | 219 |
|
2016 Acquisitions
CVSR Drop Down — Prior to September 1, 2016, the Company had a 48.95% interest in CVSR,an entity that is considered a VIE under ASC 810, but for which was accountedit is not considered the primary beneficiary. The Company accounts for as anits interest in this entity and entities in which it has a significant investment under the equity method investment.On September 1, 2016, the Company acquired from NRG the remaining 51.05% interest of CVSR Holdco LLC, which indirectly owns the CVSR solar facility, for total cash consideration of $78.5 million plus an immaterial working capital adjustment. The Company also assumed additional debt of $496 million, which represents 51.05% of the CVSR project level debt and 51.05% of the notes issued under the CVSR Holdco Financing Agreement, as of the closing date,accounting, as further described inunder Item 15 — Note 10, Long-term Debt, to the consolidated financial statements for the year ended December 31, 2016 included in the Company's May 9, 2017 Form 8-K. The acquisition was funded with cash on hand.
The assets and liabilities transferred to the Company relate to interests under common control by NRG and were recorded at historical cost in accordance with ASC 805-50, Business Combinations - Related Issues. The difference between the cash paid and historical value of the CVSR Drop Down of $112 million, as well as $6 million of AOCL, was recorded as a distribution to NRG with the offset to contributed capital. Because the transaction constituted a transfer of net assets under common control, the guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect since the inception of common control. In connection with the retrospective adjustment of prior periods, the Company now consolidates CVSR and 100% of its debt, consisting of $771 million of project level debt and $200 million of notes issued under the CVSR Holdco Financing Agreement as of September 1, 2016. In connection with the retrospective adjustment of prior periods, the Company has removed the equity method investment from all prior periods and adjusted its financial statements to reflect its results of operations, financial position and cash flows as if it had consolidated CVSR from the beginning of the financial statement period.
Note 4 — 5,Investments Accounted for by the Equity Method and Variable Interest Entities,
to the consolidated financial statements included in the Company’s 2022 Form 10-K.
Rosie Central BESS — On June 30, 2023, the Company, through its indirect subsidiary, Rosie Class B LLC, the indirect owner of the Rosamond Central solar project, became the owner of the Class B membership interests of Rosie BESS Devco LLC, or Rosie Central BESS, in order to facilitate and fund the construction of a 147 MW battery energy storage system, or BESS, that will be co-located at the Rosamond Central solar facility. Clearway Renew indirectly owns the Class A membership interests. The Company accounts for its investment in Rosie Central BESS as an equity method investment. The Company’s investment consists of $10 million contributed into Rosie Central BESS, funded through contributions from the Company and its cash equity investor in Rosie TargetCo LLC, which consolidates Rosie Class B LLC. On July 3, 2023, Rosie Class B LLC contributed an additional $20 million into Rosie Central BESS, as further described in Note 7, Long-term Debt.
Additionally, on June 30, 2023, Rosamond Central entered into an asset purchase agreement with Clearway Renew to acquire the BESS project assets at mechanical completion for a purchase price of $360 million, of which $72 million is payable at mechanical completion with the remaining $288 million payable at substantial completion. The Company will fund $17 million of the purchase price at mechanical completion and $67 million of the purchase price at substantial completion with the remaining purchase price funded through contributions from the cash equity investor in Rosie TargetCo LLC and the tax equity investor in Rosie TE Holdco LLC. The BESS project is anticipated to reach mechanical completion in the second half of 2023 and to reach substantial completion in the first half of 2024.
The Company’s maximum exposure to loss as of June 30, 2023 is limited to its equity investment in the unconsolidated entities, as further summarized in the table below:
| | | | | | | | |
Name | Economic Interest | Investment Balance |
| | (In millions) |
Avenal | 50% | $ | 5 | |
Desert Sunlight | 25% | 227 | |
Elkhorn Ridge | 67% | 18 | |
GenConn (a) | 50% | 80 | |
Rosie Central BESS | 50% | 10 | |
San Juan Mesa | 75% | 12 | |
| | $ | 352 | |
(a)GenConn is a variable interest entity.
Entities that are Consolidated
TheAs further described under Item 15 — Note 5, Investments Accounted for by the Equity Method and Variable Interest Entities, to the consolidated financial statements included in the Company’s 2022 Form 10-K, the Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810, Consolidations, or ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third parties in order to monetize certain tax credits associated with wind facilities,and solar facilities. The Company also has a controlling financial interest in certain partnership arrangements with third-party investors, which have also been identified as furtherVIEs. Under the Company’s arrangements that have been identified as VIEs, the third-party investors are allocated earnings, tax attributes and distributable cash in accordance with the respective limited liability agreements. Many of these arrangements also provide a mechanism to facilitate achievement of the investor’s specified return by providing incremental cash distributions to the investor at a specified date if the specified return has not yet been achieved.
The discussion below describes material changes to VIEs during the six months ended June 30, 2023.
Daggett Renewable Holdco LLC — As described in Note 5, Investments Accounted for by3, Acquisitions and Dispositions, on February 17, 2023, Daggett Solar Investment LLC, an indirect subsidiary of the Equity MethodCompany, acquired the Class A membership interests in Daggett TargetCo LLC while a cash equity investor acquired the Class B membership interests. The Company and Variable Interest Entities, the cash equity investor then contributed their Class A and B membership interests, respectively, into Daggett Renewable Holdco LLC, a partnership between the Company and the cash equity investor, and concurrently, Daggett TargetCo LLC became a wholly-owned subsidiary of Daggett Renewable Holdco LLC. The Company consolidates Daggett Renewable Holdco LLC as a VIE as the Company is the primary beneficiary, through its role as managing member. The Company recorded the noncontrolling interest of the cash equity investor in Daggett Renewable Holdco LLC at historical carrying amount, with the offset to contributed capital. Daggett TargetCo LLC consolidates, as the consolidated financial statements forindirect owner of the year ended December 31, 2016 included inprimary beneficiary, a tax equity fund, Daggett TE Holdco LLC, which owns the Company's May 9, 2017 Form 8-K.Daggett 3 solar project. The tax equity investor’s interest is shown as noncontrolling interest and the HLBV method is utilized to allocate the income or losses of Daggett TE Holdco LLC.
Summarized financial information for the Company'sCompany’s consolidated VIEs consisted of the following as of SeptemberJune 30, 2017:2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(In millions) | Alta TE Holdco LLC | | Buckthorn Holdings, LLC | | DGPV Funds (a) | | Daggett Renewable Holdco LLC (b) | | Langford TE Partnership LLC | | Lighthouse Renewable Holdco LLC (c) |
Other current and non-current assets | $ | 59 | | | $ | 6 | | | $ | 88 | | | $ | 142 | | | $ | 12 | | | $ | 123 | |
Property, plant and equipment | 290 | | | 189 | | | 510 | | | 570 | | | 119 | | | 819 | |
Intangible assets | 193 | | | — | | | 13 | | | — | | | 2 | | | — | |
Total assets | 542 | | | 195 | | | 611 | | | 712 | | | 133 | | | 942 | |
Current and non-current liabilities | 37 | | | 11 | | | 66 | | | 492 | | | 53 | | | 299 | |
Total liabilities | 37 | | | 11 | | | 66 | | | 492 | | | 53 | | | 299 | |
Noncontrolling interest | 39 | | | 22 | | | 27 | | | 234 | | | 62 | | | 511 | |
Net assets less noncontrolling interest | $ | 466 | | | $ | 162 | | | $ | 518 | | | $ | (14) | | | $ | 18 | | | $ | 132 | |
|
| | | | | | | | | | | |
(In millions) | NRG Wind TE Holdco | | Alta Wind TE Holdco | | Spring Canyon |
Other current and non-current assets | $ | 175 |
| | $ | 17 |
| | $ | 4 |
|
Property, plant and equipment | 417 |
| | 443 |
| | 96 |
|
Intangible assets | 2 |
| | 265 |
| | — |
|
Total assets | 594 |
| | 725 |
| | 100 |
|
Current and non-current liabilities | 206 |
| | 9 |
| | 6 |
|
Total liabilities | 206 |
| | 9 |
| | 6 |
|
Noncontrolling interest | 22 |
| | 96 |
| | 63 |
|
Net assets less noncontrolling interests | $ | 366 |
| | $ | 620 |
| | $ | 31 |
|
Entities that(a)DGPV Funds is comprised of Clearway & EFS Distributed Solar LLC, DGPV Fund 4 LLC, Golden Puma Fund LLC, Renew Solar CS4 Fund LLC and Chestnut Fund LLC, which are not Consolidatedall tax equity funds.
The Company has interests in entities that(b)Daggett Renewable Holdco LLC consolidates Daggett TE Holdco LLC, which is a consolidated VIE.
(c) Lighthouse Renewable Holdco LLC consolidates Mesquite Star Tax Equity Holdco LLC, Black Rock TE Holdco LLC, Mililani TE Holdco LLC and Waiawa TE Holdco LLC, which are considered VIEs under ASC 810, but for which it is not considered the primary beneficiary. The Company accounts for its interests in these entities under the equity method of accounting, as further described in Note 5, Investments Accounted for by the Equity Method and Variable Interest Entities, to the consolidated financial statements for the year ended December 31, 2016 included in the Company's May 9, 2017 Form 8-K.VIEs.
The Company's maximum exposure to loss as of September 30, 2017 is limited to its equity investment in the unconsolidated entities, as further summarized in the table below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(In millions) | Lighthouse Renewable Holdco 2 LLC(a) | | Oahu Solar LLC | | Pinnacle Repowering TE Holdco LLC | | Rattlesnake TE Holdco LLC | | Rosie TargetCo LLC | | Wildorado TE Holdco LLC | | Other (b) |
Other current and non-current assets | $ | 42 | | | $ | 39 | | | $ | 6 | | | $ | 14 | | | $ | 45 | | | $ | 20 | | | $ | 14 | |
Property, plant and equipment | 353 | | | 160 | | | 100 | | | 180 | | | 234 | | | 202 | | | 148 | |
Intangible assets | — | | | — | | | 15 | | | — | | | — | | | — | | | 1 | |
Total assets | 395 | | | 199 | | | 121 | | | 194 | | | 279 | | | 222 | | | 163 | |
Current and non-current liabilities | 130 | | | 22 | | | 5 | | | 17 | | | 97 | | | 19 | | | 71 | |
Total liabilities | 130 | | | 22 | | | 5 | | | 17 | | | 97 | | | 19 | | | 71 | |
Noncontrolling interest | 232 | | | 24 | | | 42 | | | 83 | | | 128 | | | 105 | | | 67 | |
Net assets less noncontrolling interest | $ | 33 | | | $ | 153 | | | $ | 74 | | | $ | 94 | | | $ | 54 | | | $ | 98 | | | $ | 25 | |
|
| | | |
(In millions) | Maximum exposure to loss |
Four Brothers Solar, LLC | $ | 221 |
|
Granite Mountain Holdings, LLC | 81 |
|
Iron Springs Holdings, LLC | 56 |
|
GenConn Energy LLC | 102 |
|
NRG DGPV Holdco 1 LLC | 71 |
|
NRG RPV Holdco 1 LLC | 65 |
|
NRG DGPV Holdco 2 LLC | 54 |
|
NRG DGPV Holdco 3 LLC | 20 |
|
NRG DGPV(a)Lighthouse Renewable Holdco 2 LLC — The Company contributed $37 million into NRG DGPVconsolidates Mesquite Sky TE Holdco 2 LLC, or DGPV Holdco 2 during the nine months ended September 30, 2017, with an additional $2 million due to NRG in accounts payable — affiliate as of September 30, 2017, to be funded in tranches as the project milestones are completed. The Company co-owns approximately 107 MW of distributed solar capacity, based on cash to be distributed, withwhich is a weighted average contract life of approximately 21 years as of September 30, 2017.consolidated VIE.
On October 12, 2017, the Company and NRG amended the DGPV Holdco 2 partnership agreement to increase the aggregate commitment of $50 million to $60 million in order to accommodate funding of additional projects.
NRG DGPV Holdco 3 LLC— On September 26, 2017, the Company entered into an additional partnership with NRG by forming NRG DGPV Holdco 3 LLC, or DGPV Holdco 3, in which the Company would invest up to $50 million in an operating portfolio of distributed solar assets, primarily(b)Other is comprised of community solar projects, developed by NRG. The Company invested $4 million during September 2017 with an additional $16 million due to NRG in accounts payable - affiliate as of September 30, 2017, to be funded in tranches as the project milestones are completed. The Company co-owns approximately 33 MW of distributed solar capacity, based on cash to be distributed, with a weighted average contract life of approximately 20 years as of September 30, 2017.
Utah Solar Portfolio — As described in Note 3, Business Acquisitions, on March 27, 2017, as part of the March 2017 Drop Down Assets acquisition, the Company acquired from NRG 100% of the Class A equity interests in the Utah Solar Portfolio, comprised of Four Brothers Solar, LLC, Granite Mountain Holdings,Elbow Creek TE Holdco LLC and Iron Springs Holdings,Spring Canyon TE Holdco LLC. The Class B interests of the Utah Solar Portfolio are owned by a tax equity investor, or TE Investor, who receives 99% of allocations of taxable income and other items until the flip point, which occurs when the TE Investor obtains a specified return on its initial investment, at which time the allocations to the TE Investor change to 50%. The Company generally receives 50% of distributable cash throughout the term of the tax-equity arrangements. The three entities comprising the Utah Solar Portfolio are VIEs. As the Company is not the primary beneficiary, the Company uses the equity method of accounting to account for its interests in the Utah Solar Portfolio. The Company utilizes the HLBV method to determine its share of the income or losses in the investees.
The following tables present summarized financial information for the Utah Solar Portfolio:
|
| | | | | | | | | | | | | | | | |
| | Three months ended September 30, | | Nine months ended September 30, |
(In millions) | | 2017 | | 2016 | | 2017 | | 2016 |
Income Statement Data: | | | | | | | | |
Utah Solar Portfolio | | | | | | | | |
Operating revenues | | $ | 23 |
| | $ | — |
| | $ | 60 |
| | $ | — |
|
Operating income | | 9 |
| | — |
| | 17 |
| | — |
|
Net income | | 9 |
| | — |
| | 17 |
| | — |
|
| | September 30, 2017 | | December 31, 2016 |
Balance Sheet Data: | | (In millions) |
Utah Solar Portfolio | | | | |
Current assets | | $ | 25 |
| | $ | 20 |
|
Non-current assets | | 1,091 |
| | 1,105 |
|
Current liabilities | | 9 |
| | 14 |
|
Non-current liabilities | | 21 |
| | 38 |
|
Non-recourse project-level debt of unconsolidated affiliates
Agua Caliente Financing— As described in Note 3, Business Acquisitions, the Company acquired a 16% interest in the Agua Caliente solar facility through its acquisition of Agua Caliente Borrower 2 LLC. As of September 30, 2017, Agua Caliente Solar LLC, the direct owner of the Agua Caliente solar facility, had $833 million outstanding under the Agua Caliente financing agreement with the Federal Financing Bank, or FFB, borrowed to finance the costs of constructing the facility. The Company's pro-rata share of the Agua Caliente financing arrangement was $133 million as of September 30, 2017. Amounts borrowed under the Agua Caliente financing agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375%, mature in 2037 and are secured by the assets of Agua Caliente Solar LLC. The loans provided by the FFB are guaranteed by the U.S. DOE.
Note 5 — Fair Value of Financial Instruments
Fair Value Accounting under ASC 820
ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1—quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date.
•Level 2—inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•Level 3—unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date.
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement.
For cash and cash equivalents, restricted cash, accounts receivable — trade, accounts receivable — affiliate,affiliates, accounts payable current portion of the— trade, accounts payable — affiliates and accrued expenses and other current liabilities, the carrying amounts approximate 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 estimated fair values of the Company’s recorded financial instruments not carried at fair market value or that do not approximate fair value are as follows:
|
| | | | | | | | | | | | | | | |
| As of September 30, 2017 | | As of December 31, 2016 |
| Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
(In millions) | |
Assets: | | | | | | | |
Notes receivable (a) | $ | 18 |
| | $ | 18 |
| | $ | 30 |
| | $ | 30 |
|
Liabilities: | | | | | | | |
Long-term debt — affiliate | 618 |
| | 626 |
| | 618 |
| | 608 |
|
Long-term debt — external, including current portion (b) | $ | 5,268 |
| | $ | 5,301 |
| | $ | 5,451 |
| | $ | 5,435 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| As of June 30, 2023 | | As of December 31, 2022 |
| Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| (In millions) |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Long-term debt, including current portion — affiliate | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 2 | |
Long-term debt, including current portion — external (a) | 7,097 | | | 6,516 | | | 6,874 | | | 6,288 | |
(a) Includes the long-term portion of notes receivable, which is recorded in other noncurrent assets on the Company's consolidated balance sheets.
(b)Excludes deferred financingnet debt issuance costs, which are recorded as a reduction to long-term debt on the Company'sCompany’s consolidated balance sheets.
The fair value of the Company'sCompany’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, 2017 and December 31, 2016:portion:
|
| | | | | | | | | | | | | | | |
| 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 | $ | 884 |
| | $ | 5,043 |
| | $ | 833 |
| | $ | 5,210 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| As of June 30, 2023 | | As of December 31, 2022 |
| Level 2 | | Level 3 | | Level 2 | | Level 3 |
| (In millions) |
Long-term debt, including current portion | $ | 1,841 | | | $ | 4,677 | | | $ | 1,836 | | | $ | 4,454 | |
Recurring Fair Value Measurements
The Company records its derivative assets and liabilities at fair market value on its consolidated balance sheet. The following table presents assets and liabilities measured and recorded at fair value on the Company'sCompany’s consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:
|
| | | | | | | | | | | |
| As of September 30, 2017 | | As of December 31, 2016 |
| Fair Value (a) | | Fair Value (a) | | Fair Value (a) |
(In millions) | Level 2 | | Level 1 | | Level 2 |
Derivative assets: | | | | | |
Commodity contracts | $ | — |
| | $ | 1 |
| | $ | 1 |
|
Interest rate contracts | — |
| | — |
| | 1 |
|
Total assets | — |
| | 1 |
| | 2 |
|
Derivative liabilities: | | | | | |
Commodity contracts | 2 |
| | — |
| | 1 |
|
Interest rate contracts | 64 |
| | — |
| | 75 |
|
Total liabilities | $ | 66 |
| | $ | — |
| | $ | 76 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | As of June 30, 2023 | | As of December 31, 2022 |
| | | Fair Value (a) | | Fair Value (a) |
(In millions) | | | Level 2 | | Level 3 | | | | Level 2 | | Level 3 | | |
Derivative assets: | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Interest rate contracts | | | $ | 117 | | | $ | — | | | | | $ | 89 | | | $ | — | | | |
Other financial instruments (b) | | | — | | | 12 | | | | | — | | | 17 | | | |
Total assets | | | $ | 117 | | | $ | 12 | | | | | $ | 89 | | | $ | 17 | | | |
Derivative liabilities: | | | | | | | | | | | | | |
Commodity contracts | | | $ | — | | | $ | 303 | | | | | $ | — | | | $ | 353 | | | |
| | | | | | | | | | | | | |
Total liabilities | | | $ | — | | | $ | 303 | | | | | $ | — | | | $ | 353 | | | |
(a)There were no derivative assets classified as Level 1 or Level 3 and no liabilities classified as Level 1 as of SeptemberJune 30, 2017. There were no derivative assets or liabilities classified as Level 3 as of September 30, 20172023 and December 31, 2016.2022.
(b)Includes SREC contract.
The following table reconciles the beginning and ending balances for instruments that are recognized at fair value in the consolidated financial statements using significant unobservable inputs:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
(In millions) | | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) | | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
Beginning balance | | $ | (316) | | | $ | (280) | | | $ | (336) | | | $ | (154) | |
Settlements | | 5 | | | 22 | | | 9 | | | 28 | |
| | | | | | | | |
Additions due to loss of NPNS exception | | — | | | — | | | — | | | (22) | |
Total gains (losses) for the period included in earnings | | 20 | | | (74) | | | 36 | | | (184) | |
Ending balance | | $ | (291) | | | $ | (332) | | | $ | (291) | | | $ | (332) | |
Change in unrealized gains included in earnings for derivatives and other financial instruments held as of June 30, 2023 | | $ | 20 | | | | | $ | 36 | | | |
Derivative and Financial Instruments Fair Value Measurements
The Company's contracts are non-exchange-traded and valued using prices provided by external sources. For the Company’s energy markets, management receives quotes from multiple sources.The Company uses quoted observable forward prices to value its commodity contracts. To the extent that multiple quotesobservable forward prices are received,not available, the quoted prices reflect the average of the bid-ask mid-pointforward prices obtained from all sources believedthe prior year, adjusted for inflation. As of June 30, 2023, contracts valued with prices provided by models and other valuation techniques make up 100% of derivative liabilities and other financial instruments.
The Company’s significant positions classified as Level 3 include physical commodity contracts executed in illiquid markets. The significant unobservable inputs used in developing fair value include illiquid power tenors and location pricing, which is derived by extrapolating pricing as a basis to provideliquid locations. The tenor pricing and basis spread are based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available.
The following table quantifies the most liquid market forsignificant unobservable inputs used in developing the commodity.fair value of the Company’s Level 3 positions:
| | | | | | | | | | | | | | | | | | | | | | | |
| June 30, 2023 |
| Fair Value | | Input/Range |
| Assets | Liabilities | Valuation Technique | Significant Unobservable Input | Low | High | Weighted Average |
| (In millions) | | | | | |
Commodity Contracts | $ | — | | $ | (303) | | Discounted Cash Flow | Forward Market Price (per MWh) | $ | 21.02 | | $ | 71.74 | | $ | 38.17 | |
Other Financial Instruments | 12 | | — | | Discounted Cash Flow | Forecast annual generation levels of certain DG solar facilities | 60,801 MWh | 121,602 MWh | 115,622 MWh |
The following table provides the impact on the fair value measurements to increases/(decreases) in significant unobservable inputs as of June 30, 2023:
| | | | | | | | | | | |
Significant Unobservable Input | Position | Change In Input | Impact on Fair Value Measurement |
Forward Market Price Power | Sell | Increase/(Decrease) | Lower/(Higher) |
Forecast Generation Levels | Sell | Increase/(Decrease) | Higher/(Lower) |
The fair value of each contract is discounted using a risk freerisk-free interest rate. In addition, a credit reserve is applied to reflect credit risk, which is, for interest rate swaps, calculated based on credit default swaps using the bilateral method. For commodities, to the extent that the net exposureNet Exposure under a specific master agreement is an asset, the Company uses the counterparty’s default swap rate. If the net exposureNet Exposure under a specific master agreement is a liability, the Company uses NRG'sa proxy of its own default swap rate. For interest rate swaps and commodities, the credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume the liabilities or that a market participant would be willing to pay for the assets. As of SeptemberJune 30, 2017,2023, the creditnon-performance reserve resultedwas a $26 million gain recorded primarily to total operating revenues in a $1 million increase in fair value in interest expense.the consolidated statements of income. It is possible that future market prices could vary from those used in recording assets and liabilities and such variations could be material.
Concentration of Credit Risk
In addition to the credit risk discussion inas disclosed under Item 15 — Note 2, Summary of Significant Accounting Policies, to the consolidated financial statements for the year ended December 31, 2016 included in the Company's May 9, 2017Company’s 2022 Form 8-K,10-K, the following item is a discussion of the concentration of credit risk for the Company'sCompany’s financial instruments. 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. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) daily monitoring of counterparties' credit limits;limits on an as needed basis; (iii) as applicable, the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties.
Counterparty credit exposure includes credit risk exposure under certain long-term agreements, including solar and other PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company estimates the exposure related to 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, credit risk exposure to these counterparties attributable to the Company's ownership interests was approximately $2.9 billion for the next five years. The majorityA significant portion of these powercommodity contracts are with utilities 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 adverse financial conditions, which the Company is unable to predict. Certain subsidiaries of the Company sell the output of their facilities to PG&E, a significant counterparty of the Company, under long-term PPAs, and PG&E’s credit rating is below investment-grade.
Note 6 — Accounting for Derivative Instruments and Hedging Activities
This footnote should be read in conjunction with the complete description under Item 15 — Note 7, Accounting for Derivative Instruments and Hedging Activities, to the consolidated financial statements for the year ended December 31, 2016included in the Company's May 9, 2017Company’s 2022 Form 8-K.
Energy-Related Commodities
As of September 30, 2017, the Company had energy-related derivative instruments extending through 2020. At September 30, 2017, these contracts were not designated as cash flow or fair value hedges.10-K.
Interest Rate Swaps
The Company enters into interest rate swap agreements in order to hedge the variability of expected future cash interest payments. As of SeptemberJune 30, 2017,2023, the Company had interest rate derivative instruments on non-recourse debt extending through 2036,2040, a portion of which arewere designated as cash flow hedges. Under the interest rate swap agreements, the Company pays a fixed rate and the counterparties to the agreements pay a variable interest rate.
Energy-Related Commodities
As of June 30, 2023, the Company had energy-related derivative instruments extending through 2033. At June 30, 2023, these contracts were not designated as cash flow or fair value hedges.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buybuy/(sell) of the Company'sCompany’s open derivative transactions broken out by commodity:
| | | | | | | | | | | | | | | | | |
| | | Total Volume |
| | | June 30, 2023 | | December 31, 2022 |
Commodity | Units | | (In millions) |
| | | | | |
Power | MWh | | (17) | | | (18) | |
Interest | Dollars | | $ | 1,667 | | | $ | 1,084 | |
| | | | | |
| | | | | |
|
| | | | | | | | | |
| | | Total Volume |
| | | September 30, 2017 | | December 31, 2016 |
Commodity | Units | | (In millions) |
Natural Gas | MMBtu | | 2 |
| | 3 |
|
Interest | Dollars | | $ | 1,983 |
| | $ | 2,070 |
|
Fair Value of Derivative Instruments
There were no derivative asset positions on the balance sheet as of September 30, 2017. The following table summarizes the fair value within the derivative instrument valuation on the consolidated balance sheet:sheets:
| | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value |
| Derivative Assets | | Derivative Liabilities |
| June 30, 2023 | | December 31, 2022 | | June 30, 2023 | | December 31, 2022 |
| (In millions) |
Derivatives Designated as Cash Flow Hedges: | | | | | | | |
Interest rate contracts current | $ | 7 | | | $ | 7 | | | $ | — | | | $ | — | |
Interest rate contracts long-term | 16 | | | 18 | | | — | | | — | |
Total Derivatives Designated as Cash Flow Hedges | $ | 23 | | | $ | 25 | | | $ | — | | | $ | — | |
Derivatives Not Designated as Cash Flow Hedges: | | | | | | | |
Interest rate contracts current | $ | 27 | | | $ | 19 | | | $ | — | | | $ | — | |
Interest rate contracts long-term | 67 | | | 45 | | | — | | | — | |
Commodity contracts current | — | | | — | | | 44 | | | 50 | |
Commodity contracts long-term | — | | | — | | | 259 | | | 303 | |
Total Derivatives Not Designated as Cash Flow Hedges | $ | 94 | | | $ | 64 | | | $ | 303 | | | $ | 353 | |
Total Derivatives | $ | 117 | | | $ | 89 | | | $ | 303 | | | $ | 353 | |
|
| | | | | | | | | | | |
| Fair Value |
| Derivative Assets | | Derivative Liabilities |
| December 31, 2016 | | September 30, 2017 | | December 31, 2016 |
| (In millions) |
Derivatives Designated as Cash Flow Hedges: | | | | | |
Interest rate contracts current | $ | — |
| | $ | 7 |
| | $ | 26 |
|
Interest rate contracts long-term | 1 |
| | 13 |
| | 39 |
|
Total Derivatives Designated as Cash Flow Hedges | 1 |
| | 20 |
| | 65 |
|
Derivatives Not Designated as Cash Flow Hedges: | | | | | |
Interest rate contracts current | — |
| | 15 |
| | 5 |
|
Interest rate contracts long-term | — |
| | 29 |
| | 5 |
|
Commodity contracts current | 2 |
| | 1 |
| | 1 |
|
Commodity contracts long-term | — |
| | 1 |
| | — |
|
Total Derivatives Not Designated as Cash Flow Hedges | 2 |
| | 46 |
| | 11 |
|
Total Derivatives | $ | 3 |
| | $ | 66 |
| | $ | 76 |
|
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. As of SeptemberJune 30, 2017, there were no offsetting amounts at2023 and December 31, 2022, the counterparty master agreement level noramount of outstanding collateral paid or received. As of December 31, 2016, therereceived was no outstanding collateral paid or received.immaterial. The following tables summarize the offsetting of derivatives by the counterparty master agreement level as of December 31, 2016:counterparty: | | | | | | | | | | | | | | | | | |
| Gross Amounts Not Offset in the Statement of Financial Position |
As of June 30, 2023 | Gross Amounts of Recognized Assets/Liabilities | | Derivative Instruments | | Net Amount |
Commodity contracts | (In millions) |
| | | | | |
Derivative liabilities | $ | (303) | | | $ | — | | | $ | (303) | |
Total commodity contracts | $ | (303) | | | $ | — | | | $ | (303) | |
Interest rate contracts | | | | | |
Derivative assets | $ | 117 | | | $ | — | | | $ | 117 | |
| | | | | |
Total interest rate contracts | $ | 117 | | | $ | — | | | $ | 117 | |
Total derivative instruments | $ | (186) | | | $ | — | | | $ | (186) | |
| | | | | | | | | | | | | | | | | |
| Gross Amounts Not Offset in the Statement of Financial Position |
As of December 31, 2022 | Gross Amounts of Recognized Assets/Liabilities | | Derivative Instruments | | Net Amount |
Commodity contracts | (In millions) |
| | | | | |
Derivative liabilities | $ | (353) | | | $ | — | | | $ | (353) | |
Total commodity contracts | $ | (353) | | | $ | — | | | $ | (353) | |
Interest rate contracts | |
Derivative assets | $ | 89 | | | $ | — | | | $ | 89 | |
| | | | | |
Total interest rate contracts | $ | 89 | | | $ | — | | | $ | 89 | |
Total derivative instruments | $ | (264) | | | $ | — | | | $ | (264) | |
|
| | | | | | | | | | | |
As of December 31, 2016 | Gross Amounts of Recognized Assets/Liabilities | | Derivative Instruments | | Net Amount |
Commodity contracts: | (In millions) |
Derivative assets | $ | 2 |
| | $ | — |
| | $ | 2 |
|
Derivative liabilities | (1 | ) | | — |
| | (1 | ) |
Total commodity contracts | 1 |
| | — |
| | 1 |
|
Interest rate contracts: | | | | | |
Derivative assets | 1 |
| | (1 | ) | | — |
|
Derivative liabilities | (75 | ) | | 1 |
| | (74 | ) |
Total interest rate contracts | (74 | ) | | — |
| | (74 | ) |
Total derivative instruments | $ | (73 | ) | | $ | — |
| | $ | (73 | ) |
Accumulated Other Comprehensive LossIncome (Loss)
The following table summarizes the effects on the Company’s accumulated OCLOCI (OCL) balance attributable to interest rate swaps designated as cash flow hedge derivatives:derivatives:
|
| | | | | | | | | | | | | | | |
| Three months ended September 30, | | Nine months ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
| (In millions) |
Accumulated OCL beginning balance | $ | (86 | ) | | $ | (168 | ) | | $ | (86 | ) | | $ | (99 | ) |
Reclassified from accumulated OCL to income due to realization of previously deferred amounts | 5 |
| | 6 |
| | 13 |
| | 13 |
|
Mark-to-market of cash flow hedge accounting contracts | 2 |
| | 14 |
| | (6 | ) | | (62 | ) |
Accumulated OCL ending balance | (79 | ) | | (148 | ) | | (79 | ) | | (148 | ) |
Accumulated OCL attributable to noncontrolling interests | (1 | ) | | (2 | ) | | (1 | ) | | (2 | ) |
Accumulated OCL attributable to NRG Yield LLC | $ | (78 | ) | | $ | (146 | ) | | $ | (78 | ) | | $ | (146 | ) |
Losses expected to be realized from OCL during the next 12 months | $ | 17 |
| | | | $ | 17 |
| | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended June 30, | | Six months ended June 30, |
| 2023 | | 2022 | | 2023 | | 2022 |
| (In millions) |
Accumulated OCI (OCL) beginning balance | $ | 23 | | | $ | 3 | | | $ | 27 | | | $ | (13) | |
Reclassified from accumulated OCI (OCL) to income due to realization of previously deferred amounts | (1) | | | 2 | | | (1) | | | 5 | |
Mark-to-market of cash flow hedge accounting contracts | 5 | | | 5 | | | 1 | | | 18 | |
Accumulated OCI ending balance | 27 | | | 10 | | | 27 | | | 10 | |
Accumulated OCI attributable to noncontrolling interests | 6 | | | 4 | | | 6 | | | 4 | |
Accumulated OCI attributable to Clearway Energy LLC | $ | 21 | | | $ | 6 | | | $ | 21 | | | $ | 6 | |
Gains expected to be realized from OCI during the next 12 months | $ | 6 | | | | | $ | 6 | | | |
| | | | | | | |
Amounts reclassified from accumulated OCLOCI (OCL) into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to interest expense. There was no ineffectiveness for the 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 matching 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 Consolidated Statements of Income
The Company has interest rate derivative instruments that are not designated as cash flow hedges. The effect of interest rate hedges is recorded to interest expense. For the three months ended September 30, 2017 and 2016, the impactMark-to-market gains/(losses) related to the consolidated statements of income was a gain of $7 million and $2 million, respectively. For the nine months ended September 30, 2017 and 2016, the impact to the consolidated statements of income was a loss of $2 million and $7 million, respectively.
A portion of the Company’s derivative commodity contracts relates to its Thermal Business for the purchase of fuel commodities based on the forecasted usage of the thermal district energy centers. Realized gains and losses on these contractsderivatives are reflected in the fuel costs that are permitted to be billed to customers through the related customer contracts or tariffs and, accordingly, no gains or losses are reflectedrecorded in the consolidated statements of income as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended June 30, | | Six months ended June 30, |
| 2023 | | 2022 | | 2023 | | 2022 |
| (In millions) |
Interest Rate Contracts (Interest expense) | $ | 22 | | | $ | 36 | | | $ | 1 | | | $ | 77 | |
Commodity Contracts (Mark-to-market for economic hedging activities) (a) | 32 | | | (49) | | | 50 | | | (174) | |
(a) Relates to long-term commodity contracts at Elbow Creek, Mesquite Star, Mt. Storm, Langford and Mesquite Sky. During the six months ended June 30, 2022, the commodity contract for these contracts.Langford, which previously met the NPNS exception, no longer qualified for NPNS treatment and, accordingly, is accounted for as a derivative and marked to fair value through operating revenues.
See Note 5, Fair Value of Financial Instruments, for a discussion regarding concentration of credit risk.
Note 7 — Long-term Debt
This footnotenote should be read in conjunction with the complete description under Item 15 — Note 10, Long-term Debt,to the consolidated financial statements for the year ended December 31, 2016 included in the Company's May 9, 2017Company’s 2022 Form 8-K. Long-term debt10-K. The Company’s borrowings, including short-term and long-term portions, consisted of the following:
|
| | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 | | September 30, 2017, interest rate % (a) | | Letters of Credit Outstanding at September 30, 2017 |
| | (In millions, except rates) | | |
Long-term debt - affiliate, due 2019 | | $ | 337 |
| | $ | 337 |
| | 3.580 | | |
Long-term debt - affiliate, due 2020 | | 281 |
| | 281 |
| | 3.325 | | |
2024 Senior Notes | | 500 |
| | 500 |
| | 5.375 | | |
2026 Senior Notes | | 350 |
| | 350 |
| | 5.000 | | |
Project-level debt: | | | | | | | | |
Agua Caliente Borrower 2, due 2038 | | 41 |
| | — |
| | 5.430 | | 17 |
|
Alpine, due 2022 | | 138 |
| | 145 |
| | L+1.750 | | 37 |
|
Alta Wind I - V lease financing arrangements, due 2034 and 2035 | | 940 |
| | 965 |
| | 5.696 - 7.015 | | 103 |
|
CVSR, due 2037 | | 746 |
| | 771 |
| | 2.339 - 3.775 | | — |
|
CVSR Holdco Notes, due 2037 | | 194 |
| | 199 |
| | 4.680 | | 13 |
|
El Segundo Energy Center, due 2023 | | 400 |
| | 443 |
| | L+1.75 - L+2.375 | | 102 |
|
Energy Center Minneapolis, due 2017 and 2025 | | 82 |
| | 96 |
| | 5.950 -7.250 | | — |
|
Energy Center Minneapolis Series D Notes, due 2031 | | 125 |
| | 125 |
| | 3.550 | | — |
|
Laredo Ridge, due 2028 | | 96 |
| | 100 |
| | L+1.875 | | 10 |
|
Marsh Landing, due 2017 and 2023 | | 334 |
| | 370 |
| | L+1.750 - L+1.875 | | 34 |
|
Tapestry, due 2021 | | 165 |
| | 172 |
| | L+1.625 | | 20 |
|
Utah Solar Portfolio, due 2022 | | 284 |
| | 287 |
| | L+2.625 | | 13 |
|
Viento, due 2023 | | 169 |
| | 178 |
| | L+3.00 | | 27 |
|
Walnut Creek, due 2023 | | 279 |
| | 310 |
| | L+1.625 | | 49 |
|
Other | | 425 |
| | 440 |
| | Various | | 37 |
|
Subtotal project-level debt: | | 4,418 |
| | 4,601 |
| | | | |
Total debt | | 5,886 |
| | 6,069 |
| | | | |
Less current maturities | | (300 | ) | | (291 | ) | | | | |
Less net debt issuance costs | | (54 | ) | | (62 | ) | | | | |
Total long-term debt | | $ | 5,532 |
| | $ | 5,716 |
| | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
(In millions, except rates) | June 30, 2023 | | December 31, 2022 | | June 30, 2023 interest rate % (a) | | Letters of Credit Outstanding at June 30, 2023 |
Intercompany Note with Clearway, Inc. | $ | 2 | | | $ | 2 | | | 4.430 | | | |
| | | | | | | |
| | | | | | | |
2028 Senior Notes | 850 | | | 850 | | | 4.750 | | | |
2031 Senior Notes | 925 | | | 925 | | | 3.750 | | | |
2032 Senior Notes | 350 | | | 350 | | | 3.750 | | | |
Clearway Energy LLC and Clearway Energy Operating LLC Revolving Credit Facility, due 2028 (b) | — | | | — | | | S+1.850 | | $ | 188 | |
| | | | | | | |
Non-recourse project-level debt: | | | | | | | |
Agua Caliente Solar LLC, due 2037 | 640 | | | 649 | | | 2.395-3.633 | | 45 | |
Alta Wind Asset Management LLC, due 2031 | 11 | | | 12 | | | L+2.625 | | — | |
Alta Wind I-V lease financing arrangements, due 2034 and 2035 | 679 | | | 709 | | | 5.696-7.015 | | 47 | |
Alta Wind Realty Investments LLC, due 2031 | 21 | | | 22 | | | 7.000 | | | — | |
Borrego, due 2024 and 2038 | 50 | | | 51 | | | Various | | — | |
Buckthorn Solar, due 2025 | 119 | | | 119 | | | S+2.100 | | 22 | |
Capistrano Wind Portfolio, due 2029 and 2031 | 145 | | | 156 | | | S+2.100-S+2.150 | | 34 | |
Carlsbad Energy Holdings LLC, due 2027 | 114 | | | 115 | | | S+1.900 | | 82 | |
Carlsbad Energy Holdings LLC, due 2038 | 407 | | | 407 | | | 4.120 | | | — | |
Carlsbad Holdco, LLC, due 2038 | 197 | | | 197 | | | 4.210 | | | 6 | |
CVSR, due 2037 | 612 | | | 627 | | | 2.339-3.775 | | — | |
CVSR Holdco Notes, due 2037 | 151 | | | 160 | | | 4.680 | | | 12 | |
Daggett 3, due 2023 and 2028 | 446 | | | — | | | S+1.262 | | 35 | |
DG-CS Master Borrower LLC, due 2040 | 406 | | | 413 | | | 3.510 | | | 30 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Marsh Landing, due 2023 | — | | | 19 | | | | | — | |
Mililani I, due 2027 | 47 | | | 47 | | | S+1.600 | | 5 | |
NIMH Solar, due 2024 | 156 | | | 163 | | | S+2.150 | | 16 | |
Oahu Solar Holdings LLC, due 2026 | 82 | | | 83 | | | S+1.525 | | 11 | |
| | | | | | | |
Rosie Class B LLC, due 2029 | 77 | | | 76 | | | S+1.375 | | 15 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Utah Solar Holdings, due 2036 | 253 | | | 257 | | | 3.590 | | | 15 | |
Viento Funding II, LLC, due 2029 | 180 | | | 184 | | | S+1.475 | | 25 | |
Waiawa, due 2028 | 46 | | | 97 | | | S+1.600 | | 12 | |
Walnut Creek, due 2023 | — | | | 19 | | | | | — | |
WCEP Holdings, LLC, due 2023 | — | | | 26 | | | | | — | |
Other | 130 | | | 137 | | | Various | | 250 | |
Subtotal non-recourse project-level debt | 4,969 | | | 4,745 | | | | | |
Total debt | 7,096 | | | 6,872 | | | | | |
Less current maturities | (332) | | | (324) | | | | | |
Less net debt issuance costs | (59) | | | (61) | | | | | |
Add premiums (c) | 3 | | | 4 | | | | | |
Total long-term debt | $ | 6,708 | | | $ | 6,491 | | | | | |
(a)As of SeptemberJune 30, 2017,2023, S+ equals SOFR plus x% and L+equals 3 month LIBOR plus x%, except for.
(b) Applicable rate is determined by the Utah Solar Portfolio, where L+equals 1 month LIBOR plus x%borrower leverage ratio, as defined in the credit agreement.
(c) Premiums relate to the 2028 Senior Notes.
The financing arrangements listed above contain certain covenants, including financial covenants that the Company is required to be in compliance with during the term of the respective arrangement. As of SeptemberJune 30, 2017,2023, the Company was in compliance with all of the required covenants.
The discussion below describes material changes to or additions of long-term debt for the ninesix months ended SeptemberJune 30, 2017.2023.
NRG YieldClearway Energy LLC and NRG YieldClearway Energy Operating LLC Revolving Credit Facility
On March 15, 2023, Clearway Energy Operating LLC refinanced the Amended and Restated Credit Agreement, which (i) replaced LIBOR with SOFR plus a credit spread adjustment of 0.10% as the applicable reference rate, (ii) increased the available revolving commitments to an aggregate principal amount of $700 million, (iii) extended the maturity date to March 15, 2028, (iv) increased the letter of credit sublimit to $594 million and (v) implemented certain other technical modifications.
As of SeptemberJune 30, 2017, there were2023, the Company had no outstanding borrowings under the revolving credit facility and the Company had $68$188 million ofin letters of credit outstanding.
Thermal FinancingProject-level Debt
Rosamond Central (Rosie Class B LLC)
On March 16, 2017, NRG Energy Center MinneapolisJune 30, 2023, Rosie Class B LLC amended its financing agreement to provide for (i) a term loan in the amount of $77 million, (ii) construction loans up to $115 million, which will convert to a term loan upon the BESS project reaching substantial completion, (iii) tax equity bridge loans up to $188 million, which will be repaid with tax equity proceeds received upon the BESS project reaching substantial completion, (iv) an increase to the letter of credit sublimit to $41 million and (v) an extension of the maturity date of the term loan and construction loans to five years subsequent to term conversions.
On July 3, 2023, Rosie Class B LLC received total loan proceeds of $138 million, which was comprised of $115 million in construction loans and $28 million in tax equity bridge loans, net of $5 million in debt issuance costs that were deferred. Also on July 3, 2023, Rosie Class B LLC issued a loan to a consolidated subsidiary of NRG Thermal LLC, amendedClearway Renew in the shelf facility of its existing Thermal financing arrangement to allow for the issuance of an additional $10 million of Series F notes at a 4.60% interest rate, or Series F Notes, increasing the totalaggregate principal amount of notes available for issuance under$117 million in order to finance the shelf facility to $80 million. The Series F Notes will be secured by substantially allconstruction of the assetsBESS project. The loan bears interest at 9.00% and matures when the project reaches substantial completion, which is anticipated in the first half of NRG Energy Center Minneapolis LLC. NRG
Thermal LLC has guaranteed the indebtedness and its guarantee is secured by a pledge2024. The Company also contributed $20 million of the loan proceeds into Rosie Central BESS, as further described in Note 4, Investments Accounted for by the Equity Method and Variable Interest Entities.
Waiawa
On March 30, 2023, when the Waiawa solar project reached substantial completion, the tax equity interestsinvestor contributed an additional $41 million and CEG contributed an additional $8 million, which was utilized, along with the $17 million in all of NRG Thermal LLC’s subsidiaries.
Financing Relatedescrow, to repay the $55 million tax equity bridge loan, to fund $10 million in construction completion reserves and to pay $1 million in associated fees. Subsequent to the acquisition on October 3, 2022, the Company borrowed an additional $25 million in construction loans that was converted to a term loan in the amount of $47 million on March 2017 Drop Down Assets30, 2023 that matures on March 30, 2028.
Agua Caliente Borrower 2, due 2038Daggett 3
On February 17, 2017, Agua Caliente Borrower 1 LLC, an indirect subsidiary2023, as part of NRG, and Agua Caliente Borrower 2 LLC, issued $130 millionthe acquisition of senior secured notes under the Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC financing agreement, or Agua Caliente Holdco Financing Agreement, that bear interest at 5.43% and mature on December 31, 2038. AsDaggett 3, as further described in Note 3, Business Acquisitions and Dispositions, on March 27, 2017, the Company acquired Agua Caliente Borrower 2 LLC from NRG as partassumed the project’s financing agreement, which included a $181 million construction loan that converts to a term loan upon the project reaching substantial completion, $229 million tax equity bridge loan and $75 million sponsor equity bridge loan. The sponsor equity bridge loan was repaid at acquisition date, along with $8 million in associated fees, utilizing all of the March 2017 Drop Down Assets acquisitionproceeds from the Company and assumed NRG's portioncash equity investor, which were contributed back to the Company by CEG. The tax equity bridge loan will be repaid with the final proceeds received from the tax equity investor upon Daggett 3 reaching substantial completion, which is expected to occur in the second half of senior secured notes under2023, along with the Agua Caliente Holdco Financing Agreement. Agua Caliente Borrower 2 LLC holds $41$62 million of the Agua Caliente Holdco debt as of September 30, 2017. The debt is joint and several with respect to Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC and is securedthat was contributed into escrow by the tax equity interests of each borrower ininvestor at acquisition date. Subsequent to the Agua Caliente solar facility.
Utah Solar Portfolio, due 2022
As part of the March 2017 Drop Down Assets acquisition, the Company assumed non-recourse debt of $287borrowed an additional $36 million relating to the Utah Solar Portfolio at an interest rate of LIBOR plus 2.625%. The debt matures on December 16, 2022. The $287 million consisted of $222 million outstanding at the time of NRG's acquisition of the Utah Solar Portfolio on November 2, 2016, and additional borrowings of $65 million, net of debt issuance costs, incurred during 2016. The Company holds $284 million of the Utah Solar Portfolio debt as of September 30, 2017.in construction loans.
Note 8 — Segment Reporting
The Company’s segment structure reflects how management currently operates and allocates resources. The Company'sCompany’s businesses are primarily segregated based on conventional power generation, renewable businesses which consist of solar, and wind and the thermal and chilled water business.energy storage The Corporate segment reflects the Company'sCompany’s corporate costs.costs and includes eliminating entries. The Company'sCompany’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, and CAFD, as well as economic gross margin and net income (loss).
| | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended June 30, 2023 |
(In millions) | Conventional Generation | | Renewables | | Corporate (a) | | Total |
Operating revenues | $ | 115 | | | $ | 291 | | | $ | — | | | $ | 406 | |
Cost of operations, exclusive of depreciation, amortization and accretion shown separately below | 40 | | | 79 | | | (1) | | | 118 | |
Depreciation, amortization and accretion | 32 | | | 96 | | | — | | | 128 | |
| | | | | | | |
General and administrative | — | | | — | | | 9 | | | 9 | |
| | | | | | | |
Transaction and integration costs | — | | | — | | | 2 | | | 2 | |
| | | | | | | |
| | | | | | | |
Operating income (loss) | 43 | | | 116 | | | (10) | | | 149 | |
Equity in earnings of unconsolidated affiliates | 1 | | | 2 | | | — | | | 3 | |
| | | | | | | |
Other income, net | 1 | | | 3 | | | 5 | | | 9 | |
| | | | | | | |
Interest expense | (8) | | | (23) | | | (24) | | | (55) | |
Net Income (Loss) | $ | 37 | | | $ | 98 | | | $ | (29) | | | $ | 106 | |
Total Assets | $ | 2,169 | | | $ | 10,020 | | | $ | 429 | | | $ | 12,618 | |
(a)Includes eliminations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended June 30, 2022 |
(In millions) | Conventional Generation | | Renewables | | Thermal | | Corporate (a) | | Total |
Operating revenues | $ | 103 | | | $ | 247 | | | $ | 18 | | | $ | — | | | $ | 368 | |
| | | | | | | | | |
Cost of operations, exclusive of depreciation, amortization and accretion shown separately below | 28 | | | 73 | | | 11 | | | — | | | 112 | |
Depreciation, amortization and accretion | 33 | | | 93 | | | — | | | — | | | 126 | |
| | | | | | | | | |
General and administrative | — | | | — | | | 1 | | | 8 | | | 9 | |
| | | | | | | | | |
Transaction and integration costs | — | | | — | | | — | | | 3 | | | 3 | |
Development costs | — | | | — | | | 1 | | | — | | | 1 | |
Total operating costs and expenses | 61 | | | 166 | | | 13 | | | 11 | | | 251 | |
Gain on sale of business | — | | | — | | | — | | | 1,291 | | | 1,291 | |
Operating income | 42 | | | 81 | | | 5 | | | 1,280 | | | 1,408 | |
Equity in earnings of unconsolidated affiliates | 1 | | | 9 | | | — | | | — | | | 10 | |
| | | | | | | | | |
| | | | | | | | | |
Other income, net | — | | | 4 | | | — | | | 1 | | | 5 | |
Interest expense | (10) | | | (11) | | | (1) | | | (25) | | | (47) | |
Net Income | $ | 33 | | | $ | 83 | | | $ | 4 | | | $ | 1,256 | | | $ | 1,376 | |
(a)Includes eliminations.
| | | Three months ended September 30, 2017 | | Six months ended June 30, 2023 |
(In millions) | Conventional Generation | | Renewables | | Thermal | | Corporate | | Total | (In millions) | Conventional Generation | | Renewables | | Corporate (a) | | Total |
Operating revenues | $ | 88 |
| | $ | 131 |
| | $ | 46 |
| | $ | — |
| | $ | 265 |
| Operating revenues | $ | 210 | | | $ | 484 | | | $ | — | | | $ | 694 | |
Cost of operations | 16 |
| | 33 |
| | 29 |
| | — |
| | 78 |
| |
Depreciation and amortization | 27 |
| | 56 |
| | 5 |
| | — |
| | 88 |
| |
Cost of operations, exclusive of depreciation, amortization and accretion shown separately below | | Cost of operations, exclusive of depreciation, amortization and accretion shown separately below | 69 | | | 158 | | | (1) | | | 226 | |
Depreciation, amortization and accretion | | Depreciation, amortization and accretion | 65 | | | 191 | | | — | | | 256 | |
| General and administrative | — |
| | — |
| | — |
| | 4 |
| | 4 |
| General and administrative | — | | | — | | | 19 | | | 19 | |
Transaction and integration costs | | Transaction and integration costs | — | | | — | | | 2 | | | 2 | |
| Operating income (loss) | 45 |
| | 42 |
| | 12 |
| | (4 | ) | | 95 |
| Operating income (loss) | 76 | | | 135 | | | (20) | | | 191 | |
Equity in earnings of unconsolidated affiliates | 3 |
| | 25 |
| | — |
| | — |
| | 28 |
| |
Equity in earnings (losses) of unconsolidated affiliates | | Equity in earnings (losses) of unconsolidated affiliates | 2 | | | (2) | | | — | | | — | |
| Other income, net | 1 |
| | — |
| | — |
| | — |
| | 1 |
| Other income, net | 2 | | | 4 | | | 11 | | | 17 | |
| Interest expense | (13 | ) | | (39 | ) | | (2 | ) | | (18 | ) | | (72 | ) | Interest expense | (19) | | | (87) | | | (48) | | | (154) | |
Net Income (Loss) | $ | 36 |
| | $ | 28 |
| | $ | 10 |
| | $ | (22 | ) | | $ | 52 |
| Net Income (Loss) | $ | 61 | | | $ | 50 | | | $ | (57) | | | $ | 54 | |
Total Assets | $ | 1,920 |
| | $ | 5,821 |
| | $ | 420 |
| | $ | 79 |
| | $ | 8,240 |
| |
|
(a) Includes eliminations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six months ended June 30, 2022 |
(In millions) | Conventional Generation | | Renewables | | Thermal | | Corporate (a) | | Total |
Operating revenues | $ | 211 | | | $ | 294 | | | $ | 77 | | | $ | — | | | $ | 582 | |
Cost of operations, exclusive of depreciation, amortization and accretion shown separately below | 49 | | | 141 | | | 50 | | | — | | | 240 | |
Depreciation, amortization and accretion | 66 | | | 184 | | | — | | | — | | | 250 | |
| | | | | | | | | |
General and administrative | — | | | — | | | 2 | | | 19 | | | 21 | |
Transaction and integration costs | — | | | — | | | — | | | 5 | | | 5 | |
Development costs | — | | | — | | | 2 | | | — | | | 2 | |
Total operating costs and expenses | 115 | | | 325 | | | 54 | | | 24 | | | 518 | |
Gain on sale of business | — | | | — | | | — | | | 1,291 | | | 1,291 | |
Operating income (loss) | 96 | | | (31) | | | 23 | | | 1,267 | | | 1,355 | |
Equity in earnings of unconsolidated affiliates | 2 | | | 12 | | | — | | | — | | | 14 | |
| | | | | | | | | |
Other income, net | — | | | 4 | | | — | | | 1 | | | 5 | |
Loss on debt extinguishment | — | | | (2) | | | — | | | — | | | (2) | |
Interest expense | (18) | | | (19) | | | (6) | | | (51) | | | (94) | |
Net Income (Loss) | $ | 80 | | | $ | (36) | | | $ | 17 | | | $ | 1,217 | | | $ | 1,278 | |
| | | | | | | | | |
(a) Includes eliminations.
|
| | | | | | | | | | | | | | | | | | | |
| Three months ended September 30, 2016 |
(In millions) | Conventional Generation | | Renewables | | Thermal | | Corporate | | Total |
Operating revenues | $ | 82 |
| | $ | 142 |
| | $ | 48 |
| | $ | — |
| | $ | 272 |
|
Cost of operations | 14 |
| | 31 |
| | 31 |
| | — |
| | 76 |
|
Depreciation and amortization | 20 |
| | 50 |
| | 5 |
| | — |
| | 75 |
|
General and administrative | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
Operating income (loss) | 48 |
| | 61 |
| | 12 |
| | (3 | ) | | 118 |
|
Equity in earnings of unconsolidated affiliates | 3 |
| | 13 |
| | — |
| | — |
| | 16 |
|
Other income, net | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Interest expense | (13 | ) | | (37 | ) | | (2 | ) | | (16 | ) | | (68 | ) |
Net Income (Loss) | $ | 39 |
| | $ | 37 |
| | $ | 10 |
| | $ | (19 | ) | | $ | 67 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Nine months ended September 30, 2017 |
(In millions) | Conventional Generation | | Renewables | | Thermal | | Corporate | | Total |
Operating revenues | $ | 246 |
| | $ | 391 |
| | $ | 130 |
| | $ | — |
| | $ | 767 |
|
Cost of operations | 53 |
| | 100 |
| | 86 |
| | — |
| | 239 |
|
Depreciation and amortization | 77 |
| | 149 |
| | 15 |
| | — |
| | 241 |
|
General and administrative | — |
| | — |
| | — |
| | 14 |
| | 14 |
|
Acquisition-related transaction and integration costs | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Operating income (loss) | 116 |
| | 142 |
| | 29 |
| | (16 | ) | | 271 |
|
Equity in earnings of unconsolidated affiliates | 9 |
| | 54 |
| | — |
| | — |
| | 63 |
|
Other income, net | 1 |
| | 1 |
| | — |
| | 1 |
| | 3 |
|
Interest expense | (39 | ) | | (128 | ) | | (7 | ) | | (53 | ) | | (227 | ) |
Net Income (Loss) | $ | 87 |
| | $ | 69 |
| | $ | 22 |
| | $ | (68 | ) | | $ | 110 |
|
Total Assets | $ | 1,920 |
| | $ | 5,821 |
| | $ | 420 |
| | $ | 79 |
| | $ | 8,240 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Nine months ended September 30, 2016 |
(In millions) | Conventional Generation | | Renewables | | Thermal | | Corporate | | Total |
Operating revenues | $ | 246 |
| | $ | 412 |
| | $ | 131 |
| | $ | — |
| | $ | 789 |
|
Cost of operations | 53 |
| | 98 |
| | 87 |
| | — |
| | 238 |
|
Depreciation and amortization | 60 |
| | 149 |
| | 15 |
| | — |
| | 224 |
|
General and administrative | — |
| | — |
| | — |
| | 8 |
| | 8 |
|
Operating income (loss) | 133 |
| | 165 |
| | 29 |
| | (8 | ) | | 319 |
|
Equity in earnings of unconsolidated affiliates | 10 |
| | 24 |
| | — |
| | — |
| | 34 |
|
Other income, net | 1 |
| | 2 |
| | — |
| | — |
| | 3 |
|
Interest expense | (36 | ) | | (115 | ) | | (5 | ) | | (48 | ) | | (204 | ) |
Net Income (Loss) | $ | 108 |
| | $ | 76 |
| | $ | 24 |
| | $ | (56 | ) | | $ | 152 |
|
Note 9 — Related Party Transactions
In addition to the transactions and relationships described elsewhere in thesethe notes to the consolidated financial statements, NRG and certain subsidiaries of NRGCEG provide services to the Company and its project entities. Amounts due to NRGCEG subsidiaries are recorded as accounts payable - affiliate— affiliates and amounts due to the Company from NRG or itsCEG subsidiaries are recorded as accounts receivable - affiliate— affiliates in the Company'sCompany’s consolidated balance sheet.
Power Purchase Agreements (PPAs) betweensheets. The disclosures below summarize the CompanyCompany’s material related party transactions with CEG and NRG Power Marketing
Elbow Creek and Doverits subsidiaries that are parties to PPAs with NRG Power Marketing and generate revenue under the PPAs, which are recorded to operating revenuesincluded in the Company's consolidated statements of operations. For the three and nine months ended September 30, 2017, Elbow Creek and Dover, collectively, generated revenue of $3 million and $10 million, respectively. For the three and nine months ended September 30, 2016, Elbow Creek and Dover, collectively, generated revenue of $4 million and $10 million, respectively.Company’s operating costs.Energy Marketing Services Agreement by and between Thermal entities and NRG Power Marketing
NRG Energy Center Dover LLC, NRG Energy Center Minneapolis, NRG Energy Center Phoenix LLC, and NRG Energy Center Paxton LLC, or Thermal entities, are parties to Energy Marketing Services Agreements with NRG Power Marketing, a wholly-owned subsidiary of NRG. Under the agreements, NRG Power Marketing procures fuel and fuel transportation for the operation of Thermal entities. For the three and nine months ended September 30, 2017, Thermal entities purchased $1 million and $7 million, respectively, of natural gas from NRG Power Marketing. For the three and nine months ended September 30, 2016, Thermal entities purchased $1 million and $6 million, respectively, of natural gas from NRG Power Marketing.
Operation and Maintenance (O&M) Services Agreements by and between Company's subsidiaries and NRG
Certain of the Company's subsidiaries are party to O&M Services Agreements with NRG, pursuant to which NRG subsidiaries provide necessary and appropriate services to operate and maintain the subsidiaries' plant operations, businesses and thermal facilities. NRG is reimbursed for the provided services, as well as for all reasonable and related expenses and expenditures, and payments to third parties for services and materials rendered to or on behalf of the parties to the agreements. NRG is not entitled to any management fee or mark-up under the agreements. The following table summarizes material O&M costs recorded in the cost of operations line in the Company's consolidated statements of operations:
|
| | | | | | | | | | | | | | | | |
| | Three months ended September 30, | | Nine months ended September 30, |
(in millions) | | 2017 | | 2016 | | 2017 | | 2016 |
O&M costs | | $ | 10 |
| | $ | 9 |
| | $ | 29 |
| | $ | 28 |
|
There were balances of $21 million and $22 million due from the entities above to NRG in accounts payable — affiliate as of September 30, 2017 and December 31, 2016, respectively. As of September 30, 2017, $3 million was recorded in long term liabilities of the consolidated balance sheet.
O&MServices Agreements by and between GenConn and NRG
GenConn incurs fees under two O&M agreements with wholly-owned subsidiaries of NRG. For the three months and nine months ended September 30, 2017 and September 30, 2016, the aggregate fees incurred under the agreements were $1 million and $4 million for each period in each year, respectively.
Administrative Services Agreement by and between Marsh Landing and NRG West Coast LLC
On December 19, 2016, Marsh Landing entered into an administrative services agreement with NRG West Coast LLC, a wholly owned subsidiary of NRG. The administrative services agreement was previously between Marsh Landing and GenOn Energy Services, LLC, a wholly-owned subsidiary of NRG and was subsequently assigned to and assumed by NRG West Coast LLC. The Company reimbursed costs under this agreement of $4 million and $10 million for the three and nine months ended September 30, 2017, respectively. The Company reimbursed costs under the agreement of $4 million and $9 million for the three and nine months ended September 30, 2016, respectively.
Administrative Services Agreements by and between the Company and NRG RenewClearway Renewable Operation & Maintenance LLC
Various wholly-owned subsidiaries of the Company in the Renewables segment are party to administrative services agreements with NRG RenewClearway Renewable Operation and& Maintenance LLC, or RENOM, a wholly-owned subsidiary of NRG,CEG, which provides operation and maintenance, or O&M, services on behalf ofto these entities.subsidiaries. The Company incurred total expenses for these services in the amount of $6$19 million and $16$15 million for the three and nine months ended SeptemberJune 30, 2017,2023 and 2022, respectively. The Company incurred total expenses for these services of $4$36 million and $9$30 million for the three and ninesix months ended SeptemberJune 30, 2016,2023 and 2022, respectively. There was a balance of $4$11 million and $5$14 million due to RENOM as of SeptemberJune 30, 20172023 and December 31, 2016,2022, respectively.
ManagementAdministrative Services AgreementAgreements by and between the Company and NRGCEG
NRG providesVarious wholly-owned subsidiaries of the Company are parties to services agreements with Clearway Asset Services LLC and Solar Asset Management LLC, two wholly-owned subsidiaries of CEG, which provide various operation, management,administrative services to the Company's subsidiaries. The Company incurred expenses under these agreements of $6 million and $5 million for the three months ended June 30, 2023, and 2022, respectively. The Company incurred expenses under these agreements of $10 million and $8 million for the six months ended June 30, 2023 and 2022, respectively. There was a balance of $2 million and $3 million due to CEG as of June 30, 2023 and December 31, 2022, respectively.
CEG Master Services Agreements
The Company is a party to the CEG Master Services Agreements, pursuant to which CEG and certain of its affiliates or third-party service providers provide certain services to the Company, including operational and administrative services, which include human resources, accounting, tax, legal, information systems, treasury,external affairs, accounting, procurement and risk management as set forthservices,and the Company provides certain services to CEG, including accounting, internal audit, tax and treasury services, in exchange for the Management Services Agreement. Aspayment of September 30, 2017, the base management fee was approximately $8 million per year, subject to an inflation-based adjustment annually at an inflation factor based on the year-over-year U.S. consumer price index.fees in respect of such services. The fee is also subject to adjustments following the consummationCompany incurred net expenses under these agreements of acquisitions and as a result of a change in the scope of services provided under the Management Services Agreement. Costs incurred under this agreement were $2 million and $8$1 million for each of the three months ended June 30, 2023, and 2022, respectively. The Company incurred net expenses under these agreements of $3 million and $2 million for the three and ninesix months ended SeptemberJune 30, 2017,2023 and 2022, respectively. Costs incurred under this agreement for the three and nine months ended September 30, 2016 were $1 million and $6 million, respectively. The costs incurred under the Management Service Agreement included certain direct expenses incurred by NRG on behalf of the Company in addition to the base management fee.
Note 10 — Condensed Consolidating Financial InformationContingencies
As of September 30, 2017, Yield Operating LLC had outstanding $500 million of the 2024 Senior Notes and $350 million of the 2026 Senior Notes, collectively Senior Notes, as described in Note 10, Long-term Debt to the consolidated financial statements for the year ended December 31, 2016 included in the Company's May 9, 2017 Form 8-K. These Senior Notes are guaranteed by NRG Yield LLC, as well as certain of the Company's subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include the rest of the Company's subsidiaries, including those that are subject to project financing.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2017:
|
|
NRG Yield LLC |
Alta Wind 1-5 Holding Company, LLC |
Alta Wind Company, LLC |
NRG Energy Center Omaha Holdings LLC |
NRG Energy Center Omaha LLC |
NYLD Fuel Cell Holdings LLC |
UB Fuel Cell, LLC |
NRG South Trent Holdings LLC |
NRG Yield DGPV Holding LLC |
NRG Yield RPV Holding LLC |
Yield Operating LLC conducts its business through and derives its income from its subsidiaries. Therefore, its ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and Yield Operating LLC'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 Yield Operating LLC. However, there may be restrictions for certain non-guarantor subsidiaries.
The following condensed consolidating financial information presents the financial information of NRG Yield LLC, Yield Operating LLC, the issuer of the Senior Notes, 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 Yield LLC consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG Yield LLC 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. As described in Note 1, Nature of Business, the Company completed the acquisition of the August 2017 Drop Down Assets, March 2017 Drop Down Assets and CVSR Drop Down Asset from NRG on August 1, 2017, March 27, 2017 and September 1, 2016, respectively. The guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect since the inception of common control. Accordingly, the Company prepared its condensed consolidating financial statements to reflect the transfers as if they had taken place from the beginning of the financial statements period.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
For the Three Months Ended September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| NRG Yield LLC | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Yield Operating LLC (Note Issuer) | | Eliminations(a) | | Consolidated |
| (In millions) |
Operating Revenues | | | | | | | | | | | |
Total operating revenues | $ | — |
| | $ | 6 |
| | $ | 259 |
| | $ | — |
| | $ | — |
| | $ | 265 |
|
Operating Costs and Expenses | | | | | | | | | | | |
Cost of operations | — |
| | 3 |
| | 75 |
| | — |
| | — |
| | 78 |
|
Depreciation and amortization | — |
| | 1 |
| | 87 |
| | — |
| | — |
| | 88 |
|
General and administrative | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
|
Total operating costs and expenses | — |
| | 4 |
| | 162 |
| | 4 |
| | — |
| | 170 |
|
Operating Income (Loss) | — |
| | 2 |
| | 97 |
| | (4 | ) | | — |
| | 95 |
|
Other Income (Expense) | | | | | | | | | | | |
Equity in earnings (losses) of consolidated affiliates | 75 |
| | (4 | ) | | — |
| | 59 |
| | (130 | ) | | — |
|
Equity in earnings of unconsolidated affiliates | — |
| | 7 |
| | 6 |
| | 15 |
| | — |
| | 28 |
|
Other income, net | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Interest expense | — |
| | — |
| | (54 | ) | | (18 | ) | | — |
| | (72 | ) |
Total other income (expense), net | 75 |
| | 3 |
| | (47 | ) | | 56 |
| | (130 | ) | | (43 | ) |
Net Income | 75 |
| | 5 |
| | 50 |
| | 52 |
| | (130 | ) | | 52 |
|
Less: Net loss attributable to noncontrolling interests | — |
| | — |
| | (1 | ) | | (23 | ) | | 1 |
| | (23 | ) |
Net Income Attributable to NRG Yield LLC | $ | 75 |
| | $ | 5 |
| | $ | 51 |
| | $ | 75 |
| | $ | (131 | ) | | $ | 75 |
|
(a) All significant intercompany transactions have been eliminated in consolidation.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
For the Nine Months ended September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| NRG Yield LLC | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Yield Operating LLC (Note Issuer) | | Eliminations(a) | | Consolidated |
| (In millions) |
Operating Revenues | | | | | | | | | | | |
Total operating revenues | $ | — |
| | $ | 16 |
| | $ | 751 |
| | $ | 1 |
| | $ | (1 | ) | | $ | 767 |
|
Operating Costs and Expenses | | | | | | | | | | | |
Cost of operations | — |
| | 10 |
| | 229 |
| | 1 |
| | (1 | ) | | 239 |
|
Depreciation and amortization | — |
| | 3 |
| | 238 |
| | — |
| | — |
| | 241 |
|
General and administrative | — |
| | — |
| | — |
| | 14 |
| | — |
| | 14 |
|
Acquisition-related transaction and integration costs | — |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
Total operating costs and expenses | — |
| | 13 |
| | 467 |
| | 17 |
| | (1 | ) | | 496 |
|
Operating Income (Loss) | — |
| | 3 |
| | 284 |
| | (16 | ) | | — |
| | 271 |
|
Other Income (Expense) | | | | | | | | | | | |
Equity in earnings of consolidated affiliates | 165 |
| | 6 |
| | — |
| | 153 |
| | (324 | ) | | — |
|
Equity in earnings of unconsolidated affiliates | — |
| | 9 |
| | 28 |
| | 26 |
| | — |
| | 63 |
|
Other income, net | 1 |
| | — |
| | 2 |
| | — |
| | — |
| | 3 |
|
Interest expense | — |
| | — |
| | (173 | ) | | (54 | ) | | — |
| | (227 | ) |
Total other income (expense), net | 166 |
| | 15 |
| | (143 | ) | | 125 |
| | (324 | ) | | (161 | ) |
Net Income | 166 |
| | 18 |
| | 141 |
| | 109 |
| | (324 | ) | | 110 |
|
Less: Net loss attributable to noncontrolling interests | — |
| | — |
| | (3 | ) | | (56 | ) | | 3 |
| | (56 | ) |
Net Income Attributable to NRG Yield LLC | $ | 166 |
| | $ | 18 |
| | $ | 144 |
| | $ | 165 |
| | $ | (327 | ) | | $ | 166 |
|
(a) All significant intercompany transactions have been eliminated in consolidation.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the Three Months Ended September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| NRG Yield LLC | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Yield Operating LLC (Note Issuer) | | Eliminations(a) | | Consolidated |
| (In millions) |
Net Income | $ | 75 |
| | $ | 5 |
| | $ | 50 |
| | $ | 52 |
| | $ | (130 | ) | | $ | 52 |
|
Other Comprehensive Income | | | | | | | | | | | |
Unrealized gain on derivatives | 7 |
| | — |
| | 7 |
| | 7 |
| | (14 | ) | | 7 |
|
Other comprehensive income | 7 |
| | — |
| | 7 |
| | 7 |
| | (14 | ) | | 7 |
|
Comprehensive Income | 82 |
| | 5 |
| | 57 |
| | 59 |
| | (144 | ) | | 59 |
|
Less: Comprehensive loss attributable to noncontrolling interests | — |
| | — |
| | (1 | ) | | (23 | ) | | 1 |
| | (23 | ) |
Comprehensive Income Attributable to NRG Yield LLC | $ | 82 |
| | $ | 5 |
| | $ | 58 |
| | $ | 82 |
| | $ | (145 | ) | | $ | 82 |
|
(a) All significant intercompany transactions have been eliminated in consolidation.
For the Nine Months ended September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| NRG Yield LLC | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Yield Operating LLC (Note Issuer) | | Eliminations(a) | | Consolidated |
| (In millions) |
Net Income | $ | 166 |
| | $ | 18 |
| | $ | 141 |
| | $ | 109 |
| | $ | (324 | ) | | $ | 110 |
|
Other Comprehensive Income | | | | | | | | | | | |
Unrealized loss on derivatives | 7 |
| | — |
| | 7 |
| | 7 |
| | (14 | ) | | 7 |
|
Other comprehensive loss | 7 |
| | — |
| | 7 |
| | 7 |
| | (14 | ) | | 7 |
|
Comprehensive Income | 173 |
| | 18 |
| | 148 |
| | 116 |
| | (338 | ) | | 117 |
|
Less: Comprehensive loss attributable to noncontrolling interests | — |
| | — |
| | (3 | ) | | (56 | ) | | 3 |
| | (56 | ) |
Comprehensive Income Attributable to NRG Yield LLC | $ | 173 |
| | $ | 18 |
| | $ | 151 |
| | $ | 172 |
| | $ | (341 | ) | | $ | 173 |
|
(a) All significant intercompany transactions have been eliminated in consolidation.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | NRG Yield LLC | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Yield Operating LLC (Note Issuer) | | Eliminations(a) | | Consolidated |
ASSETS | | (In millions) |
Current Assets | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 76 |
| | $ | — |
| | $ | 102 |
| | $ | — |
| | $ | — |
| | $ | 178 |
|
Restricted cash | | — |
| | — |
| | 140 |
| | — |
| | — |
| | 140 |
|
Accounts receivable — trade | | — |
| | 3 |
| | 123 |
| | — |
| | — |
| | 126 |
|
Accounts receivable — affiliate | | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
Inventory | | — |
| | 1 |
| | 37 |
| | — |
| | — |
| | 38 |
|
Notes receivable | | — |
| | — |
| | 15 |
| | — |
| | — |
| | 15 |
|
Prepayments and other current assets | | — |
| | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
Total current assets | | 77 |
| | 4 |
| | 439 |
| | — |
| | — |
| | 520 |
|
Net property, plant and equipment | | — |
| | 59 |
| | 5,188 |
| | — |
| | — |
| | 5,247 |
|
Other Assets | | | | | | | | | | | | |
Investment in consolidated subsidiaries | | 1,828 |
| | 482 |
| | — |
| | 3,134 |
| | (5,444 | ) | | — |
|
Equity investments in affiliates | | — |
| | 210 |
| | 598 |
| | 375 |
| | — |
| | 1,183 |
|
Intangible assets, net | | — |
| | 55 |
| | 1,179 |
| | — |
| | — |
| | 1,234 |
|
Other non-current assets | | — |
| | — |
| | 56 |
| | — |
| | — |
| | 56 |
|
Total other assets | | 1,828 |
| | 747 |
| | 1,833 |
| | 3,509 |
| | (5,444 | ) | | 2,473 |
|
Total Assets | | $ | 1,905 |
| | $ | 810 |
| | $ | 7,460 |
| | $ | 3,509 |
| | $ | (5,444 | ) | | $ | 8,240 |
|
(a) All significant intercompany transactions have been eliminated in consolidation.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2017
(Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | NRG Yield LLC | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Yield Operating LLC (Note Issuer) | | Eliminations(a) | | Consolidated |
LIABILITIES AND MEMBERS' EQUITY | | (In millions) |
Current Liabilities | | | | | | | | | | | | |
Current portion of long-term debt — external | | $ | — |
| | $ | — |
| | $ | 300 |
| | $ | — |
| | $ | — |
| | $ | 300 |
|
Accounts payable | | — |
| | 2 |
| | 25 |
| | — |
| | — |
| | 27 |
|
Accounts payable — affiliate | | — |
| | 5 |
| | 19 |
| | 21 |
| | — |
| | 45 |
|
Derivative instruments | | — |
| | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Accrued expenses and other current liabilities | | — |
| | 1 |
| | 80 |
| | 13 |
| | — |
| | 94 |
|
Total current liabilities | | — |
| | 8 |
| | 447 |
| | 34 |
| | — |
| | 489 |
|
Other Liabilities | | | | | | | | | | | | |
Long-term debt — external | | — |
| | — |
| | 4,074 |
| | 840 |
| | — |
| | 4,914 |
|
Long-term debt — affiliate | | — |
| | — |
| | — |
| | 618 |
| | — |
| | 618 |
|
Accounts payable — affiliate | | — |
| | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
Derivative instruments | | — |
| | — |
| | 43 |
| | — |
| | — |
| | 43 |
|
Other non-current liabilities | | — |
| | — |
| | 79 |
| | 8 |
| | — |
| | 87 |
|
Total non-current liabilities | | — |
| | — |
| | 4,199 |
| | 1,466 |
| | — |
| | 5,665 |
|
Total Liabilities | | — |
| | 8 |
| | 4,646 |
| | 1,500 |
| | — |
| | 6,154 |
|
Commitments and Contingencies | | | | | | | | | | | | |
Members' Equity | | | | | | | | | | | | |
Contributed capital | | 1,897 |
| | 853 |
| | 2,734 |
| | 2,077 |
| | (5,664 | ) | | 1,897 |
|
Retained earnings (accumulated deficit) | | 86 |
| | (49 | ) | | 100 |
| | (171 | ) | | 120 |
| | 86 |
|
Accumulated other comprehensive loss | | (78 | ) | | (2 | ) | | (80 | ) | | (78 | ) | | 160 |
| | (78 | ) |
Noncontrolling interest | | — |
| | — |
| | 60 |
| | 181 |
| | (60 | ) | | 181 |
|
Total Members' Equity | | 1,905 |
| | 802 |
| | 2,814 |
| | 2,009 |
| | (5,444 | ) | | 2,086 |
|
Total Liabilities and Members’ Equity | | $ | 1,905 |
| | $ | 810 |
| | $ | 7,460 |
| | $ | 3,509 |
| | $ | (5,444 | ) | | $ | 8,240 |
|
(a) All significant intercompany transactions have been eliminated in consolidation.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months ended September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | |
| | NRG Yield LLC | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Yield Operating LLC (Note Issuer) | | Consolidated |
| | (In millions) |
Net Cash Provided by (Used in) Operating Activities | | $ | — |
| | $ | 38 |
| | $ | 414 |
| | $ | (77 | ) | | $ | 375 |
|
Cash Flows from Investing Activities | | | | | | | | | | |
Intercompany transactions between Yield LLC and subsidiaries | | (13 | ) | | — |
| | — |
| | 13 |
| | — |
|
Payments for the Drop Down Assets | | — |
| | — |
| | — |
| | (176 | ) | | (176 | ) |
Capital expenditures | | — |
| | (3 | ) | | (20 | ) | | — |
| | (23 | ) |
Cash receipts from notes receivable | | — |
| | — |
| | 11 |
| | — |
| | 11 |
|
Return of investment from unconsolidated affiliates | | — |
| | 7 |
| | 9 |
| | 16 |
| | 32 |
|
Net investments in unconsolidated affiliates | | — |
| | (41 | ) | | (7 | ) | | — |
| | (48 | ) |
Net Cash Used in Investing Activities | | (13 | ) | | (37 | ) | | (7 | ) | | (147 | ) | | (204 | ) |
Cash Flows from Financing Activities | | | | | | | | | | |
Transfer of funds under intercompany cash management arrangement | | (6 | ) | | (1 | ) | | — |
| | 7 |
| | — |
|
Net contributions from noncontrolling interests | | — |
| | — |
| | — |
| | 13 |
| | 13 |
|
Net distributions and return of capital to NRG prior to the acquisition of Drop Down Assets | | — |
| | — |
| | (42 | ) | | (7 | ) | | (49 | ) |
(Payments of) proceeds from distributions | | (149 | ) | | — |
| | (211 | ) | | 211 |
| | (149 | ) |
Payment of debt issuance costs | | — |
| | — |
| | (4 | ) | | — |
| | (4 | ) |
Proceeds from Issuance of Class C units | | 33 |
| | — |
| | — |
| | — |
| | 33 |
|
Proceeds from the issuance of long-term debt — external | | — |
| | — |
| | 41 |
| | — |
| | 41 |
|
Payments for long-term debt | | — |
| | — |
| | (224 | ) | | — |
| | (224 | ) |
Net Cash (Used in) Provided by Financing Activities | | (122 | ) | | (1 | ) | | (440 | ) | | 224 |
| | (339 | ) |
Net Decrease in Cash, Cash Equivalents and Restricted Cash | | (135 | ) | | — |
| | (33 | ) | | — |
| | (168 | ) |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 211 |
| | — |
| | 275 |
| | — |
| | 486 |
|
Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 76 |
| | $ | — |
| | $ | 242 |
| | $ | — |
| | $ | 318 |
|
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2016
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| NRG Yield LLC (a) | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries (a) | | NRG Yield Operating LLC (Note Issuer) (a) | | Eliminations (b) | | Consolidated (a) |
| (In millions) |
Operating Revenues | | | | | | | | | | | |
Total operating revenues | $ | — |
| | $ | 7 |
| | $ | 265 |
| | $ | — |
| | $ | — |
| | $ | 272 |
|
Operating Costs and Expenses | | | | | | | | | | | |
Cost of operations | — |
| | 3 |
| | 73 |
| | — |
| | — |
| | 76 |
|
Depreciation and amortization | — |
| | 2 |
| | 73 |
| | — |
| | — |
| | 75 |
|
General and administrative | — |
| | — |
| | — |
| | 3 |
| | — |
| | 3 |
|
Total operating costs and expenses | — |
| | 5 |
| | 146 |
| | 3 |
| | — |
| | 154 |
|
Operating Income (Loss) | — |
| | 2 |
| | 119 |
| | (3 | ) | | — |
| | 118 |
|
Other Income (Expense) | | | | | | | | | | | |
Equity in earnings of consolidated affiliates | 105 |
| | 4 |
| | — |
| | 73 |
| | (182 | ) | | — |
|
Equity in earnings of unconsolidated affiliates | — |
| | (1 | ) | | 3 |
| | 14 |
| | — |
| | 16 |
|
Other income, net | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Interest expense | — |
| | — |
| | (51 | ) | | (17 | ) | | — |
| | (68 | ) |
Total other income (expense), net | 105 |
| | 3 |
| | (47 | ) | | 70 |
| | (182 | ) | | (51 | ) |
Net Income | 105 |
| | 5 |
| | 72 |
| | 67 |
| | (182 | ) | | 67 |
|
Less: Net loss attributable to noncontrolling interests | — |
| | — |
| | (1 | ) | | (38 | ) | | 1 |
| | (38 | ) |
Net Income Attributable to NRG Yield LLC | $ | 105 |
| | $ | 5 |
| | $ | 73 |
| | $ | 105 |
| | $ | (183 | ) | | $ | 105 |
|
(a) Retrospectively adjusted as discussed in Note 1, Nature of Business.
(b) All significant intercompany transactions have been eliminated in consolidation.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
For the Nine Months Ended September 30, 2016
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| NRG Yield LLC (a) | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries (a) | | NRG Yield Operating LLC (Note Issuer) (a) | | Eliminations (b) | | Consolidated (a) |
| (In millions) |
Operating Revenues | | | | | | | | | | | |
Total operating revenues | $ | — |
| | $ | 17 |
| | $ | 772 |
| | $ | — |
| | $ | — |
| | $ | 789 |
|
Operating Costs and Expenses | | | | | | | | | | | |
Cost of operations | — |
| | 10 |
| | 228 |
| | — |
| | — |
| | 238 |
|
Depreciation and amortization | — |
| | 4 |
| | 220 |
| | — |
| | — |
| | 224 |
|
General and administrative | — |
| | — |
| | — |
| | 8 |
| | — |
| | 8 |
|
Total operating costs and expenses | — |
| | 14 |
| | 448 |
| | 8 |
| | — |
| | 470 |
|
Operating Income (Loss) | — |
| | 3 |
| | 324 |
| | (8 | ) | | — |
| | 319 |
|
Other Income (Expense) | | | | | | | | | | | |
Equity in income of consolidated affiliates | 219 |
| | 21 |
| | — |
| | 184 |
| | (424 | ) | | — |
|
Equity in earnings of unconsolidated affiliates | — |
| | 7 |
| | 3 |
| | 24 |
| | — |
| | 34 |
|
Other income, net | — |
| | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
Interest expense | — |
| | — |
| | (156 | ) | | (48 | ) | | — |
| | (204 | ) |
Total other income (expense), net | 219 |
| | 28 |
| | (150 | ) | | 160 |
| | (424 | ) | | (167 | ) |
Net Income | 219 |
| | 31 |
| | 174 |
| | 152 |
| | (424 | ) | | 152 |
|
Less: Net loss attributable to noncontrolling interests | — |
| | — |
| | (1 | ) | | (67 | ) | | 1 |
| | (67 | ) |
Net Income Attributable to NRG Yield LLC | $ | 219 |
| | $ | 31 |
| | $ | 175 |
| | $ | 219 |
| | $ | (425 | ) | | $ | 219 |
|
(a)Retrospectively adjusted as discussed in Note 1, Nature of Business.
(b)All significant intercompany transactions have been eliminated in consolidation.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the Three Months Ended September 30, 2016
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| NRG Yield LLC (a) | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries (a) | | NRG Yield Operating LLC (Note Issuer) (a) | | Eliminations (b) | | Consolidated (a) |
| (In millions) |
Net Income | $ | 105 |
| | $ | 5 |
| | $ | 72 |
| | $ | 67 |
| | $ | (182 | ) | | $ | 67 |
|
Other Comprehensive Income | | | | | | | | | | | |
Unrealized gain on derivatives | 11 |
| | — |
| | 19 |
| | 20 |
| | (30 | ) | | 20 |
|
Other comprehensive income | 11 |
| | — |
| | 19 |
| | 20 |
| | (30 | ) | | 20 |
|
Comprehensive Income | 116 |
| | 5 |
| | 91 |
| | 87 |
| | (212 | ) | | 87 |
|
Less: Comprehensive loss attributable to noncontrolling interests | — |
| | — |
| | (1 | ) | | (30 | ) | | 1 |
| | (30 | ) |
Comprehensive Income Attributable to NRG Yield LLC | $ | 116 |
| | $ | 5 |
| | $ | 92 |
| | $ | 117 |
| | $ | (213 | ) | | $ | 117 |
|
(a) Retrospectively adjusted as discussed in Note 1, Nature of Business.
(b)All significant intercompany transactions have been eliminated in consolidation.
For the Nine Months Ended September 30, 2016
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| NRG Yield LLC (a) | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries (a) | | NRG Yield Operating LLC (Note Issuer) (a) | | Eliminations (b) | | Consolidated (a) |
| (In millions) |
Net Income | $ | 219 |
| | $ | 31 |
| | $ | 174 |
| | $ | 152 |
| | $ | (424 | ) | | $ | 152 |
|
Other Comprehensive Loss | | | | | | | | | | | |
Unrealized loss on derivatives | (49 | ) | | — |
| | (45 | ) | | (49 | ) | | 94 |
| | (49 | ) |
Other comprehensive loss | (49 | ) | | — |
| | (45 | ) | | (49 | ) | | 94 |
| | (49 | ) |
Comprehensive Income | 170 |
| | 31 |
| | 129 |
| | 103 |
| | (330 | ) | | 103 |
|
Less: Comprehensive loss attributable to noncontrolling interests | — |
| | — |
| | (1 | ) | | (67 | ) | | 1 |
| | (67 | ) |
Comprehensive Income Attributable to NRG Yield LLC | $ | 170 |
| | $ | 31 |
| | $ | 130 |
| | $ | 170 |
| | $ | (331 | ) | | $ | 170 |
|
(a) Retrospectively adjusted as discussed in Note 1, Nature of Business.
(b)All significant intercompany transactions have been eliminated in consolidation.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2016
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | NRG Yield LLC(a) | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries(a) | | NRG Yield Operating LLC (Note Issuer)(a) | | Eliminations (b) | | Consolidated(a) |
ASSETS | | (In millions) |
Current Assets | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 211 |
| | $ | — |
| | $ | 110 |
| | $ | — |
| | $ | — |
| | $ | 321 |
|
Restricted cash | | — |
| | — |
| | 165 |
| | — |
| | — |
| | 165 |
|
Accounts receivable — trade | | — |
| | 2 |
| | 90 |
| | — |
| | — |
| | 92 |
|
Accounts receivable — affiliate | | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Inventory | | — |
| | 2 |
| | 37 |
| | — |
| | — |
| | 39 |
|
Derivative instruments | | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Notes receivable | | — |
| | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
Prepayments and other current assets | | — |
| | — |
| | 19 |
| | 1 |
| | — |
| | 20 |
|
Total current assets | | 211 |
| | 4 |
| | 440 |
| | 1 |
| | — |
| | 656 |
|
| | | | | | | | | | | | |
Net property, plant and equipment | | — |
| | 59 |
| | 5,401 |
| | — |
| | — |
| | 5,460 |
|
Other Assets | | | | | | | | | | | | |
Investment in consolidated subsidiaries | | 1,867 |
| | 527 |
| | — |
| | 3,212 |
| | (5,606 | ) | | — |
|
Equity investments in affiliates | | — |
| | 171 |
| | 600 |
| | 381 |
| | — |
| | 1,152 |
|
Intangible assets, net | | — |
| | 56 |
| | 1,230 |
| | — |
| | — |
| | 1,286 |
|
Derivative instruments | | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Other non-current assets | | — |
| | — |
| | 64 |
| | 1 |
| | — |
| | 65 |
|
Total other assets | | 1,867 |
| | 754 |
| | 1,895 |
| | 3,594 |
| | (5,606 | ) | | 2,504 |
|
Total Assets | | $ | 2,078 |
| | $ | 817 |
| | $ | 7,736 |
| | $ | 3,595 |
| | $ | (5,606 | ) | | $ | 8,620 |
|
(a) Retrospectively adjusted as discussed in Note 1, Nature of Business.
(b)All significant intercompany transactions have been eliminated in consolidation.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2016
(Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | NRG Yield LLC(a) | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries(a) | | NRG Yield Operating LLC (Note Issuer)(a) | | Eliminations (b) | | Consolidated(a) |
LIABILITIES AND MEMBERS' EQUITY | | (In millions) |
Current Liabilities | | | | | | | | | | | | |
Current portion of long-term debt — external | | $ | — |
| | $ | — |
| | $ | 291 |
| | $ | — |
| | $ | — |
| | $ | 291 |
|
Accounts payable | | — |
| | 2 |
| | 18 |
| | 3 |
| | — |
| | 23 |
|
Accounts payable — affiliate | | — |
| | 7 |
| | 15 |
| | 18 |
| | — |
| | 40 |
|
Derivative instruments | | — |
| | — |
| | 32 |
| | — |
| | — |
| | 32 |
|
Accrued expenses and other current liabilities | | — |
| | 1 |
| | 60 |
| | 24 |
| | — |
| | 85 |
|
Total current liabilities | | — |
| | 10 |
| | 416 |
| | 45 |
| | — |
| | 471 |
|
Other Liabilities | | | | | | | | | | | | |
Long-term debt — external | | — |
| | — |
| | 4,259 |
| | 839 |
| | — |
| | 5,098 |
|
Long-term debt — affiliate | | — |
| | — |
| | — |
| | 618 |
| | — |
| | 618 |
|
Accounts payable — affiliate | | — |
| | — |
| | 9 |
| | — |
| | — |
| | 9 |
|
Derivative instruments | | — |
| | — |
| | 44 |
| | — |
| | — |
| | 44 |
|
Other non-current liabilities | | — |
| | — |
| | 76 |
| | — |
| | — |
| | 76 |
|
Total non-current liabilities | | — |
| | — |
| | 4,388 |
| | 1,457 |
| | — |
| | 5,845 |
|
Total Liabilities | | — |
| | 10 |
| | 4,804 |
| | 1,502 |
| | — |
| | 6,316 |
|
Commitments and Contingencies | | | | | | | | | | | | |
Members' Equity | | | | | | | | | | | | |
Contributed capital | | 2,127 |
| | 874 |
| | 2,920 |
| | 2,103 |
| | (5,897 | ) | | 2,127 |
|
Retained earnings (Accumulated deficit) | | 36 |
| | (65 | ) | | 35 |
| | (151 | ) | | 181 |
| | 36 |
|
Accumulated other comprehensive loss | | (85 | ) | | (2 | ) | | (87 | ) | | (85 | ) | | 174 |
| | (85 | ) |
Noncontrolling Interest | | — |
| | — |
| | 64 |
| | 226 |
| | (64 | ) | | 226 |
|
Total Members' Equity | | 2,078 |
| | 807 |
| | 2,932 |
| | 2,093 |
| | (5,606 | ) | | 2,304 |
|
Total Liabilities and Members’ Equity | | $ | 2,078 |
| | $ | 817 |
| | $ | 7,736 |
| | $ | 3,595 |
| | $ | (5,606 | ) | | $ | 8,620 |
|
(a) Retrospectively adjusted as discussed in Note 1, Nature of Business.
(b)All significant intercompany transactions have been eliminated in consolidation.
NRG YIELD LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2016
|
| | | | | | | | | | | | | | | | | | | | |
| | NRG Yield LLC (a) | | Other Guarantor Subsidiaries | | Non-Guarantor Subsidiaries (a) | | NRG Yield Operating LLC (Note Issuer) | | Consolidated (a) |
| | (In millions) |
Net Cash Provided by Operating Activities | | $ | — |
| | $ | 45 |
| | $ | 365 |
| | $ | 34 |
| | $ | 444 |
|
Cash Flows from Investing Activities | | | | | | | | | | |
Intercompany transactions from Yield LLC to subsidiaries | | 145 |
| | — |
| | — |
| | (145 | ) | | — |
|
Acquisition of Drop Down Assets, net of cash acquired | | — |
| | — |
| | — |
| | (77 | ) | | (77 | ) |
Capital expenditures | | — |
| | — |
| | (16 | ) | | — |
| | (16 | ) |
Cash receipts from notes receivable | | — |
| | — |
| | 11 |
| | — |
| | 11 |
|
Return of investment from unconsolidated affiliates | | — |
| | 3 |
| | — |
| | 13 |
| | 16 |
|
Net investments in unconsolidated affiliates | | — |
| | (48 | ) | | — |
| | (21 | ) | | (69 | ) |
Net Cash Provided by (Used in) Investing Activities | | 145 |
| | (45 | ) | | (5 | ) | | (230 | ) | | (135 | ) |
Cash Flows from Financing Activities | | | | | | | | | | |
|
Transfer of funds under intercompany cash management arrangement | | 54 |
| | — |
| | — |
| | (54 | ) | | — |
|
Net contributions from noncontrolling interests | | — |
| | — |
| | — |
| | 7 |
| | 7 |
|
Net distributions and return of capital to NRG prior to the acquisition of Drop Down Assets | | — |
| | — |
| | (126 | ) | | — |
| | (126 | ) |
(Payments of) proceeds from distributions | | (127 | ) | | — |
| | (204 | ) | | 204 |
| | (127 | ) |
Payment of debt issuance costs | | — |
| | — |
| | (1 | ) | | (5 | ) | | (6 | ) |
Proceeds from the revolving credit facility | | — |
| | — |
| | — |
| | 60 |
| | 60 |
|
Payments for the revolving credit facility | | — |
| | — |
| | — |
| | (366 | ) | | (366 | ) |
Proceeds from the issuance of long-term debt - external | | — |
| | — |
| | 200 |
| | 350 |
| | 550 |
|
Payments for long-term debt | | — |
| | — |
| | (204 | ) | | — |
| | (204 | ) |
Net Cash (Used in) Provided by Financing Activities | | (73 | ) | | — |
| | (335 | ) | | 196 |
| | (212 | ) |
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash | | 72 |
| | — |
| | 25 |
| | — |
| | 97 |
|
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 15 |
| | — |
| | 226 |
| | — |
| | 241 |
|
Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 87 |
| | $ | — |
| | $ | 251 |
| | $ | — |
| | $ | 338 |
|
(a) Retrospectively adjusted as discussed in Note 1, Nature of Business.
Note 11 — Contingencies
This note should be read in conjunction with the complete description under Item 15 — Note 14, Commitments and Contingencies, to the Company's 2016consolidated financial statements included in the Company’s 2022 Form 10-K.
The Company'sCompany’s material legal proceedings areproceeding is described below. The Company believes that it has a valid defensesdefense to thesethis legal proceedingsproceeding and intends to defend themit vigorously. The Company 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 mattersmatter discussed below. In addition, legal costs are expensed as incurred. Management assesses such matters based on current information and makes a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. The Company is unable to predict the outcome of the legal proceedingsproceeding below or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimatesestimate of such contingenciescontingency accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company'sCompany’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 proceedingsproceeding noted below, the Company and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management'smanagement’s opinion, the disposition of these ordinary course matters will not materially adversely affect the Company'sCompany’s consolidated financial position, results of operations, or cash flows.
Braun v. NRG Yield, Inc. — Buckthorn Solar Litigation
On April 19, 2016, plaintiffsOctober 8, 2019, the City of Georgetown, Texas, or Georgetown, filed a putative class action lawsuit against NRG Yield, Inc.,petition in the currentDistrict Court of Williamson County, Texas naming Buckthorn Westex, LLC, the Company’s subsidiary that owns the Buckthorn Westex solar project, as the defendant, alleging fraud by nondisclosure and former membersbreach of its board of directors individually,contract in connection with the project and other parties in California Superior Court in Kern County, CA. Plaintiffs allege various violationsthe PPA, and seeking (i) rescission and/or cancellation of the Securities ActPPA, (ii) declaratory judgment that the alleged breaches constitute an event of default under the PPA entitling Georgetown to terminate, and (iii) recovery of all damages, costs of court, and attorneys’ fees. On November 15, 2019, Buckthorn Westex filed an original answer and counterclaims (i) denying Georgetown’s claims, (ii) alleging Georgetown has breached its contracts with Buckthorn Westex by failing to pay amounts due, toand (iii) seeking relief in the defendants’form of (x) declaratory judgment that Georgetown’s alleged failure to disclose material facts related to low wind production prior to NRG Yield, Inc.'s June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory damages, rescission, attorney’spay amounts due constitute breaches of and an event of default under the PPA and that Buckthorn did not commit any events of default under the PPA, (y) recovery of costs, expenses, interest, and attorneys’ fees, and costs. The defendants(z) such other relief to which it is entitled at law or in equity. In response to motions for partial summary judgment filed demurrers and a motion challenging jurisdiction on October 18, 2016. On October 26, 2017,by each party, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on December 6, 2017 and the defendants' reply is due on February 8, 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 partiesdenied Georgetown’s motion in the Delaware Chancery Court. The complaint alleges that the defendants breached their respective fiduciary dutiesits entirety, granted Buckthorn Westex’s motion with regardrespect to the recapitalization of NRG Yield, Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s feesfraud by nondisclosure claim and injunctive relief. The defendants filed adenied Buckthorn Westex’s motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objectionwith respect to the motion to dismiss on February 15, 2017. The defendants' reply was filed on March 24, 2017. The court heard oral argument on the 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.
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., or GenOn, 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. On April 30, 2017, the Noteholders filed an amended complaint that asserts additional claims of fraudulent transfer, insider preference and breach of fiduciary duties. In additioncontract claim. The case is scheduled to NRGproceed to trial in October 2023. Buckthorn Westex believes the allegations of Georgetown are meritless, 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 paidBuckthorn Westex is vigorously defending its rights under the Services Agreement and any other damages that the court deems appropriate. On April 28, 2017, the bondholders filed an amended complaint adding the GenOn directors and officers as defendants and asserting claims that they breached certain fiduciary duties. Plaintiffs specifically allege that the transfer of Marsh Landing to NRG Yield LLC constituted a fraudulent transfer. On June 12, 2017, certain GenOn entities, NRG and certain holders of the GenOn and GenOn Americas Generation, LLC senior notes entered into a restructuring support and lock-up agreement. Pursuant to the terms of the restructuring support and lock-up agreement, this matter should ultimately be resolved if GenOn's plan of reorganization, originally submitted on June 29, 2017, is approved by the United States Bankruptcy Court for the Southern District of Texas, Houston Division.
PPA.
ITEM 2 — Management'sManagement’s Discussion and Analysis of Financial Condition and the Results of Operations
The following discussion analyzes the Company'sCompany’s historical financial condition and results of operations, which were recast to include the effect of the August 2017 Drop Down Assets and the March 2017 Drop Down Assets.operations.
As you read this discussion and analysis, refer to the Company's Consolidated Financial StatementsCompany’s consolidated financial statements to this Form 10-Q, which present the results of operations for the three and ninesix months ended SeptemberJune 30, 2017,2023 and 2016.2022. Also refer to the Company's May 9, 2017Company’s 2022 Form 8-K,10-K, which includes detailed discussions of various items impacting the Company'sCompany’s business, results of operations and financial condition.
The discussion and analysis below has been organized as follows:
•Executive Summary, including a description of the business and significant events that are important to understanding the results of operations and financial condition;
Known trends that may affect the Company’s results of operations and financial condition in the future;
•Results of operations, including an explanation of significant differences between the periods in the specific line items of the consolidated statements of income;
•Financial condition addressing liquidity position, sources and uses of cash, capital resources and requirements, commitments and off-balance sheet arrangements;
•Known trends that may affect the Company’s results of operations and financial condition in the future; and
•Critical accounting policies which are most important to both the portrayal of the Company'sCompany’s financial condition and results of operations, and which require management's most difficult, subjective or complex judgment.
Executive Summary
Introduction and Overview
NRG YieldClearway Energy LLC, was formed by NRG astogether with its consolidated subsidiaries, or the Company, is an energy infrastructure investor with a Delaware limited liability companyfocus on March 5, 2013, to serve as the primary vehicle through which NRG owns, operatesinvestments in clean energy and acquiresowner of modern, sustainable and long-term contracted renewable and conventional generation and thermal infrastructure assets.assets across North America. The Company believes it is well positioned to besponsored by GIP and TotalEnergies through the portfolio company, Clearway Energy Group LLC, or CEG, which is equally owned by GIP and TotalEnergies. GIP is an independent infrastructure fund manager that makes equity and debt investments in infrastructure assets and businesses. TotalEnergies is a premier company for investors seeking stable and growing distributions income from a diversified portfolio of lower-risk high-quality assets.global multi-energy company.
The Company owns a diversified portfoliois one of contractedthe largest renewable and conventional generation and thermal infrastructure assetsenergy owners in the U.S. with over 5,500 net MW of installed wind and solar generation projects. The Company’s contracted generation portfolio collectively represents 5,080over 8,000 net MW as of September 30, 2017. Eachassets also includes approximately 2,500 net MW of environmentally-sound, highly efficient natural gas-fired generation facilities. Through this environmentally-sound, diversified and primarily contracted portfolio, the Company endeavors to increase distributions to its unit holders. The majority of the Company’s revenues are derived from long-term contractual arrangements for the output or capacity from these assets sells substantially all of its output pursuant to long-term offtake agreements with creditworthy counterparties.assets. The weighted average remaining contract duration of these offtake agreements was approximately 16 10 years as of SeptemberJune 30, 2017, 2023based on CAFD. The Company also owns thermal infrastructureCAFD.
As of June 30, 2023, the Company’s operating assets with an aggregate steam and chilled waterare comprised of the following projects:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Projects | | Percentage Ownership | | Net Capacity (MW) (a) | | Counterparty | | Expiration | | |
Conventional | | | | | | | | | | |
Carlsbad | | 100 | % | | 527 | | | San Diego Gas & Electric | | 2038 | | |
El Segundo | | 100 | % | | 550 | | | SCE | | 2023 - 2026 | | |
GenConn Devon | | 50 | % | | 95 | | | Connecticut Light & Power | | 2040 | | |
GenConn Middletown | | 50 | % | | 95 | | | Connecticut Light & Power | | 2041 | | |
Marsh Landing | | 100 | % | | 720 | | | Various | | 2023 - 2030 | | |
Walnut Creek | | 100 | % | | 485 | | | SCE | | 2023 - 2026 | | |
Total Conventional | | | | 2,472 | | | | | | | |
Utility Scale Solar | | | | | | | | | | |
Agua Caliente | | 51 | % | | 148 | | | PG&E | | 2039 | | |
Alpine | | 100 | % | | 66 | | | PG&E | | 2033 | | |
Avenal | | 50 | % | | 23 | | | PG&E | | 2031 | | |
Avra Valley | | 100 | % | | 27 | | | Tucson Electric Power | | 2032 | | |
Blythe | | 100 | % | | 21 | | | SCE | | 2029 | | |
Borrego | | 100 | % | | 26 | | | San Diego Gas and Electric | | 2038 | | |
Buckthorn Solar (b) | | 100 | % | | 150 | | | City of Georgetown, TX | | 2043 | | |
CVSR | | 100 | % | | 250 | | | PG&E | | 2038 | | |
Desert Sunlight 250 | | 25 | % | | 63 | | | SCE | | 2034 | | |
Desert Sunlight 300 | | 25 | % | | 75 | | | PG&E | | 2039 | | |
Kansas South | | 100 | % | | 20 | | | PG&E | | 2033 | | |
Mililani I (b) (c) | | 50 | % | | 20 | | | Hawaiian Electric Company | | 2042 | | |
Oahu Solar Projects (b) | | 100 | % | | 61 | | | Hawaiian Electric Company | | 2041 | | |
Roadrunner | | 100 | % | | 20 | | | El Paso Electric | | 2031 | | |
Rosamond Central (b) | | 50 | % | | 96 | | | Various | | 2035 - 2047 | | |
TA High Desert | | 100 | % | | 20 | | | SCE | | 2033 | | |
Utah Solar Portfolio | | 100 | % | | 530 | | | PacifiCorp | | 2036 | | |
Waiawa (b) (c) | | 50 | % | | 36 | | | Hawaiian Electric Company | | 2043 | | |
Total Utility Scale Solar (d) | | | | 1,652 | | | | | | | |
Distributed Solar | | | | | | | | | | |
DGPV Fund Projects (b) | | 100 | % | | 286 | | | Various | | 2030 - 2044 | | |
Solar Power Partners (SPP) Projects | | 100 | % | | 25 | | | Various | | 2026 - 2037 | | |
Other DG Projects | | 100 | % | | 21 | | | Various | | 2023 - 2039 | | |
Total Distributed Solar (d) | | | | 332 | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Projects | | Percentage Ownership | | Net Capacity (MW) (a) | | Counterparty | | Expiration | | |
Wind | | | | | | | | | | |
Alta I | | 100 | % | | 150 | | | SCE | | 2035 | | |
Alta II | | 100 | % | | 150 | | | SCE | | 2035 | | |
Alta III | | 100 | % | | 150 | | | SCE | | 2035 | | |
Alta IV | | 100 | % | | 102 | | | SCE | | 2035 | | |
Alta V | | 100 | % | | 168 | | | SCE | | 2035 | | |
Alta X (b) | | 100 | % | | 137 | | | SCE | | 2038 | | |
Alta XI (b) | | 100 | % | | 90 | | | SCE | | 2038 | | |
Black Rock (b) | | 50 | % | | 58 | | | Toyota and AEP | | 2036 | | |
Buffalo Bear | | 100 | % | | 19 | | | Western Farmers Electric Co-operative | | 2033 | | |
Capistrano Wind Portfolio | | 100 | % | | 413 | | | Various | | 2030 - 2033 | | |
Elbow Creek (b) | | 100 | % | | 122 | | | Various | | 2029 | | |
Elkhorn Ridge | | 66.7 | % | | 54 | | | Nebraska Public Power District | | 2029 | | |
Forward | | 100 | % | | 29 | | | Constellation NewEnergy, Inc. | | 2025 | | |
Goat Wind | | 100 | % | | 150 | | | Dow Pipeline Company | | 2025 | | |
Langford (b) | | 100 | % | | 160 | | | Goldman Sachs | | 2033 | | |
Laredo Ridge | | 100 | % | | 81 | | | Nebraska Public Power District | | 2031 | | |
Lookout | | 100 | % | | 38 | | | Southern Maryland Electric Cooperative | | 2030 | | |
Mesquite Sky (b) | | 50 | % | | 170 | | | Various | | 2033 - 2036 | | |
Mesquite Star (b) | | 50 | % | | 210 | | | Various | | 2032 - 2035 | | |
Mt. Storm | | 100 | % | | 264 | | | Citigroup | | 2031 | | |
Ocotillo | | 100 | % | | 55 | | | N/A | | | | |
Odin | | 99.9 | % | | 21 | | | Missouri River Energy Services | | 2028 | | |
Pinnacle (b) | | 100 | % | | 54 | | | Maryland Department of General Services and University System of Maryland | | 2031 | | |
Rattlesnake (b) (e) | | 100 | % | | 160 | | | Avista Corporation | | 2040 | | |
San Juan Mesa | | 75 | % | | 90 | | | Southwestern Public Service Company | | 2025 | | |
Sleeping Bear | | 100 | % | | 95 | | | Public Service Company of Oklahoma | | 2032 | | |
South Trent | | 100 | % | | 101 | | | AEP Energy Partners | | 2029 | | |
Spanish Fork | | 100 | % | | 19 | | | PacifiCorp | | 2028 | | |
Spring Canyon II (b) | | 90.1 | % | | 31 | | | Platte River Power Authority | | 2039 | | |
Spring Canyon III (b) | | 90.1 | % | | 26 | | | Platte River Power Authority | | 2039 | | |
Taloga | | 100 | % | | 130 | | | Oklahoma Gas & Electric | | 2031 | | |
Wildorado (b) | | 100 | % | | 161 | | | Southwestern Public Service Company | | 2027 | | |
Total Wind (d) | | | | 3,658 | | | | | | | |
Total net generation capacity | | | | 8,114 | | | | | | | |
(a) Net capacity represents the maximum, or rated, generating capacity of 1,319 net MWtthe facility multiplied by the Company’s percentage ownership in the facility as of June 30, 2023.
(b) Projects are part of tax equity arrangements and electric generationownership percentage is based on cash to be distributed, as further described in Note 4, Investments Accounted for by the Equity Method and Variable Interest Entities.
(c)Includes storage capacity that matches the facility’s rated generating capacity.
(d)Typical average capacity factors are 25% for solar facilities and 25-45% for wind facilities. For the six months ended June 30, 2023, the Company's solar and wind facilities had weighted-average capacity factors of 27% and 31%, respectively. For the six months ended June 30, 2022, the Company’s solar and wind facilities had weighted-average capacity factors of 30% and 35%, respectively. The weight-average capacity factors can vary based on seasonality and weather conditions.
(e)Rattlesnake has a deliverable capacity of 123 net144 MW. These thermal infrastructure assets provide steam, hot water and/or chilled water, and in some instances electricity, to commercial businesses, universities, hospitals and governmental units in multiple locations, principally through long-term contracts or pursuant to rates regulated by state utility commissions.
Significant Events
Drop Down Transactions
•On July 12, 2017, NRG announced that it had adopted and initiated a three-year, three-part improvement plan, or the NRG Transformation Plan. As part of the NRG Transformation Plan, NRG announced that it is exploring strategic alternatives for its renewables platform and its interest in the Company. NRG, through its holdings of Class B common stock and Class D common stock, has a 55.1% voting interest in Yield, Inc. and receives distributions fromJune 30, 2023, the Company, through its ownership ofindirect subsidiary, Rosie Class B unitsLLC, the indirect owner of the Rosamond Central solar project, became the owner of the Class B membership interests of Rosie Central BESS in order to facilitate and fund the construction of a 147 MW BESS project that will be co-located at the Rosamond Central solar facility. Clearway Renew indirectly owns the Class D units. NRG stated that the strategic alternatives span a varietyA membership interests. The Company’s investment consists of ownership structures and partnership types, including the potential partial or full monetization of NRG's renewables platform and NRG's interest in the Company. NRG is Yield, Inc.'s controlling stockholder and$10 million contributed into Rosie Central BESS, funded through contributions from the Company has been highly dependentand its cash equity investor in Rosie TargetCo LLC, which consolidates Rosie Class B LLC. On July 3, 2023, Rosie Class B LLC contributed an additional $20 million into Rosie Central BESS. Additionally, on NRG for, among other things, growth opportunities and management and administration services. See Part I, Item 1A, Risk Factors in the Company's 2016 Form 10-K as well as Part II, Item 1A, Risk Factors in the Company's Form 10-Q for the quarter ended June 30, 2017,2023, Rosamond Central entered into an asset purchase agreement with Rosie Central BESS to acquire the BESS project assets at mechanical completion for risks related toa purchase price of $360 million, of which $72 million is payable at mechanical completion with the NRG Transformation Plan and the Company's relationship with NRG.
Regulatory Matters
remaining $288 million payable at substantial completion. The Company’s regulatory matters are described in the Company’s 2016 Form 10-K in Item 1, Business — Regulatory Matters and Item 1A, Risk Factors.
As owners of power plants and participants in wholesale and thermal energy markets, certainCompany will fund $17 million of the Company's subsidiaries arepurchase price at mechanical completion and $67 million of the purchase price at substantial completion. See Note 4, Investments Accounted for by the Equity Method and Variable Interest Entities, for further discussion of the transactions.
•On May 19, 2023, the Company, through an indirect subsidiary, entered into an agreement with Clearway Renew to acquire Cedar Creek Holdco LLC, which is the indirect owner of the Cedar Creek wind project, a 160 MW project located in Bingham County, Idaho, for $107 million in cash, subject to regulation by various federal and state government agencies. These include FERC andcustomary working capital adjustments. Upon the PUCT, as well as other public utility commissions in certain states where the Company's assets are located. Eachclosing of the Company's U.S. generating facilities qualifies astransaction, the Company will indirectly own all of the Class B membership interests in Cedar Creek TE Holdco LLC, a EWG or QF. In addition,tax equity fund which will consolidate the CompanyCedar Creek wind project, while a tax equity investor will own all of the Class A membership interests. The consummation of the transaction is subject to customary closing conditions and certain third-party approvals and is expected in the market rules, proceduresfirst half of 2024.
•On May 3, 2023, the Company entered into an agreement with Clearway Renew to repower the Cedro Hill wind project, which is included in the Capistrano Wind Portfolio and protocolsis located in Bruni, Texas. The Company expects to invest approximately $63 million in net corporate capital, subject to closing adjustments. Contingent upon achieving repowering commercial operations in the second half of 2024, the 160 MW project will sell power to its existing counterparty, an investment-grade utility, for an additional 15 years ending in 2045 under an amended PPA.
•On February 17, 2023, the Company, through its indirect subsidiary, Daggett Solar Investment LLC, acquired the Class A membership interests in Daggett TargetCo LLC, the indirect owner of the various ISODaggett 3 solar project, a 300 MW solar project with matching storage capacity that is currently under construction, located in San Bernardino, California from Clearway Renew for cash consideration of $21 million. Simultaneously, a cash equity investor acquired the Class B membership interests in Daggett TargetCo LLC from Clearway Renew for cash consideration of $129 million. The Company and RTO markets in which it participates. Likewise,the cash equity investor then contributed their Class A and B membership interests, respectively, into Daggett Renewable Holdco LLC, a partnership between the Company must also complyand the cash equity investor, which consolidates Daggett TargetCo LLC. Daggett TargetCo LLC consolidates, as the indirect owner of the primary beneficiary, a tax equity fund, Daggett TE Holdco LLC, which owns the Daggett 3 solar project. See Note 3, Acquisitions and Dispositions, for further discussion of the transaction.
Corporate Financing Activities
•On March 15, 2023, Clearway Energy Operating LLC refinanced the Amended and Restated Credit Agreement. See Note 7, Long-term Debt, for further discussion of the amendment.
Project-level Financing Activities
•In connection with the mandatory reliability requirements imposed by NERC2022 Drop Down of Waiawa and the regional reliability entities2023 Drop Down of Daggett 3, the Company assumed non-recourse project-level debt. See Note 7, Long-term Debt, for further discussion of the non-recourse project-level debt associated with each project.
•On June 30, 2023, Rosie Class B LLC amended its financing agreement. On July 3, 2023, the Company received total loan proceeds of $138 million under the refinancing. Also on July 3, 2023, Rosie Class B LLC issued a loan to a consolidated subsidiary of Clearway Renew in the regions whereaggregate principal amount of $117 million in order to finance the Company operates.construction of the BESS project. See Note 7, Long-term Debt, for further discussion of the project financing activities.
The Company'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.
Environmental Matters
The Company’s environmental matters are described in the Company’s 2016 Form 10-K in Item 1, Business — Environmental Matters and Item 1A, Risk Factors.
The Company is subject to a wide range of environmental laws induring the development, construction, ownership and operation of projects.facilities. These existing and future laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of facilities. The Company is also subjectobligated to comply with all environmental laws regardingand regulations applicable within each jurisdiction and required to implement environmental programs and procedures to monitor and control risks associated with the protectionconstruction, operation and decommissioning of wildlife, including migratory birds, eagles, threatened and endangered species.regulated or permitted energy assets. Federal and state environmental laws have historically become more stringent over time, although this trend could slow or pausechange in the near term with respect to federal laws under the current U.S. presidential administration.future.
Trends Affecting Results of Operations and Future Business Performance
The Company’s trendsenvironmental matters are further described in the Company’s 2022 Form 10-K in Item 1, Business — Environmental Matters and Item 1A, Risk Factors.
Regulatory Matters
The Company’s regulatory matters are described in the Company’s May 9, 20172022 Form 8-K10-K in Item 7, Management’s Discussion1, Business — Regulatory Matters and Analysis of Financial Condition and Results of Operations - Trends Affecting Results of Operations and Future Business Performance.Item 1A, Risk Factors.
Operational Matters
El Segundo Forced Outage
In January 2017, the El Segundo Energy Center began a forced outage on Units 5 and 6 due to increasing vibrations on successive operations at Unit 5. In consultation with the Company’s operations and maintenance service provider, a subsidiary of NRG, the Company elected to replace the rotor on Unit 5. Both Unit 5 and 6 returned to service on February 24, 2017. In July 2017, the Company executed a warranty settlement agreement with the original equipment manufacturer that reduced total cost from $12 million to approximately $5 million.
Walnut Creek Forced Outage
During the first half of 2017, Walnut Creek experienced forced outages due to mechanical failures of turbine parts that caused downstream damage to several of the plant's Units, primarily Unit 1. The repairs necessary to return Unit 1 to service were completed in the second quarter of 2017 and the plant has performed reliably since then. The estimated cost of this outage is approximately $8 million before the recovery of insurance proceeds, a significant portion of which the Company believes is recoverable by year end. In the third quarter of 2017, the Company, through Walnut Creek, executed an amendment to the contractual service agreement with the original equipment manufacturer to improve long term reliability. The amendment provides for the original equipment manufacturer to perform all required, currently available and future turbine reliability upgrades in exchange for an investment of approximately $15 million that will be paid over the next five years.
ROFO Asset Update
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting NRG’s Puente Power Project, a ROFO Asset, 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 hearing on the motion was held on October 31, 2017, after which the CEC took the matter under submission subject to a written decision to be issued at 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.
Consolidated Results of Operations
The following table provides selected financial information: | | | Three months ended September 30, | | Nine months ended September 30, | | Three months ended June 30, | | Six months ended June 30, |
(In millions) | 2017 | | 2016 | | Change | | 2017 | | 2016 | | Change | (In millions) | 2023 | | 2022 | | Change | | 2023 | | 2022 | | Change |
Operating Revenues | | | | | | | | | | | | Operating Revenues | | | | | | | | | | | |
Energy and capacity revenues | $ | 283 |
| | $ | 289 |
| | $ | (6 | ) | | $ | 819 |
| | $ | 840 |
| | $ | (21 | ) | Energy and capacity revenues | $ | 379 | | | $ | 431 | | | $ | (52) | | | $ | 683 | | | $ | 791 | | | $ | (108) | |
Other revenue | | Other revenue | 48 | | | 30 | | | 18 | | | 60 | | | 52 | | | 8 | |
Contract amortization | (18 | ) | | (17 | ) | | (1 | ) | | (52 | ) | | (51 | ) | | (1 | ) | Contract amortization | (47) | | | (41) | | | (6) | | | (94) | | | (83) | | | (11) | |
Mark-to-market for economic hedges | | Mark-to-market for economic hedges | 26 | | | (52) | | | 78 | | | 45 | | | (178) | | | 223 | |
Total operating revenues | 265 |
| | 272 |
| | (7 | ) | | 767 |
| | 789 |
| | (22 | ) | Total operating revenues | 406 | | | 368 | | | 38 | | | 694 | | | 582 | | | 112 | |
Operating Costs and Expenses | | | | | | | | | | | | Operating Costs and Expenses | | | | | | | | | | | |
Cost of fuels | 15 |
| | 18 |
| | (3 | ) | | 45 |
| | 48 |
| | (3 | ) | Cost of fuels | 16 | | | 7 | | | 9 | | | 16 | | | 29 | | | (13) | |
Emissions credit amortization | — |
| | — |
| | — |
| | — |
| | 6 |
| | (6 | ) | |
| Operations and maintenance | 46 |
| | 41 |
| | 5 |
| | 143 |
| | 134 |
| | 9 |
| Operations and maintenance | 76 | | | 76 | | | — | | | 159 | | | 152 | | | 7 | |
Other costs of operations | 17 |
| | 17 |
| | — |
| | 51 |
| | 50 |
| | 1 |
| Other costs of operations | 26 | | | 29 | | | (3) | | | 51 | | | 59 | | | (8) | |
Depreciation and amortization | 88 |
| | 75 |
| | 13 |
| | 241 |
| | 224 |
| | 17 |
| |
Depreciation, amortization and accretion | | Depreciation, amortization and accretion | 128 | | | 126 | | | 2 | | | 256 | | | 250 | | | 6 | |
| General and administrative | 4 |
| | 3 |
| | 1 |
| | 14 |
| | 8 |
| | 6 |
| General and administrative | 9 | | | 9 | | | — | | | 19 | | | 21 | | | (2) | |
Acquisition-related transaction and integration costs | — |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
| |
Transaction and integration costs | | Transaction and integration costs | 2 | | | 3 | | | (1) | | | 2 | | | 5 | | | (3) | |
Development costs | | Development costs | — | | | 1 | | | (1) | | | — | | | 2 | | | (2) | |
Total operating costs and expenses | 170 |
| | 154 |
| | 16 |
| | 496 |
| | 470 |
| | 26 |
| Total operating costs and expenses | 257 | | | 251 | | | 6 | | | 503 | | | 518 | | | (15) | |
Gain on sale of business | | Gain on sale of business | — | | | 1,291 | | | (1,291) | | | — | | | 1,291 | | | (1,291) | |
Operating Income | 95 |
| | 118 |
| | (23 | ) | | 271 |
| | 319 |
| | (48 | ) | Operating Income | 149 | | | 1,408 | | | (1,259) | | | 191 | | | 1,355 | | | (1,164) | |
Other Income (Expense) | | | | |
| | | | | |
| Other Income (Expense) | | | | | | | | | | | |
Equity in earnings of unconsolidated affiliates | 28 |
| | 16 |
| | 12 |
| | 63 |
| | 34 |
| | 29 |
| Equity in earnings of unconsolidated affiliates | 3 | | | 10 | | | (7) | | | — | | | 14 | | | (14) | |
| Other income, net | 1 |
| | 1 |
| | — |
| | 3 |
| | 3 |
| | — |
| Other income, net | 9 | | | 5 | | | 4 | | | 17 | | | 5 | | | 12 | |
Interest expense | (72 | ) | | (68 | ) | | (4 | ) | | (227 | ) | | (204 | ) | | (23 | ) | |
Loss on debt extinguishment | | Loss on debt extinguishment | — | | | — | | | — | | | — | | | (2) | | | 2 | |
Derivative interest income | | Derivative interest income | 22 | | | 36 | | | (14) | | | 1 | | | 77 | | | (76) | |
Other interest expense | | Other interest expense | (77) | | | (83) | | | 6 | | | (155) | | | (171) | | | 16 | |
Total other expense, net | (43 | ) | | (51 | ) | | 8 |
| | (161 | ) | | (167 | ) | | 6 |
| Total other expense, net | (43) | | | (32) | | | (11) | | | (137) | | | (77) | | | (60) | |
Net Income | 52 |
| | 67 |
| | (15 | ) | | 110 |
| | 152 |
| | (42 | ) | Net Income | 106 | | | 1,376 | | | (1,270) | | | 54 | | | 1,278 | | | (1,224) | |
Less: Net loss attributable to noncontrolling interests | (23 | ) | | (38 | ) | | 15 |
| | (56 | ) | | (67 | ) | | 11 |
| |
Net Income Attributable to NRG Yield LLC | $ | 75 |
| | $ | 105 |
| | $ | (30 | ) | | $ | 166 |
| | $ | 219 |
| | $ | (53 | ) | |
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests | | Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests | — | | | (6) | | | 6 | | | (30) | | | (46) | | | 16 | |
Net Income Attributable to Clearway Energy LLC | | Net Income Attributable to Clearway Energy LLC | $ | 106 | | | $ | 1,382 | | | $ | (1,276) | | | $ | 84 | | | $ | 1,324 | | | $ | (1,240) | |
|
| | | | | | | | | | | |
| Three months ended September 30, | | Nine months ended September 30, |
Business metrics: | 2017 | | 2016 | | 2017 | | 2016 |
Renewables MWh generated/sold (in thousands) (a) | 1,544 |
| | 1,744 |
| | 5,295 |
| | 5,563 |
|
Conventional MWh generated (in thousands) (a)(b) | 717 |
| | 628 |
| | 1,172 |
| | 1,265 |
|
Thermal MWt sold (in thousands) | 463 |
| | 496 |
| | 1,450 |
| | 1,497 |
|
Thermal MWh sold (in thousands) (c) | 9 |
| | 12 |
| | 27 |
| | 61 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended June 30, | | Six months ended June 30, |
Business metrics: | 2023 | | 2022 | | 2023 | | 2022 |
Solar MWh generated/sold (in thousands) (a) | 1,544 | | | 1,538 | | | 2,410 | | | 2,598 | |
Wind MWh generated/sold (in thousands) (a) | 2,433 | | | 2,878 | | | 5,177 | | | 5,137 | |
Renewables MWh generated/sold (in thousands) (a) | 3,977 | | | 4,416 | | | 7,587 | | | 7,735 | |
Thermal MWt sold (in thousands) (b) | — | | | 183 | | | — | | | 835 | |
Thermal MWh sold (in thousands) (b) | — | | | 5 | | | — | | | 19 | |
Conventional MWh generated (in thousands) (a) (c) | 139 | | | 289 | | | 227 | | | 421 | |
Conventional equivalent availability factor | 90.1 | % | | 88.3 | % | | 82.3 | % | | 91.8 | % |
(a)Volumes do not include the MWh generated/sold by the Company'sCompany’s equity method investments.
(b) On May 1, 2022, the Company completed the sale of 100% of its interests in the Thermal Business to KKR.
(c) Volumes generated arein 2022 were not sold as the Conventional facilities sellsold only capacity rather than energy.energy prior to 2023.
(c)MWh sold do not include 34 MWh and 110 MWh during the three months ended September 30, 2017 and 2016, respectively, and 52 MWh and 184 MWh during the nine months ended September 30, 2017 and 2016, respectively, generated by NRG Dover, a subsidiary of the Company, under the PPA with NRG Power Marketing, as further described in Note 9, Related Party Transactions.
Management’s Discussion of the Results of Operations for the Three Months Ended SeptemberJune 30, 20172023 and 20162022
Gross MarginOperating Revenues
The Company calculates gross margin in order to evaluate operating performance as operatingOperating revenues less cost of sales, which includes cost of fuel, 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' 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 reviewedincreased by the Company's chief operating decision maker. Economic gross margin is defined as energy and capacity revenue less cost of fuels. Economic gross margin excludes the following components from GAAP gross margin: contract amortization, mark-to-market results, emissions credit amortization and (losses) gains on economic hedging activities. Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled.
The below tables present the composition of gross margin, as well as the reconciliation to economic gross margin, for the three months ended September 30, 2017 and 2016:
|
| | | | | | | | | | | | | | | |
| Conventional Generation | | Renewables | | Thermal | | Total |
(In millions) | |
Three months ended September 30, 2017 | | | | | | | |
Energy and capacity revenues | $ | 89 |
| | $ | 147 |
| | $ | 47 |
| | $ | 283 |
|
Cost of fuels | — |
| | — |
| | (15 | ) | | (15 | ) |
Contract amortization | (1 | ) | | (16 | ) | | (1 | ) | | (18 | ) |
Gross margin | 88 |
| | 131 |
| | 31 |
| | 250 |
|
Contract amortization | 1 |
| | 16 |
| | 1 |
| | 18 |
|
Economic gross margin | $ | 89 |
| | $ | 147 |
| | $ | 32 |
| | $ | 268 |
|
| | | | | | | |
Three months ended September 30, 2016 | | | | | | | |
Energy and capacity revenues | $ | 83 |
| | $ | 158 |
| | $ | 48 |
| | $ | 289 |
|
Cost of fuels | — |
| | (1 | ) | | (17 | ) | | (18 | ) |
Contract amortization | (1 | ) | | (16 | ) | | — |
| | (17 | ) |
Gross margin | 82 |
| | 141 |
| | 31 |
| | 254 |
|
Contract amortization | 1 |
| | 16 |
| | — |
| | 17 |
|
Economic gross margin | $ | 83 |
| | $ | 157 |
| | $ | 31 |
| | $ | 271 |
|
Gross margin decreased by $4$38 million during the three months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016,2022, due to a combination of the following:drivers summarized in the table below:
| | | | | | | | | |
| | (In millions) | |
Renewables Segment | Decrease driven primarily by lower than average wind production in 2023, compared with higher than average wind production in 2022. | $ | (46) | | |
| Increase driven primarily by the acquisition of the Capistrano Wind Portfolio in August 2022. | 16 | | |
| Increase for solar acquisitions driven by Mililani I and Waiawa, which reached commercial operations in July 2022 and January 2023, respectively, offset by the disposition of Kawailoa in August 2022. | 2 | | |
Conventional Segment | Increase driven by the sales-type lease revenue recognition of the Marsh Landing Black Start addition that commenced operations on May 31, 2023. | 21 | | |
| Increase at El Segundo facility primarily driven by higher availability due to the timing of the 2023 annual planned maintenance outages. | 6 | | |
| Decrease at Walnut Creek and Marsh Landing facilities primarily driven by lower prices for capacity revenue due to the expiring PPAs during the second quarter of 2023 and commencement of RA capacity revenue. | (15) | | |
| | | |
| | | |
Thermal Segment | Decrease in revenue due to the sale of the Thermal business on May 1, 2022. | (18) | | |
Mark-to-market for economic hedges | Increase primarily driven by decreases in forward power prices in the ERCOT and PJM markets. | 78 | | |
Contract amortization | Increase primarily driven by amortization of the intangible assets of PPAs related to the acquisition of the Capistrano Wind Portfolio in August 2022. | (6) | | |
| | $ | 38 | | |
| | | |
|
| | | |
| (In millions) |
|
Decrease in the Renewables segment due to a 12% decrease in volume generated by wind projects, primarily at NRG Wind TE Holdco, Alta Wind and Tapestry, as well as a 6% decrease in solar generation, primarily at CVSR in connection with lower insolation | $ | (10 | ) |
Increase in the Conventional segment due to fewer outages at Walnut Creek in 2017, as well as increased start revenues at El Segundo and Marsh Landing | 6 |
|
Decrease in gross margin
| $ | (4 | ) |
Cost of Fuels
Operations and Maintenance
Operations and maintenance expenseCost of fuels increased by $5$9 million during the three months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016,2022, due to a $15 million increase for the Conventional segment primarily due to the forced outagesassociated costs of the sales-type lease recognition of the Marsh Landing Black Start addition that took place at Walnut Creekcommenced operations on May 31, 2023, as further described in Note 2, Summary of Significant Accounting Policies, offset by a $6 million decrease driven by the sale of the Thermal Business on May 1, 2022.
Gain on Sale of Business
On May 1, 2022, the Company completed the sale of 100% of its interests in the first halfThermal Business to KKR, resulting in a gain on sale of 2017.
Depreciation and Amortization Expense
Depreciation and amortization expense increased by $13 million during the three months ended September 30, 2017, compared to the same period in 2016, primarily due to change in estimated useful lives for certain componentsbusiness of fixed assets in the Renewables and Conventional segments in the first half of 2017.approximately $1.29 billion.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates increaseddecreased by $12$7 million during the three months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016,2022, primarily due to an increasethe change in earnings from the Utah Solar Portfolio, which was acquired by NRG in November 2016,fair value of interest rate swaps, as well as an increase in earnings from Desert Sunlight, partially offset by a decrease in earnings from Avenallower wind production.
Interest Expense
Interest expense increased by $4$8 million during the three months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016,2022, primarily due to:to the following:
| | | | | |
| (In millions) |
Change in fair value of interest rate swaps | $ | 14 | |
Decrease in interest expense due to decreased principal balances of project-level debt | (4) | |
Decrease in interest expense due to the sale of the Thermal Business on May 1, 2022 | (1) | |
Decrease in interest expense due to decreased principal balances of Corporate debt, which includes repayment of the outstanding borrowings under the Bridge Loan Agreement and the revolving credit facility on May 3, 2022 | (1) | |
| $ | 8 | |
|
| | | |
| (In millions) |
|
Issuance of the new long-term debt, primarily including 2026 Senior Notes in August 2016, Energy Center Minneapolis Series D Notes due 2031 issued in October 2016, and Agua Caliente Borrower 2 due 2038 issued in February 2017 | $ | 6 |
|
Utah Solar Portfolio debt assumed in connection with the acquisition of the March 2017 Drop Down Assets | 4 |
|
Lower principal balances on certain project level debt in 2017, as well as higher revolver borrowings in 2016 | (4 | ) |
Amortization of de-designated interest rate swaps, partially offset by the change in fair value of interest rate swaps | (2 | ) |
Increase in interest expense | $ | 4 |
|
IncomeNet Loss Attributable to Noncontrolling Interests and Redeemable Noncontrolling Interests
For the three months ended SeptemberJune 30, 2017,2023, net (loss) income attributable to noncontrolling interests and redeemable noncontrolling interests was comprised of the following:
| | | | | |
| (In millions) |
Losses attributable to tax equity financing arrangements and the application of the HLBV method | $ | (11) | |
Income attributable to third-party partnerships | 11 | |
| |
| |
| $ | — | |
For the three months ended June 30, 2022, the Company had a net loss of $23$6 million attributable to noncontrolling interests and redeemable noncontrolling interests with respect to its tax equity financing arrangements and the application of the HLBV method. For the three months ended September 30, 2016, the Company had a loss of $38 million attributable to noncontrolling interests with respect to its tax equity financing arrangements and the application of the HLBV method, which generally allocates more loss to the noncontrolling interest in the first several years after fund formation, reflecting the allocation of tax items such as production tax credits and tax depreciation to the fund investors.
Management’s Discussion of the Results of Operations for the NineSix Months Ended SeptemberJune 30, 20172023 and 20162022
Gross MarginOperating Revenues
The Company calculates gross margin in order to evaluate operating performance as operatingOperating revenues less cost of sales, which includes cost of fuel, contract and emission credit amortization and mark-to-market for economic hedging activities.
Economic Gross Margin
In addition to gross margin,increased by $112 million during 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' 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 energy and capacity revenue less cost of fuels. Economic gross margin excludes the following components from GAAP gross margin: contract amortization, mark-to-market results, emissions credit amortization and (losses) gains on economic hedging activities. Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled.
The below tables present the composition of gross margin, as well as the reconciliation to economic gross margin, for the ninesix months ended SeptemberJune 30, 2017 and 2016:2023, compared to the same period in 2022, due to a combination of the drivers summarized in the table below:
| | | | | | | | |
| | (In millions) |
Renewables Segment | Decrease driven primarily by lower than average wind production during the second quarter of 2023, compared with higher than average wind production during the second quarter of 2022. | $ | (47) | |
| Decrease driven primarily by lower solar generation due to weather. | (14) | |
| Increase driven primarily by the acquisition of the Capistrano Wind Portfolio in August 2022. | 36 | |
| Increase for solar acquisitions driven by Mililani I and Waiawa, which reached commercial operations in July 2022 and January 2023, respectively, offset by the disposition of Kawailoa in August 2022. | 3 | |
Conventional Segment | Decrease at Walnut Creek and Marsh Landing facilities primarily driven by lower prices for capacity revenue due to the expiring PPAs during the second quarter of 2023 and commencement of RA capacity revenue. | (15) | |
| Decrease driven by outages at the Walnut Creek and Marsh Landing facilities during the first quarter of 2023, resulting in lower capacity revenue. | (5) | |
| Decrease primarily driven by longer planned maintenance outages at the El Segundo facility in 2023. | (2) | |
| Increase driven by the sales-type lease revenue recognition of the Marsh Landing Black Start addition that commenced operations on May 31, 2023. | 21 | |
Thermal Segment | Decrease primarily driven by the sale of the Thermal Business on May 1, 2022. | (77) | |
Mark-to-market economic hedging activities | Increase primarily driven by decreases in forward power prices in the ERCOT and PJM markets. | 223 | |
| | |
Contract amortization | Increase primarily driven by amortization of the intangible assets of PPAs related to the acquisition of the Capistrano Wind Portfolio in August 2022. | (11) | |
| | $ | 112 | |
|
| | | | | | | | | | | | | | | |
| Conventional Generation | | Renewables | | Thermal | | Total |
(In millions) | |
Nine months ended September 30, 2017 | | | | | | | |
Energy and capacity revenues | $ | 250 |
| | $ | 437 |
| | $ | 132 |
| | $ | 819 |
|
Cost of fuels | — |
| | — |
| | (45 | ) | | (45 | ) |
Contract amortization | (4 | ) | | (46 | ) | | (2 | ) | | (52 | ) |
Gross margin | 246 |
| | 391 |
| | 85 |
| | 722 |
|
Contract amortization | 4 |
| | 46 |
| | 2 |
| | 52 |
|
Economic gross margin | $ | 250 |
| | $ | 437 |
| | $ | 87 |
| | $ | 774 |
|
| | | | | | | |
Nine months ended September 30, 2016 | | | | | | | |
Energy and capacity revenues | $ | 250 |
| | $ | 458 |
| | $ | 132 |
| | $ | 840 |
|
Cost of fuels | (1 | ) | | (1 | ) | | (46 | ) | | (48 | ) |
Contract amortization | (4 | ) | | (46 | ) | | (1 | ) | | (51 | ) |
Emissions credit amortization | (6 | ) | | — |
| | — |
| | (6 | ) |
Gross margin | 239 |
| | 411 |
| | 85 |
| | 735 |
|
Contract amortization | 4 |
| | 46 |
| | 1 |
| | 51 |
|
Emissions credit amortization | 6 |
| | — |
| | — |
| | 6 |
|
Economic gross margin | $ | 249 |
| | $ | 457 |
| | $ | 86 |
| | $ | 792 |
|
Cost of FuelsGross margin
Cost of fuels decreased by $13 million during the ninesix months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016,2022, due to a combinationthe sale of the following:Thermal Business on May 1, 2022, which resulted in a decrease of $28 million, offset by a $15 million increase for the Conventional segment primarily due to the associated costs of the sales-type lease recognition of the Marsh Landing Black Start addition that commenced operations on May 31, 2023, as further described in Note 2, Summary of Significant Accounting Policies.
|
| | | |
| (In millions) |
|
Decrease in the Renewables segment due to a 4% decrease in volume generated by wind projects, primarily in connection with lower wind resource at the Alta Wind, and NRG Wind TE Holdco projects, as well as a 5% decrease in solar generation, primarily at CVSR in connection with lower insolation | $ | (20 | ) |
Increase in the Conventional segment, primarily due to Emissions credit amortization of NOx allowances at Walnut Creek and El Segundo in compliance with amendments to the Regional Clean Air Incentives Market program in 2016 | 7 |
|
Decrease in gross margin | $ | (13 | ) |
Operations and Maintenance Expense
Operations and maintenance expense increased by $9$7 million during the ninesix months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016, primarily2022, due to forced outages at Walnut Creek and El Segundoa combination of the drivers summarized in 2017.the table below:
Depreciation and Amortization | | | | | | | | |
| | (In millions) |
Renewables Segment | Increase primarily driven by the acquisition of the Capistrano Wind Portfolio in August 2022. | $ | 11 | |
| Increase primarily driven by maintenance activities at the wind facilities. | 6 | |
| Increase for solar acquisitions driven by Daggett 3 in February 2023, Mililani I in March 2022 and Waiawa in November 2022, offset by the disposition of Kawailoa in August 2022. | 2 |
Conventional Segment | Increase primarily driven by outages at the Walnut Creek and Marsh Landing facilities. | 4 | |
| Increase primarily driven by higher costs related to additional planned maintenance outages at the El Segundo facility in 2023. | 2 | |
Thermal Segment | Decrease primarily driven by the sale of the Thermal Business on May 1, 2022. | (18) | |
| | |
| | |
| | |
| | $ | 7 | |
Other Costs of Operations Expense
Depreciation and amortizationOther costs of operations expense increaseddecreased by $17$8 million during the ninesix months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016,2022, primarily due to the combinationsale of the following:Thermal Business on May 1, 2022 and a decrease in property taxes in both the Conventional and the Renewables segments.
|
| | | |
| (In millions) |
|
Increase in depreciation expense due to an update in estimated useful lives for certain components of fixed assets in the first half of 2017 in the Conventional and Renewables segments | $ | 23 |
|
Decrease in depreciation expense at NRG Wind TE Holdco, primarily due to the effect of assets impairment at Elbow Creek, Goat and Forward that took place in December 2016, as further described in Note 9 - Asset Impairments to the Company's 2016 Form 10-K. | (6 | ) |
Increase in depreciation and amortization expense | $ | 17 |
|
On May 1, 2022, the Company completed the sale of 100% of its interests in the Thermal Business to KKR, resulting in a gain on sale of business of approximately $1.29 billion.Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates increaseddecreased by $29$14 million during the ninesix months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016,2022, primarily due to the acquisitionchange in fair value of the Utah Solar Portfolio in November 2016, partially offset by a decrease in earnings from the Company's partnerships with NRG. interest swaps and higher depreciation expense, as well as lower wind production.
Interest Expense Other Income, Net
Interest expenseOther income, net increased by $23$12 million during the ninesix months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016,2022, primarily due to:to higher interest income earned on investments in money market and time deposit accounts, which have retained larger balances as a result of the proceeds received from the sale of the Thermal Business on May 1, 2022.
Interest Expense
Interest expense increased by $60 million during the six months ended June 30, 2023, compared to the same period in 2022, primarily due to the following:
| | | | | |
| (In millions) |
Change in fair value of interest rate swaps | $ | 76 | |
Decrease in interest expense due to decreased principal balances of project-level debt | (7) | |
Decrease in interest expense due to the sale of the Thermal Business on May 1, 2022 | (6) | |
Decrease in interest expense due to decreased principal balances of Corporate debt, which includes repayment of the outstanding borrowings under the Bridge Loan Agreement and the revolving credit facility on May 3, 2022 | (3) | |
| $ | 60 | |
|
| | | |
| (In millions) |
|
Issuance of the new long-term debt in the second half of 2016, including primarily 2026 Senior Notes, CVSR Holdco Notes due 2037, and Energy Center Minneapolis Series D Notes due 2031 | $ | 20 |
|
Utah Solar Portfolio debt assumed in connection with the acquisition of the March 2017 Drop Down Assets | 12 |
|
Amortization of de-designated interest rate swaps, as well as the change in fair value of interest rate swaps | 2 |
|
Higher revolver borrowings in 2016 combined with the lower principal balances on project level debt in 2017 | (11 | ) |
Increase in interest expense | $ | 23 |
|
IncomeNet Loss Attributable to Noncontrolling Interests and Redeemable Noncontrolling Interests
For the ninesix months ended SeptemberJune 30, 2017,2023, the Company had a net loss of $56$30 million attributable to noncontrolling interests with respect to its tax equity financing arrangements and the applicationredeemable noncontrolling interests comprised of the HLBV method. following:
| | | | | |
| (In millions) |
Losses attributable to tax equity financing arrangements and the application of the HLBV method | $ | (44) | |
Income attributable to third-party partnerships | 14 | |
| |
| |
| $ | (30) | |
For the ninesix months ended SeptemberJune 30, 2016,2022, the Company had a net loss of $67$46 million attributable to noncontrolling interests with respect to its tax equity financing arrangements and applicationredeemable noncontrolling interests comprised of the HLBV method, which generally allocates more loss to the noncontrolling interest in the first several years after fund formation, reflecting the allocation of tax items such as production tax credits and tax depreciation to the fund investors.
following:
| | | | | |
| (In millions) |
Losses attributable to tax equity financing arrangements and the application of the HLBV method | $ | (24) | |
Losses attributable to third-party partnerships | (22) | |
| |
| |
| $ | (46) | |
Liquidity and Capital Resources
The Company'sCompany’s principal liquidity requirements are to meet its financial commitments, finance current operations, fund capital expenditures, including acquisitions from time to time, service debt and pay distributions. As a normal part of the Company'sCompany’s business, depending on market conditions, the Company will from time to time consider opportunities to repay, redeem, repurchase or refinance its indebtedness. Changes in the Company'sCompany’s operating plans, lower than anticipated sales, increased expenses, acquisitions or other events may cause the Company to seek additional debt or equity financing in future periods. There can be no guarantee that financing will be available on acceptable terms or at all. Debt financing, if available, could impose additional cash payment obligations and additional covenants and operating restrictions.
Current Liquidity Position
As of SeptemberJune 30, 20172023 and December 31, 20162022, the Company'sCompany’s liquidity was approximately $745 million$1.43 billion and $921 million,$1.37 billion, respectively, comprised of cash, restricted cash and availability under the Company'sCompany’s revolving credit facility.
| | | | | | | | | | | | | | |
(In millions) | | June 30, 2023 | | December 31, 2022 |
Cash and cash equivalents: | | | | |
Clearway Energy LLC, excluding subsidiaries | | $ | 413 | | | $ | 536 | |
Subsidiaries | | 134 | | | 121 | |
Restricted cash: | | | | |
Operating accounts | | 104 | | | 109 | |
Reserves, including debt service, distributions, performance obligations and other reserves | | 267 | | | 230 | |
Total cash, cash equivalents and restricted cash | | 918 | | | 996 | |
Revolving credit facility availability | | 512 | | | 370 | |
Total liquidity | | $ | 1,430 | | | $ | 1,366 | |
The Company'sCompany’s liquidity includes $140$371 million and $165$339 million of restricted cash balances as of SeptemberJune 30, 20172023 and December 31, 20162022, respectively. Restricted cash consists primarily of funds to satisfy the requirements of certain debt agreementsarrangements and funds held within the Company'sCompany’s projects that are restricted in their use. The Company's various financing arrangements are described in Note 7, Long-term Debt. As of SeptemberJune 30, 2017,2023, these restricted funds were comprised of $104 million designated to fund operating expenses, approximately $168 million designated for current debt service payments and $85 million restricted for reserves including debt service, performance obligations and other reserves, as well as capital expenditures. The remaining $14 million is held in distribution reserve accounts.
Clearway Energy LLC and Clearway Energy Operating LLC Revolving Credit Facility
On March 15, 2023, Clearway Energy Operating LLC refinanced the Amended and Restated Credit Agreement, which (i) replaced LIBOR with SOFR plus a credit spread adjustment of 0.10% as the applicable reference rate, (ii) increased the available revolving commitments to an aggregate principal amount of $700 million, (iii) extended the maturity date to March 15, 2028, (iv) increased the letter of credit sublimit to $594 million and (v) implemented certain other technical modifications.
As of June 30, 2023, the Company had $427 million of available borrowings under its revolving credit facility.
As of September 30, 2017, there were no outstanding borrowings under the revolving credit facility and there were $68$188 million ofin letters of credit outstanding under the Company's revolving credit facility.outstanding. The facility will continue to be used for general corporate purposes including financing of future acquisitions and posting letters of credit.
Management believes that the Company'sCompany’s liquidity position, cash flows from operations, and availability under its revolving credit facility will be adequate to meet the Company'sCompany’s financial commitments; debt service obligations; growth, operating and maintenance capital expenditures; and to fund distributions to Yield,Clearway, Inc. and NRG.CEG. Management continues to regularly monitor the Company'sCompany’s ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.
Sources of Liquidity
The Company’s principal sources of liquidity include cash on hand, cash generated from operations, proceeds from sales of assets, borrowings under new and existing financing arrangements and the issuance of additional equity and debt securities by Clearway, Inc. or the Company as appropriate given market conditions. As described in Note 7, Long-term Debt, to this Form 10-Q and Item 15 — Note 10, Long-term Debt, to the consolidated financial statements included in the Company’s 2022 Form 10-K, the Company’s financing arrangements consist of corporate level debt, which includes Senior Notes, intercompany borrowings with Clearway, Inc. and the revolving credit facility, the ATM Program and project-level financings for its various assets.
Credit Ratings
Credit rating agencies rate a firm'sfirm’s public debt securities. These ratings are utilized by the debt markets in evaluating a firm'sfirm’s credit risk. Ratings influence the price paid to issue new debt securities by indicating to the market the Company'sCompany’s ability to pay principal, interest and preferred dividends. Rating agencies evaluate a firm'sfirm’s industry, cash flow, leverage, liquidity and hedge profile, among other factors, in their credit analysis of a firm'sfirm’s credit risk.
As of SeptemberJune 30, 2017,2023, the Company's 2024Company’s 2028 Senior Notes, 2031 Senior Notes and 20262032 Senior Notes arewere rated BB by S&P and Ba2 by Moody's, respectively. The ratings outlook is stable.Moody’s.
Sources of Liquidity
The Company's principal sources of liquidity include cash on hand, cash generated from operations, borrowings under new and existing financing arrangements and the issuance of additional equity and debt securities as appropriate given market conditions. As described inItem 1— Note 7, Long-term Debt, to this Form 10-Q and Note 10, Long-term Debt, to the consolidated financial statements included in the Company's May 9, 2017 Form 8-K, the Company's financing arrangements consist of the revolving credit facility, the Senior Notes, the ATM Program, its intercompany borrowings with Yield, Inc. and project-level financings for its various assets.
At-the-Market Equity Offering Program
NRG Yield, Inc. is party to an equity distribution agreement with Barclays Capital Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC, as sales agents. Pursuant to the terms of the equity distribution agreement, NRG Yield, Inc. may offer and sell shares of its Class C common stock par value $0.01 per share, from time to time through the sales agents up to an aggregate sales price of $150,000,000 through an at-the-market equity offering program, or the ATM Program. NRG Yield, Inc. may also sell shares of its Class C common stock to any of the sales agents, as principals for its own account, at a price agreed upon at the time of sale. During the three months ended September 30, 2017, Yield, Inc. issued 987,727 shares of Class C common stock under the ATM Program for gross proceeds of $18 million. During the nine months ended September 30, 2017, Yield, Inc. issued 1,921,866 shares of Class C common stock under the ATM Program for gross proceeds of $35 million and incurred commission fees of $346 thousand. Yield, Inc. used the net proceeds to acquire 1,921,866 Class C units from Yield LLC.
Thermal Financing
On March 16, 2017, NRG Energy Center Minneapolis LLC, a subsidiary of NRG Thermal LLC, amended the shelf facility of its existing Thermal financing arrangement to allow for the issuance of an additional $10 million of Series F notes at a 4.60% interest rate, or the Series F Notes, increasing the total principal amount of notes available for issuance under the shelf facility to $80 million. The Series F Notes will be secured by substantially all of the assets of NRG Energy Center Minneapolis LLC. NRG Thermal LLC has guaranteed the indebtedness and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal LLC’s subsidiaries.
Uses of Liquidity
The Company'sCompany’s requirements for liquidity and capital resources, other than for operating its facilities, are categorized as: (i) debt service obligations, as described more fully in Item 1 — Note 7, Long-term Debt; (ii) capital expenditures; (iii) off-balance sheet arrangements; (iv) acquisitions and investments;investments, as described more fully in Note 3, Acquisitions and (iv)Dispositions and Note 4, Investments Accounted for by the Equity Method and Variable Interest Entities; and (v) distributions.
Capital Expenditures
The Company'sCompany’s capital spending program is mainly focused on maintenance capital expenditures, consisting of costs to maintain the assets currently operating, such as costs to replace or refurbish assets during routine maintenance, and growth capital expenditures consisting of costs to construct new assets and costs to complete the construction of assets where construction is in process, and capital expenditures related to acquiring additional thermal customers. process.
For the ninesix months ended SeptemberJune 30, 20172023, the Company used approximately $23$109 million to fund capital expenditures, including growthexpenditures of $2$96 million in the ThermalRenewables segment, funded through construction-related financing. Renewables segment capital expenditures included $86 million incurred in connection with expansion of its customer base. For the nine months ended September 30, 2016,Daggett 3 solar project, $7 million incurred in connection with the Waiawa solar project and $3 million incurred by other wind and solar projects. In addition, the Company used approximately $16incurred $13 million to fundin maintenance capital expenditures, of which $12 million related to maintenance expenditures. The Company develops annual capital spending plans based on projected requirements for maintenance and growth capital. The Company estimated an additional $5 million and $32estimates $35 million of maintenance expenditures for the remainder of 2017 and full 2018, respectively. 2023. These estimates are subject to continuing review and adjustment and actualadjustment. Actual capital expenditures may vary from these estimates.
Acquisitions and Investments
The Company intends to acquire generation and thermal infrastructure assets developed and constructed by NRG and third parties in the future, as well as generation and thermal infrastructure assets from third parties where the Company believes its knowledge of the market and operating expertise provides a competitive advantage, and to utilize such acquisitions as a means to grow its CAFD.
On February 24, 2017, the Company amended and restated the ROFO Agreement, expanding the ROFO Assets pipeline with the addition of 234 net MW of utility-scale solar projects, consisting of Buckthorn, a 154 net MW solar facility in Texas, and Hawaii solar projects, which have a combined capacity of 80 net MW.
On October 17, 2017, NRG offered the Company the opportunity to purchase 100% of its ownership interest in Buckthorn pursuant to the ROFO Agreement. The Buckthorn acquisition is subject to negotiation and approval by the Company's independent directors.
As discussed in Item 1 — Note 3, Business Acquisitions, the Company completed the following acquisitions in 2017:
November 2017 Drop Down Assets — On November 1, 2017, the Company acquired a 38 MW solar portfolio primarily comprised of assets from NRG's Solar Power Partners (SPP) funds and other projects developed by NRG, for cash consideration of $71 million, excluding working capital adjustments, plus assumed non-recourse debt of $26 million. As of September 30, 2017, the November 2017 Drop Down Assets' debt was $33 million, of which $7 million was paid by NRG in October 2017.
August 2017 Drop Down Assets — On August 1, 2017, the Company acquired the remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, from NRG for total cash consideration of $44 million, including a working capital adjustment of $3 million. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027.
March 2017 Drop Down Assets — On March 27, 2017, the Company acquired the following interests from NRG: (i) Agua Caliente Borrower 2 LLC, which owns a 16% interest (approximately 31% of NRG's 51% interest) in the Agua Caliente solar farm, one of the ROFO Assets, representing ownership of approximately 46 net MW of capacity, and (ii) NRG's interests in seven utility-scale solar farms located in Utah, which are part of a tax equity structure with Dominion Solar Projects III, Inc., or Dominion, from which the Company would receive 50% of cash to be distributed. The Company paid cash consideration of $130 million, plus $2 million of working capital and assumed non-recourse project debt. The purchase price for the acquisition was funded with cash on hand.
Investment Partnership with NRG
On September 26, 2017, the Company entered into a partnership with NRG by forming NRG DGPV Holdco 3 LLC, or DGPV Holdco 3, in which the Company would invest up to $50 million in an operating portfolio of distributed solar assets, primarily comprised of community solar projects, developed by NRG. The Company invested $4 million during September 2017 with an additional $16 million due to NRG in accounts payable - affiliate as of September 30, 2017, to be funded in tranches as the project milestones are completed. The Company co-owns approximately 33 MW of distributed solar capacity, based on cash to be distributed, with a weighted average contract life of approximately 20 years as of September 30, 2017.
During the nine months ended September 30, 2017, the Company invested $37 million in NRG DGPV Holdco 2 LLC.
Cash Distributions to Yield, Inc. and NRG
The Company intends to distribute to its unit holders in the form of a quarterly distribution all of the CAFD it generates each quarter, less reserves for the prudent conduct of the business, including among others, maintenance capital expenditures to maintain the operating capacity of the assets. CAFD is defined as net income before interest expense, income taxes, depreciation and amortization, plus cash distributions from unconsolidated affiliates, cash receipts from notes receivable, less cash distributions to noncontrolling interests, maintenance capital expenditures, pro-rata EBITDA from unconsolidated affiliates, cash interest paid, income taxes paid, principal amortization of indebtedness and changes in prepaid and accrued capacity payments. Dividends on the Class A common stock and Class C common stock are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.
The following table lists the distributions paid on the Company's Class A, B, C and D units during the nine months ended September 30, 2017:
|
| | | | | | | | | | | |
| Third Quarter 2017 | | Second Quarter 2017 | | First Quarter 2017 |
Distributions per Class A, B, C and D unit | $ | 0.28 |
| | $ | 0.27 |
| | $ | 0.26 |
|
On October 31, 2017, the Company declared a distribution on its Class A, Class B, Class C and Class D units of $0.288 per unit payable on December 15, 2017 to unit holders of record as of December 1, 2017.
Cash Flow Discussion
The following table reflects the changes in cash flows for the nine months ended September 30, 2017, compared to the nine months ended September 30, 2016:
|
| | | | | | | | | | | |
| Nine months ended September 30, | | |
| 2017 | | 2016 | | Change |
| (In millions) |
Net cash provided by operating activities | $ | 375 |
| | $ | 444 |
| | $ | (69 | ) |
Net cash used in investing activities | (204 | ) | | (135 | ) | | (69 | ) |
Net cash used in financing activities | (339 | ) | | (212 | ) | | (127 | ) |
Net Cash Provided By Operating Activities
|
| | | |
Changes to net cash provided by operating activities were driven by: | (In millions) |
Decrease in operating income adjusted for non-cash items | $ | (52 | ) |
Decrease in working capital driven primarily by timing of cash receipts from customers in the first nine months of 2017 compared to the same period in 2016 | (26 | ) |
Higher distributions from unconsolidated affiliates primarily due to the acquisition of the Utah Solar Portfolio, which was acquired by the Company in March 2017 and by NRG in November 2016 | 9 |
|
| $ | (69 | ) |
Net Cash Used In Investing Activities
|
| | | |
Changes to net cash used in investing activities were driven by: | (In millions) |
Payments for the August 2017 Drop Down Assets and March 2017 Drop Down Assets compared to the payments made for the CVSR Drop Down in 2016 | $ | (99 | ) |
Decrease in investments in unconsolidated affiliates in 2017 primarily due to the timing of funding of the projects | 37 |
|
Higher capital expenditures in 2017 compared to the same period in 2016 due primarily to maintenance expenditures at Walnut Creek as a result of the forced outages | (7 | ) |
| $ | (69 | ) |
Net Cash Used in Financing Activities
|
| | | |
Changes in net cash used in financing activities were driven by: | (In millions) |
Proceeds from the issuance of Class C units | $ | 33 |
|
Net borrowings under the revolving credit facility in 2016 | 306 |
|
Higher borrowings in 2016, primarily related to the proceeds from the issuance of 2026 Senior Notes and CVSR Holdco Notes due 2037 combined with higher repayments of long-term debt and increased financing fees in 2017 | (527 | ) |
Increase in net contributions from noncontrolling interests due to higher production-based payments in 2017 compared to 2016 | 6 |
|
Increase in distributions paid to unit holders | (22 | ) |
Lower payments of distributions to NRG for the Drop Down Assets relating to the pre-acquisition period in 2017 compared to 2016 | 77 |
|
| $ | (127 | ) |
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contracts
The Company may enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties.
Retained or Contingent Interests
The Company 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 SeptemberJune 30, 2017,2023, the Company has several investments with an ownership interest percentage of 50% or less in energy and an energy-related entitiesentity that areis accounted for under the equity method. Utah Solar Portfolio, GenConn DGPV Holdco 1, RPV Holdco, DGPV Holdco 2, and DGPV Holdco 3 areis a variable interest entitiesentity for which the Company is not the primary beneficiary.
The Company'sCompany’s pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $643$317 million as of SeptemberJune 30, 2017.2023. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to the Company. For a complete description of debt held by unconsolidated affiliates seeNote 5, Investments Accounted for by the Equity Method and Variable Interest Entities to the consolidated financial statements for the year ended December 31, 2016 included in the Company's May 9, 2017 Form 8-K.
Contractual Obligations and Commercial Commitments
The Company has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company'sCompany’s capital expenditure programs, as disclosed in the Company's 2016Company’s 2022 Form 10-K. See also Note
Acquisitions and Investments
The Company intends to acquire generation assets developed and constructed by CEG, as well as generation assets from third parties where the Company believes its knowledge of the market and operating expertise provides a competitive advantage, and to utilize such acquisitions as a means to grow its business.
Rosie Central BESS — On June 30, 2023, the Company, through its indirect subsidiary, Rosie Class B LLC, the indirect owner of the Rosamond Central solar project, became the owner of the Class B membership interests of Rosie Central BESS in order to facilitate and fund the construction of a 147 MW BESS project that will be co-located at the Rosamond Central solar facility. Clearway Renew indirectly owns the Class A membership interests. The Company’s investment consists of $10 million contributed into Rosie Central BESS, funded through contributions from the Company and its cash equity investor in Rosie TargetCo LLC, which consolidates Rosie Class B LLC. On July 3, Business Acquisitions2023, Rosie Class B LLC contributed an additional $20 million into Rosie Central BESS. Additionally, on June 30, 2023, Rosamond Central entered into an asset purchase agreement with Rosie Central BESS to this Form 10-Qacquire the BESS project assets at mechanical completion for a discussionpurchase price of $360 million, of which $72 million is payable at mechanical completion with the remaining $288 million payable at substantial completion. The Company will fund $17 million of the purchase price at mechanical completion and $67 million of the purchase price at substantial completion. The BESS project is anticipated to reach mechanical completion in the second half of 2023 and to reach substantial completion in the first half of 2024.
On June 30, 2023, Rosie Class B LLC amended its financing agreement. On July 3, 2023, the Company received total loan proceeds of $138 million under the refinancing, which is net of $5 million in debt issuance costs. Also on July 3, 2023, Rosie Class B LLC issued a loan to a consolidated subsidiary of Clearway Renew in the aggregate principal amount of $117 million in order to finance the construction of the BESS project.
Waiawa Drop Down —In connection with the 2022 Drop Down of Waiawa, the Company assumed the project’s financing agreement, which includes a construction loan that converted to a term loan on March 30, 2023 upon the project reaching substantial completion and a tax equity bridge loan that was repaid on March 30, 2023.
Daggett 3 Drop Down — On February 17, 2023, the Company, through its indirect subsidiary, Daggett Solar Investment LLC, acquired the Class A membership interests in Daggett TargetCo LLC, the indirect owner of the Daggett 3 solar project, from Clearway Renew for cash consideration of $21 million and then contributed its Class A membership interests into Daggett Renewable Holdco LLC, a partnership between the Company and a cash equity investor, which consolidates Daggett TargetCo LLC. Daggett TargetCo LLC consolidates, as the indirect owner of the primary beneficiary, a tax equity fund, Daggett TE Holdco LLC, which owns the Daggett 3 solar project. Daggett 3 has PPAs with investment-grade counterparties that have a 15-year weighted average contract duration that commence when the underlying operating assets reach commercial operations, which is expected to occur in the second half of 2023. The acquisition was funded with existing sources of liquidity. As part of the acquisition, the Company assumed the project’s financing agreement, which included a construction loan that converts to a term loan upon the project reaching substantial completion, a tax equity bridge loan that will be repaid when the project reaches substantial completion and a sponsor equity bridge loan that was repaid at acquisition date. Subsequent to the acquisition, CEG funded an additional contingencies$43 million in project completion costs, which will be repaid with the proceeds received when the project reaches substantial completion, which is expected to occur in the second half of 2023.
Cash Distributions to Clearway, Inc. and CEG
The Company intends to distribute to its unit holders in the form of a quarterly distribution all of the CAFD it generates each quarter less reserves for the prudent conduct of the business, including among others, maintenance capital expenditures to maintain the operating capacity of the assets. Distributions on the Company’s units are subject to available capital, market conditions and compliance with associated laws, regulations and other contractual obligations. The Company expects that, occurredbased on current circumstances, comparable cash distributions will continue to be paid in the foreseeable future.
The following table lists the distributions paid on the Company’s Class A, B, C and D units during 2017.the six months ended June 30, 2023:
| | | | | | | | | | | | | | | | | |
| | | | | Second Quarter 2023 | | First Quarter 2023 |
Distributions per Class A, B, C and D unit | | | | | $ | 0.3818 | | | $ | 0.3745 | |
| | | | | | | |
On August 7, 2023, the Company declared a distribution on its Class A, Class B, Class C and Class D units of $0.3891 per unit payable on September 15, 2023 to unit holders of record as of September 1, 2023.
Cash Flow Discussion
The following tables reflect the changes in cash flows for the comparative periods:
| | | | | | | | | | | | | | | | | |
| Six months ended June 30, | | |
| 2023 | | 2022 | | Change |
| (In millions) |
Net cash provided by operating activities | $ | 235 | | | $ | 280 | | | $ | (45) | |
Net cash (used in) provided by investing activities | (116) | | | 1,331 | | | (1,447) | |
Net cash used in financing activities | (197) | | | (977) | | | 780 | |
Net Cash Provided by Operating Activities
| | | | | |
Changes to net cash provided by operating activities were driven by: | (In millions) |
Decrease in operating income adjusted for non-cash items | $ | (46) | |
Increase in working capital primarily driven by the timing of accounts receivable collections and payments of current liabilities | (11) | |
Decrease in distributions from unconsolidated affiliates | (6) | |
Transaction expenses paid on May 1, 2022 in connection with the sale of the Thermal Business | 18 | |
| |
| $ | (45) | |
| |
| |
Net Cash (Used in) Provided by Investing Activities
| | | | | |
Changes to net cash (used in) provided by investing activities were driven by: | (In millions) |
Proceeds from the sale of the Thermal Business in 2022 | $ | (1,457) | |
Increase in capital expenditures | (28) | |
Increase in investments in unconsolidated affiliates | (10) | |
Decrease in cash paid for Drop Down Assets | 44 | |
Increase in the return of investment from unconsolidated affiliates | 4 | |
| $ | (1,447) | |
| |
| |
Net Cash Used in Financing Activities
| | | | | |
Changes in net cash used in financing activities were driven by: | (In millions) |
| |
| |
Increase in contributions from noncontrolling interest members and CEG, net of distributions | $ | 282 | |
Decrease in payments for the revolving credit facility, net of proceeds | 245 | |
Decrease in payments for long-term debt, net of proceeds | 245 | |
Cash released from escrow distributed to CEG in 2022 | 64 | |
Tax related distributions in 2023 | (45) | |
Increase in distributions paid to unit holders | (12) | |
Other | 1 | |
| $ | 780 | |
Fair Value of Derivative Instruments
The Company may enter into fuelcommodity purchase contracts and other energy-related derivativefinancial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at certain generation facilities.prices. In addition, in order to mitigate interest rate risk associated with the issuance of variable rate debt, the Company enters into interest rate swap agreements.
The tables below disclose the activities of non-exchange traded contracts accounted for at fair value in accordance with ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at SeptemberJune 30, 20172023, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at SeptemberJune 30, 20172023. For a full discussion of the Company'sCompany’s valuation methodology of its contracts, see Derivative Fair Value Measurements in Item — 1 Note 5, Fair Value of Financial Instruments.
| | | | | |
Derivative Activity (Losses) Gains | (In millions) |
Fair value of contracts as of December 31, 2022 | $ | (264) | |
Contracts realized or otherwise settled during the period | 22 | |
Contracts acquired during the period | 27 | |
| |
| |
Changes in fair value | 29 | |
Fair value of contracts as of June 30, 2023 | $ | (186) | |
|
| | | |
Derivative Activity (Losses)/Gains | (In millions) |
Fair value of contracts as of December 31, 2016 | $ | (73 | ) |
Contracts realized or otherwise settled during the period | 21 |
|
Changes in fair value | (14 | ) |
Fair value of contracts as of September 30, 2017 | $ | (66 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of contracts as of June 30, 2023 |
| 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 |
| (In millions) |
| | | | | | | | | |
Level 2 | $ | 34 | | | $ | 40 | | | $ | 24 | | | $ | 19 | | | $ | 117 | |
Level 3 | (44) | | | (85) | | | (75) | | | (99) | | | (303) | |
Total | $ | (10) | | | $ | (45) | | | $ | (51) | | | $ | (80) | | | $ | (186) | |
|
| | | | | | | | | | | | | | | | | | | |
| Fair value of contracts as of September 30, 2017 |
| Maturity | | |
Fair Value Hierarchy Losses | 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) |
Level 2 | $ | 23 |
| | $ | 25 |
| | $ | 12 |
| | $ | 6 |
| | $ | 66 |
|
The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. NRG, on behalf of the Company, measures the sensitivity of the 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 net open position.
Critical Accounting Policies and Estimates
The Company'sCompany’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, the Company evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actualActual results may differ substantially from the Company'sCompany’s estimates. Any effects on the Company'sCompany’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'sCompany’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. The Company'sCompany’s critical accounting policies include impairment of long livedincome taxes and valuation allowance for deferred tax assets, accounting utilizing Hypothetical Liquidation at Book Value, or HLBV, acquisition accounting and other intangible assets and acquisition accounting.
The Company tests its long-lived assets for impairment whenever indicators of impairment exist. Certain ofdetermining the Company’s projects have useful lives that extend well beyond the contract period and therefore, management’s view of long-term merchant power prices in the post-contract periods may have a significant impact on the expected future cash flows for these projects. The Company’s annual budget is utilized to determine the cash flows associated with the Company’s long-lived assets, which
incorporates various assumptions, including the Company’s long-term view of natural gas prices and its impact on merchant power prices and fuel costs. The Company’s annual budget process is finalized and approved by the Board of Directors in the fourth quarter. It is possible that the updated long term cash flows will not support the carryingfair value of certain assets, and the Company will be required to test such assets for impairment. During the preparation of the budget, the Company noted that management’s view of long term merchant power prices has decreased, and accordingly, it is possible that certain of the Company's long-lived assets will be impaired during the fourth quarter of 2017.financial instruments.
Recent Accounting Developments
See Item — 1 Note 2, Summary of Significant Accounting Policies, for a discussion of recent accounting developments.
ITEM 3 — Quantitative and Qualitative Disclosures About Market Risk
The Company is exposed to several market risks in its normal business activities. Market risk is the potential loss that may result from market changes associated with the Company’s 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 and credit risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 37A —Quantitative and Qualitative Disclosures About Market Risk, of the Company’s 2022 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 electricity, natural gas and emissions credits. The Company manages the commodity price risk of certain of its merchant generation operations by entering into derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted power sales. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.05 per MWh increase or decrease in power prices across the term of the derivatives contracts would cause a change of approximately $6 million to the net value of power derivatives as of June 30, 2023.
Interest Rate Risk
The Company 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. See Note 6, Derivative Instruments and Hedging Activities, for more information.
Most of 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 Item 15 — Note 10, Long-term Debt, to the Company’s audited consolidated financial statements for the year ended December 31, 2022 included in the 2022 Form 10-K for more information about interest rate swaps of the Company’s project subsidiaries.
If all of the interest rate swaps had been discontinued on June 30, 2023, the counterparties would have owed the Company $121 million. Based on the credit ratings of the counterparties, the Company believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.
The Company has been omittedlong-term debt instruments that subject it to the risk of loss associated with movements in market interest rates. As of June 30, 2023, a change of 1%, or 100 basis points, in interest rates would result in an approximately $2 million change in market interest expense on a rolling twelve-month basis.
As of June 30, 2023, the fair value of the Company’s debt was $6.52 billion and the carrying value was $7.10 billion. The Company estimates that a decrease of 1%, or 100 basis points, in market interest rates would have increased the fair value of its long-term debt by approximately $338 million.
Liquidity Risk
Liquidity risk arises from this reportthe general funding needs of the Company’s activities and in the management of the Company’s assets and liabilities.
Counterparty Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the reduced disclosure format permittedterms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; and (ii) the use of credit mitigation measures such as prepayment arrangements or volumetric limits. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by General Instruction H(2)having a diversified portfolio of counterparties. See Note 5, Fair Value of Financial Instruments, to Form 10-Q.the consolidated financial statements for more information about concentration of credit risk.
ITEM 4 — Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure ControlsandProcedures
Under the supervision and with the participation of the Company'sCompany’s management, including its principal executive officer, principal financial officer and principal accounting officer, the Company 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'sCompany’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
There were no changes in the Company’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 June 30, 2023 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II -— OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
For a discussion of the material legal proceedings in which the Company was involved through SeptemberJune 30, 2017,2023, see Note 11, 10, Contingencies, to this Form 10-Q.
ITEM 1A — RISK FACTORS
Information regarding risk factors appears in Part I, Item 1A, Risk Factors, in the Company's 2016Company’s 2022 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'sCompany’s risk factors since those reported in its 20162022 Form 10-K and its Form 10-Q for the quarter ended June 30, 2017.10-K.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Item 2 has been omitted from this report for the Registrants pursuant to the reduced disclosure format permitted by General Instruction H(2) to Form 10-Q.None.
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
Item 3 has been omitted from this report for the Registrants pursuant to the reduced disclosure format permitted by General Instruction H(2) to Form 10-Q.None.
ITEM 4 — MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5 — OTHER INFORMATION
None.
During the three months ended June 30, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.
ITEM 6 — EXHIBITS
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Number | | Description | | Method of Filing |
31.110.1†* | | | | Incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 24, 2023. |
31.1 | | | | Filed herewith. |
31.2 | | | | Filed herewith. |
31.332 | | | | Filed herewith. |
32 | | | | Furnished herewith. |
101 INS | | Inline XBRL Instance Document. | | Filed herewith. |
101 SCH | | Inline XBRL Taxonomy Extension Schema. | | Filed herewith. |
101 CAL | | Inline XBRL Taxonomy Extension Calculation Linkbase. | | Filed herewith. |
101 DEF | | Inline XBRL Taxonomy Extension Definition Linkbase. | | Filed herewith. |
101 LAB | | Inline XBRL Taxonomy Extension Label Linkbase. | | Filed herewith. |
101 PRE | | Inline XBRL Taxonomy Extension Presentation Linkbase. | | Filed herewith. |
104 | | Cover Page Interactive Data File (the cover page interactive data file does not appear in Exhibit 104 because its Inline XBRL tags are embedded within the Inline XBRL document). | | Filed herewith. |
† Schedules and similar attachments to this Exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company agrees to furnish supplementally a copy of any omitted schedule or exhibit to the U.S. Securities and Exchange Commission upon request.
* Certain portions of this Exhibit have been redacted pursuant to Item 601(b)(10)(iv) of Regulation S-K. The omitted information is (i) not material and (ii) would likely cause competitive harm to the Company if publicly disclosed. The Company agrees to furnish supplementally an unredacted copy of this Exhibit to the SEC upon request.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| NRG YIELDCLEARWAY ENERGY LLC
(Registrant)
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| /s/ CHRISTOPHER S. SOTOS | |
| Christopher S. Sotos | |
| President and Chief Executive Officer (Principal Executive Officer) | |
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| /s/ CHAD PLOTKIN | |
| Chad Plotkin | |
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| /s/ SARAH RUBENSTEIN | |
| Sarah Rubenstein | |
Date: August 8, 2023 | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | |
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| /s/ DAVID CALLEN | |
| David Callen | |
Date: November 2, 2017 | Chief Accounting Officer
( and Principal Accounting Officer)
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